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UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Parts 35 and 37

(Docket Nos. RM05-17-000 and RM05-25-000; Order No. 890)

Preventing Undue Discrimination and Preference in Transmission Service

(Issued February 16, 2007)

AGENCY

: Federal Energy Regulatory Commission.

ACTION

: Final Rule

SUMMARY

: The Federal Energy Regulatory Commission is amending the regulations

and the pro forma

open access transmission tariff adopted in Order Nos. 888 and 889 to

ensure that transmission services are provided on a basis that is just, reasonable and not

unduly discriminatory or preferential. The final rule is designed to: (1) strengthen the

pro forma

open-access transmission tariff, or OATT, to ensure that it achieves its original

purpose of remedying undue discrimination; (2) provide greater specificity to reduce

opportunities for undue discrimination and facilitate the Commission’s enforcement; and

(3) increase transparency in the rules applicable to planning and use of the transmission

system.

EFFECTIVE DATE

: This rule will become effective [insert date 60 days after

publication in the FEDERAL REGISTER].

Docket Nos. RM05-17-000 and RM05-25-000

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FOR FURTHER INFORMATION CONTACT

Daniel Hedberg (Technical Information)

Office of Energy Markets and Reliability

Federal Energy Regulatory Commission

888 First Street, N.E.

Washington, D.C. 20426

(202) 502-6243

W. Mason Emnett (Legal Information)

Office of the General Counsel – Energy Markets

Federal Energy Regulatory Commission

888 First Street, N.E.

Washington, D.C. 20426

(202) 502-6540

Kathleen Barrón (Legal Information)

Office of the General Counsel – Energy Markets

Federal Energy Regulatory Commission

888 First Street, N.E.

Washington, D.C. 20426

(202) 502-6461

SUPPLEMENTARY INFORMATION

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Preventing Undue Discrimination and Preference

in Transmission Service

Docket Nos.

RM05-17-000

RM05-25-000

ORDER NO. 890

FINAL RULE

(Issued February 16, 2007)

TABLE OF CONTENTS

Paragraph Numbers

I. INTRODUCTION .......................................................................................................1.

II. BACKGROUND ........................................................................................................9.

A. Historical Antecedent .......................................................................................... 9.

B. Order No. 888 and Subsequent Reforms ........................................................... 14.

C. EPAct 2005 and Recent Developments ............................................................. 22.

III. NEED FOR REFORM OF ORDER NO. 888......................................................26.

A. Opportunities for Undue Discrimination Continue to Exist.............................. 26.

B. Lack of Transparency Undermines Confidence in Open Access and Impedes

Enforcement of Open Access Requirements .......................................................... 44.

C. Congestion and Inadequate Infrastructure Development Impede Customers’ Use

of the Grid ............................................................................................................... 52.

D. A Consistent Method of Measuring ATC Is Needed ........................................ 62.

E. Discriminatory Pricing of Imbalances ............................................................... 70.

F. Redispatch/Conditional Firm ............................................................................ 73.

G. EPAct 2005 Emphasized Certain Policies and Priorities for the Commission 79.

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IV. SUMMARY, SCOPE AND APPLICABILITY OF THE FINAL RULE .........82.

A. Summary of Reforms......................................................................................... 83.

B. Core Elements of Order No. 888 That Are Retained......................................... 91.

1. Federal/State Jurisdiction .............................................................................. 92.

2. Native Load Protection .................................................................................. 95.

3. The Types of Transmission Services Offered ............................................. 110.

4. Functional Unbundling................................................................................. 117.

C. Applicability of the Final Rule ....................................................................... 124.

1. Non-ISO/RTO Public Utility Transmission Providers ................................ 124.

2. ISO and RTO Public Utility Transmission Providers and Transmission Owner

Members of ISOs and RTOs ............................................................................ 143.

3. Non-Public Utility Transmission Providers/Reciprocity ............................ 162.

V. REFORMS OF THE OATT .................................................................................193.

A. Consistency and Transparency of ATC Calculations ..................................... 193.

B. Coordinated, Open and Transparent Planning ................................................ 418.

C. Transmission Pricing ...................................................................................... 603.

1. General ......................................................................................................... 603.

2. Energy and Generation Imbalances ............................................................. 627.

3. Credits for Network Customers .................................................................. 729.

4. Capacity Reassignment ............................................................................... 778.

5. “Operational” Penalties................................................................................ 826.

a. Unreserved Use Penalties ........................................................................ 826.

b. Distribution of Operational Penalties ...................................................... 850.

c. Applicability of Operational Penalties Proposal to RTOs and Other

Independent or Non-Profit Entities............................................................... 866.

6. “Higher of” Pricing Policy ........................................................................... 870.

7. Other Ancillary Services .............................................................................. 886.

D. Non-Rate Terms and Conditions ..................................................................... 901.

1. Modifications to Long-Term Firm Point-to-Point Service ......................... 901.

a. Planning Redispatch and Conditional Firm Options ............................... 901.

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b. Proposals for Transparent Redispatch ................................................... 1095.

c. Other Requested Service Modifications ............................................... 1165.

2. Hourly Firm Service .................................................................................. 1177.

3. Rollover Rights ......................................................................................... 1214.

4. Modification of Receipt or Delivery Points............................................... 1268.

5. Acquisition of Transmission Service ........................................................ 1296.

a. Processing of Service Requests ............................................................ 1296.

b. Reservation Priority ............................................................................... 1394.

6. Designation of Network Resources............................................................ 1432.

a. Qualification as a Network Resource .................................................... 1432.

b. Documentation for Network Resources................................................. 1507.

c. Undesignation of Network Resources ................................................... 1534.

7. Clarifications Related to Network Service ................................................ 1592.

a. Secondary Network Service................................................................... 1592.

b. Behind the Meter Generation ................................................................ 1614.

8. Transmission Curtailments ........................................................................ 1620.

9. Standardization of Rules and Practices...................................................... 1633.

a. Business Practices .................................................................................. 1633.

b. Liability and Indemnification ............................................................... 1662.

10. OATT Definitions ................................................................................... 1678.

E. Enforcement .................................................................................................. 1714.

1. General Policy............................................................................................ 1715.

2. Civil Penalties ............................................................................................ 1724.

VI. INFORMATION COLLECTION STATEMENT...........................................1752.

VII. ENVIRONMENTAL ANALYSIS ...................................................................1758.

VIII. REGULATORY FLEXIBILITY ACT ANALYSIS ....................................1759.

IX. DOCUMENT AVAILABILITY........................................................................ 1760.

X. EFFECTIVE DATE AND CONGRESSIONAL NOTIFICATION................1763.

Docket Nos. RM05-17-000 and RM05-25-000

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APPENDIX A: Summary of Compliance Requirements

APPENDIX B: Commenting Party Acronyms

APPENDIX C: Pro Forma

Open Access Transmission Tariff

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Joseph T. Kelliher, Chairman;

Suedeen G. Kelly, Marc Spitzer,

Philip D. Moeller, and Jon Wellinghoff.

Preventing Undue Discrimination and Preference in

Transmission Service

Docket Nos.

RM05-17-000

RM05-25-000

ORDER NO. 890

FINAL RULE

(Issued February 16, 2007)

I. Introduction

1. This Final Rule addresses and remedies opportunities for undue discrimination

under the pro forma

Open Access Transmission Tariff (OATT) adopted in 1996 by Order

No. 888.

This landmark rulemaking fostered greater competition in wholesale power

markets by reducing barriers to entry in the provision of transmission service. In the ten

Promoting Wholesale Competition Through Open Access Non-discriminatory

Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities

and Transmitting Utilities, Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. &

Regs. ¶ 31,036 (1996), order on reh’g

, Order No. 888-A, 62 FR 12274 (Mar. 14, 1997),

FERC Stats. & Regs. ¶ 31,048 (1997), order on reh’g

, Order No. 888-B, 81 FERC

¶ 61,248 (1997), order on reh’g

, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff’d in

relevant part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667

(D.C. Cir. 2000) (TAPS v. FERC

), aff’d sub nom. New York v. FERC, 535 U.S. 1

(2002).

Docket Nos. RM05-17-000 and RM05-25-000 - 2 -

years since Order No. 888, however, the Commission has found that the OATT contains

flaws that undermine realizing its core objective of remedying undue discrimination. In

the Notice of Proposed Rulemaking (NOPR) issued on May 19, 2006, the Commission

proposed to remedy those flaws.

After receiving approximately 6,500 pages of

comments from close to 300 parties, we now take final action. We highlight below the

most critical reforms being adopted today.

2. First, the Final Rule will increase nondiscriminatory access to the grid by

eliminating the wide discretion that transmission providers currently have in calculating

available transfer capability (ATC).

The calculation of ATC is one of the most critical

functions under the OATT because it determines whether transmission customers can

access alternative power supplies. Despite this, the existing OATT does not prescribe

how ATC should be calculated because the Commission sought to rely on voluntary

efforts by the industry to develop consistent methods of ATC calculation. This voluntary

industry effort has not proven successful. The Commission therefore acts today to

require public utilities, working through the North American Electric Reliability

Preventing Undue Discrimination and Preference in Transmission Service,

Notice of Proposed Rulemaking, 71 FR 32,636 (Jun. 6, 2006), FERC Stats. & Regs.

¶ 32,603 (2006).

The Commission used the term “Available Transmission Capability” in Order

No. 888 to describe the amount of additional capability available in the transmission

network to accommodate additional requests for transmission services. To be consistent

with the term generally accepted throughout the industry, the Commission revises the

pro forma

OATT to adopt the term “Available Transfer Capability.”

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Corporation (NERC), to develop consistent methodologies for ATC calculation and to

publish those methodologies to increase transparency. This important reform will

eliminate the wide discretion that exists today in calculating ATC and ensure that

customers are treated fairly in seeking alternative power supplies.

3. Second, the Final Rule will increase the ability of customers to access new

generating resources and promote efficient utilization of transmission by requiring an

open, transparent, and coordinated transmission planning process. Transmission planning

is a critical function under the pro forma

OATT because it is the means by which

customers consider and access new sources of energy and have an opportunity to explore

the feasibility of non-transmission alternatives. Despite this, the existing pro forma

OATT provides limited guidance regarding how transmission customers are treated in the

planning process and provides them very little information on how transmission plans are

developed. These deficiencies are serious, given the substantial need for new

infrastructure in this Nation.

We act today to remedy these deficiencies by requiring

Congress placed special emphasis on the development of transmission

infrastructure, including the consideration of advanced transmission technologies, in the

Energy Policy Act of 2005 (EPAct 2005). See

Pub. L. No. 109-58, 119 Stat. 594 (to be

codified in scattered titles of the U.S.C.). The Commission has taken steps to implement

that goal in numerous contexts, including recent rulemaking proceedings that address the

promotion of transmission investment through pricing reform and the siting of certain

transmission facilities. See

Promoting Transmission Investment through Pricing Reform,

Order No. 679, 71 FR 43294 (Jul. 31, 2006), FERC Stats. & Regs. ¶ 31,222 (2006), order

on reh’g, Order No. 679-A, 72 FR 1152 (Jan. 10, 2007), FERC Stats. & Regs. ¶ 31,236

(2007), reh’g pending; Regulations for Filing Applications for Permits to Site Interstate

Electric Transmission Facilities, Order No. 689, 71 FR 69440 (Dec. 1, 2006), FERC

(continued)

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transmission providers to open their transmission planning process to customers,

coordinate with customers regarding future system plans, and share necessary planning

information with customers.

4. Third, the Final Rule will also increase the efficient utilization of transmission by

eliminating artificial barriers to use of the grid. The existing pro forma

OATT allows a

transmission provider to deny a request for long-term point-to-point service if the request

cannot be satisfied in only one hour of the requested term. This practice discourages the

efficient use of the existing grid and precludes access to alternative power supplies. We

reform this practice by requiring that a conditional firm option be offered to customers

seeking long-term point-to-point service, i.e.

, conditional firm service. We also modify

the redispatch obligations of transmission providers to increase the efficient utilization of

the grid, while also ensuring that reliability to native load customers is maintained.

5. Fourth, by adopting these and other reforms, the Final Rule facilitates the use of

clean energy resources such as wind power. Conditional firm service is particularly

important to wind resources that can provide significant economic and environmental

value even if curtailed under limited circumstances. Open and coordinated transmission

planning will enhance the ability of customers to access clean energy resources as part of

Stats. & Regs. ¶ 31,234 (2006), reh’g pending

. As discussed herein, several actions taken

in this Final Rule also relate to the need for investments in transmission infrastructure and

are consistent with the Commission’s responsibilities under EPAct 2005.

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their future resource portfolio. The Final Rule also benefits clean energy resources by

reforming energy and generator imbalance charges. These reforms are particularly

important to intermittent resources such as wind power because these resources have

limited ability to control their output and, hence, must be assured that imbalance charges

are no more than required to provide appropriate incentives for prudent behavior.

6. Fifth, the Final Rule will strengthen compliance and enforcement efforts. We are

increasing the transparency of pro forma

OATT administration, thereby increasing the

ability of customers and our Office of Enforcement to detect undue discrimination. We

are adopting operational penalties for clear violations of an OATT, thereby enhancing

compliance while also reducing the burdens on our Office of Enforcement. We are also

increasing the clarity of many other OATT requirements, thereby facilitating compliance

by transmission providers with our regulations. This Final Rule thus reflects the close

integration of our Office of Enforcement into policy development at the Commission.

Several of the reforms we adopt today are informed by our experience with OATT

administration through oversight, audits, and investigations performed by the Office of

Enforcement.

7. Finally, we modify and improve several provisions of the pro forma

OATT using

our experience over the past ten years and clarify others that have proven ambiguous.

For example, we reform our rollover rights policy to ensure that the rights and obligations

of rollover customers are consistent with the resulting obligations of transmission

providers to plan and upgrade the system to accommodate rollovers. We remove the

Docket Nos. RM05-17-000 and RM05-25-000 - 6 -

price cap on reassigned capacity because it is not necessary to remedy market power and

doing so will otherwise increase the efficient use of existing capacity. We increase the

efficient use of existing capacity by providing a priority to certain “pre-confirmed”

requests for service. We increase certainty by providing greater clarity regarding the

wholesale contracts that qualify as network resources. We also adopt numerous

clarifications that should assist transmission providers and customers in implementing

and using the pro forma

OATT

8. Our actions in this proceeding have been informed to a great extent by the

comments received in response to our notices of inquiry in the above-captioned dockets

and the subsequent NOPR.

We appreciate the time and thoughtfulness of all sectors of

the industry in preparing comments. We have found them very informative and useful in

reaching our decisions in this Final Rule.

II. Background

A. Historical Antecedent

9. In the NOPR, the Commission explained the historical background that led up to

the issuance of Order No. 888, and the initiation of this rulemaking proceeding. We

repeat that history here to place in context the actions we take today.

Preventing Undue Discrimination and Preference in Transmission Services,

Notice of Inquiry, 112 FERC ¶ 61,299 (2005) (NOI); Information Requirements for

Available Transfer Capability, Notice of Inquiry, 111 FERC ¶ 61,274 (2005) (ATC NOI).

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10. In the first few decades after enactment of the Federal Power Act (FPA) in 1935,

the industry was characterized mostly by self-sufficient, vertically integrated electric

utilities, in which generation, transmission, and distribution facilities were owned by a

single entity and sold as part of a bundled service to wholesale and retail customers.

Most electric utilities built their own power plants and transmission systems, entered into

interconnection and coordination arrangements with neighboring utilities, and entered

into long-term contracts to make wholesale requirements sales (bundled sales of

generation and transmission) to municipal, cooperative, and investor-owned utilities

connected to each utility's transmission system. Each system covered a limited service

area, which was defined by the retail franchise decisions of state regulatory agencies.

This structure of separate systems arose naturally primarily due to cost and the

technological limitations on the distance over which electricity could be transmitted.

11. A number of statutory, economic, and technological developments in the 1970s

led to an increase in coordinated operations and competition. Among those was the

passage of the Public Utility Regulatory Policies Act of 1978 (PURPA),

which was

designed to lessen dependence on foreign fossil fuels by encouraging the development of

alternative generation sources and imposing a mandatory purchase obligation on utilities

for generation from such sources. PURPA also enabled the Commission to order

Pub. L. No. 95-617, 92 Stat. 3117 (1978) (codified in U.S.C. titles 15, 16, 26, 30,

42, and 43).

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wheeling of electricity under limited circumstances.

The rapid expansion and

performance of the independent power industry following the enactment of PURPA

demonstrated that traditional, vertically integrated public utilities need not be the only

sources of reliable power. During this period, the profile of generation investment began

to change, and a market for non-traditional power supply beyond the purchases required

by PURPA began to emerge. The economic and technological changes in the

transmission and generation sectors helped encourage many new entrants in the

generating markets that could sell electric energy profitably with smaller scale

technology at a lower price than many utilities selling from their existing generation

facilities at rates reflecting cost. However, it became increasingly clear that the potential

consumer benefits that could be derived from these technological advances could be

realized only if more efficient generating plants could obtain access to the regional

transmission grids. Because many traditional vertically integrated utilities still did not

provide open access to third parties and favored their own generation if and when they

Section 211 of the FPA, 16 U.S.C. 824j. In earlier years, a few customers were

able to obtain access as a result of litigation, beginning with the U.S. Supreme Court’s

decision in Otter Tail Power Company v. United States

, 410 U.S. 366 (1973).

Additionally, some customers gained access by virtue of Nuclear Regulatory

Commission license conditions and voluntary preference power transmission

arrangements associated with federal power marketing agencies. See, e.g.

, Consumers

Power Co., 6 NRC 887, 1036-44 (1977); Toledo Edison Co., 10 NRC 265, 327-34

(1979); Florida Municipal Power Agency v. Florida Power and Light Co.

, 839 F. Supp.

1563 (M.D. Fla. 1993).

Docket Nos. RM05-17-000 and RM05-25-000 - 9 -

provided transmission access to third parties, access to cheaper, more efficient generation

sources remained limited.

12. The Commission encouraged the development of independent power producers

(IPPs), as well as emerging power marketers, by authorizing market-based rates for their

power sales on a case-by-case basis, and by encouraging more widely available

transmission access on a case-by-case basis. Market-based rates helped to develop

competitive bulk power markets by allowing generating utilities to move more quickly

and flexibly to take advantage of short-term or even long-term market opportunities than

those utilities operating under traditional cost-of-service tariffs. In approving these

market-based rates, the Commission required that the seller and its affiliates lack market

power or mitigate any market power that they may have had.

The major concern of the

Commission was whether the seller or its affiliates could limit competition and thereby

drive up prices. A key inquiry became whether the seller or its affiliates owned or

controlled transmission facilities in the relevant service area and therefore, by denying

access or imposing discriminatory terms or conditions on transmission service, could

foreclose other generators from competing. Beginning in the late 1980s, in order to

mitigate their market power to meet the Commission’s conditions, public utilities seeking

See, e.g., Dartmouth Power Associates Limited Partnership, 53 FERC ¶ 61,117

(1990); Commonwealth Atlantic Limited Partnership

, 51 FERC ¶ 61,368 (1990);

Doswell Limited Partnership

, 50 FERC ¶ 61,251 (1990); Citizens Power & Light Co.,

48 FERC ¶ 61,210 (1989); Ocean State Power

, 44 FERC ¶ 61,261 (1988); and Orange

and Rockland Utilities, Inc., 42 FERC ¶ 61,012 (1988).

Docket Nos. RM05-17-000 and RM05-25-000 - 10 -

Commission authorization for blanket approval of market-based rates for generation

services under section 205 of the FPA filed "open access" transmission tariffs of general

applicability.

The Commission also approved proposed mergers under section 203 of

the FPA on the condition that the merging companies remedy anticompetitive effects

potentially caused by the merger by filing "open access" tariffs. The early tariffs

submitted in market-based rate proceedings under section 205 and merger proceedings

under section 203 did not, however, provide access to the transmission system that was

comparable to the service the transmission providers used for their own purposes.

Rather, they typically made available only point-to-point transmission service, i.e.

service from a single point of receipt to a single point of delivery. As these early tariffs

were offered only by transmission providers that volunteered to provide service to third

parties, they resulted in a patchwork of open access that was not sufficient to facilitate

wholesale generation markets.

13. In response to the competitive developments following PURPA, and the fact that

limited transmission access and significant regulatory barriers continued to constrain the

development of generation by independent power producers, Congress enacted Title VII

of the Energy Policy Act of 1992 (EPAct 1992).

EPAct 1992 reduced regulatory

See Order No. 888 at 31,644 n.52.

Pub. L. No. 102-486, 106 Stat. 2776 (1992) (codified at, among other places,

15 U.S.C. 79z-5a and 16 U.S.C. 796 (22-25), 824j-l).

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barriers to entry by creating a class of “Exempt Wholesale Generators” that were exempt

from the requirements of the Public Utility Holding Company Act of 1935.

EPAct

1992 also expanded the Commission's authority to approve applications for transmission

services under sections 211 and 212 of the FPA.

Though the Commission aggressively

implemented expanded section 211, it ultimately concluded that the procedural

limitations in section 211 thwarted the Commission’s ability to effectively eliminate

undue discrimination in the provision of transmission service.

B. Order No. 888 and Subsequent Reforms

14. In April 1996, as part of its statutory obligation under sections 205 and 206 of the

FPA to remedy undue discrimination, the Commission adopted Order No. 888

prohibiting public utilities from using their monopoly power over transmission to unduly

discriminate against others. In that order, the Commission required all public utilities

that own, control or operate facilities used for transmitting electric energy in interstate

commerce to file open access non-discriminatory transmission tariffs that contained

15 U.S.C. 79a, repealed by EPAct 2005 sec. 1263; see Repeal of the Public

Utility Holding Company Act of 1935 and Enactment of the Public Utility Holding

Company Act of 2005, Order No. 667, 70 FR 75592 (Dec. 20, 2005), FERC Stats. &

Regs. ¶ 31,197 (2005), order on reh’g

, Order No. 667-A, 71 FR 28446 (May 16, 2006),

FERC Stats. & Regs. ¶ 31,213 (2006), order on reh’g

, Order No. 667-B, 71 FERC 42750

(Jul. 28, 2006), FERC Stats. & Regs. ¶ 31,224 (2006), reh’g pending

16 U.S.C. 824j (authorizing the Commission to require transmission utilities to

provide service in certain circumstances); 16 U.S.C. 824k (establishing rates for service

provided pursuant to an order under section 211).

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minimum terms and conditions of non-discriminatory service. It also obligated such

public utilities to “functionally unbundle” their generation and transmission services.

This meant public utilities had to take transmission service (including ancillary services)

for their own new wholesale sales and purchases of electric energy under the open access

tariffs, and to separately state their rates for wholesale generation, transmission and

ancillary services.

Each public utility was required to file the pro forma OATT

included in Order No. 888 without any deviation (except a limited number of terms and

conditions that reflect regional practices).

After the effectiveness of their OATTs,

public utilities were allowed to file, pursuant to section 205 of the FPA, deviations that

were consistent with or superior to the pro forma

OATT’s terms and conditions. Because

certain owners, controllers or operators of interstate transmission facilities were not

subject to the Commission’s jurisdiction under sections 205 and 206 and thus were not

subject to Order No. 888, the Commission adopted a reciprocity provision in the

pro forma

OATT that conditions the use by a non-public utility of a public utility’s open

This is known as “functional unbundling” because the transmission element of a

wholesale sale is separated or unbundled from the generation element of that sale,

although the public utility may provide both functions. See

infra section IV.B.4 of this

Final Rule.

See Order No. 888 at 31,769-70 (noting that the pro forma OATT expressly

identified certain non-rate terms and conditions, such as the time deadlines for

determining available transfer capability in section 18.4 or scheduling changes in sections

13.8 and 14.6, that may be modified to account for regional practices if such practices are

reasonable, generally accepted in the region, and consistently adhered to by the

transmission provider).

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access services on an agreement to offer non-discriminatory transmission services in

return.

15. In addition to imposing the functional unbundling requirement, the Commission

also encouraged broader reforms through the formation of independent system operators

(ISOs). The Commission stated that ISOs can provide significant benefits such as

enhancing regional efficiencies and further remedying undue discrimination.

While the

Commission declined to mandate ISOs, it set forth eleven principles for assessing ISO

proposals submitted to the Commission.

16. Order No. 888 also clarified the Commission's interpretation of the federal and

state jurisdictional boundaries over transmission and local distribution. While Order No.

888 reaffirmed that the Commission has exclusive jurisdiction over the rates, terms, and

conditions of unbundled retail transmission in interstate commerce by public utilities, it

nevertheless recognized the legitimate concerns of state regulatory authorities regarding

the transmission component of bundled retail sales. The Commission therefore declined

to extend its unbundling requirement to the transmission component of bundled retail

sales. On appeal, the U.S. Supreme Court affirmed this element of Order No. 888,

finding that the Commission made a statutorily permissible choice.

Order No. 888 at 31,655.

Id. at 31,730-32.

New York v. FERC, 535 U.S. 1 (2002).

Docket Nos. RM05-17-000 and RM05-25-000 - 14 -

17. The same day it issued Order No. 888, the Commission issued a companion order,

Order No. 889,

addressing the separation of vertically integrated utilities’ transmission

and merchant functions, the information transmission providers were required to make

public, and the electronic means they were required to use to do so. Order No. 889

imposed Standards of Conduct governing the separation of, and communications

between, the utility’s transmission and wholesale power functions, to prevent the utility

from giving its merchant arm preferential access to transmission information. All public

utilities that owned, controlled or operated facilities used in the transmission of electric

energy in interstate commerce were required to create or participate in an Open Access

Same-Time Information System (OASIS) that was to provide existing and potential

transmission customers the same access to transmission information.

18. Among the information public utilities were required to post on their OASIS was

the transmission provider’s calculation of ATC. Though the Commission acknowledged

that before-the-fact measurement of the availability of transmission service is “difficult,”

it concluded that it was important to give potential transmission customers “an easy-to-

understand indicator of service availability.”

Because formal methods did not then

Open Access Same-Time Information System (Formerly Real-Time Information

Networks) and Standards of Conduct, Order No. 889, 61 FR 21737 (May 10, 1996),

FERC Stats. & Regs. ¶ 31,035 (1996), order on reh’g

, Order No. 889-A, FERC Stats.

& Regs. ¶ 31,049 (1997), order on reh’g

, Order No. 889-B, 81 FERC ¶ 61,253 (1997).

Order No. 889 at 31,605.

Docket Nos. RM05-17-000 and RM05-25-000 - 15 -

exist to calculate ATC and total transfer capability (TTC), the Commission encouraged

industry efforts to develop consistent methods for calculating ATC and TTC.

Order

No. 889 ultimately required transmission providers to base their calculations on “current

industry practices, standards and criteria” and to describe their methodology in their

tariffs.

The Commission noted that the requirement that transmission providers

purchase only ATC that is posted as available “should create an adequate incentive for

them to calculate ATC and TTC as accurately and as uniformly as possible.”

19. The electric industry continued to undergo economic and regulatory changes in the

years following the issuance of Order No. 888. Retail access was adopted by

approximately 25 states in the late 1990s.

This state restructuring activity spurred

significant changes at the wholesale level as well by encouraging or requiring the

divestiture of generation plants by traditional electric utilities and the development of

ISOs that could manage short-term energy markets necessary to support retail access. At

the same time, there was a significant increase in the number of mergers between

traditional electric utilities and between electric utilities and gas pipeline companies, and

large increases in the number of power marketers and independent generation facility

Id. at 31,607.

Id.

See Energy Information Administration, Retail Unbundling – U.S. Summary

(2005), http://www.eia.doe.gov/oil_gas/natural_gas/restructure/state/us.html.

Docket Nos. RM05-17-000 and RM05-25-000 - 16 -

developers entering the marketplace. Trade in bulk power markets increased

significantly and the Nation's transmission grid was used more heavily and in new ways

as customers took advantage of the pro forma

OATT and purchased power from

competitive sellers.

20. In the wake of these changes, in December 1999, the Commission adopted Order

No. 2000.

That rulemaking recognized that Order No. 888 set the foundation upon

which competitive electric markets could develop, but did not eliminate the potential to

engage in undue discrimination and preference in the provision of transmission service.

The rulemaking also recognized that Order No. 888 did not address the regional nature of

the grid, including the treatment of parallel flows, pancaked rates, and congestion

management. Thus, the Commission encouraged the creation of RTOs to address

important operational and reliability issues and eliminate any residual discrimination in

transmission services that can occur when the operation of the transmission system

remains in the control of a vertically integrated utility. The Commission found that

RTOs would increase the efficiency of wholesale markets by eliminating pancaked rates,

internalizing parallel flow, managing congestion efficiently, and operating markets for

Regional Transmission Organizations, Order No. 2000, 65 FR 809 (Jan. 6,

2000), FERC Stats. & Regs. ¶ 31,089 (1999), order on reh’g

, Order No. 2000-A, 65 FR

12088 (Mar. 8, 2000), FERC Stats. & Regs. ¶ 31,092 (2000), aff’d sub nom.

Public

Utility District No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C.

Cir. 2001).

Order No. 2000 at 31,015.

Docket Nos. RM05-17-000 and RM05-25-000 - 17 -

energy, capacity and ancillary services. The Commission established an open,

collaborative process that relied on voluntary regional participation to design RTOs

tailored to the specific needs of each region. The Commission noted, however, that “[i]f

the industry fails to form RTOs under this approach, the Commission will reconsider

what further regulatory steps are in the public interest.”

21. Following Order No. 2000, RTOs were approved in several regions of the country

including the Northeast (PJM; ISO New England),

the Midwest (MISO) and the South

(SPP). In most cases, RTOs have assumed responsibility for calculating ATC across the

footprint of the RTO, as well as the planning and expansion of the transmission grid, at

least for facilities necessary for maintaining system reliability. However, large areas of

the Nation have not developed RTOs using the voluntary structure adopted by the

Commission in Order No. 2000. Moreover, transmission customers have complained that

even in RTO markets there are instances when comparable transmission service is not

provided, particularly in the area of transmission planning.

C. EPAct 2005 and Recent Developments

22. Enacted on August 8, 2005, EPAct added a number of new authorities and

priorities for the Commission and emphasized certain of its existing obligations. Among

other things, EPAct 2005 recognized the importance of adequate transmission

Id. at 30,993.

A list of commenter acronyms can be found in Appendix B.

Docket Nos. RM05-17-000 and RM05-25-000 - 18 -

infrastructure development and its role in facilitating the development of competitive

wholesale markets. The Congressional directives in EPAct 2005 are intended to reverse

the decline in transmission infrastructure investment. For example, Congress required

the Commission to adopt a rule establishing incentive ratemaking for transmission

infrastructure to help promote reliability and reduce congestion.

Congress also directed

the Commission to encourage the deployment of advanced technologies.

Congress

further directed the Commission to “exercise its authority” under EPAct 2005 “in a

manner that facilitates the planning and expansion of transmission facilities to meet the

reasonable needs of load-serving entities.”

Congress also gave the Commission certain

“backstop” transmission siting authority, and authorized the creation of interstate

compacts establishing transmission siting agencies.

EPAct 2005 also authorized the

Commission to require unregulated transmitting utilities (except for certain small entities)

EPAct 2005 sec. 1241 (to be codified at section 219 of the FPA, 16 U.S.C.

824s).

EPAct 2005 sec. 1223 (to be codified at 42 U.S.C. 16422). Indeed, Congress

provided specific guidance as to the types of advanced technologies that should be

encouraged in infrastructure improvements to include, among others, optimized

transmission line configurations (including multiple phased transmission lines),

controllable load, distributed generation (including PV, fuel cells, and microturbines),

and enhanced power device monitoring. Id.

EPAct 2005 sec. 1233(a) (to be codified at section 217(b)(4) of the FPA,

16 U.S.C. 824q).

EPAct 2005 sec. 1221(a) (to be codified at section 216 of the FPA, 16 U.S.C.

824p).

Docket Nos. RM05-17-000 and RM05-25-000 - 19 -

to provide access to their transmission facilities on a comparable basis.

Congress

further ordered the Department of Energy (DOE) to study the benefits of economic

dispatch and required the Commission to convene regional joint boards to develop a

report to Congress containing recommendations for the use of security constrained

economic dispatch within each region.

Congress also directed the Commission to

facilitate price transparency in markets for the sale and transmission of electric energy in

interstate commerce, having due regard for the public interest, the integrity of those

markets, fair competition, and the protection of consumers, and it authorized the

Commission to prescribe rules to provide for the dissemination of information about the

availability and price of wholesale electric energy and transmission service.

Finally,

Congress emphasized compliance with the Commission’s regulations, adopting and

EPAct 2005 sec. 1231 (to be codified at section 211A of the FPA, 16 U.S.C.

824j-1).

EPAct 2005 sec. 1234 (to be codified at 42 U.S.C. 16432); EPAct 2005 sec.

1298 (to be codified at section 223 of the FPA, 16 U.S.C. 824w). EPAct 2005 sec.

1234(b) defined economic dispatch as “the operation of generation facilities to produce

energy at the lowest cost to reliably serve consumers, recognizing any operational limits

of generation and transmission facilities.”

EPAct 2005 sec. 1281 (to be codified at section 220 of the FPA, 16 U.S.C.

824t).

Docket Nos. RM05-17-000 and RM05-25-000 - 20 -

increasing the civil and criminal penalties for violations of Commission-administered

statutes and regulations.

23. Recognizing the need for reform of Order No. 888 in light of the Commission’s

continuing concern regarding whether the pro forma

OATT adequately remedies undue

discrimination, the Commission issued an NOI on September 16, 2005

seeking

comments on appropriate reforms of the Order No. 888 pro forma

OATT. In the NOI,

the Commission expressed its preliminary view that reforms to the pro forma

OATT and

public utilities’ OATTs are necessary to avoid undue discrimination or preference in the

provision of transmission service. The NOI sought comments on how best to accomplish

the Commission’s goals, specifically with respect to enhancements that are needed to (1)

remedy any unduly discriminatory or preferential application of the pro forma

OATT or

(2) improve the clarity of the Order No. 888 pro forma

OATT and the individual public

utility tariffs in order to more readily identify violations and facilitate compliance.

24. The Commission received over 4,000 pages of initial and reply comments on the

NOI. Based on these comments, the comments submitted in response to the ATC NOI,

our experience in implementing Order No. 888, and the changes in the industry since we

EPAct 2005 sec. 1284(d) (to be codified at section 316 of the FPA, 16 U.S.C.

825o); EPAct 2005 sec. 1284(e) (to be codified at section 316A of the FPA, 16 U.S.C.

825o-1).

See supra note 5.

Id.

Docket Nos. RM05-17-000 and RM05-25-000 - 21 -

adopted it, the Commission proposed to reform the pro forma

OATT in a number of

ways. The Commission issued the NOPR on May 19, 2006 proposing a number of

reforms aimed at remedying undue discrimination in the provision of open access

transmission service and improving the clarity of the pro forma

OATT and the individual

tariffs of transmission providers in order to more readily identify violations and facilitate

compliance. The Commission received over 5,700 pages of initial and reply comments in

response. In response to comments on the particular issue of redispatch and conditional

firm service (discussed in more detail below), the Commission issued a Notice of Request

for Supplemental Comments on November 15, 2006,

that resulted in receipt of an

additional 750 pages of comments.

25. Based on this voluminous record, the Commission concludes that reform of the

pro forma

OATT and associated amendments to its regulations are necessary to reduce

the potential for undue discrimination and provide clarity in the obligations of

transmission providers and customers alike. We turn next to a more complete

explanation of this need for reform.

Preventing Undue Discrimination and Preference in Transmission Service,

117 FERC ¶ 61,185 (2006).

Docket Nos. RM05-17-000 and RM05-25-000 - 22 -

III. Need for Reform of Order No. 888

A. Opportunities for Undue Discrimination Continue to Exist

26. Although Order No. 888 has been successful in many important respects, the need

for reform of the Order No. 888 pro forma

OATT has been apparent for some time. In

1999, the Commission held, in adopting Order No. 2000, that the pro forma

OATT could

not fully remedy undue discrimination because transmission providers retained both the

incentive and the ability to discriminate against third parties, particularly in areas where

the pro forma

OATT left the transmission provider with significant discretion.

The

Commission made a similar finding in Order No. 2003,

holding that opportunities for

undue discrimination continue to exist in areas where the pro forma

OATT leaves

transmission providers with substantial discretion.

The NOPR reaffirmed these

findings, preliminarily concluding that opportunities for undue discrimination continue to

exist in the provision of open access transmission service. The Commission therefore

Order No. 2000 at 31,105.

See Standardization of Generator Interconnection Agreements and Procedures,

Order No. 2003, 68 FR 49845 (Aug. 19, 2003), FERC Stats. & Regs. ¶ 31,146 at P 11-12

(2003), order on reh’g

, Order No. 2003-A, 69 FR 15932 (Mar. 26, 2004), FERC Stats.

& Regs. ¶ 31,160 (2004), order on reh’g

, Order No. 2003-B, 70 FR 265 (Jan. 4, 2005),

FERC Stats. & Regs. ¶ 31,171 (2004), order on reh’g

, Order No. 2003-C, 70 FR 37,661

(Jun. 30, 2005), FERC Stats. & Regs. ¶ 31,190 (2005), aff’d sub nom.

National

Association of Regulatory Utility Commissioners v. FERC, No. 04-1148, 2007 U.S. App.

LEXIS 626 (D.C. Cir. Jan. 12, 2007).

Order No. 2003 at P 11-12.

Docket Nos. RM05-17-000 and RM05-25-000 - 23 -

proposed a number of reforms to the pro forma

OATT to address the opportunities and

incentives transmission providers have to unduly discriminate.

Comments

27. Many commenters agree with the Commission that reforms to the pro forma

OATT are needed because there continue to be both the opportunity and incentive for

transmission providers to engage in undue discrimination.

28. Several commenters offered examples of their experiences with transmission

providers, where they believe transmission providers have acted in an unduly

discriminatory fashion.

Constellation claims that on multiple occasions it has been

denied a transmission request when the transmission provider’s OASIS indicates that

ATC is available, but Constellation had no effective and timely way to challenge that

determination because of the ATC “black box.” Constellation states that given that its

needs for transmission service are often near-term or immediate – e.g.

, to facilitate a

load-serving obligation or wholesale transaction that must be consummated quickly –

seeking redress at the Commission for improperly denied service generally is not time- or

cost-effective. Instead, Constellation asserts, it is often forced to accept the

determination of the transmission provider that ATC is not available (even though its

E.g., APPA, EPSA, East Texas Cooperatives, Fayetteville, NRG, Occidental,

TAPS, TDU Systems, Williams, Entegra Reply, and NRECA Reply.

See, e.g., Dow, Fayetteville, Occidental, and Williams.

Docket Nos. RM05-17-000 and RM05-25-000 - 24 -

OASIS may indicate otherwise) and seek alternate transmission paths and/or products to

consummate its transaction.

29. Powerex also describes instances where a transmission provider has granted short-

term firm point-to-point transmission service requests to transmission customers who

have been allowed to remain in the queue, even when zero ATC is posted, in the hopes

that a transmission provider’s OASIS site wrongly indicates zero ATC or will soon be

updated. Powerex asserts that such practices clog the short-term point-to-point

transmission queue with multiple requests and result in duplicative requests for service

that reflect customers’ attempts to secure service, rather than the actual quantity of

service needed. Moreover, Powerex argues, transmission provider discretion in this area

and the lack of transparency raise customer concerns about preferential treatment.

30. Occidental claims that it has first-hand experience with a vertically integrated

transmission provider that, despite having an OATT, appears to have persistently used its

transmission system to preferentially benefit its merchant function. Similarly, Williams

alleges that its interests have been consistently and significantly compromised by the

discretion afforded transmission providers in the interpretation of the OATT and the lack

of transparency in requesting, scheduling and interrupting of transmission service.

31. Other commenters, however, argue that the Commission’s proposed reforms are

based on unsupported allegations of undue discrimination. EEI maintains that any

opportunities to engage in undue discrimination have been largely mitigated by current

regulatory policies and changes in the industry. EEI explains that, unlike the situation

Docket Nos. RM05-17-000 and RM05-25-000 - 25 -

that existed when the Commission enacted Order No. 888, much of the country’s

transmission facilities are now under the control of RTOs and ISOs. In addition, EEI

states, other transmission providers have transferred (or are in the process of transferring)

the administration of their OATTs and OASIS functions to independent transmission

service coordinators. Even among the transmission providers who have taken neither of

those steps, EEI argues that the open access requirements of Order No. 888 and the

Standards of Conduct of Order Nos. 889 and 2004 have largely eliminated the ability of

transmission providers to engage in undue discrimination in the provision of transmission

service.

In addition, EEI states, the Commission’s expanded civil penalty authority

added to the FPA by EPAct 2005 gives the Commission a powerful tool that will further

eliminate any remaining incentive of transmission providers to engage in undue

discrimination in the provision of transmission service. Therefore, EEI asserts, any

modifications to the OATT should be narrowly tailored to address the perceptions

residual undue discrimination. To the extent that such perceptions exist, however,

Community Power Alliance states that, in the absence of concrete record evidence, they

are just that – perceptions.

32. Although Duke strongly supports, as a policy matter, OATT reforms that will

eliminate the perception that undue discrimination is possible and/or likely, Duke argues

that the FPA does not provide the Commission the authority to remedy mere

See also Indicated Parties Reply.

Docket Nos. RM05-17-000 and RM05-25-000 - 310 -

and clarify the principle in certain important respects in response to the comments

received. At the outset, we wish to clarify that our primary objective in adopting this

principle is to ensure that the transmission planning process encompasses more than

reliability considerations. Although planning to maintain reliability is a critical priority,

it is not the only one. Planning involves both reliability and economic considerations.

When planning to serve native load customers, a prudent vertically integrated

transmission provider will plan not only to maintain reliability, but also consider whether

transmission upgrades or other investments can reduce the overall costs of serving native

load. Such upgrades can, for example, reduce congestion (redispatch) costs or integrate

efficient new resources (including demand resources) and new or growing loads. Thus,

to represent good utility practice and provide comparable service, the transmission

planning process under the pro forma

OATT must consider both reliability and economic

considerations. The purpose of this principle is to ensure that the latter is considered

adequately in the transmission planning process.

543. Some commenters argue that economic upgrades should be considered only in the

context of individual requests for service under the pro forma

OATT. The Commission

disagrees. The process for addressing individual requests for service under the pro forma

OATT is adequate for customers who request specific transmission rights to purchase

power from a particular resource in a particular location during a defined time period.

However, it does not provide an opportunity for customers to consider whether potential

upgrades or other investments could reduce congestion costs or otherwise integrate new

Docket Nos. RM05-17-000 and RM05-25-000 - 311 -

resources on an aggregated or regional basis outside of a specific request for

interconnection or transmission service. It thus limits, for example, groups of customers

from considering more comprehensive solutions to transmission congestion, including

investment in demand response. It also limits multiple LSEs from considering, on a more

aggregated basis, whether particular upgrades may represent the most economic means of

integrating new generation resources (e.g.

, wind resources) located in a common area that

could be accessed by many customers. The Commission believes such coordinated

studies can, for system planning purposes, be more beneficial than studies performed on a

request-by-request basis. We also find that they are consistent with the requirement to

provide comparable service. Transmission providers are not limited, in serving native

load customers, to studying potential transmission upgrades only in the context of

specific requests for service under the pro forma

OATT.

544. Some transmission providers appear to object to this principle because they fear

that an obligation to study potential upgrades is equivalent to an obligation to fund or

build such upgrades. We clarify that this is not the intent of this principle. There is a

difference between a planning process that is coordinated and open and one that dictates

construction and cost responsibility. Both considerations are important, but, as we

explain above, they are distinct. The purpose of this principle is to ensure that customers

may request studies that evaluate potential upgrades or other investments that could

reduce congestion or integrate new resources and loads on an aggregated or regional

basis (e.g.

, wind developers), not to assign cost responsibility for those investments or

Docket Nos. RM05-17-000 and RM05-25-000 - 312 -

otherwise determine whether they should be implemented. The issue of cost allocation is

addressed in Principle No. 9 below.

545. The Commission also disagrees with the contentions of certain RTOs or ISOs that

they need not comply with this principle. Although RTO and ISO planning processes

tend to be more open and coordinated than the processes used by vertically-integrated

transmission providers, this does not mean that RTO or ISO processes adequately

address, in all circumstances, investments that are primarily economic in nature. When

many RTO and ISO planning processes were created, they focused primarily on system

enhancements necessary to maintain reliability. However, in recent years, as congestion

has increased and generation reserve margins have declined, many RTOs and ISOs have

taken increasingly progressive steps to identify investments that could reduce congestion

and/or integrate new resources. For example, we recently approved a proposal by PJM to

significantly enhance its RTEP planning process.

322

We applaud these efforts as

consistent with the direction of the reforms adopted herein. However, we decline to

provide a blanket exception for RTOs and ISOs. Each RTO or ISO must show that its

planning process is consistent with or superior to the requirements of the Final Rule in all

respects.

546. Some commenters express concern that this principle may result in costly

congestion studies that are of little interest or value to customers. Our intent is not to

322

See PJM Interconnection, L.L.C., 117 FERC ¶ 61,218 (2006), reh’g pending.

Docket Nos. RM05-17-000 and RM05-25-000 - 313 -

impose a costly study requirement that is unrelated to the real-world concerns of

consumers. In the NOPR, we sought comment on whether specific metrics (e.g.

, zero

ATC or TLR frequency) should be used to trigger the congestion study requirement.

After considering the comments on this topic, we do not believe that any single metric, or

group of metrics, is adequate for that purpose. Relying on discrete metrics in this

instance would risk both over- and under-inclusiveness – i.e.

, triggering too many studies,

thereby imposing cost burdens on transmission providers that are not appropriate, or

triggering too few studies, thereby omitting important studies that could help customers

identify cost-effective solutions to congestion. Additionally, we direct transmission

providers, in consultation with their stakeholders during development of their Attachment

K compliance filings (as discussed above), to develop a means to allow the transmission

provider and stakeholders to cluster or batch requests for economic planning studies so

that the transmission provider may perform the studies in the most efficient manner. We

will also require the requests for economic planning studies, as well as the responses to

the requests, be posted on the transmission provider’s OASIS or web site, subject to

confidentiality requirements.

547. The Commission will modify the principle to allow customers to choose the

studies that are of the greatest value to them. Specifically, we are modifying the principle

to require that stakeholders be given the right to request a defined number of high priority

Docket Nos. RM05-17-000 and RM05-25-000 - 314 -

studies annually (e.g.

, five to ten studies)

323

to address congestion and/or the integration

of new resources or loads. The intent of this approach is to allow customers, not the

transmission provider, to identify those portions of the transmission system where they

have encountered transmission problems due to congestion or whether they believe

upgrades and other investments may be necessary to reduce congestion and to integrate

new resources. The customers should be able to request that the transmission provider

study enhancements that could reduce such congestion or integrate new resources on an

aggregated or regional basis without having to submit a specific request for service. This

approach ensures that the economic studies required under this principle are focused on

customer needs and concerns, not administratively determined metrics that may bear no

necessary relation to those concerns. Once such studies are requested, the transmission

provider would conduct the studies, including appropriate sensitivity analyses, in a

manner that is open and coordinated with the affected stakeholders. The cost of the

defined number of high priority studies would be recovered as part of the overall pro

forma OATT cost of service.

324

By limiting this principle to a defined number of high

priority studies annually, we are not precluding stakeholders from requesting additional

323

The example of five to ten studies mentioned in this Final Rule is merely

illustrative. We recognize that the facts of each case will be used to determine the

number of high priority studies allowed under a transmission plan.

324

This cost recovery mechanism is comparable and nondiscriminatory because

the transmission provider already has the ability to include in its pro forma

OATT rates

the cost of service associated with studies performed on behalf of native load customers.

Docket Nos. RM05-17-000 and RM05-25-000 - 315 -

studies. However, to provide appropriate financial incentives, the stakeholder(s)

requesting these additional studies would be responsible for paying the cost of such

studies.

548. We also will modify this principle with respect to the scope of the studies being

performed. The Commission proposed in the NOPR that the studies address “significant

and recurring congestion.” However, the Commission also sought comment on whether,

in addition, the study process should address upgrades associated with new generation

resources and provide information needed to proactively evaluate such resources. We

discuss the comments on this proposal in more detail below, but, as described therein, we

agree that the study process should incorporate such considerations. We therefore

modify Principle No. 8 to encompass the study of upgrades to integrate new generation

resources or loads on an aggregated or regional basis. This is appropriate because

congestion can limit both the efficient dispatch of existing generation resources as well as

inhibit the development of new supply and demand resources. Moreover, many regions

of the country must make investments in the near future to meet load growth and,

accordingly, studies of the most economic means of making such investments are

critically important to consumers.

549. By expanding the scope of this principle, we do not intend to supplant the existing

process for individual customers to integrate new resources or loads through specific

requests for interconnection or transmission service under the pro forma

OATT. Rather,

we contemplate that any such studies conducted pursuant to this principle, as explained

Docket Nos. RM05-17-000 and RM05-25-000 - 316 -

above, would be for purposes of planning for the alleviation of congestion through

integration of new supply and demand resources into the regional transmission grid or

expanding the regional transmission grid in a manner that can benefit large numbers of

customers, such as by evaluating transmission upgrades necessary to connect major new

areas of generation resources (such as areas that can support substantial wind generation).

Specific requests for service would continue to be studied pursuant to existing pro forma

OATT processes.

550. With respect to studying the cost of congestion, several transmission providers

argue that they do not have access to information regarding generation costs either from

their merchant function or unaffiliated customers. We agree that the transmission

provider should be obligated to study the cost of congestion only to the extent it has

information to do so. We make clear, however, that if stakeholders request that a

particular congested area be studied, they must supply relevant data within their

possession to enable the transmission provider to calculate the level of congestion costs

that is occurring or is likely to occur in the near future. To the extent that the

transmission provider’s merchant function possesses such information (e.g.

, redispatch

cost information), it must provide that information to the extent necessary to conduct

such studies. Providing for confidential treatment and application of the Standards of

Conduct, as discussed above, will give assurance to customers that their cost and other

information will not be used improperly. To that end, we direct transmission providers to

Docket Nos. RM05-17-000 and RM05-25-000 - 317 -

clearly define the information sharing obligations placed on customers in the planning

attachment to their pro forma

OATT.

551. In response to those commenters that argue that regional congestion studies should

be sufficient, we agree that regional congestion studies can be used as part of regional

transmission planning processes required by this Final Rule. For example, to the extent

the DOE has extensively studied congestion in certain broad areas, it is not necessary or

appropriate for transmission providers to duplicate these studies. However, regional

studies typically provide broad information on overall regional power flows and may not

provide sufficient detail on local system conditions and congestion, such as detail on

congested local facilities that may limit customer supply options, or detail on local

conditions where additional service could be provided through redispatch. Moreover,

although the DOE may identify areas where congestion exists or new generation may be

developed, the purpose of DOE congestion studies is not to develop specific transmission

system plans to remedy such congestion or integrate such resources. The DOE studies

are therefore not a substitute for a more open and coordinated planning process to address

specific upgrades that could reduce congestion or integrate new resources and loads. We

therefore require each transmission provider to comply with the revised economic

planning studies principle in this Final Rule both as to its own transmission system and as

to the regional planning process described above.

Docket Nos. RM05-17-000 and RM05-25-000 - 318 -

i. Cost Allocation for New Projects

552. In the NOPR, the Commission asked for comment on whether there should be a

requirement for public utilities to develop cost allocation principles to address the

recovery of costs associated with new transmission projects. In particular, the

Commission asked whether the development of specific cost allocation principles would

provide greater certainty and hence support the construction of new infrastructure or

whether cost allocation is better handled on a case-by-case basis.

Comments

553. Several commenters express concern that the Final Rule not reopen cost allocation

principles in RTOs and ISOs or in the OATTs of vertically-integrated transmission

providers.

325

Duke argues that the Final Rule should not address cost allocation for new

transmission at all, stating that transmission pricing should be evaluated in a separate

proceeding. Other commenters agree that cost allocation issues should be handled on a

case-by-case basis.

326

554. Some commenters urge the Commission to define cost allocation principles in this

proceeding.

327

For example, E.ON believes that the cost of upgrades should be directly

325

E.g., Duke, EEI, ELCON, ISO/RTO Council, MISO Transmission Owners,

SCE, and Southern.

326

E.g., APPA, Arkansas Commission, PGP, Santee Cooper, Southwestern Coop,

and Sacramento.

327

E.g., E.ON, National Grid and WIRES.

Docket Nos. RM05-17-000 and RM05-25-000 - 319 -

allocated to parties benefiting from an expansion and proposes that the host transmission

owner should coordinate and be responsible for obtaining funding. Many transmission

customers, however, support rolled-in cost recovery for network upgrades.

328

TDU

Systems ask the Commission to clarify that direct assignment of facility upgrade costs

only applies to point-to-point service, unless it is being used for the delivery of

designated network resources to serve network load. If direct assignment is retained,

TDU Systems suggest the Commission consider standardizing directly assignable

facilities on a regional basis and stress that the critical factor is comparability. TAPS

suggests “regional” cost-spreading for backbone high voltage facilities and criticizes

participant funding because it encourages would-be beneficiaries to wait and hope that

others will step forward first.

555. Old Dominion emphasizes the need for cross-border transmission cost allocation

mechanisms. In joint projects, Salt River emphasizes that it is inconsistent with an open

season approach to assign benefits to a party and then assign cost responsibility beyond

what the project participant would voluntarily assume based on the subscription rights

received. Both Bonneville and TVA believe that cost allocation principles should be

based on a determination of beneficiaries and cost causation. New Mexico Attorney

General stresses that cost recovery for construction of transmission intended for

wholesale or market transactions should not be allocated to native load. NCPA states that

328

E.g., AWEA, NCEMC, NCPA, NRECA, Seattle, and TDU Systems.

Docket Nos. RM05-17-000 and RM05-25-000 - 320 -

it would expect some Commission deference to recovery of costs of projects identified in

a truly collaborative process.

556. At the October 12 Technical Conference, PJM stated that the Commission should

provide generic guidance on what would be acceptable regarding cost allocation, though

Progress Energy did not favor putting a cost allocation approach in the pro forma

OATT,

as modified by the Final Rule. National Grid expressed the view that the Commission

would need to address cost allocation generally, arguing that cost allocation solely on a

project-by-project basis is inefficient.

Commission Determination

557. The Commission finds, after considering the comments, that it is appropriate to

include a specific principle regarding cost allocation. The manner in which the costs of

new transmission are allocated is critical to the development of new infrastructure.

Transmission providers and customers cannot be expected to support the construction of

new transmission unless they understand who will pay the associated costs. We therefore

find that, for a planning process to comply with the Final Rule, it must address the

allocation of costs of new facilities.

558. The Commission emphasizes, however, that we are not modifying the existing

mechanisms to allocate costs for projects that are constructed by a single transmission

owner and billed under existing rate structures. Our intent is not to upset existing cost

allocation methods applicable to specific requests for interconnection or transmission

service under the pro forma

OATT. The cost allocation principle discussed herein is

Docket Nos. RM05-17-000 and RM05-25-000 - 321 -

intended to apply to projects that do not fit under the existing structure, such as regional

projects involving several transmission owners or economic projects that are identified

through the study process described above, rather than through individual requests for

service. We will not impose a particular allocation method for such projects, but rather

will permit transmission providers and stakeholders to determine their own specific

criteria which best fit their own experience and regional needs. The proposal should

identify the types of new projects that are not covered under existing cost allocation rules

and, therefore, would be affected by this cost allocation principle.

559. Although the Commission does not prescribe any specific cost allocation method

in the Final Rule, we believe some overall guidance is appropriate. Our decisions

regarding transmission cost allocation reflect the premise that "[a]llocation of costs is not

a matter for the slide-rule. It involves judgment on a myriad of facts. It has no claim to

an exact science."

329

We therefore allow regional flexibility in cost allocation and, when

considering a dispute over cost allocation, exercise our judgment by weighing several

factors. First, we consider whether a cost allocation proposal fairly assigns costs among

participants, including those who cause them to be incurred and those who otherwise

benefit from them. Second, we consider whether a cost allocation proposal provides

adequate incentives to construct new transmission. Third, we consider whether the

proposal is generally supported by state authorities and participants across the region.

329

Colorado Interstate Gas Co. v. FPC, 324 U.S. 581, 589 (1945).

Docket Nos. RM05-17-000 and RM05-25-000 - 322 -

560. These three factors are interrelated. For example, a cost allocation proposal that

has broad support across a region is more likely to provide adequate incentives to

construct new infrastructure than one that does not. The states, which have primary

transmission siting authority, may be reluctant to site regional transmission projects if

they believe the costs are not being allocated fairly. Similarly, a proposal that allocates

costs fairly to participants who benefit from them is more likely to support new

investment than one that does not. Adequate financial support for major new

transmission projects may not be obtained unless costs are assigned fairly to those who

benefit from the project.

561. These factors are particularly important as applied to the economic upgrades

discussed above – e.g.

, upgrades to reduce congestion or enable groups of customers to

access new generation. As a general matter, we believe that the beneficiaries of any such

project should agree to support the costs of such projects. However, we recognize that

there are free rider problems associated with new transmission investment, such that

customers who do not agree to support a particular project may nonetheless receive

substantial benefits from it. In the past, different regions have attempted to address such

issues in a variety of ways, such as by assigning transmission rights only to those who

financially support a project or spreading a portion of the cost of certain high-voltage

projects more broadly than the immediate beneficiary/supporters of the project. We

believe that a range of solutions to this problem are available. We therefore continue to

believe that regional solutions that garner the support of stakeholders, including affected

Docket Nos. RM05-17-000 and RM05-25-000 - 323 -

state authorities, are preferable. Moreover, it is important that each region address these

issues up front, at least in principle, rather than having them relitigated each time a

project is proposed. Participants seeking to support new transmission investment need

some degree of certainty regarding cost allocation to pursue such investments.

3. Additional Issues Relating to Planning Reform

a. Independent Third Party Coordinator

562. In the NOPR, the Commission acknowledged that an independent third party

coordinator would provide benefits for transmission planning, but did not propose to

require independence. Noting that independence could take many forms, the

Commission sought comment on the level of independence that could provide benefits

and the institutions that could offer such independence.

Comments

563. Overall comments on the use of an independent third party to oversee or

coordinate the planning process range from those who believe it is not needed to those

who feel that it should be required rather than merely encouraged. Arguing against the

need for an independent coordinator, South Carolina E&G does not believe an

independent third party is either necessary or desirable. Arguing in favor of an

independent coordinator, EPSA strongly supports independent oversight and believes that

third party oversight will be necessary in non-RTO areas, particularly where transmission

Docket Nos. RM05-17-000 and RM05-25-000 - 324 -

providers have conducted non-transparent processes.

330

Most commenters fall

somewhere between these two positions, finding potential benefits in independence but

concurring with the proposal not to mandate it.

564. Several public utility commenters acknowledge the potential benefits of using an

independent coordinator and believe the Commission should encourage it.

331

National

Grid, for example, finds it difficult to see how a non-independent transmission provider

would be able to manage confidential information in a manner fair to all stakeholders and

recommends finding independent administration of planning “superior to” non-

independent administration. Other commenters note only that independence can be

beneficial or suggest that the Commission be open to independent third parties when

offered.

332

Progress agrees there can be benefits, but does not believe an independent

coordinator is needed to ensure confidence.

330

See also AWEA, Arkansas Commission, Old Dominion, and Project for

Sustainable FERC Energy Policy. Old Dominion stresses that even in RTOs, the

transmission owners may have the ability to exercise market power and, therefore, the

market monitoring unit should have the requisite independence and authority to

investigate and address undue influence.

331

E.g., National Grid, PPL, Constellation, and Tacoma.

332

E.g., APPA, Bonneville, California Commission, Duke, Indianapolis Power,

NCEMC, NRECA, NorthWestern, Progress Energy, CREPC, Sacramento, Seattle, and

TDU Systems. Some public power entities, such as APPA, NRECA, and TDU Systems

are concerned with ensuring that the costs of an independent coordinator do not outweigh

the benefits.

Docket Nos. RM05-17-000 and RM05-25-000 - 325 -

565. EEI argues against an independence requirement, seeing no need to require non-

RTO/ISO transmission providers to engage independent third parties to oversee the

planning process.

333

EEI believes the planning processes proposed in the NOPR are

adequate without third party oversight and maintains that requiring third party

coordination could add another layer of administration, might encroach on state authority,

and could create the possibility that the transmission provider would lose control of the

transmission plan. EEI however also notes that the Commission could require

independent oversight in circumstances where a transmission planner has failed to

implement the principles or has engaged in undue discrimination in planning for

customer needs.

566. The consensus at the October 12 Technical Conference was generally supportive

of the potential benefits of an independent facilitator, but not supportive of a mandate.

There was general support for the idea that an independent facilitator can assist with

handling sensitive information and provide confidence that analysis of information would

be fair, although several participants stated that sufficient trust and confidence could be

obtained without an independent facilitator.

333

TVA believes that the levels of independence practiced in NERC and NAESB

and the implementation and administration of those standards by the regional entities

(such as SERC) are adequate and appropriate.

Docket Nos. RM05-17-000 and RM05-25-000 - 326 -

Commission Determination

567. The Commission adopts the NOPR proposal to not require the use of an

independent third party coordinator at this time. We agree that there are benefits to be

gained from independent third party oversight, as cited by commenters, such as the

ability to manage confidential information and the ability to ensure equitable treatment of

all viewpoints in planning. We therefore encourage transmission providers and their

customers and other stakeholders to explore aspects of planning where the use of an

independent coordinator would be beneficial and to incorporate those aspects in their

planning process compliance filings.

568. It is, however, possible to comply with the principles without the use of an

independent third party. We expect the transmission plans themselves to be developed

under an open process that includes coordination among each transmission provider, its

customers, other stakeholders, and its neighbors. A transmission provider will need to

demonstrate to us in a compliance filing that the plan meets the principles, including

providing a dispute resolution process. We believe that an open, transparent planning

process, with meaningful coordination and dispute resolution, will provide a sufficient

basis for customers to identify and raise meaningful concerns if a plan does not treat

similarly-situated customers in a comparable manner, where planning appears to be

conducted in a discriminatory manner, or in other instances where the independence of

planning may be in question. If disputes do arise in these areas and cannot be resolved

Docket Nos. RM05-17-000 and RM05-25-000 - 327 -

consensually, we are available to either encourage a consensual resolution (e.g.

, by use of

the Dispute Resolution Service) or resolve them ourselves if a complaint is filed.

b. State Commission Participation

569. In the NOPR, the Commission strongly encouraged the participation of state

commissions and other state agencies in the coordinated planning process, particularly

with regard to regional planning. The Commission sought comment on how best to

accommodate effective state participation.

Comments

570. All commenters addressing the question of state participation agree that states

have an important role in transmission planning, but there were only limited comments

recommending specific processes to encourage state participation. Supporters of state

participation generally believe that it can assist in obtaining siting approval and in cost

recovery. ISO/RTO Council and individual RTOs and ISOs point to their current

processes for including states in their region in the planning process. Noting the local

benefits that can derive from interstate transmission projects, American Transmission

supports collaborative efforts among states such as the Organization of MISO States.

However, American Transmission and other commenters suggest that the Commission

defer to the states to determine how they participate in the planning process.

334

E.g., American Transmission, Duke, and Progress Energy.

Docket Nos. RM05-17-000 and RM05-25-000 - 328 -

571. Allegheny believes it should be the responsibility of the transmission provider to

maintain good communication with state commissions. Nevada Companies assert that

the real question the Commission should be posing is how to coordinate the state

jurisdictional role in transmission planning and construction and the obligations imposed

by the Commission on transmission providers, so that the system of coordination does not

put transmission providers in the middle between conflicting state and Commission

requirements. Moreover, Santa Clara notes that some state commissions do not represent

all energy consumers, since they are charged only with regulating public utilities, and

could be conflicted and disinclined to act in the best interests of entities not under their

jurisdiction.

572. NARUC supports active state commission participation in both RTO and non-

RTO markets.

335

NARUC asks that the Commission clarify that its planning proposals

assume that the results of state commission planning decisions relating to retail load will

be incorporated into the planning process rather than subject to further review. NARUC

and New Mexico Attorney General also ask for clarification that joint planning will allow

for communications between resource and transmission planners for the purpose of

developing state-required resource plans and that this will not be considered a violation

335

Similar views are expressed by APPA, Arkansas Commission, Bonneville,

California Commission, NCEMC, NYAPP, and CREPC. NYAPP, however, asks the

Commission to be vigilant in not allowing state commissions improper control over the

planning process.

Docket Nos. RM05-17-000 and RM05-25-000 - 329 -

of the Standards of Conduct. PNM-TNMP and Southern support the NARUC position in

their reply comments.

573. New York Commission wants to ensure that the Commission’s planning

responsibilities cover only transmission that serves a bulk power system function.

336

Florida Commission believes that it already has direct oversight of grid planning and

related issues, through among other things its participation in the FRCC planning process

and review of the annual Ten Year Site Plan. Seattle does not believe that any additional

requirements are needed for state commission participation. Other commenters are

concerned that state policy goals, such as California’s Renewable Portfolio Standard, be

included in the coordinated planning required by the Final Rule.

337

NARUC and

California Commission also discuss state staff and fiscal constraints on participation, and

California Commission suggests that the Commission consider a tariff rider to fund state

participation.

Commission Determination

574. The Commission strongly encourages state participation in the transmission

planning process and expects that all transmission providers will respect states’ concerns,

336

NYAPP, on the other hand, urges the Commission to require planning for all

transmission facilities, not just bulk power facilities.

337

E.g., AWEA, California Commission, and Project for Sustainable FERC

Energy Policy.

Docket Nos. RM05-17-000 and RM05-25-000 - 330 -

such as retail resource needs, in the planning process.

338

As with any other interested

stakeholder, we emphasize that planning must be coordinated with relevant state

regulators (including city councils, local siting boards, and other agencies) that wish to

participate in the transmission provider’s planning process. We will not prescribe a

particular level of state participation, but rather encourage states to determine their own

level of participation, consistent with applicable state law.

339

We stress that state

determinations with respect to retail load will not be second-guessed, but that once those

determinations are incorporated into the transmission plan, the transmission planning

principles will apply (e.g.

, for purposes of determining whether similarly-situated

customers are treated comparably).

575. Just as we intend to coordinate with state regulators and other agencies, we also

encourage those parties to collaborate amongst themselves as well, particularly

regionally, in order to reach agreement on how best to review and approve new

transmission facilities that are the product of the coordinated and regional planning

338

As noted above, we expect the concerns of NARUC and others that the

application of the Commission’s Standards of Conduct are inhibiting state resource

planning will be addressed in the rulemaking proceeding on the Standards of Conduct in

Docket No. RM01-7-000. See

supra note 257.

339

We also recognize that there are concerns about how state regulators and other

agencies will recover the costs associated with their participation in the planning process.

As discussed below, we direct transmission providers to propose a mechanism for cost

recovery in their planning compliance filings. These proposals should include relevant

cost recovery for state regulators, to the extent requested.

Docket Nos. RM05-17-000 and RM05-25-000 - 331 -

process required by this Final Rule. We intend to defer to such agreements between state

regulators and other agencies in a given region as appropriate. We are, moreover,

sensitive to concerns, such as Allegheny’s, about the overlapping nature of regulatory

jurisdiction over planning matters. We believe the planning principles in this Final Rule

will help alleviate this concern by facilitating coordination through open, transparent

planning and enhanced exchange of information. We also understand Santa Clara’s

concern that certain state regulators do not represent all energy consumers in some states;

however, we do not believe this detracts from the significant interest that state regulators

and other agencies have with regard to transmission planning for their state and region.

c. Flexibility in Implementation and Examples of Compliant

Processes

576. In the NOPR, the Commission sought comment on how much flexibility the

transmission provider should be given in implementing the principles and requested

examples of transmission planning processes that comply with the proposed principles.

Comments

577. Commenters generally favor flexibility and urge the Commission not to be too

prescriptive regarding how the planning processes must satisfy the planning principles.

Many entities in the Western Interconnection cite the overall WECC process as largely

compliant with the principles. Nevada Companies notes that the WECC process works

well under the existing pro forma

OATT, so that few changes should be required to

implement the proposal. In the East, Progress Energy and Duke cite NC Transmission

Docket Nos. RM05-17-000 and RM05-25-000 - 332 -

Planning as an example of an effective planning process that generally meets the

principles.

578. Constellation agrees with providing flexibility, but believes the Commission

should strongly encourage transmission providers to model their compliance filings after

existing processes, such as those in RTOs and ISOs. ISO/RTO Council and all individual

RTOs and ISOs argue that their processes are generally compliant and should not be

disturbed. Transmission providers in RTOs and ISOs generally support this position.

340

579. Some entities believe that flexibility should be permitted in order to deal with

regional variations, but that individual transmission providers should have limited

flexibility in implementing the planning process.

341

Some commenters simply state that

regional flexibility should be permitted, without further elaboration.

342

Other

commenters urge the Commission to limit both regional and local flexibility.

343

580. NRG argues that system planning models should reflect economic dispatch to

facilitate efficient utilization and also argues in favor of requirements for specific criteria

on the treatment of system overloads and contingencies. AWEA proposes a specific

regional planning protocol patterned off the “Collaborative Governance” model

340

E.g., Allegheny, Duke, and National Grid.

341

E.g., APPA, East Texas Cooperatives, Seattle, and TDU Systems.

342

E.g., Bonneville, Salt River, PJM, and TVA.

343

E.g., Arkansas Municipal, Project for Sustainable FERC Energy Policy, and

Southwestern Coop.

Docket Nos. RM05-17-000 and RM05-25-000 - 333 -

developed during mediation for the Southeast RTO in Docket No. RT01-100.

581. In reply to commenters arguing in favor of less flexibility, Indianapolis Power

maintains that its experience in MISO shows that flexibility is needed, citing the wide

variations within the MISO footprint and the difficulties experienced in planning for a

single large region. MidAmerican opposes the NRG proposal for regional modeling

standards, as well as the AWEA proposal for a regional planning protocol, as too

burdensome. Exelon expresses general agreement with the EEI position on flexibility,

but states that planning processes outside RTOs do not presently meet the NOPR’s

requirements. Exelon states planning processes outside RTOs should follow the planning

direction of RTOs like PJM.

Commission Determination

582. Although we allow flexibility in the development of a coordinated and regional

planning process, the Commission will carefully review transmission planning

compliance filings to ensure that each planning process is consistent with the planning

principles and other requirements in this Final Rule. We encourage transmission

providers to give consideration to existing planning processes, such as those already

implemented by ISOs or RTOs, or those proposed by AWEA, as they work with their

customers and other stakeholders to develop a transmission planning process that

complies with the Final Rule. The Commission makes clear, however, that we do not

endorse any specific existing process as a model for all transmission providers.

Docket Nos. RM05-17-000 and RM05-25-000 - 334 -

d. Recovery of Planning Costs

583. In the NOPR, the Commission recognized that participants in the planning process

must be assured of recovery of their costs incurred in the planning process, as well as

assured that the costs will be borne equitably by all parties benefiting from the process.

The Commission also sought comment on whether there should be a principle or

requirement regarding cost recovery and allocation associated with funding the regional

planning requirement.

Comments

584. Public utility commenters generally support the principle that costs should be

borne by the beneficiaries of the process. EEI agrees, but argues that the Commission

should not establish a specific cost basis for recovery, and several other commenters

concur.

344

NorthWestern and PSEG support a cost causation principle for allocation of

costs of planning, and Southern argues that entities that request any transmission

sensitivity studies should bear the costs of those studies.

585. There is general agreement with the principle that costs should be recoverable, and

some public utilities request that the Commission clarify that all planning costs not

directly assigned are recoverable through transmission provider transmission rates.

345

344

E.g., Duke, Indianapolis Power, MidAmerican, Progress Energy, PSEG, South

Carolina E&G, and SPP.

345

E.g., Southern and South Carolina E&G.

Docket Nos. RM05-17-000 and RM05-25-000 - 335 -

Other commenters believe that the parties in the planning process should determine how

planning costs should be allocated and funded. APPA urges simplicity, the avoidance of

double collecting (e.g.

, LSEs should not have to pay through both transmission rates and

individually) and stresses the need to assess costs based on size and assets. Other

comments are consistent with equitable allocation of planning costs.

346

Commission Determination

586. We will not propose a specific method for recovery and allocation of planning

costs in this Final Rule. We recognize, however, the importance of planning cost

recovery and will require transmission planning processes to provide a mechanism for

recovery of costs. We direct transmission providers to work with other participants in the

planning process, as part of the collaborative process described above, to develop their

cost recovery proposals in order to determine whether all relevant parties, including state

agencies, have the ability to recover the costs of participating in the planning process.

Transmission providers should also consider whether mechanisms for regional cost

recovery may be appropriate, such as through agreements (formal or informal) to incur

and allocate costs jointly. The Commission will consider resulting cost recovery

proposals, including special riders to transmission rates, with an eye toward encouraging

the broadest participation in the planning process possible.

346

E.g., Bonneville, NRECA, and CREPC.

Docket Nos. RM05-17-000 and RM05-25-000 - 336 -

e. Open Season For Joint Ownership

587. In the NOPR, the Commission expressed its belief that an open season to allow

market participants to participate in joint ownership, particularly for large new

transmission projects, could stimulate grid investment and ensure that all customers have

the ability to participate in new projects on a nondiscriminatory basis. The Commission

sought comment on whether to include such a requirement and, if so, what conditions or

limitations should be associated with it.

Comments

588. As a general matter, a number of commenters believe that the planning process

should include a mandate to construct identified upgrades or otherwise hold transmission

providers accountable for carrying out the plan.

347

EEI and others argue that such a

mandate would go beyond planning and result in providers giving up control of their

systems. In their replies, LPPC and Sacramento assert that the decision to build facilities

and to carry out transmission plans must rest with transmission providers and state

authorities and that, in any event, it is unclear that the Commission has the authority to

compel construction pursuant to regional transmission plans. At the October 12

Technical Conference, there was considerable discussion of the obligation to build and its

relationship to the planning process proposed in the NOPR.

347

E.g., APPA, East Texas Cooperatives Reply, FMPA, NCPA, TAPS, TDU

Systems, Utah Municipals, and WIRES.

Docket Nos. RM05-17-000 and RM05-25-000 - 337 -

589. While not necessarily opposed to voluntary joint ownership arrangements in

general, many commenters oppose the idea of mandated open seasons.

348

EEI provides a

representative summary of the arguments of those opposed to open seasons. First, EEI

argues that the Commission does not have the authority to order joint ownership and that

joint ownership could interfere with state siting authority. It maintains that the instances

where the Commission can order transmission construction are very limited and do not

extend to the authority to order joint ownership.

349

Second, EEI argues that joint

ownership will not provide the benefits cited by the Commission, stating that there is

ample evidence that joint ownership of transmission lines is not needed to achieve

economies of scale in construction. In its view, the level of transmission investment is

currently increasing and joint ownership should not be expected to create additional

sources of transmission investment. Third, EEI contends that prospective joint owners

mistakenly believe they will not be subject to the same requirements as Commission-

348

E.g., Allegheny, American Transmission, Constellation, New York

Transmission Owners, MidAmerican, Duke, EEI, Entergy, FirstEnergy, MISO, National

Grid, Northeast Utilities, NorthWestern, Progress Energy, PSEG, South Carolina E&G,

SCE, Southern, SPP, Tacoma, Tucson, and Xcel.

349

APPA, FMPA, TAPS, and TDU Systems, however, point to various sources of

authority on which the Commission could rely to mandate open seasons and joint

ownership, such as: to remedy undue discrimination under FPA sections 205 and 206; to

carry out FPA section 214(b)(4)’s requirement to facilitate the planning and expansion of

transmission facilities to satisfy the needs of load-serving entities; as a condition of

market-based rate authority, FPA section 203 approval, or transmission rate incentives

under FPA section 219; and under the permitting regulations promulgated under FPA

section 216(c)(2)(B) dealing with backstop siting authority.

Docket Nos. RM05-17-000 and RM05-25-000 - 338 -

jurisdictional owners and urge the Commission to make clear that both jurisdictional and

nonjurisdictional owners would be subject to the same requirements for service over

jointly-owned facilities. If the Commission were to order joint ownership, Duke argues

that it must condition such ownership by a nonjurisdictional entity on that entity filing a

safe harbor OATT ensuring reciprocal open access by that joint owner.

590. Tacoma notes that ColumbiaGrid includes a mechanism for small users to

participate in transmission projects in the proposal it is considering for its planning

process. Xcel supports adopting the open season concept as an option in joint planning

requirements. Though it does not completely oppose the principle, MidAmerican sees

significant practical problems in developing and implementing an open season proposal

and regards the open season idea as premature. Others generally support allowing for

open seasons and joint ownership, but also do not believe they should be mandated.

350

591. A number of other commenters, however, support requiring open seasons as a

method of ensuring that identified upgrades are constructed. ELCON is strongly in favor,

stating that open seasons for joint ownership is an “idea whose time has come” and

expressing frustration that the Commission has not already acted on this proposal. FMPA

argues that joint ownership will aid in providing additional capital for transmission

projects. TDU Systems urge the Commission to require transmission providers,

350

E.g., Bonneville, California Commission, and CREPC. Bonneville stresses that

any jointly-owned facilities should have a single operator.

Docket Nos. RM05-17-000 and RM05-25-000 - 339 -

including RTOs and ISOs, to hold open seasons.

351

Joined by Arkansas Commission,

TDU Systems argue that open seasons should not be limited to large projects. PGP

supports open seasons when providers do not voluntarily agree to add capacity based on

the results of the transmission plan. TDU Systems cite the Neptune and Cross-Sound

Cable projects, where regulated utilities failed to provide solutions despite the need for

expansion of the system in those regions. Seattle argues that voluntary joint ownership of

projects should not be contingent upon an open season requirement. TANC points to

current joint ownership arrangements in the Western Interconnection. Sacramento

likewise notes that the joint planning and ownership process in the Western

Interconnection has been a success, but asks the Commission to make clear that physical

rights set asides are available in CAISO to accommodate non-LMP co-owners.

592. On reply, EEI, Entergy, and Southern repeat arguments against joint ownership

and open seasons. EEI replies that FMPA’s claim that joint ownership will result in

increased investment is not based on fact and will not increase access. In its reply, TDU

Systems states that joint ownership would not, as argued by EEI, infringe on state siting,

as states would retain this authority over the jointly-developed project. APPA also

stresses that its members have fewer difficulties obtaining service where joint ownership

is permitted. In their replies, Lassen, Santa Clara, and TANC argue that the Commission

351

Similar comments were made by APPA, Arkansas Commission, FMPA

(includes a legal analysis in an attachment), NCPA, MISO/PJM States, Santa Clara,

Southwestern Coop, TANC, and TAPS.

Docket Nos. RM05-17-000 and RM05-25-000 - 340 -

should not, as suggested by Duke, condition the participation of a nonjurisdictional entity

in a jointly-owned project on that entity filing a safe harbor OATT, as public power

entities use the capacity they need and sell the rest whether or not they have a safe harbor

OATT on file. However, TAPS asks on reply that access to jointly-owned facilities be

available through a pro forma

OATT. Participants at the October 12 Technical

Conference expressed both support for joint ownership, as well as caution. National Grid

states that it has had good success with joint ownership, but that jointly-owned projects

are more complicated and can take longer to develop.

Commission Determination

593. The Commission believes there are benefits to joint ownership of transmission

facilities, particularly large backbone facilities, both in terms of increasing opportunities

for investment in the transmission grid, as well as ensuring nondiscriminatory access to

the transmission grid by transmission customers. The comments received in response to

the NOPR support the notion that joint ownership can provide these benefits in many

cases. For example, as TDU Systems note, the Neptune and Cross-Sound Cable projects

have resulted in significant amounts of new transmission capacity in regions facing

chronic constraints. We encourage joint ownership for other large backbone transmission

Docket Nos. RM05-17-000 and RM05-25-000 - 341 -

upgrades included in the transmission plan developed by the planning process required by

this Final Rule.

352

594. We acknowledge, however, that joint ownership can increase the complexity of

planning and developing a transmission project and are sensitive to concerns that formal

open seasons can add to that complexity. We therefore do not mandate open season

procedures to allow market participants to participate in joint ownership. We recognize

that there may be reasons, given the complexity of the transmission grid and changing

conditions of supply and demand for power, why any given facility identified in a

transmission plan may not ultimately be constructed. Consequently, our planning

reforms do not include an obligation to construct each facility identified in the plan,

whether individually or through joint ownership mechanisms. At the same time, the

Commission agrees that joint ownership may be useful in certain situations and

encourages transmission providers and customers alike to consider the use of open

seasons to realize construction of upgrades identified in the planning studies. If a

transmission provider declines to construct an identified upgrade, we also encourage

customers and third parties to consider, either individually or jointly, development and

ownership of a project to the extent consistent with applicable state law.

352

As the Commission stated in Order No. 679-A, “[t]he Commission will look

favorably on incentive requests that include public power joint ownership.” Order No.

679-A at P 102.

Docket Nos. RM05-17-000 and RM05-25-000 - 342 -

f. Specific Study Processes Beyond Reliability and

Congestion Reduction

595. In the NOPR, the Commission sought comment on whether there should be a

specific study process to identify opportunities to enhance the grid for purposes beyond

maintaining reliability or reducing current congestion. Such a study process could allow

interested entities, including state resource agencies and others, to request the

transmission provider to model grid upgrades needed to accommodate the construction of

new resources and provide information needed to proactively evaluate such resources.

The Commission expected that such studies would not conflict with state prerogatives,

but rather would provide states with better information to evaluate all relevant resource

options.

Comments

596. Most transmission provider commenters favor providing for study of some grid

enhancement beyond reliability and congestion-related needs, but believe the Final Rule

should not mandate a specific study process. Various commenters argue that the

Commission should allow planning participants to determine details such as the scope,

number, and cost responsibility for the studies.

353

MISO states that it is working on these

issues, but enhancement beyond maintaining reliability or reducing congestion is a

complicated subject best left to each RTO or ISO to decide.

353

E.g., EEI, MISO, NorthWestern, PSEG, and Tacoma.

Docket Nos. RM05-17-000 and RM05-25-000 - 343 -

597. Some commenters are more explicit or expansive in their recommendations.

CAISO recommends that the Commission develop a policy to encourage construction of

transmission lines necessary to connect renewable resources,

354

and Suez Energy NA

provides similar comments about new remote generation. PJM believes the planning

process should look at future congestion and building for resources not yet announced.

The New Jersey Board believes that demand-side management and other solutions, such

as distributed renewable generation, also should be considered. WIRES and ELCON

believe all credible proposals should be studied. TAPS asserts that planning should study

grid enhancements needed for new potential resources.

355

These views are consistent

with the views of many of the commenters that support additional study processes.

356

TDU Systems, however, point out that planning for reliability and economics should be

incorporated into the open and inclusive planning process and, therefore, a special study

process should not be needed.

598. Other commenters are opposed to additional processes: South Carolina E&G does

not see a need for additional studies; Southern believes additional study processes would

354

Related to this, California Commission asserts that regional planning processes

need to be closely linked with the resource adequacy planning processes and renewable

energy portfolio standards on the state level.

355

EEI replies in opposition to TAPS’ assertions that planning should address

transmission for potential resources, arguing that such a requirement would be cost

prohibitive and would harm users.

356

E.g., APPA, Arkansas Commission, AWEA, CREPC, Sacramento, and Seattle.

Docket Nos. RM05-17-000 and RM05-25-000 - 344 -

be overly burdensome and would divert attention away from the fundamentals of prudent

planning; and Bonneville notes that market participants often make requests for

expensive studies without following through on them. Santee Cooper cautions the

Commission against giving license to those who would attempt to hijack the regional

planning process in order to advance a generation-related agenda, and note that the

Commission’s authority does not extend to generation resource adequacy.

Commission Determination

599. We believe that development of a study process for identifying opportunities for

grid enhancement beyond reliability and congestion reduction has the potential to provide

useful information and would generally benefit development of the transmission grid.

We therefore will include such study processes within the scope of Principle No. 8. In

the NOPR, that principle concerned only congestion studies, but, as modified above, it

now includes studies regarding upgrades that could integrate new generation resources.

We note that various commenters argued for the consideration of demand resources in

development of enhancements to the transmission grid.

357

As we explain above,

consideration of such resources falls within Principle No. 8, as modified by the Final

Rule.

357

E.g., New Jersey Board, Ohio Power Siting Board, and WIRES.

Docket Nos. RM05-17-000 and RM05-25-000 - 345 -

g. Level of Detail in the OATT

600. In the NOPR, the Commission sought comment on the level of detail to be

required to be in the transmission provider’s OATT regarding its planning process.

Comments

601. Several commenters argued that the details of the planning process should be

included in the transmission providers’ OATTs.

358

Seattle noted that the OATT should

balance the need for detailed planning requirements with the need for regional processes

to evolve.

Commission Determination

602. The Commission agrees that the transmission planning attachment to a

transmission provider’s OATT must include sufficient detail to enable transmission

customers to understand the transmission provider’s planning process. This new

attachment must therefore include:

a) the process for consulting with customers and neighboring transmission

providers;

b) the notice procedures and anticipated frequency of meetings or planning-

related communications;

c) a written description of the methodology, criteria, and processes used to

develop transmission plans;

d) the method of disclosure of transmission plans and related studies and the

criteria, assumptions and data underlying those plans and studies;

358

E.g., APPA, NRECA, Old Dominion, and Seattle. APPA also suggests OASIS

posting.

Docket Nos. RM05-17-000 and RM05-25-000 - 346 -

e) the obligations of and methods for customers to submit data to the transmission

provider;

f) the dispute resolution process;

g) the transmission provider’s study procedures for economic upgrades to address

congestion or the integration of new resources; and

h) the relevant cost allocation procedures or principles.

C. Transmission Pricing

1. General

603. As the Commission explained in Order No. 888, the pro forma

OATT was

designed to include primarily non-rate terms and conditions of open access non-

discriminatory transmission service. Transmission providers first were required to adopt

the non-rate terms and conditions of the pro forma

OATT and then, in a subsequent filing

under FPA section 205, to propose corresponding rates for service provided under their

OATTs. Consistent with the focus of Order No. 888 on the non-rate terms and conditions

of open access, the Commission did not propose broad reform of transmission pricing

policy through the NOPR. Rather, the Commission identified in the NOPR several

discrete pricing rules that it considered part and parcel of OATT service that merit

reform, which we discuss in more detail later in this section. The Commission also

specifically noted in the NOPR that the purpose of this rulemaking is to strengthen the

pro forma

OATT to remedy undue discrimination and not to create new market

structures.

Docket Nos. RM05-17-000 and RM05-25-000 - 347 -

604. Despite the clear scope of this rulemaking, several commenters contend that

broader ratemaking reforms should be implemented in order to remove obstacles to

achieving competitive markets. Various commenters assert that rate pancaking must be

eliminated in this reform, noting that the Commission has recognized in the past that

pancaked rates inhibit the development of competitive markets.

359

Arkansas Municipal

and TDU Systems contend that pancaked rates are particularly burdensome for customers

with loads and resources on multiple transmission providers systems and those that sit

essentially at or on the boundaries. TDU Systems argue that the failure to eliminate

pancaked rates has caused many of the TDU Systems to spend many millions of dollars

to build transmission from generation to interconnect with multiple control areas in order

to avoid paying multiple wheeling charges.

605. Some of these commenters also advocate that the Commission should move

towards joint rates.

360

Arkansas Municipal Power argues that moving toward joint rates

outside an RTO will not only eliminate competitive barriers outside RTOs, but would

reduce the disincentive to formation of new and expanded RTOs. TAPS complains that

the NOPR requires regional planning, but has no provision requiring transmission

providers to build facilities to support regional needs, arguing that joint rates would ease

this problem. TDU Systems argue, however, that any joint rate methodology should not

359

E.g., Arkansas Municipal, AWEA, FMPA, and TDU Systems.

360

E.g., Arkansas Municipal, TAPS, and TDU Systems

Docket Nos. RM05-17-000 and RM05-25-000 - 348 -

shift costs to other network customers, especially where surcharges are sought that might

open the door to potential over-recovery by transmission providers as argued in the PJM

/MISO proceedings. Old Dominion also contends that the Commission should add a

requirement in the pro forma

OATT that regional transmission costs be recovered

through a single regional transmission rate of a rolled-in nature. Relative to cost

recovery, Old Dominion believes that rolled-in zonal rates work for local facilities within

a single transmission owner footprint, but regional rolled-in rates would be necessary for

larger footprints.

606. Old Dominion also contends that the lack of periodic review by the Commission

of stated transmission rates sends a strong economic signal to transmission owners to not

invest in new transmission. Old Dominion argues that the Commission should require

periodic rate reviews at least every five years or implement formula rates which would

remove economic incentives for failing to build transmission.

607. EEI argues that the Commission should not address in this proceeding TDU

Systems’ proposal to require transmission providers to eliminate pancaked transmission

rates in non-RTO regions because it involves complex issues that are not easily resolved.

EEI contends that transmission providers should not be required to eliminate multiple

transmission rates across multiple systems simply to allow TDU members to avoid the

economic consequences of their decisions to purchase energy from off-system resources.

608. Other commenters ask the Commission to institute much broader market reforms

in this rulemaking, arguing that the Commission will not be able to achieve its objectives

Docket Nos. RM05-17-000 and RM05-25-000 - 349 -

of remedying undue discrimination and developing competitive wholesale markets

without a fundamental change in market structures. Several commenters advocate

changing the market structure in non-RTO markets to allow transmission customers to

access the transmission provider’s dispatch and redispatch options.

361

Some

commenters

362

go further to assert that the Commission require the use of locational

marginal pricing (LMP) as a part of OATT reform. Other commenters

363

assert that the

Commission would not need to adopt a full RTO market design to achieve its more

limited objectives, but contend that eliminating the fundamental inconsistency between

the OATT rules and actual operation of the grid would remove a major obstacle to other

reforms. Several commenters

364

contend that requiring use of a security constrained

economic dispatch is a needed part of this reform.

609. Chandley-Hogan contend that the key element to ensuring transmission services

are provided on a just, reasonable and not unduly discriminatory basis is to provide open

access to the security constrained economic dispatch and the associated imbalance

pricing that arises from that dispatch. Chandley-Hogan state that using a security

constrained economic dispatch would also substantially reduce the problems inherent in

361

E.g., Chandley-Hogan, Constellation, and PJM.

362

E.g., Morgan Stanley and Steel Manufacturers Associations.

363

E.g., Chandley-Hogan and PJM.

364

E.g., EPSA and Chandley-Hogan.

Docket Nos. RM05-17-000 and RM05-25-000 - 350 -

the pro forma

OATT’s reliance on contract paths and ATC for transmission service

scheduling.

610. Chandley-Hogan contend that a viable path to Order No. 888 reform is to start

from the premise that open access to the dispatch (and redispatch) and marginal cost

pricing for imbalances and redispatch to accommodate transmission are keys to getting

open, non-discriminatory access to transmission. Chandley-Hogan argue that dispatch is

the essential transmission service and providing open access to this dispatch is a path to

achieving open, non-discriminatory access to transmission. Chandley-Hogan contend

that a third party cannot effectively access the grid without accessing and closely

interacting with the system operator’s dispatch, including determining if transmission

service is available, acquiring redispatch service to allow its schedule to proceed without

curtailment, and settling imbalances from scheduled levels. Williams agrees with

Chandley-Hogan that a system allowing non-RTO utilities to deny and curtail service

requests whenever there is little ATC left and without offering redispatch to a third party

is completely flawed. Williams argues that these same requests would be accommodated

in an RTO through redispatch as long as the RTO has sufficient offers to arrange a

security constrained economic dispatch.

611. EPSA argues on reply that an all-inclusive, “asset-blind” administration of open

dispatch is needed to fully eliminate undue discrimination. EPSA states that security

constrained dispatch will provide reliable operation and efficient utilization of the

transmission grid by promoting the use of newer, cleaner and less expensive power

Docket Nos. RM05-17-000 and RM05-25-000 - 351 -

plants. EPSA urges that these issues should be explored further here or in another policy

proceeding. Project for Sustainable FERC Energy Policy asserts that there is no

assurance of non-discriminatory access to transmission services and competitive

wholesale markets unless load and potential competitors of the control area operators are

treated comparably during dispatch. Project for Sustainable FERC Energy Policy

supports additional provisions to the pro forma

OATT requiring transparency and

fairness in system dispatch and redispatch such as either an “open dispatch” requirement

or a rule-based framework with standards of conduct and OASIS disclosure, as well as

reporting and auditing requirement to eliminate anticompetitive incentives. Project for

Sustainable FERC Energy Policy argues that sufficient data to establish marginal system

costs and permit comparisons with the prices/costs of neighboring systems should be

disclosed on OASIS.

612. PJM proposes open dispatch consisting of control of the dispatch function by a

disinterested entity and the institution of a spot or balancing market to allow for the

formation of real-time prices. Project for Sustainable FERC Energy Policy encourages

the further separation of the system operator’s dispatch functions from its merchant

functions, to include specific dispatch transparency and comparability mandates as per

PJM’s and Transparent Dispatch Advocates’ request. Project for Sustainable FERC

Energy Policy supports comparable dispatch services through an independent entity. In

its reply comments, Williams supports the rules based dispatch service proposed by PJM

Docket Nos. RM05-17-000 and RM05-25-000 - 352 -

and states that it will reduce the opportunity for transmission providers to levy unjust and

unreasonable redispatch rates.

613. PJM also contends that non-RTO/ISO systems have negative impacts on RTO

systems because of the respective treatment of import transactions by non-RTOs/ISOs

and RTOs/ISOs and the incidence of loop flows in market environments. PJM argues

that entities scheduling flows through PJM that actually loop onto other systems

nevertheless benefit financially because they collect the difference between the relatively

high price at the interface where the energy is scheduled to enter the PJM footprint and

the lower price at the interface where the energy is scheduled to leave the PJM footprint.

When energy does not flow as scheduled, PJM states that the otherwise expected,

beneficial impact on the transmission constraints are not realized, resulting in price

differentials between the affected interfaces. As a result, PJM contends that such

scheduled transactions only contribute to the FTR revenue adequacy issues PJM has

experienced over the last 12 months.

614. PJM asserts that it is unduly preferential for a non-RTO/ISO utility to take

advantage of the benefits of the organized markets of a bordering RTO/ISO without any

obligation to bear any of the costs of administering those markets. PJM contends that it

is unduly discriminatory and an impediment to the development of competitive markets

to permit a non-RTO/ISO utility adjacent to an RTO/ISO’s organized, transparent

markets to accept the benefits of those markets and the regional transmission planning

process that sustains them, while the same utility relies on non-market-based congestion

Docket Nos. RM05-17-000 and RM05-25-000 - 353 -

management and limits the access of its competitors, including those who are members of

the relevant RTO/ISO, to its dispatch sequence and wholesale prices within its service

area. PJM asks the Commission to declare that it would not be unduly discriminatory for

an RTO/ISO to include in its tariff a provision that makes an external system operator’s

access to those markets contingent on the external operator providing reciprocal access to

its dispatch and planning functions for RTO/ISO members, as well as access to the

external system’s real-time marginal system cost information.

615. Transparent Dispatch Advocates propose on reply that the Commission require the

industry to develop inter-control area coordination agreements to provide for reciprocal

redispatch to alleviate constraints at specified border flowgates. Transparent Dispatch

Advocates argue that redispatch over a larger area provides transmission providers more

options to extract the full efficiency of their systems by allowing import/export

transactions and intra-control area flows to continue that would otherwise be curtailed by

providing redispatch of generation across a border at a lower cost than would result had

the transaction been curtailed. Transparent Dispatch Advocates further propose that the

Commission establish principles in the Final Rule to guide the development of these

coordination agreements and require filing of the agreements within 12 months of the

issuance of the Final Rule. Transparent Dispatch Advocates suggest that technical

conferences may need to be scheduled to address any utility specific issues that arise.

616. Morgan Stanley and Steel Manufacturers Association contend that every control

area should be moving toward LMP and that facing an imbalance cost measured by full

Docket Nos. RM05-17-000 and RM05-25-000 - 354 -

replacement value of redispatch measured under LMP is the correct incentive to follow a

schedule. Entegra similarly argues that customers and state regulators would benefit from

more transparency regarding congestion on the transmission system and that the most

efficient way to provide this transparency is to require transmission providers to apply

LMP models to their systems and to post the resulting modeled LMPs.

617. Several commenters object to the proposal for a mandatory all-inclusive redispatch

using bid-based pricing.

365

These commenters generally argue that such a proposal could

not lawfully be adopted in the Final Rule because it dramatically departs from the scope

of the NOPR. They also argue that the proposal is bad policy because there is no record

showing that consumers would benefit from the costly and disruptive implementation

required for the proposal and that adoption of the proposal would create controversy

given that Congress and the Commission have already rejected an LMP-based model of

industry restructuring. Sacramento adds that given the record of transmission investment

in RTOs, open redispatch might not meet the transmission expansion goals of the NOPR.

618. Southern argues on reply that there is no legal basis for claims that a lack of open

dispatch results in undue discrimination. Southern states that the entities at issue are not

similarly situated and that open dispatch concerns resource procurement, an area beyond

the scope of the Commission’s jurisdiction. Southern further argues that the open

dispatch remedy proposed by PJM and others would require radical restructuring and

365

E.g., LPPC, Entergy, and Sacramento.

Docket Nos. RM05-17-000 and RM05-25-000 - 355 -

market reforms that are unfounded, lack a legal basis and would result in political

discord. Southern states that open dispatch would violate FPA section 217 by threatening

the ability of LSEs to maintain access to transmission rights to serve native load. In its

reply comments, Entergy states that the open dispatch proposal should be rejected

because it is unnecessary to ensure open access transmission service, is contrary to the

Congressional intent in passing EPAct 2005, exceeds the scope of the Commission’s

jurisdiction by overriding state jurisdiction over sales to retail customers, and would

result in opposition that will delay other reforms and distract the Commission with

divisive litigation.

619. Sacramento states that the proposals for mandatory redispatch, the control of the

dispatch by a disinterested entity, and the institution of a spot or balancing market to

allow for the formation of real-time prices would undermine customers’ objectives to

receive uninterrupted transmission service at a predictable price and ignore transmission

system operational limitations. Sacramento states that the value of mandatory redispatch

in the Western Grid is limited because constraints often overlap and change from thermal

to voltage to stability constraints at differing load levels and redispatching large amounts

of generation to relieve constraints because of the distance between loads and generation

cannot be achieved in the timeframes required to maintain reliability. Sacramento is

concerned that PJM’s proposal would cause appropriation of generation built to serve a

transmission provider’s native load in order to effectuate third-party transmission

Docket Nos. RM05-17-000 and RM05-25-000 - 356 -

transactions, strain the transmission provider’s grid, and cause additional curtailment of

native load and firm transactions when a force majeure event occurs.

620. Entergy cites the approval of the ICT proposal as ample evidence that the

incremental approach proposed in the NOPR is a better means of improving clarity,

transparency and improvements in dispatch efficiency than the Transparent Dispatch

Advocates and PJM seek to mandate. Entergy states that the arguments posed by PJM

and Chandley-Hogan do not target remedying discrimination or ensuring comparability,

but rather focus on what they believe are mechanisms for more efficient use of the grid.

Overall, Entergy does not support any changes to the basic nature of the services

available under the pro forma

OATT or the development of real-time markets to ensure

comparable access.

621. In its reply comments, Sacramento disagrees with PJM’s claims that TLRs are a

discriminatory substitute for real-time redispatch and PJM’s proposal to eliminate such

use of TLRs in favor of an expanded redispatch obligation. Sacramento argues that firm

customers under the pro forma

OATT do not expect TLRs, while those in Day 2 RTOs

expect that generation will be redispatched. Sacramento adds that TLRs affect all loads,

but that the nature of firm physical rights service is that it will not be interrupted except

in very narrow defined circumstances.

622. Southern argues that customers selling between RTO and non-RTO systems are

treated equally since part of the transaction is under an LMP treatment and the other part

is under OATT treatment. In response to PJM’s allegations that loop flows are unduly

Docket Nos. RM05-17-000 and RM05-25-000 - 357 -

discriminatory to its customers, Southern states that loop flows are unavoidable

consequences of integrating electrical systems and that PJM itself imposes loop flows on

non-RTO systems, the effects of which are not compensated by PJM. If PJM believes

that entities are free-riding on its system or manipulating its system, Southern argues that

PJM could seek to increase market participation charges or file a complaint with the

Commission. Sacramento agrees that this rulemaking is the wrong forum for resolving

seams issues given the stated scope of the NOPR. Sacramento adds that border utilities

do not “free ride” on RTO markets because these markets impose significant costs on

border entities. Sacramento also disagrees that open redispatch would resolve loop flow

problems and suggests other mechanism for addressing loop flow. Finally, Sacramento

states that TLRs are an Eastern Interconnection process that, although rare, occur in

RTOs and non-RTO areas.

Commission Determination

623. As the Commission explained in the NOPR, we do not intend to undertake a

comprehensive overhaul of our transmission pricing policies in this rulemaking. Instead,

the Commission proposed a number of specific reforms to discrete provisions in the pro

forma OATT and a clarification to our “higher of” policy for pricing of transmission

system expansions. Given the limited scope of this proceeding, we do not believe it

would be appropriate to adopt the broader ratemaking proposals suggested by

commenters. Issues of rate pancaking, including joint rates, regional rolled-in rates and

rate reviews are beyond the scope of this proceeding.

Docket Nos. RM05-17-000 and RM05-25-000 - 358 -

624. Similarly, the Commission made clear in the NOPR that the purpose of the

proposed rule is to strengthen the pro forma

OATT to remedy undue discrimination and

not to impose any particular market structure on the industry. The Commission’s focus

in this proceeding was and remains the development of competitive wholesale markets

through the reduction of barriers to entry created through the control of transmission

assets. We continue to believe that the appropriate focus of this rulemaking is to

strengthen competitive wholesale markets by adopting reforms to address remaining

areas of undue discrimination and issues of comparability rather than mandating a

fundamental change in the market structure.

625. We therefore reject requests to institute systems that require the real-time use of

regional security constrained economic dispatch and LMP for granting real-time

transmission service and for the settlement of imbalances or to otherwise require

transmission providers to use LMP-based modeling. We believe that LMP market

designs can provide significant benefits to customers through more efficient use of the

grid, but do not believe that such market designs are the only way to remedy undue

discrimination or achieve comparability. We continue to support regional flexibility in

market development, provided that the market design implemented by the transmission

providers provides other transmission customers with comparable service to that which

the transmission providers provide to their own native loads and affiliates.

626. We also reject arguments regarding seams issues creating an undue discrimination

between market and non-market areas that must be resolved in this proceeding. We note

Docket Nos. RM05-17-000 and RM05-25-000 - 359 -

that there are currently processes underway to address seams issues both in the Eastern

and Western Interconnections.

366

We believe that such seams issues are beyond the

scope of this rule and are better addressed on a case-by-case basis or, as appropriate, in

the proceeding on RTO Border Utility Issues.

367

2. Energy and Generation Imbalances

627. In Order No. 888, the Commission concluded that six ancillary services must be

included in an OATT.

368

One of those ancillary services is energy imbalance service

under Schedule 4 of the pro forma

OATT.

369

Energy imbalance service is provided when

the transmission provider makes up for any difference that occurs over a single hour

between the scheduled and the actual delivery of energy to a load located within its

control area.

370

The Commission recognized, in general, that the amount of energy taken

by load in an hour is variable and not subject to the control of either a wholesale seller or

a wholesale requirements buyer.

371

366

See, e.g., RTO Border Utility Issues, Notice of Technical Conference on Seams

Issues for RTOs and ISOs in the Eastern Interconnections, (Docket No. AD06-9-000)

(issued Jan. 25, 2007).

367

Id.

368

Order No. 888 at 31,703.

369

Id.

370

See Id. at 31,960.

371

Order No. 888-A at 30,230.

Docket Nos. RM05-17-000 and RM05-25-000 - 360 -

628. The Commission found that energy imbalance service should have an energy

deviation band appropriate for load variations and a price for exceeding the deviation

band that is appropriate for excessive load variations.

372

The Commission established an

hourly deviation band of +/- 1.5 percent (with a minimum of 2 MW) for energy

imbalance. The Commission explained that this deviation band promotes good

scheduling practices by transmission customers, which ensures that the implementation

of one scheduled transaction does not overly burden another.

373

629. With respect to compensation associated with the hourly energy deviation band,

the Commission explained that, for energy imbalances within the deviation band, the

transmission customer may make up the difference within 30 days (or other reasonable

period generally accepted in the region) by adjusting its energy deliveries to eliminate the

imbalance (i.e.

, return energy in kind within 30 days).

374

In addition, the Commission

explained that the transmission customer must compensate the transmission provider for

each imbalance that exceeds the hourly deviation band and for accumulated minor

imbalances that are not made-up within 30 days.

375

With respect to the price of energy

372

Id.

373

Id. at 30,232.

374

Id. at 30,229.

375

Id. The Commission further stated that the pro forma OATT permits schedule

changes up to twenty minutes before the hour at no charge, and that it would allow the

transmission provider and the customer to negotiate and file another deviation band more

(continued)

Docket Nos. RM05-17-000 and RM05-25-000 - 361 -

imbalance service, the Commission explained that it intentionally did not provide detailed

pricing requirements.

376

Instead, the Commission required transmission providers to

propose rates for energy imbalance service.

377

630. Although transmission providers have different energy imbalance charges, they

typically require customers to correct energy imbalances within the deviation band

through return in kind or a financial settlement that requires payment for underdeliveries

of energy equal to 100 percent of the transmission provider’s system incremental cost for

the hour the deviation occurred. For energy overdeliveries, the transmission customer

would receive a payment equal to 100 percent of the transmission provider’s decremental

cost for the hour the deviation occurred.

378

Outside the deviation band, transmission

providers either charge the transmission customer (1) a percentage of the utility’s system

cost, such as 110 percent of incremental costs for underscheduling or 90 percent of

flexible to the customer, if the same deviation band is made available on a not unduly

discriminatory basis. Id.

at 30,232-33.

376

Id. at 30,234.

377

Id.

378

See, e.g., Arizona Public Service Co., FERC Electric Tariff, Twelfth Revised

Volume No. 2, Schedule 4 (Energy Imbalance Charge), accepted in Arizona Public

Service Co., Docket No. ER04-442-003 (Sep. 30, 2004) (unpublished letter order); Public

Service Company of New Mexico, FERC Electric Tariff, Second Revised Volume No. 4.,

Schedule 4 (Energy Imbalance Charge), accepted in Public Service Co. of New Mexico

Docket No. ER04-416-002 (Sep. 30, 2004) (unpublished letter order).

Docket Nos. RM05-17-000 and RM05-25-000 - 362 -

decremental costs for overscheduling or (2) the greater of a percentage of system costs or

a fixed charge, such as $100 per MWh.

379

631. While the Commission found in Order No. 888 that energy imbalance was an

ancillary service, it also recognized that another imbalance may arise for differences

between energy scheduled for delivery from a generator and the amount of energy

actually generated in an hour,

380

commonly called generator imbalance. The Commission

concluded, however, that a generator should be able to deliver its scheduled hourly

energy with precision and expressed concern that allowing a generator to deviate from its

schedule by 1.5 percent without penalty, so long as it returned the energy in kind at

another time, would discourage good generator operating practices.

381

The Commission

stated that a generator’s interconnection agreement with its transmission provider or

control area operator should specify the requirements for the generator to meet its

schedule and any consequence for persistent failure to meet its schedule.

382

379

See Idaho Power Co., 102 FERC ¶ 61,351 (2003); Duke Electric Transmission

FERC Electric Tariff, Third Revised Volume 4, Original Sheet No. 120 accepted in Duke

Energy Corp., Docket No. ER04-812-001 (Jul. 2, 2004) (unpublished letter order).

380

Order No. 888-A at 30,230.

381

Id.

382

Id.

Docket Nos. RM05-17-000 and RM05-25-000 - 363 -

632. The Commission subsequently accepted in a number of cases modifications to a

transmission provider’s OATT to include generator imbalance provisions.

383

Moreover,

in Order No. 2003-B, the Commission permitted the transmission provider to include a

provision for generator balancing service arrangements in individual interconnection

agreements.

384

Further, in a NOPR concerning generator imbalance provisions for

intermittent resources, the Commission proposed to establish a standardized schedule

under the pro forma

OATT to address generator imbalances created by intermittent

resources and to clarify the application of the current energy imbalance provision of the

pro forma

OATT.

385

In particular, the Commission proposed that generator imbalance

provisions for intermittent resources would reflect a deviation band of +/- 10 percent

(with a minimum of 2 MW) and allow net hourly intermittent generator imbalances

within the deviation band to be settled at the system incremental cost at the time of the

383

See, e.g., Niagara Mohawk Power Corp., 86 FERC ¶ 61,009, order on reh’g,

87 FERC ¶ 61,148 (1999) (Niagara Mohawk

); PacifiCorp, 95 FERC ¶ 61,145, order on

reh’g and clarification, 95 FERC ¶ 61,467 (2001); Alliant Energy Corporate Services,

Inc., 93 FERC ¶ 61,340 (2000); Wolverine Power Supply Coop., 93 FERC ¶ 61,330

(2000); Commonwealth Edison Co.

, 93 FERC ¶ 61,021 (2000); FirstEnergy Operating

Cos., 93 FERC ¶ 61,200 (2000), order denying reh’g & granting clarification, 94 FERC

¶ 61,184 (2001); Tampa Electric Co.

, 90 FERC ¶ 61,330 (2000), reh’g denied, 95 FERC

¶ 61,101 (2001); Florida Power Corp.

, 89 FERC ¶ 61,263 (1999); Consumers Energy

Co., 87 FERC ¶ 61,170 (1999) (Consumers).

384

Order No. 2003-B at P 74-75.

385

Imbalance Provisions for Intermittent Resources; Assessing the State of Wind

Energy in Wholesale Electricity Markets, Notice of Proposed Rulemaking, 70 FR 21349

(Apr. 26, 2005), FERC Stats. & Regs. ¶ 32,581 at P 9 (2005) (Imbalance Provisions

Proceeding).

Docket Nos. RM05-17-000 and RM05-25-000 - 364 -

imbalance.

386

The Commission also reiterated its policy that a transmission provider may

only charge the transmission customer for either hourly generator imbalances or hourly

energy imbalances for the same imbalance, but not both.

387

633. A variety of different deviation bands and pricing methods are on file for

generator imbalances. Rates for generator imbalance underdeliveries range from the

greater of $100/MWh or 110 percent of system incremental cost to the greater of

$150/MWh or 200 percent of the incremental cost.

388

Generator imbalance rates for

386

The Commission defined incremental cost as “the transmission provider’s

actual average hourly cost of the last 10 MW dispatched to supply the transmission

provider’s native load, based on the replacement cost of fuel, unit heat rates, start-up

costs, incremental operation and maintenance costs, and purchased and interchange

power costs and taxes.” Id.

at P 9 n.17 (citing Consumers, 87 FERC ¶ 61,170 at 61,179

(1999)).

387

Under existing Commission policy, a transmission provider may only charge a

transmission customer for the penalty percent adder to the incremental cost for either a

hourly generator imbalances or a hourly energy imbalances for the same imbalance. For

example, if a transmission customer has a 100 MWh point–to-point schedule in a control

area, but produces 105 MWh and consumes 105 MWh, the transmission provider may

charge the transmission customer 110% of its incremental cost for the 5 MWh of energy

imbalance, but then must pay the transmission customer its incremental cost for the 5

MWh generator imbalance.

388

See Duke Energy Corp., Docket No. ER05-855-000 (Dec. 20, 2005)

(unpublished letter order) (accepting Duke Electric Transmission’s Large Generator

Interconnection Agreement with Power Ventures Group, LLC (Duke Delegated Letter

Order)).

Docket Nos. RM05-17-000 and RM05-25-000 - 365 -

overdeliveries range from 90 percent

389

of system decremental cost to 50 percent

390

of the

decremental cost.

a. Tiered Approach to Imbalance Penalties in the OATT

NOPR Proposal

634. In the NOPR, the Commission noted that the existing energy imbalance charges

described in Order No. 2003 are the subject of significant concern and confusion in the

industry. The Commission expressed concern about the variety of different

methodologies used for determining imbalance charges and whether the level of the

charges provides the proper incentive to keep schedules accurate without being excessive.

The Commission therefore proposed to modify the current pro forma

OATT Schedule 4

treatment of energy imbalances and to adopt a separate pro forma

OATT schedule for the

treatment of generator imbalances.

635. The Commission proposed to create new energy and generator imbalance

schedules based on the following three principles: (1) the charges must be based on

incremental cost or some multiple thereof; (2) the charges must provide an incentive for

accurate scheduling, such as by increasing the percentage of the adder above (and below)

incremental cost as the deviations become larger; and (3) the provisions must account for

389

See Entergy Services, Inc., 90 FERC ¶ 61,272 (2000) (concerning various

generator imbalance agreements).

390

See Duke Delegated Letter Order.

Docket Nos. RM05-17-000 and RM05-25-000 - 366 -

the special circumstances presented by intermittent generators and their limited ability to

precisely forecast or control generation levels, such as waiving the more punitive adders

associated with higher deviations.

636. The Commission noted that Bonneville has adopted an energy imbalance pricing

approach based on a three-tiered deviation band that appears workable for both energy

imbalance service and generation imbalance service. Under this approach, imbalances of

less than or equal to 1.5 percent of the scheduled energy (or two megawatts, whichever is

larger) would be netted on a monthly basis and settled financially at 100 percent of

incremental or decremental cost at the end of each month. Imbalances between 1.5 and

7.5 percent of the scheduled amounts (or two to ten megawatts, whichever is larger)

would be settled financially at 90 percent of the transmission provider’s system

decremental cost for overscheduling imbalances that require the transmission provider to

decrease generation or 110 percent of the incremental cost for underscheduling

imbalances that require increased generation in the control area. Imbalances greater than

7.5 percent of the scheduled amounts (or 10 megawatts, whichever is larger) would be

settled at 75 percent of the system decremental cost for overscheduling imbalances or 125

percent of the incremental cost for underscheduling imbalances. Intermittent resources

are exempt from the third-tier deviation band and pay the second-tier deviation band

charges for all deviations greater than the larger of 1.5 percent or two megawatts.

637. The Commission sought comment regarding whether this tiered approach should

be adopted for inclusion in the pro forma

OATT for energy and generator imbalances.

Docket Nos. RM05-17-000 and RM05-25-000 - 367 -

The Commission specifically asked whether this approach provides sufficient incentives

to ensure that transmission systems can be operated in a reliable manner and ensure that

customers are treated in a just and reasonable manner.

Comments

638. A number of entities generally support a tiered approach to imbalance penalties

that progressively increases the penalties for imbalances, as implemented by

Bonneville.

391

These commenters generally state that a graduated bandwidth approach

recognizes the link between escalating deviations and potential reliability impacts on the

system. Other entities, however, take issue with aspects of the Commission’s proposal or

propose a different approach to resolving imbalances. For example, Entegra submits that

the Commission should require transmission providers to establish, or permit market

participants to establish, markets or pools for the netting and settlement of imbalances.

Steel Manufacturers Association argues for the Commission to require real-time

balancing markets.

639. Among those supporting the Commission’s proposal, Ameren asserts that the

tiered approach properly allows for higher penalties for imbalances that have a greater

impact on the system and thus have a greater potential to affect reliability. NorthWestern

is not opposed to the generation imbalance provisions applying to all generators, arguing

391

E.g., Ameren, Northwest IOUs, Progress Energy, Suez Energy NA, Public

Power Council, Sacramento, South Carolina E&G, Pinnacle, Allegheny, TDU Systems,

Constellation, Imperial, and Morgan Stanley.

Docket Nos. RM05-17-000 and RM05-25-000 - 368 -

that imbalance charges must be based upon incremental cost and must provide an

incentive for accurate scheduling. Morgan Stanley contends that basing the imbalance

charge on incremental cost should be a bedrock principle for developing methods to

financially settle imbalances.

640. Progress Energy, Sacramento, and Entergy encourage the Commission to allow

each transmission provider to have the flexibility to craft penalty provisions that provide

the right incentives to encourage their transmission customers to act responsibly. Grant

similarly contends that the transmission provider must be able to decide what to charge

for imbalance services and must consider the incentives for resource development and the

potential for cross-subsidies paid by other customers associated with such pricing. Grant

argues that transmission providers should have an ability to “opt out” if they can

demonstrate an inability to provide the service without creating an undue burden on other

ratepayers.

641. Constellation, while supporting the Commission’s proposal, asks that transmission

providers be required to utilize a security constrained economic dispatch to procure and

settle imbalances at least cost, which would ensure that least cost is determined on the

most efficient basis. Constellation contends that imbalance charges should be based on

the transmission provider’s actual cost of meeting a positive imbalance or liquidating a

negative imbalance, which costs can include required ancillary services and redispatch

costs. Morgan Stanley states that facing an imbalance cost measured by full replacement

value of redispatch measured under LMP would be an appropriate incentive. Morgan

Docket Nos. RM05-17-000 and RM05-25-000 - 369 -

Stanley contends that the pro forma

OATT should specify using opportunity cost

principles to charge for imbalance solutions in those areas without LMP and come as

close to mimicking the result under LMP as possible. In reply comments, Mark Lively

suggests the Commission make the price for imbalances a function of the size of Area

Control Error. Public Power Council recommends that transmission providers not assess

penalties against loads or resources when their deviations from the schedule help the

system in a given delivery hour. TDU Systems argue that inadvertent scheduling errors

that do not threaten system integrity or reliability should not be penalized through

charges for imbalances that exceed incremental cost in the upper tiers of imbalance

bandwidths.

642. Although FirstEnergy states that the Bonneville approach for generator imbalances

is appropriate, it argues that the current pro forma

OATT methodology for calculating

and assessing energy imbalances should be retained. FirstEnergy argues that it is more

appropriate and fair to apply a graduated penalty structure to generation imbalances since

greater deviations usually occur from generation. Ameren, however, believes that

generators are generally better able to control their imbalances than transmission

customers who take energy off of the system and that the use of a narrower deviation

band may be appropriate for generator imbalances. Nonetheless, Ameren states that it

does not oppose the Commission’s proposal to use the same deviation bandwidths for

both energy imbalances and generator imbalances.

Docket Nos. RM05-17-000 and RM05-25-000 - 370 -

643. Ameren contends that developing standardized provisions for generator

imbalances in the OATT would eliminate the plethora of penalties that now exist.

Ameren asserts that moving to a tariff approach would increase transparency and would

help address the situation where such provisions may appear either in the relevant OATT

or in specific interconnection agreements (at least for interconnection agreements entered

into as of the date of the revised tariff provisions). Progress Energy and South Carolina

E&G support separate tariff (or Generator Interconnection Agreement) provisions for

these services, suggesting that generator and energy imbalance provisions could be

tailored for generators and LSEs. NorthWestern states that it has long been an advocate

of the inclusion of a generation imbalance OATT mechanism. TDU Systems contend

that the Commission should require that the specific bandwidths and the basis for the

charges be spelled out in detail in the revisions to the pro forma

OATT and in each

transmission provider’s tariff. Allegheny argues that changing Energy Imbalance Service

from Schedule 4 to Schedule 4a, adding a new Schedule 4b for Generator Imbalance

Service, and eliminating proposed Schedule 9 would call attention to the fact that a

transmission provider may only charge a transmission customer either an hourly

generator imbalance charge or an hourly energy imbalance charge, but not both for the

same imbalance.

644. Other entities contend that the Commission’s imbalance proposal will not do

enough to protect reliability and prevent entities from deviating from their schedules.

Entergy states that the Commission should recognize that a system with significant hydro

Docket Nos. RM05-17-000 and RM05-25-000 - 371 -

resources, such as the Bonneville system, faces different challenges in matching

generation and load than a system with predominantly thermal generation. Unlike the

fast ramping capability of hydro units, Entergy asserts that thermal units have a more

limited ability to adjust and compensate for imbalances. Entergy adds that the Bonneville

model may not provide sufficient incentives in those areas with large amounts of

independent generation. In reply comments, some APPA members noted that wind

variability may pose significant operational concerns that could increase regulating

reserve requirements, particularly on smaller transmission systems.

645. Steel Manufacturers Association asks the Commission to delete any further

reference to charges based on some multiple of incremental costs, which applies to

scheduling incentives, not cost recovery. It believes that charges based on multiples of

incremental costs are not necessary and do not produce rates that are just and reasonable.

Steel Manufacturers Association asserts that balancing mechanisms based on real time

market-clearing prices provide full compensation and adequate scheduling incentives in

the organized markets and there is no reason to apply a deadband/penalty mechanism for

individual OATT providers unless there is a demonstrated need, i.e.

, a showing that

excessive gaming by LSEs or generators has been a problem.

646. Steel Manufacturers Association also contends that the current imbalance

mechanism is a losing proposition for loads that cannot control energy consumption to

match an hourly schedule of energy deliveries, with transmission providers receiving

windfall revenues. It argues that the mechanism is unfair to smaller transmission systems

Docket Nos. RM05-17-000 and RM05-25-000 - 372 -

that are not control areas (and therefore may not settle all of their imbalances through

return-in-kind energy) and certain retail customers that take unbundled retail transmission

service. Steel Manufacturers Association asks the Commission to institute a larger

bandwidth of, at minimum, 10 percent for small wholesale customers and discrete retail

loads. It contends that large utilities and wholesale transmission customers that acquire

power for many discretely operated loads with varying load stages and load factors and

averaging those loads creates an overall predictability to load curves that permits the

practical use of a 1.5 percent bandwidth for large utilities and wholesale customers.

647. Utah Municipals assert that the Commission is wrong to believe that imbalances

tend to result from carelessness or intentional conduct rather than unavoidable

uncertainties and error. Utah Municipals contend that, while technology that permits

perfectly accurate scheduling (i.e.

, namely the AGC equipment used by control area

operators) is theoretically available, it is prohibitively expensive for many transmission

customers and unavailable to those who do not own generation. Utah Municipals argue

that financial incentives for accurate scheduling do not alter scheduling behavior or actual

imbalances, but only result in a potential windfall for the transmission provider and a

potentially significant competitive advantage for the transmission provider’s market

function, which (because of the AGC equipment that all transmission customers pay for

through rates) will not be subject to the charges. Utah Municipals suggest that the

Commission limit the imbalance charges for unintentional deviations by applying the

third deviation band only to intentional imbalances.

Docket Nos. RM05-17-000 and RM05-25-000 - 373 -

648. Imperial argues that the Bonneville approach would not provide appropriate

incentives for small geothermal generating units on its system to control their scheduled

output, especially if imbalances are recorded on an hourly basis rather than on a

cumulative basis over the course of a month. Under the Bonneville approach, Imperial

asserts that it would have to pay its generators 100 percent of its incremental cost for

overgeneration because such imbalances are usually less than 2 MW in any given hour.

It states that using a 100 percent credit for net overgeneration would result in crediting

the generator more than $28,500.

649. WECC states that it is very important to differentiate between the kind of behavior

that the Commission is worried about and appropriate practices that support system

reliability. WECC is concerned that inflexible generator imbalance provisions in the pro

forma OATT may create incentives for generators in the West to restrict governor action

on their generators in ways that degrade system reliability. WECC notes that the number

of rotating machines connected to the grid in the Eastern Interconnection is much greater

than in the Western Interconnection, which impacts the ability of generators to respond to

maintain frequency when a system’s load-resource balance changes. WECC explains

that a sudden change in load-resource balance of a particular magnitude (for example, the

loss of a 1,000 MW generating plant) will require a proportionately greater response from

each generating unit in the West as compared to the Eastern Interconnection. WECC

contends that in the West a significant frequency decline could cause responding

Docket Nos. RM05-17-000 and RM05-25-000 - 374 -

generators to exceed a 1.5 percent deviation threshold applied under current pro forma

Tariff imbalance schedules.

650. If the manner of implementing generator imbalance charges in the West does not

consider the need for generators to respond to frequency deviations, WECC worries that

these charges could produce perverse incentives that will undermine reliability. WECC

argues that generators that use set-point controllers to override governor action will be

less likely to incur imbalance charges and penalties, while those with properly operating

governors may be punished for deviating from scheduled output to respond to system

reliability needs. WECC believes that this has in fact been happening in the West and is

one of the reasons that frequency response in the Western Interconnection has

deteriorated in recent years. WECC urges the Commission to consider how generators

can be given appropriate incentives to meet their obligations to supply energy to load but

also to support system reliability by effectively responding to frequency deviations.

WECC explains that the Commission could adopt a policy that set-point controllers

should not be allowed to override governor response. WECC suggests that deviations

from scheduled generator output needed to correct frequency decay could be excused

from imbalance penalties under the pro forma

OATT.

651. Indianapolis Power contends on reply that variation should be allowed to account

for the individual facts and circumstances associated with a specific region as well as

specific types of intermittent resources. A number of entities agree with providing

Docket Nos. RM05-17-000 and RM05-25-000 - 375 -

flexibility to intermittent generators, but suggest different ways of doing so.

392

Fertilizer

Institute agrees that intermittent resources should be exempt from any penalties beyond

the 90 percent/110 percent “second tier.” However, Fertilizer Institute also believes that

intermittent resources should receive greater tolerance before they run into the

90 percent /110 percent penalty level in the first place. Fertilizer Institute urges the

Commission to relax the first-tier tolerance band from 2MW to 20MW (or 40 percent of

nameplate capacity, whichever is greater) for intermittent generators only. It asserts that

this action is consistent with the Commission's recognition that intermittent generators

can undergo sudden changes of conditions for which they cannot fairly be held

responsible. Fertilizer Institute argues that a broader first-tier tolerance band for these

generators will present no threat to the transmission grid, because intermittent generation

facilities are limited both in size and in number.

652. Geothermal Producers supports a first-tier deviation band of +/- 5 percent for

intermittent resources, rather than the 1.5 percent threshold proposed by Bonneville.

Geothermal Producers believes a 5 percent band is appropriate for intermittent resources,

since a five percent band more accurately recognizes that intermittent resources are less

capable of controlling deviations from schedules than are conventional resources. For

over- or under-deliveries in excess of five percent, Geothermal Producers contends that

intermittent resources should be charged no more than the control area’s cost of

392

E.g., NorthWestern, Fertilizer Institute, and Geothermal Producers.

Docket Nos. RM05-17-000 and RM05-25-000 - 376 -

supplying energy to correct the imbalance. Geothermal Producers also supports

Bonneville’s position that intermittent resources should be exempt from the third-tier

deviation band and instead should pay the second-tier deviation band charges for all

deviations greater than the second-tier deviation band.

653. Other commenters, however, do not support providing exceptions for intermittent

resources.

393

If society decides to provide incentives for intermittent resources, Morgan

Stanley states that this is better done in a direct fashion, such as a certification program

akin to resource adequacy rules that require LSEs to source a proportion of supply from

such resources. Morgan Stanley asserts that this would motivate developers to mitigate

imbalance costs through other market or technical means to the full extent of the

economic signal imbedded in the imbalance price and thereby optimize the design and

operation of such resources. MidAmerican argues on reply that special treatment of

intermittent resources and loads has the effect of penalizing those resources and loads

that have made investments to manage scheduling and enhance reliability. TDU Systems

believe that the NOPR’s third principle, which requires transmission providers to accord

special treatment to intermittent generators, is contrary to the principle of comparability.

654. Northwest IOUs argue that the transmission provider should have the option to

elect whether to exempt intermittent resources from the third-tier deviation band and

393

E.g., Morgan Stanley, Northwest IOUs, Steel Manufacturers Association, and

TDU Systems.

Docket Nos. RM05-17-000 and RM05-25-000 - 377 -

instead charge, in a not unduly discriminatory or preferential manner, the second-tier

deviation band charge for all deviations greater than the larger of 1.5 percent or 2

megawatts.

655. Several commenters suggested that the Commission include a definition of

intermittent resource in the final rule. Fertilizer Institute and South Carolina E&G

contend that it is essential for the Commission to provide a clear definition of

“intermittent generation” or “intermittent resource” to avoid disputes. Fertilizer Institute

argues that the question of whether a given generator is “intermittent” - and thereby

entitled to the special provisions - is likely to become a source of contention. Fertilizer

Institute suggests that an intermittent resource be defined as “an electric generator that

(1) cannot store its fuel sources and (2) has limited capability to be dispatched and to

respond to changes in system demand and transmission security constraints.” EEI,

however, suggests that the definition apply only to weather-driven units. Fertilizer

Institute argues on reply that restricting the definition in this way would be unduly

discriminatory. Fertilizer Institute argues that the definition should include the most

common forms of intermittent generation - wind and solar power - as well as the less

common but equally valuable forms, such as generation with ocean energy or "waste

heat" from an industrial process. Fertilizer Institute asserts that the Commission should

not broaden the definition of intermittent resource to encompass generators who are not

truly “intermittent” and should not narrow the definition to exclude some intermittent

generators in favor of others. Fertilizer Institute contends on reply that a generator should

Docket Nos. RM05-17-000 and RM05-25-000 - 378 -

not have to be “weather-driven” to qualify as “intermittent.” Geothermal Producers

supports the inclusion of geothermal energy as an intermittent resource. Geothermal

Resources contends that geothermal resources satisfy both the Commission's proposed

definition and the EEI proposal.

656. Ameren and Entergy ask the Commission to clarify that it does not intend to

amend any existing interconnection agreements to require the use of any pro forma

imbalance penalties. Entergy believes that the present form of its Generation

Interconnection Agreement is absolutely critical to managing imbalances on its system

and maintaining reliability. Entergy states that it has developed specialized software to

monitor and manage generator imbalances and employs six system operators (one per

shift) to monitor and manage generator imbalances.

657. Although Entergy supports the “grandfathering” of existing generator imbalance

arrangements, it does not believe that it would be appropriate to require the prospective

use of a different methodology while simultaneously maintaining the grandfathered

arrangements. Entergy contends that administering two different generator imbalance

arrangements would not be consistent with the comparability principles of Order No. 888

and would be difficult and costly from an operational perspective.

658.

Several commenters

394

argue on reply that it would be inappropriate for the

Commission to grandfather existing imbalance provisions. In its reply comments, Entegra

394

E.g., Fertilizer Institute, Entegra, and TAPS.

Docket Nos. RM05-17-000 and RM05-25-000 - 379 -

argues that prior arrangements should remain in place only if a transmission provider can

demonstrate that its existing imbalance arrangements are consistent with or superior to

the provisions of the pro forma

OATT as modified by the Final Rule in this proceeding.

659. EEI and Exelon contend that the transmission provider may not be able to charge a

generator under its OATT if the generator is not the transmission customer and, therefore,

generators should be able to include standardized imbalance terms in agreements with

eligible customers prior to providing service. Exelon suggests that the Commission both

adopt in the pro forma

OATT a standard imbalance penalty structure and direct

transmission providers to include the same terms and conditions in their interconnection

agreements with generators. TAPS suggests on reply that each generator could simply

be required to sign a service agreement that requires it to comply with the generator

imbalance provisions of the transmission provider’s OATT.

Unless the pro forma

OATT governs both generator and load imbalances, TAPS argues that it would be

impossible to implement and enforce the Commission’s prohibition against charging both

energy and generator imbalances for a single transaction.

660. ICNU argues on reply that the Commission should adopt less restrictive imbalance

charges for retail access customers or, at a minimum, continue to recognize that the

standard energy imbalance charge needs to be modified to accommodate direct access

customers. ICNU asks the Commission to modify its proposed imbalance provision to

reflect the unique characteristics of direct access customers by adopting wider imbalance

bandwidths and/or waiving the more punitive adders associated with higher deviations.

Docket Nos. RM05-17-000 and RM05-25-000 - 380 -

661. Several entities assert that the proposed imbalance reform should not apply to

RTOs. Exelon requests that the Commission explicitly state that these rules do not apply

in regions that have organized markets, such as PJM, that obviate the need for imbalance

penalties. They contend that within organized markets, an imbalance penalty rule is not

necessary, as the independent transmission operators have effectively addressed the

concerns that the proposed imbalance schedules are intended to address. Indicated New

York Transmission Owners contend that the Commission should grant the NYISO a

regional variation from the revised pro forma

OATT with respect to imbalance charges.

It contends that the existing mechanisms in ISO/RTO markets with LMP are consistent

with the Commission's objectives in its NOPR and that the Commission should permit a

regional variation to the NYISO. SPP states that the Commission should state that it does

not intend to affect its effort to implement a real-time energy imbalance market by any

final rule. SPP further contends that the Commission should clarify that its energy

imbalance changes do not apply to ISOs and RTOs with organized markets providing for

real-time energy imbalance markets. SPP believes that the Commission should view the

existence of a spot energy price in organized markets as superior to penalties based on

incremental costs or some multiple thereof.

662. Entegra suggests that, since many RTOs have (or are developing) separate markets

for commitment costs, it may not be necessary to incorporate such costs into imbalance

prices in certain RTO markets. Organizations of MISO and PJM States contend that this

proposed change to Schedule 4 is not applicable in the RTO context and argue that, to the

Docket Nos. RM05-17-000 and RM05-25-000 - 381 -

extent that the Commission’s suggestions regarding the special circumstances presented

by intermittent generators are applicable to RTOs, those issues are best addressed in a

context other than the instant rulemaking proceeding.

Commission Determination

663. In order to increase consistency among transmission providers in the application

of imbalance charges, and to ensure that the level of the charges provides appropriate

incentives to keep schedules accurate without being excessive, the Commission adopts in

the pro forma

OATT imbalance provisions similar to those implemented by Bonneville.

We agree with commenters that a graduated bandwidth approach recognizes the link

between escalating deviations and potential reliability impacts on the system.

Furthermore, we conclude that these provisions adhere to the three principles discussed in

the NOPR, which we also adopt here: (1) the charges must be based on incremental cost

or some multiple thereof; (2) the charges must provide an incentive for accurate

scheduling, such as by increasing the percentage of the adder above (and below)

incremental cost as the deviations become larger; and (3) the provisions must account for

the special circumstances presented by intermittent generators and their limited ability to

precisely forecast or control generation levels, such as waiving the more punitive adders

associated with higher deviations.

664. Specifically, imbalances of less than or equal to 1.5 percent of the scheduled

energy (or two megawatts, whichever is larger) will be netted on a monthly basis and

settled financially at 100 percent of incremental or decremental cost at the end of each

Docket Nos. RM05-17-000 and RM05-25-000 - 382 -

month. Imbalances between 1.5 and 7.5 percent of the scheduled amounts (or two to ten

megawatts, whichever is larger) will be settled financially at 90 percent of the

transmission provider’s system decremental cost for overscheduling imbalances that

require the transmission provider to decrease generation or 110 percent of the incremental

cost for underscheduling imbalances that require increased generation in the control area.

Imbalances greater than 7.5 percent of the scheduled amounts (or 10 megawatts,

whichever is larger) will be settled at 75 percent of the system decremental cost for

overscheduling imbalances or 125 percent of the incremental cost for underscheduling

imbalances.

665. The Commission adopts Bonneville’s tariff provisions that provide that

intermittent resources are exempt from the third-tier deviation band and would pay the

second-tier deviation band charges for all deviations greater than the larger of 1.5 percent

or two megawatts. We believe this is consistent with the fact that intermittent generators

cannot always accurately follow their schedules and that high penalties will not lessen the

incentive to deviate from their schedules.

666. Several commenters argue that the Commission should adopt a standard definition

of intermittent resource. In order to clarify application of imbalance charges, we define

an intermittent resource for this limited purpose as “an electric generator that is not

dispatchable and cannot store its fuel source and therefore cannot respond to changes in

Docket Nos. RM05-17-000 and RM05-25-000 - 383 -

system demand or respond to transmission security constraints.”

395

We conclude that this

definition of intermittent resource properly limits the exemption from imbalance charges,

without excluding certain classes of intermittent generators for which the exemption is

appropriate (e.g.

, non-weather driven intermittent resources).

667. The Commission believes that adopting a tiered approach for both energy and

generation imbalances will best balance the needs of transmission providers to operate

their transmission systems in a reliable manner with the needs of transmission customers

to have reasonable access to those systems at just and reasonable rates. Furthermore, we

conclude that the partial exemption from imbalance charges for intermittent resources

appropriately reflects the special circumstances faced by such resources and,

consequently, is not unduly discriminatory. Moreover, formalizing generator imbalance

provisions in the pro forma

OATT will standardize the future treatment of such

imbalances from the wide variety of generator imbalance provisions that exist today in

various generator interconnection agreements. Standardizing generator imbalances

should lessen the potential for undue discrimination, increase transparency and reduce

confusion in the industry that results from the current plethora of different approaches.

395

See Docket No. RM05-10-000. We note that this definition was proposed by

the Commission in the NOPR on Imbalance Provisions for Intermittent Resources. See

Imbalance Provisions for Intermittent Resources; Assessing the State of Wind Energy in

Wholesale Electricity Markets, Notice of Proposed Rulemaking, 70 FR 21349 (Apr. 26,

2005), FERC Stats. & Regs. ¶ 32,581 (2005).

Docket Nos. RM05-17-000 and RM05-25-000 - 384 -

668. Several commenters debate whether the imbalance provisions adopted here should

be applied to energy imbalances, generation imbalances, or both. The Commission

concludes that subjecting both energy and generation imbalances to the same charges is

appropriate. Energy and generation imbalances have the same net effects on the

transmission system in requiring other generation to be ramped up or down to make up

for the imbalance. As such, the Commission will modify the current pro forma

OATT

Schedule 4 treatment of energy imbalances and adopt a new separate pro forma

OATT

Schedule 9 for the treatment of generator imbalances, each based on the tiered structure

described above. To the extent a transmission provider wishes to deviate from these

revised pro forma

provisions, it may demonstrate in an FPA section 205 proceeding that

the proposed changes are consistent with or superior to the pro forma

OATT as modified

by this Final Rule. However, we note that proposed alternative provisions must comply

with the three imbalance charge principles addressed in the NOPR and adopted in this

Final Rule and be consistent with or superior to the specific imbalance charges set forth

in the pro forma

OATT (and discussed above).

669. Some commenters stated that the Commission should require transmission

providers to establish, or permit market participants to establish, markets or pools for the

netting and settlement of imbalances. As explained previously, the purpose of this rule is

to strengthen the pro forma

OATT to remedy undue discrimination and not to impose any

particular market structure. If transmission providers offer to modify their OATTs to

allow such pools, we will consider such proposals. But, imposing such requirements

Docket Nos. RM05-17-000 and RM05-25-000 - 385 -

goes beyond the scope of this proceeding. The Commission therefore declines, for all

these reasons, to impose the structural reforms requested by some commenters.

670. The Commission instead adopts the three-tiered approach in the pro forma

OATT.

As with other reforms adopted in this Final Rule, all transmission providers must submit

compliance filings containing these pro forma

tariff provisions. Transmission providers

with previously-approved tariff provisions governing imbalances that no longer conform

to the pro forma

OATT, as revised in this Final Rule, may seek renewed approval of

those tariff deviations in accordance with the procedures described in section IV.C above,

demonstrating that the alternative imbalance charge structures are consistent with or

superior to the reformed pro forma

OATT. With respect to the concerns raised by ISOs

and RTOs, we agree that LMP-based markets can provide an efficient and

nondiscriminatory means of settling imbalances and, as indicated in the NOPR, we are

not proposing to redesign ISO/RTO markets in this rulemaking. Nevertheless, ISOs and

RTOs must follow the procedures described in the Applicability section for seeking

approval of deviations that are consistent with or superior to the pro forma

OATT.

671. We do not, however, abrogate existing generator imbalance agreements between

transmission providers and their customers. These agreements have been negotiated

between willing parties, and the Commission will not re-open them generically in this

proceeding. To the extent a particular party desires to amend an existing generator

imbalance agreement in light of the reforms we adopt in this Final Rule, that party may

exercise whatever rights it may have under the agreement or FPA section 206.

Docket Nos. RM05-17-000 and RM05-25-000 - 386 -

672. With regard to WECC’s frequency-response concerns, we agree that a generator

should be excused from imbalance penalties that occur due to directed reliability actions

by generators to correct frequency. It would not be appropriate to assess imbalance

charges on generator deviations that are associated with supporting system reliability by

responding to frequency deviations as directed by the transmission provider or general

reliability requirements. As such, if a response from a generator (particularly in the West)

is required to prevent frequency decay and the corresponding deviations from the

generator’s schedule would cause additional imbalance penalties, the transmission

provider should exempt the generator from those penalty charges.

b. Intentional Deviations

NOPR Proposal

673. In the NOPR, the Commission noted that the Bonneville imbalance provision

allows for greater charges when a customer has an “intentional deviation.”

396

The

396

See 2006 Transmission and Ancillary Service Rate Schedules, approved in

United States Dep’t of Energy – Bonneville Power Administration

, 112 FERC ¶ 62,258

(2005). The Bonneville tariff provides that “For any hour(s) that an imbalance is

determined by [Bonneville] to be an Intentional Deviation: (1) No credit is given when

energy taken is less than the scheduled energy, (2) When energy taken exceeds the

scheduled energy, the charge is the greater of: i) 125% of [Bonneville’s] highest

incremental cost that occurs during that day, or ii) 100 mills per kilowatthour.” An

“Intentional Deviation” is defined as “a deviation that is persistent during multiple

consecutive hours or at specific times of the day,” a “pattern of under-delivery or over-

use of energy,” or “persistent over-generation or under-use during Light Load Hours,

particularly when the customer does not respond by adjusting schedules for future days to

correct these patterns.” Id.

at 46.

Docket Nos. RM05-17-000 and RM05-25-000 - 387 -

Commission sought comment on whether the pro forma

OATT imbalance provision

should provide for similar penalties for behavior that represents deliberate reliance on the

transmission provider’s generation resources, as opposed to scheduling errors, with such

penalties being subject to prior notice and approval by the Commission and based on the

facts and circumstances of the individual transmission provider.

Comments

674. Several entities contend that higher imbalance charges and penalties for

deliberately leaning on the grid can be appropriate.

397

Imperial supports an imbalance

provision that allows for greater charges for persistent or patterned deviations. Pinnacle

agrees that deliberate reliance on the transmission provider’s generation resources is

inappropriate and could adversely affect the reliability of the transmission system, but

they are unsure if such an intentional deviation could be proven. Imperial also expresses

concern that the burden to prove the intent of the generator will fall on transmission

providers and that, in reality, transmission providers may face an uphill battle to prove a

generator’s deviation was intended. South Carolina E&G and Imperial request that the

Commission provide a specific process for imposing such penalties, including what

procedures should be followed if a transmission provider seeks to have the Commission

impose such penalties.

397

E.g., Imperial District Irrigation, Progress Energy and Ameren.

Docket Nos. RM05-17-000 and RM05-25-000 - 388 -

675. Several entities oppose penalties for intentional deviations or suggest

modifications. Constellation supports an elimination of the separate penalty structure for

customers deliberately leaning on the system. Constellation and Grant believe that a

graduated percentage adder/discount will provide the right incentives and disincentives

without the need for an intentional deviation provision. If deviation costs are properly

calculated, Morgan Stanley contends that requiring those who deviate to pay the full

marginal cost of that deviation would result in fair allocation of cost responsibility and

sufficient stability of system operations as a result of both cost and risk avoidance by

participants. TDU Systems argue that the Commission should eliminate the 100 mill per

kWh floor for penalties for intentional deviations.

Commission Determination

676. The Commission recognizes the need to provide transmission customers with the

appropriate incentives not to intentionally dump power on the system or lean on other

generation. We do not believe, however, that separate penalties for intentional deviations

need to be generically imposed in the pro forma

OATT. The tiered imbalance penalties

adopted in this Final Rule generally provide a sufficient incentive not to engage in such

behavior. Proposals to assess additional penalties for intentional deviations will continue

to be considered on a case-by-case basis, subject to a showing that they are necessary

under the circumstances. We note that any such tariff provisions must include clearly

defined processes for identifying intentional deviations and the associated penalties.

Docket Nos. RM05-17-000 and RM05-25-000 - 389 -

c. Calculation of Incremental Cost

NOPR Proposal

677. With respect to the pricing of energy and generation imbalances, the Commission

stated in the NOPR its belief that charges based on incremental costs or multiples of

incremental costs would provide the proper incentive to keep schedules accurate without

being excessive. The Commission proposed that incremental cost be defined to include

both energy and commitment

398

costs, to the extent additional commitments are

needed.

399

The Commission sought comment on how such charges should be calculated,

as well as how they would be applied to transmission customers. The Commission

sought further comment as to how additional demand and energy costs, if incurred in

responding to imbalances, such as redispatch, commitment, or additional regulation

reserves, should be appropriately reflected in the calculation of imbalance charges and

which customers should be charged for such costs.

398

The Commission noted that "capacity commitment" is generally defined as the

generating capacity committed by a utility to provide capability for another utility to

attain its reserve level. See, e.g.

, Central & South West Services, Inc., 48 FERC ¶ 61,197

at 61,731 n.9 (1989).

399

The Commission proposed defining incremental cost, based on its decision in

Consumers

, as the transmission provider’s actual average hourly cost of the last 10 MW

dispatched to supply the transmission provider’s native load, based on the replacement

cost of fuel, unit heat rates, start-up costs, incremental operation and maintenance costs,

and purchased and interchange power costs and taxes.

Docket Nos. RM05-17-000 and RM05-25-000 - 390 -

Comments

678. Several entities argue that incremental pricing for both energy imbalances and

generator imbalances should reflect the full incremental costs incurred by the

transmission provider (e.g.

, such as redispatch costs, capacity commitment costs or

additional regulation reserve costs) resulting from the imbalance.

400

Allegheny questions

whether the Consumer

’s definition is appropriate because “the last 10 MW” requirement

is independent of the time of the scheduling deviation. Allegheny contends that the

definition should be modified such that it specifically addresses the incremental dispatch

to supply the transmission provider’s load “in the hour in which the imbalance occurs.”

679. Entergy argues that imbalance pricing on an hourly basis does not capture all of

the costs and reliability risk to the transmission provider of over- and under-deliveries.

Entergy states that the real-time regulation burden imposed by IPPs is similar to the real-

time regulation burden imposed by loads, and loads are charged for this cost through a

transmission provider’s Schedule 3 Regulation and Frequency Response Service.

Entergy asserts that the NOPR does not propose any recovery mechanism for the

regulation burden imposed by IPPs, recognizing that Bonneville may not face significant

generator regulation costs due to the rapid ramping rate and relatively low cost of

hydroelectric resources. Entergy submits that its regional experience has demonstrated

400

E.g., Allegheny, Ameren, Indicated New York Transmission Owners, and

FirstEnergy.

Docket Nos. RM05-17-000 and RM05-25-000 - 391 -

that generator regulation service is a necessity. Entergy states that its generator

regulation service recovers charges for the generating capacity that Entergy must

maintain on-line in order to respond to the moment-to-moment deviations between

scheduled output and actual generation. Entergy explains that the charge compensates

Entergy on a cost-basis for the generation capacity used by IPPs, while at the same time

sending the appropriate economic signal that encourages generators to match their

generation with their schedules.

680. In its reply comments, EEI argues that a transmission provider should be entitled

to recover the cost of additional reserves needed to meet the increased reliability

requirements resulting from the provision of the imbalance energy if the transmission

provider generates additional energy to compensate for a load that schedules less energy

than it takes or a generator that produces less energy than it schedules. EEI further

contends that transmission providers should be permitted to include in their calculation of

imbalance charges any other costs associated with committing a unit that is not on-line

such as minimum run times, losses, etc

681. Entergy opposes a single price for settling over-deliveries and under-deliveries.

For transmission providers who choose to base energy and generator imbalance charges

on incremental and decremental costs, Entergy requests that the Commission not adopt

standardized definitions of incremental cost and decremental cost in the pro forma

OATT. In its reply comments, Entergy further argues that a requirement that the

transmission provider post incremental and decremental cost information is unfair and

Docket Nos. RM05-17-000 and RM05-25-000 - 392 -

harmful to the market, placing the transmission provider at an unfair competitive

disadvantage in the market.

Duke on reply proposes that System Incremental Cost (SIC) be

used to price both over-deliveries and under-deliveries. Duke defines SIC to mean the

incremental expense, measured in dollars per megawatt hour, incurred by the utility to

produce or procure the next megawatt hour (MWh) of energy, after serving all of the utility’s

electric energy and/or capacity sales. Duke proposes that SIC shall include but not be limited

to: the replacement cost of fuel; incremental operating and maintenance costs; emissions

allowance replacement costs and other environmental compliance costs; the cost of starting

and operating any generating units, (including costs incurred due to minimum runtimes or

loading levels); purchase and interchange power costs; and all applicable taxes or

assessments based on the revenues received or quantities sold.

682. Allegheny states that the Commission should clarify that the definition of

incremental cost is equally applicable to intermittent generator imbalance service as well

as non-intermittent generator imbalance service.

683. Pinnacle and Utah Municipals request that the Commission allow the use of

alternative pricing methodologies, such as market proxy pricing methodology based on

trading hubs in or adjacent to their respective control areas, where appropriate. Utah

Municipals urge the Commission to make clear in the final rule that market-based pricing

may be acceptable in some circumstances and to amend Schedule 4 of the pro forma

OATT to ensure that imbalance charges are designed not only to provide legitimate

incentives for accurate scheduling, but also to avoid unjustified penalties (masquerading

Docket Nos. RM05-17-000 and RM05-25-000 - 393 -

as “incentives”), to minimize the discriminatory impact of such charges, and to avoid

penalizing behavior or results that in fact help to keep the system as a whole in balance.

684. TDU Systems believe the Commission should disallow recovery of demand

charges or capacity commitment costs in any charges approved for imbalances. TAPS

and TDU Systems argue that capacity required to follow load is already paid for by

charges for regulation and reserves under Schedules 3, 5 and 6. TDU Systems also

support that the Commission continue to apply its existing policy of imposing a heavy

burden on transmission providers to justify such demand or capacity commitment charges

in the context of a full base rate case, and of requiring transmission providers to develop

alternative solutions for balancing schedules and loads.

685. To the extent transmission providers are permitted to include commitment costs in

negative imbalance charges, Entegra believes that additional monitoring would be

needed, to include posting of hourly imbalance charges, even if with a lag of a day or so.

Suez Energy NA contends that the Commission should require a transmission owner to

support its incremental cost filing on the basis of Form No. 423 data and actual

operations of the selected units, based on operational data as reported in utilities

Continuous Emission Monitoring reports.

686. EEI argues that since Schedule 3, 5 and 6 charges recover the costs of capacity

based on test year data, they would not recover the additional

costs of reserves that

transmission providers incur to compensate for their customers’ failures to match their

schedules and their loads or generator output, and they also do not recover other

Docket Nos. RM05-17-000 and RM05-25-000 - 394 -

commitment costs such as start-up costs or minimum run times. EEI argues that if

transmission providers could not recover such costs through imbalance charges, they

would not be able to recover them at all.

Commission Determination

687. The Commission concludes that it is appropriate to define incremental cost, for

purposes of the tiered imbalance provisions adopted above, as the transmission provider’s

actual average hourly cost of the last 10 MW dispatched to supply the transmission

provider’s native load, based on the replacement cost of fuel, unit heat rates, start-up

costs, incremental operation and maintenance costs, and purchased and interchange

power costs and taxes, as applicable.

688. In deriving such charges, we note that the Commission proposed in paragraph 244

of the NOPR that incremental cost be defined to include both additional energy and

commitment costs. The Commission also sought comment on how additional demand

and energy costs, such as redispatch, commitment, or additional regulation reserves,

would be appropriately recovered if incurred in responding to imbalances.

689. The Commission finds that it is appropriate, through the definition of incremental

cost, to allow for recovery of both commitment and redispatch costs while excluding the

cost recovery of additional regulation reserve costs. Commitment and redispatch costs

shall be accommodated as a part of the hourly cost of the last 10 MW dispatch and in the

start up cost portion of the definition. The Commission concludes that excluding

additional regulation costs as a general matter is appropriate since much of those costs

Docket Nos. RM05-17-000 and RM05-25-000 - 395 -

would be demand costs.

401

We believe including charges for unit commitment costs (e.g.,

start-up and minimum load costs) and O&M costs is necessary to ensure that both energy

and generation imbalance charges reflect the full incremental costs incurred by the

transmission provider. We emphasize, however, that such costs should only be the

additional costs incurred by the transmission provider due to the imbalance. If

applicable, start-up costs should be allocated pro rata

to the offending transmission

customers based on cost causation principles.

690. If the transmission provider elects to have separate demand charges assigned to

customers for the purpose of recovering the cost of holding additional reserves for

meeting imbalances, the transmission provider should file a rate schedule and

demonstrate that these charges do not allow for double recovery of such costs. To

address Entergy’s concern that the real-time regulation burden imposed by IPPs is similar

to the real-time regulation burden imposed by loads, we will allow transmission providers

to propose separate regulation charges for generation resources selling out of the control

area and consider such proposals on a case-by-case basis. We believe that the other

demand costs of providing imbalance service are already being provided under Schedule

3, 5, and 6 charges.

401

To the extent a transmission provider wishes to recover costs of additional

regulation reserves associated with providing imbalance service, it must do so via a

separate FPA section 205 filing demonstrating that these costs were incurred correcting

or accommodating a particular entity’s imbalances.

Docket Nos. RM05-17-000 and RM05-25-000 - 396 -

691. In responding to Allegheny’s comments, we clarify that the definition of

incremental cost is equally applicable to intermittent generator imbalance service as well

as non-intermittent generator imbalance service.

692. We do not believe it appropriate to require transmission providers to use market

proxy pricing to calculate incremental costs in the pro forma

OATT. The feasibility of

using market proxies must be considered on a case-by-case basis, given the

characteristics of each market. If proposed, the proxy price must represent a valid

alternative to the incremental cost calculation, reflecting competitive, transparent and

liquid conditions similar to those that would exist in the seller’s market.

402

d. Inadvertent Energy Treatment

NOPR Proposal

693. The Commission proposed in the NOPR to continue to allow inadvertent energy to

be treated differently from energy and generator imbalances, explaining that these two

types of service are not comparable. The Commission noted that, given the nature of

inadvertent energy and historical practices, transmission providers pay back inadvertent

energy imbalances and that the Commission has accepted this practice as just and

reasonable. The Commission sought comment on whether the current return-in-kind

approach to inadvertent energy encourages leaning on the grid in times of shortage and,

402

See RockGen Energy, LLC, 100 FERC ¶ 61,261 (2002) (setting for hearing,

inter alia

, whether proposed market proxy price is reliable, verifiable, and also indicative

of the prevailing price in liquid non-redispatch markets in the region).

Docket Nos. RM05-17-000 and RM05-25-000 - 397 -

therefore, whether any reforms in this area are appropriate. The Commission asked

whether pricing inadvertent energy at incremental cost (or some variant thereof) would be

an appropriate disincentive and, if any reforms in this area are appropriate, whether they

should be pursued under FPA section 215 as part of the review of reliability standards.

Comments

694. A number of commenters support continuing to allow inadvertent energy to be

treated differently from energy and generator imbalances, agreeing that these two types

of services are not comparable.

403

Allegheny argues that this historical practice makes

sense because the variables germane to inadvertent interchange are beyond the control of

individual transmission providers and, therefore, are best addressed in the context of

reliability. Entergy notes that transmission customers have some flexibility to mitigate the

deviations between their schedules and the operation of their load in real-time, while

control area interchange imbalances may involve the failure of control areas to match

their scheduled inflows and outflows due to contingencies occurring even in a third

control area.

695. Northwest IOUs argue that there is no reason to think that there is abuse of one

system leaning on another in regards to inadvertent energy, particularly in light of

Control Performance Standards 1 and 2 and other protocols for balancing flows across

403

E.g., Entergy, Allegheny, Progress Energy, Public Power Council, South

Carolina E&G, PGP, and Ameren.

Docket Nos. RM05-17-000 and RM05-25-000 - 398 -

interconnections. Public Power Council states that in-kind return of inadvertent energy

between Balancing Authorities is governed by numerous agreements and tariffs that are

designed to limit the ability of one system to lean on another.

696. Sacramento states that the Commission expressed concern in other settings that

generators may intentionally undergenerate during high-cost hours and make it up by

overgenerating during low-cost hours under a return-in-kind approach. Sacramento

contends that in kind means not only a return of energy, but a return of energy at like

times and conditions and does not believe that this results in leaning. In its reply

comments, Exelon requests that the Commission’s imbalance penalty rules explicitly

prohibit the local utility Balancing Authority operator from relying on inadvertent energy

to balance its affiliated generators’ schedules and thus obtaining a competitive advantage.

697. Other commenters disagree that inadvertent energy should continue to be treated

differently. Exelon expresses concern that in regions without organized markets there is

the potential for local utility balancing authority operators to seek to avoid paying

deviation charges by favoring their own generators over merchant generators or by using

inadvertent energy to balance their schedule. Exelon argues that a balancing authority

operator could maintain system balance by choosing to order its affiliated generators to

deviate from the schedule and thereby allow its affiliated generator to avoid deviation

charges that the merchant generator could not avoid. If the local utility balancing

authority operator relies on inadvertent energy to balance its affiliated generators’

Docket Nos. RM05-17-000 and RM05-25-000 - 399 -

schedules, Exelon contends it is using an option that is unavailable to other generation

resources and obtains a competitive advantage.

698. TDU Systems argue that energy imbalances and inadvertent interchange may

occur for many of the same reasons, e.g.

, telemetry failure, meter error, generator

governor response to system problems, human error, and under- or over-supply of

generation. TDU Systems state that deviations between load and supply, whether in the

form of energy imbalances or inadvertent interchange, require adjustment or

compensation, but there is no reason why the form of that adjustment or compensation

should be different among transmission users. TDU systems explain that NERC’s Final

Report of the Control Area Criteria Task Force describes inadvertent interchange as one

of the “strong incentives” driving the newer market participants, such as independent

generators, to become control areas, and driving existing control area operators to retain

their functions.

699. TDU Systems explain that as the Commission acknowledged in Order No. 2000,

for transmission providers in RTO regions, unequal access to balancing options can lead

to unequal access in the quality of transmission service. TDU Systems oppose deferring

consideration of inadvertent interchange issues until the Commission’s order in the

Mandatory Reliability Standards rulemaking proceeding in Docket No. RM06-16-000.

TDU Systems argue that the Commission should place energy imbalance service on a

footing as nearly comparable to inadvertent interchange as feasible by allowing like-kind

Docket Nos. RM05-17-000 and RM05-25-000 - 400 -

exchanges of energy, at the incremental cost of their own supply portfolio, to remedy

imbalances in lieu of the present paradigm of punitive charges.

700. TDU Systems also argue that the Commission should require comparability

between transmission providers and transmission customers by imposing charges for

inadvertent interchange at the suppliers’ incremental cost. FirstEnergy believes that the

Commission should establish a tiered penalty structure that, similar to the Bonneville

method discussed by the Commission, levies penalties based on the severity of the

inadvertent energy violation. TDU Systems state that currently there are no penalties for

under-supply even when one control area could be deemed to be intentionally “leaning”

on the grid to arbitrage energy market prices; but there should be.

701. FirstEnergy argues that a nationwide process should be established by the

Commission to eliminate regional differences in the treatment of inadvertent energy.

Constellation asks the Commission to require that transmission providers specifically

separate imbalances from inadvertent energy and closely track and report the two.

Commission Determination

702. As stated in the NOPR, the Commission finds that inadvertent energy is not

comparable to energy and generation imbalances and, therefore, we will continue to

allow inadvertent energy to be treated differently from energy and generation imbalances.

Inadvertent energy represents the difference between a control area’s net actual

interchange and the net scheduled interchange. It is caused by the combined effects of all

the generation and loads in the control area and generation and loads outside of the

Docket Nos. RM05-17-000 and RM05-25-000 - 401 -

control area. Variables affecting inadvertent interchange often depend on the actions or

the omissions of utilities other than the individual transmission providers and are distinct

from those resulting in energy and generation imbalances.

703. We also note that management of inadvertent energy is needed to adhere to

NAESB standards. Historically, transmission providers have paid back inadvertent

interchange imbalances in kind, which has not, as a general matter, proven to be

problematic. Our primary concern with respect to inadvertent energy is to avoid

incentives that could degrade reliability. To date, the return-in-kind approach has proven

to be adequate as a general matter. However, if there is evidence that it is no longer

sufficient to maintain reliability, or is allowing certain entities to lean on the grid to the

detriment of other entities, the Commission has authority under FPA section 215 to direct

the ERO to develop a new or modified standard to address the matter.

e. Netting/Crediting of Energy and Generator Imbalances

NOPR Proposal

704. In the NOPR, the Commission sought comment on whether or not it is appropriate

to allow a transmission customer to net energy and generator imbalances for a particular

transaction within a single control area to the extent they offset.

404

The Commission

404

For example, the Commission noted that a transmission customer scheduling

100 MWh over an hour, but with a load of 120 MWh, would face an imbalance of 20

MW. The Commission questioned whether there should be a net charge if the customer

also dispatched its generation to the same 120 MWh. Similarly, what if a transmission

(continued)

Docket Nos. RM05-17-000 and RM05-25-000 - 402 -

asked whether the potential to allow netting for offsetting imbalances contradicts the

principle of encouraging good scheduling practices. The Commission sought further

comment on what would be a reasonable percentage to net without concerns that

allowing such netting would lead to reliability concerns from using unscheduled

transmission or would cause redispatch costs by the transmission provider.

705. The Commission also proposed to add provisions to schedule 4 – Energy

Imbalance Service and schedule 9 – Generator Imbalance Service of the pro forma

OATT

to reflect the Commission’s policy that a transmission provider may only charge a

transmission customer for either hourly generator imbalances or hourly energy

imbalances for the same imbalance, but not both.

405

The Commission explained that this

policy only applies to a transmission customer that otherwise would be charged for both

generator imbalances and energy imbalances for the same imbalance occurring within the

same control area.

customer schedules 100 MWh, but has a load of 80 MWh and dispatches its generation to

80 MWh?

405

Imbalance Provisions Proceeding at 32,123 note 19 (citing Niagara Mohawk,

86 FERC ¶ 61,009 at 61,028).

Docket Nos. RM05-17-000 and RM05-25-000 - 403 -

Comments

706. A number of entities believe that transmission customers should be permitted to

net energy and generator imbalances to the extent that such imbalances offset.

406

Ameren and FirstEnergy assert that netting better reflects the impact of imbalances.

Morgan Stanley argues that allowing such netting provides a clear competitive benefit

because it would allow competitive suppliers to offer a load following service in

competition with the transmission provider. Sacramento agrees that netting of offsetting

imbalances should be allowed provided the transmission customer relies on reasonable

load forecasts.

707. Utah Municipals and Steel Manufacturers Association argue that the Commission

should impose charges based on netted imbalances, both for each customer and across the

system as a whole. PGP contends that there is no reason to charge for both imbalances if

a generator overruns during the same hour when a load overruns, so long as the overruns

cancel out within a given control area. Steel Manufacturers Association contends that the

Commission should incorporate control area-wide netting of imbalances to ensure that

penalties are only assessed on significant imbalances and energy imbalance charges do

not become a windfall profit center for utilities. Utah Municipals suggest that the

Commission provide that all imbalances be netted for each hour and that penalties

406

E.g., Ameren, FirstEnergy, Xcel, Suez Energy NA, Morgan Stanley,

Sacramento, TDU Systems, and Utah Municipals.

Docket Nos. RM05-17-000 and RM05-25-000 - 404 -

(charges above or credits below actual costs) be imposed only when the system as a

whole is out of balance by more than a de

minimis amount and, even then, only on those

customers whose imbalances fall in the same direction as the system imbalance. Utah

Municipals note that Sierra Pacific has established a similar imbalance mechanism, which

appears to be working well in its control area.

708. TDU Systems argue that the netting rules should be sufficiently flexible to allow

individual customers to net their transactions within an hour, a day, a week or a month, so

long as the results keep the transmission provider economically whole. TDU Systems

state that the Commission should not impose a cap on the quantity of netting allowed

unless the transmission provider is able to demonstrate that good system performance

requires such a cap. Ameren suggests that the Commission use a tiered system for

determining when imbalances can be netted, but argues that a transmission customer

should not be allowed to net offsetting imbalances elsewhere on the system if the

imbalance has the potential to have a significant reliability impact.

709. FirstEnergy and Utah Municipals contend that both point-to-point and network

transactions should be eligible for netting. Utah Municipals and NRECA in their reply

comments note that the Commission’s reference to “a particular transaction” does not

mesh with the needs and practices of network customers, who do not attempt to match

portions of their total hourly loads with particular resources or “transactions.” Utah

Municipals argue that the Commission’s proposal should be modified to make clear that

such customers should be permitted to net energy and generator imbalances within a

Docket Nos. RM05-17-000 and RM05-25-000 - 405 -

single control area to the extent they offset, with no requirement that the imbalances be

part of a single “transaction.”

710. Other commenters, however, contend that transmission customers should not be

permitted to net energy and generator imbalances.

407

For example, Entergy and Pinnacle

believe that to permit netting of energy and generator imbalances is to undercut the very

purpose of the imbalance provisions, which is to provide adequate incentives to schedule

correctly and in accordance with good utility practice. Pinnacle asserts that, depending

upon the location, energy or generator imbalances could create reliability or economic

problems for specific areas of the system and it is important that the transmission

operator know what is happening on its system and for the customer to adhere to accurate

scheduling. SPP argues that allowing netting of imbalance energy between generation

and load would allow price arbitrage that would be unjust and unreasonable. Indicated

New York Transmission Owners assert that positive and negative imbalances do not

actually offset, as the NOPR would suggest, but rather each imbalance independently

places stress on the transmission system. Duke states on reply that, although several

commenters support netting imbalances, not one entity supporting such netting has put

forth a workable proposal for how to implement such netting where multiple generators

are serving multiple loads.

407

E.g., Entergy, Pinnacle, Indianapolis Power, and Indicated New York

Transmission Owners.

Docket Nos. RM05-17-000 and RM05-25-000 - 406 -

711. Entergy believes that independent generators must take full responsibility for

meeting their own schedules, including making adjustments to their schedules to conform

them to their operation in real-time. Entergy argues that a netting approach, however,

would provide an incentive for a generator to over-generate above its schedule if its load

proves to be greater than expected in real-time. Entergy argues that allowing the netting

of these imbalances will result in the virtual elimination of transmission schedules.

712. In instances in which transmission customers intentionally game the transmission

system through netting, FirstEnergy contends that the transmission provider should have

the ability to apply punitive measures through a Commission-mandated penalty process.

FirstEnergy states that there appears to be no clear cut number which defines the

boundary between “good” netting and “bad” netting associated with reliability issues and

additional redispatch cost. During periods when transmission constraints exist, Entergy

contends that it may in fact be ramping up some generators to respond to imbalances

while ramping down other generation to respond to other imbalances at exactly the same

time and, therefore, it is incorrect to assume that over-generation supplied by one IPP

accompanied by under-generation from another IPP, even simultaneously, will have no

operational effect or impose no costs on a transmission provider.

713. Allegheny believes that allowing netting of hourly deviations inside the first

deviation band on a monthly basis would not allow for full recovery of imbalance costs

because balances that occur in on-peak periods cost more than imbalances that occur

during off-peak periods. Allegheny contends that deviations within the first band should

Docket Nos. RM05-17-000 and RM05-25-000 - 407 -

be measured and settled financially on an hourly or, at least, an on-peak/off-peak basis,

rather than allowing deviations during one part of the month to be offset by deviations in

another part of the month. Indianapolis Power & Light Company argues that the

imbalance volume could be within the allowed bandwidth tolerance, but still be

significant enough to allow for the energy market participant to make money off of the

price difference.

714. Entergy also contends that a crediting mechanism for generator imbalances would

be not appropriate. Entergy asserts that such a credit would result in indifference by

generators by largely immunizing them from the costs resulting from their imbalances

and, as a consequence, produce economic inefficiencies and a potential threat to system

reliability. Entergy argues that the current method, which provides an incentive to

generators to control their own imbalances, is appropriate because generators have a

desire to accurately schedule to avoid imbalances. Entergy argues that a non-offending

generator in one hour can be an offending generator in the next hour and that the credit

will bankroll generators so that penalty payments in one hour will be offset and paid for

by penalty receipts in another hour.

Commission Determination

715. The Commission recognizes that there is a trade off between the competitive

benefits of reducing imbalance charges, including allowing transmission customers to net

energy and generation imbalances, and the reliability implications of the transmission

provider needing to plan to accommodate such imbalances. Allowing transmission

Docket Nos. RM05-17-000 and RM05-25-000 - 408 -

customers to net imbalances would further comparability between the transmission

provider’s dispatch and the transmission customers serving load. However, netting and

crediting could lessen the incentive for accurate scheduling and resulting energy or

generator imbalances could create reliability or economic issues for specific areas of the

system if the transmission provider cannot adequately plan for such imbalances.

716. In weighing these tradeoffs, the Commission concludes that for both energy and

generator imbalance services it is not appropriate to require transmission providers to

allow netting of imbalances outside of the tier one band. We agree that netting can cause

problems because netting would lessen the incentive for transmission customers to

schedule accurately, and inaccurate schedules, in turn, could require actions by the

transmission provider even when the imbalances offset. Where transmission constraints

exist, a transmission customer whose load and generation was on net equal could still

have an effect on the transmission system if, as Entergy contends, some generation is

ramping up to respond to some imbalances while other generation is ramping down at

exactly the same time. Similarly, where transmission constraints exist, if one IPP has a

positive deviation from its schedule while another IPP has a corresponding negative

deviation from its schedule, the transmission provider could need to ramp up generation

in one area while simultaneously ramping down generation in another area. Further, we

believe that flexible scheduling deadlines should allow transmission customers to change

their schedules such that their loads can be accurately met and implementation of the

Docket Nos. RM05-17-000 and RM05-25-000 - 409 -

tiered imbalance bands will ensure that charges corresponding to imbalances are just and

reasonable.

f. Intra Hour Netting

NOPR Proposal

717. Under the current pro forma

OATT, energy imbalances occur when there is a

difference between the scheduled and the actual delivery of energy to a load located

within a control area aggregated over a single hour. As a result, if a transmission

customer is under its scheduled level for the first half of a given hour, but over its

schedule the second half of the hour, there would be no imbalance charge. The

Commission did not address intra hour netting in the NOPR.

Comments

718. Several commenters argue that the Final Rule should address within-hour

deviations that occur when generator imbalances are calculated on an integrated hour

basis.

408

If the generator imbalance is measured over an integrated hour, as is typical of

the current practice, TVA asserts that significant intra-hour swings may be masked.

719. South Carolina E&G states that generators, unable to ramp precisely to the 15-

minute schedules, often undergenerate in the initial part of the hour, then overgenerate in

later parts of the hour, in order to integrate closer to the schedule when settled over the

entire hour. South Carolina E&G contends these intentional swings burden the balancing

408

E.g., TVA, South Carolina E&G, and International Transmission.

Docket Nos. RM05-17-000 and RM05-25-000 - 410 -

authorities who are charged with continuously keeping Area Control Error within

predefined limits. International Transmission argues that intentional swings in output can

be quite severe, imposing operational strains on the system, negatively impacting the

control area’s ability to meet NERC Control Performance Standards, and potentially

jeopardizing reliability.

409

Entergy agrees that settling hourly energy imbalances with

generators does not provide adequate incentives for generators to schedule and dispatch

accurately within the hour. Entergy asserts that generators have imposed significant

moment to moment swings within the hour requiring it to deploy its regulating reserves in

response. Entergy states that it has been increasingly difficult to meet NERC’s operating

criteria for control area performance without committing, and incurring the costs for,

additional regulating reserves. TVA contends that all generators should be required to

ensure that the instantaneous generation level equals the scheduled output. International

Transmission asks that the imbalance provisions in the Final Rule address this situation

by either specifying penalties that may be assessed for within-hour variations or advising

that transmission providers may implement their own penalties to the extent that within-

hour variations cause operational difficulties.

720. South Carolina E&G contends that allowing generator imbalance settlements over

a shorter period, such as at 15-minute intervals, together with the proposed tiered charges

409

International Transmission provides the example that a large generator with

scheduled output of 100 MW for an hour might stay at zero for the first 50 minutes of the

hour and then generate 600 MW during the last ten minutes.

Docket Nos. RM05-17-000 and RM05-25-000 - 411 -

for imbalances, would provide better, more refined incentives for generators to more

closely match their scheduled deliveries and would help balancing authorities reduce

Area Control Error excursions. TVA suggests generator imbalances be measured on ten-

minute intervals rather than integrated over an hour. These ten-minute imbalances would

not be netted against other imbalance intervals, so as to avoid the problem of encouraging

undergeneration followed by overgeneration and vice versa. In addition to having

generator imbalance charges for generation outside the operating bands, TVA argues that

there should be a separate charge assessed based on the peak generator imbalance

between the scheduled and actual generation recorded instantaneously during the clock

hour to provide a further incentive for proper generator scheduling.

721. Pinnacle and Utah Municipals assert that a transmission provider should only

charge hourly generator imbalances or hourly energy imbalances for the same imbalance.

PGP argues that customers should pay only one charge for the net imbalance that occurs

within a single control area, either energy or generation, unless congestion occurs inside

a control area that requires redispatch.

Commission Determination

722. The Commission concludes that it is appropriate to maintain the status quo

aggregating net generation over the hour in the pro forma

OATT. Requests by

transmission providers to adopt a shorter interval will continue to be considered on a

Docket Nos. RM05-17-000 and RM05-25-000 - 412 -

case-by-case basis.

410

The Commission acknowledges that shorter intervals may be

appropriate in particular circumstances and, for this reason, declined to use a clock-hour

interval in the Large Generator Interconnection Final Rule.

411

There, the Commission

permitted use of an interval "consistent with the scheduling requirements of the

Transmission Provider's Commission-approved Tariff and any applicable Commission-

approved market structure.”

412

Allowing transmission providers to continue to propose

alternative intervals for purposes of the pro forma

OATT imbalance provisions is

therefore appropriate provided that such proposals are consistent with relevant market

structures.

g. Distribution of Penalty Revenues above Incremental Cost

NOPR Proposal

723. The Commission also sought comment in the NOPR regarding the treatment of

revenues the transmission provider receives above the cost of providing the imbalance

service.

410

See Entergy Services, Inc., 102 FERC ¶ 61,014 (2003) and Entergy Services,

Inc., 111 FERC ¶ 61,314 (2005).

411

See Order No. 2003 at P 335.

412

See pro forma LGIA Article 4.3.1

Docket Nos. RM05-17-000 and RM05-25-000 - 413 -

Comments

724. Various commenters state that the transmission provider should retain any

amounts above the incremental cost of providing imbalance service. Ameren and

Constellation argue such revenues should serve as a contribution towards the fixed costs

of providing this service. Entergy argues that premium charges would compensate it for

the administrative costs of maintaining an organization capable of providing this

purchase and sales function and provide generators with an incentive to avoid

mismatches between scheduled quantities and actual deliveries to Entergy. Entergy states

that the Commission has previously recognized that these generator imbalance charges

are analogous to the economy power rates that have historically included a percentage

adder for out-of-pocket costs to recover difficult-to-quantify costs.

725. On the other hand, FirstEnergy states that the additional revenue derived from

charges above incremental costs should be provided to generators and/or customers able

to regulate load that provided the redispatch, commitment, or additional regulation

reserves. Utah Municipals contend that the Commission should credit revenues from

charges above incremental costs to accurately-scheduling customers, rather than to the

transmission provider. Utah Municipals argue that the penalty portion of incremental and

decremental charges and rates could be credited back to all transmission customers who

incur imbalance charges and whose schedules fell within the first deviation band for that

hour. Progress Energy suggests that all imbalance revenues above the cost of providing

the imbalance should be distributed to all non-offending transmission customers, based

Docket Nos. RM05-17-000 and RM05-25-000 - 414 -

on the weighted amount of each non-offending transmission customer’s usage of the

transmission provider’s transmission system. TAPS and TDU Systems ask on reply that

penalty revenues not be earmarked for retail customers

726. Morgan Stanley believes that imbalance charges should be “keep whole” charges

calculated and designed to reimburse whoever remedied whatever problem the imbalance

caused while leaving the transmission provider financially indifferent.

Commission Determination

727. In this Final Rule, the Commission has reformed existing imbalance provisions to

reduce the variety of different methodologies used for determining imbalance charges

and ensure that the level of the charges provide appropriate incentives to keep schedules

accurate without being excessive. We also believe that transmission providers should

have a consistent method of treating revenues received through imbalance penalties or

charges that are in excess of incremental cost. The Commission has previously required

transmission providers with significant imbalance penalties to develop a mechanism to

credit penalty revenues to non-offending transmission customers.

413

This was intended to

remove the incentive of the transmission provider to hinder the development of other

imbalance services that do not rely on penalties.

414

We believe it is appropriate to

413

See Carolina Power & Light Co., 103 FERC ¶ 61,209 at P 25 (2003) (CP&L);

Entergy Svcs.

, 105 FERC ¶ 61,319, reh’g denied, 109 FERC ¶ 61,095 at P 65-66 (2004).

414

See Carolina Power & Light Co., 97 FERC ¶ 61,048 at 61,279 (2001).

Docket Nos. RM05-17-000 and RM05-25-000 - 415 -

maintain the requirement that transmission providers credit revenues in excess of

incremental costs. Therefore, as part of their compliance filings in this proceeding,

transmission providers are required to develop a mechanism for crediting such revenues

to all non-offending transmission customers (including affiliated transmission customers)

and the transmission provider on behalf of its own customers. Such a distribution of

penalty revenues recognizes that transmission providers bear the responsibility to correct

imbalances and often use their own facilities to do so.

728. We acknowledge that in the CP&L

decision, the Commission declined to allow

the transmission provider to allocate a share of imbalance penalty revenues to itself as a

user of the transmission system on behalf retail customers. Given the reforms to the pro

forma OATT imbalance provisions adopted in this Final Rule, we believe the

circumstances presented in that case are no longer applicable. There, the Commission

based its holding on its understanding that the high imbalance penalties imposed by the

transmission provider were an interim measure that were intended to be in place only

until an imbalance market was developed.

415

In this Final Rule, we are adopting

imbalance charges that are closely related to incremental cost and therefore minimize any

incentive on the part of the transmission provider to rely on penalty revenues rather than

seeking other methods of encouraging accurate scheduling. Under these circumstances,

415

Id.

Docket Nos. RM05-17-000 and RM05-25-000 - 416 -

there remains no reason to exclude the transmission provider from receiving an

appropriate share of penalty revenues.

3. Credits for Network Customers

729. In Order No. 888, the Commission established that network customers should be

eligible for credits for customer-owned transmission facilities under certain

circumstances. Specifically, section 30.9 of the pro forma

OATT states that a network

customer owning existing transmission facilities that are integrated with the transmission

provider’s transmission system may be eligible to receive cost credits against its

transmission service charges if the network customer can demonstrate that its

transmission facilities are integrated into the plans or operations of the transmission

provider to serve its power and transmission customers. Section 30.9 also states that new

facilities are eligible for credits when the facilities are jointly planned and installed in

coordination with the transmission provider.

NOPR Proposal

730. In the NOPR, the Commission proposed severing the link in the pro forma

OATT

between joint planning and credits for new facilities owned by network customers

because such linkage can act as a disincentive to coordinated planning. The Commission

proposed deleting from section 30.9 the language that permits transmission providers to

refuse crediting for new network customer-owned facilities that are not part of its

planning process, and adding language that puts a greater emphasis on comparability.

Specifically, the Commission proposed that the network customer shall receive credit for

Docket Nos. RM05-17-000 and RM05-25-000 - 417 -

transmission facilities added subsequent to the effective date of the Final Rule in this

proceeding provided that such facilities are integrated into the operations of the

transmission provider’s facilities and if the transmission facilities were owned by the

transmission provider, they would be eligible for inclusion in the transmission provider’s

annual transmission revenue requirement as specified in Attachment H of the pro forma

OATT.

731. In the NOPR, the Commission also declined to allow transmission providers as

part of this proceeding to automatically add costs of credits to the transmission provider’s

cost of service. However, the Commission stated that a transmission provider may

propose to add an automatic adjustment clause to its rates in a filing submitted under

section 205 of the FPA. The Commission also explained that it would not propose to

make credits generically available to point-to-point customers that own transmission

facilities, but clarified that if some facilities owned by a point-to-point customer meet all

the criteria for credits, consistent with the Commission’s statement in Order No. 888, the

Commission would address such situations on a fact-specific, case-by-case basis.

416

a. Severance of Credits and Planning

Comments

732. The NOPR proposal to sever the link between transmission credits and joint

planning by eliminating the joint-planning requirement for credits for new facilities

416

Order No. 888 at 31,742; Order No. 888-A at 30,271.

Docket Nos. RM05-17-000 and RM05-25-000 - 418 -

constructed by network customers is supported by a cross-section of the industry.

417

Exelon asserts that linking credits to network customers with coordinated planning

simply creates an incentive for the transmission provider to avoid coordinated planning

with the network customers so that the provider can avoid providing credits. In addition,

the criterion of “jointly planned” with the transmission provider provides little or no

value for discerning what facilities should qualify for crediting treatment. Further,

Exelon argues, tying credits to joint planning is no longer necessary because the

Commission’s regional planning initiatives will insure that most, if not all, newly

constructed facilities will be jointly planned. While EEI disagrees that the joint planning

provision has acted as a disincentive to joint planning, it agrees that the coordinated

planning initiatives in the NOPR has made the link unnecessary.

733. FMPA also argues that the link between credits and planning discourages joint

planning because companies can avoid transmission rate credits, often for competitors, by

simply refusing to jointly plan. FMPA asserts that it makes no sense to create economic

disincentives to joint planning. According to these commenters, transmission lines

cannot be built without some exchange of information; the joint planning link may

discourage the most productive exchange and can create needless and non-productive

disputation over whether joint planning did or should have taken place.

417

E.g., Allegheny, East Texas Cooperatives, ELCON, Exelon, FMPA, MDEA,

MidAmerican, MISO, Suez Energy NA, Tacoma, TAPS, and Utah Municipals.

Docket Nos. RM05-17-000 and RM05-25-000 - 419 -

734. PGP points out, however, that credits for new facilities can only result from joint

planning, because new facilities must be interconnected with the existing grid, and

planning studies are necessary for that to happen. NorthWestern requests that the

Commission reconsider its proposal to allow crediting of customer-owned facilities that

have not been jointly planned with the transmission provider. NorthWestern contends

that allowing the construction of network facilities and making a judgment after the fact

is inefficient and will result in protracted litigation and facilities that do not serve the

overall grid as efficiently as planned facilities. PNM-TNMP contends that the

Commission’s proposed action to “sever the link” will excuse the network customer from

the coordinated planning process and can only operate at cross-purposes with the

coordinated transmission planning goal that is addressed in the planning sections of the

NOPR.

Commission Determination

735. The Commission adopts the NOPR proposal to sever the link in the pro forma

OATT between joint planning and credits for new facilities owned by network customers.

The proposal received broad industry support, and we agree with these commenters that

the link between credits for new facilities and the requirement for joint planning can act

as a disincentive to coordinated planning, which is contrary to the Commission’s original

objective in adopting the provision. A transmission provider has an incentive to deny

coordinated planning in order to avoid granting credits for customer-owned transmission

facilities.

Docket Nos. RM05-17-000 and RM05-25-000 - 420 -

736. We find that arguments against the proposal are largely theoretical and do not

adequately take into account the coordinated planning provisions proposed in the NOPR.

The coordinated planning initiatives that the Commission is adopting in the Final Rule

will ensure that most, if not all, transmission facilities are planned on a coordinated basis,

making it unnecessary to retain this provision of section 30.9.

b. The New Test to Determine Eligibility for Credits

737. Comments support the test for new facilities proposed in the NOPR.

418

Some

argue that the test for network customer credits should continue to be whether the

network customer’s facilities provide capability and reliability benefits to the grid – the

same standard that would apply to inclusion of the facilities in the transmission

provider’s cost of service if the transmission provider constructed the facilities.

419

MidAmerican states that further clarification of this point in the Final Rule would be

beneficial in minimizing disputes over this issue. Likewise, MidAmerican asks the

Commission to clarify in the Final Rule that such credit can be applied only to network

customers taking OATT service and not to transmission customers that are under non-

OATT (i.e.

, grandfathered bundled agreements) contracts. PGP supports the new rules

418

E.g., Allegheny, EEI, Exelon, MISO, Nevada Companies, South Carolina

E&G, Suez Energy NA, and Tacoma.

419

E.g., Allegheny, Ameren, and MidAmerican.

Docket Nos. RM05-17-000 and RM05-25-000 - 421 -

for granting credits to network customers, but argues implementation details should be

left up to individual transmission providers.

738. Although several transmission providers support the continued use of the

integration test,

420

other commenters representing municipal and public power interests

ask that the Commission reconsider or clarify its application.

421

Some commenters argue

that given the Commission’s current interpretation of “integration” for transmission credit

purposes and the historical application of the test, retaining any integration requirement

for existing or new facilities conflicts with comparability or constitutes undue

discrimination.

422

TDU Systems argue that the integration standard has encouraged

discriminatory behavior by allowing transmission providers to charge network customers

for transmission provider facilities constructed to serve the transmission provider’s native

load, while refusing to pay the network customer for comparable customer-owned

transmission facilities. TDU Systems further argue that the integration test has resulted

in a form of “and” pricing since the TDU Systems, as network transmission service

customers, remain obligated to pay their load ratio share of the full transmission revenue

requirement of the transmission provider’s system, including the cost of transmission

facilities built to serve the transmission provider’s own loads.

420

E.g., EEI, MidAmerican, and Nevada Companies.

421

E.g., FMPA, NRECA, and TAPS.

422

E.g., East Texas Cooperatives, NRECA, TAPS, and TDU Systems.

Docket Nos. RM05-17-000 and RM05-25-000 - 422 -

739. NRECA questions the Commission’s statement in the NOPR that, in order to

satisfy the integration standard, a customer “must demonstrate that its facilities not only

are integrated with the transmission provider’s system, but also provide additional

benefits to the transmission grid in terms of capability and reliability and can be relied on

by the transmission provider for the coordinated operation of the grid.”

423

According to

NRECA, that statement identifies three nominal requirements for customer facilities—

integration, benefits and “relied upon”—as compared to the one nominal requirement for

transmission provider facilities—integration. This is fundamentally inconsistent with

comparability, NRECA continues, as the Commission seems to recognize in its rationale

for adding the comparability requirement to new facilities.

740. NRECA further argues that the NOPR failed to distinguish the proposed new

standard in revised section 30.9 from the Commission’s recent decision in North East

Texas Electric Cooperative, Inc.,

424

which found transmission provider facilities

integrated on the grounds that a showing of any degree of integration is sufficient,

rejected a “benefits” requirement, and did not consider a “relied upon” requirement. East

423

NRECA further notes that proposed OATT section 30.9 does not include these

additional “benefits” and “relied upon” requirements. NRECA argues that these

requirements cannot be part of the section 30.9, since regulatory preambles cannot vary

the words of the rule, citing

Wyoming Outdoor Council v. U.S. Forest Service, 165 F.3d

43, 53 (D.C. Cir. 1999) (“[L]anguage in the preamble of a regulation is not controlling

over the language of the regulation itself”).

424

108 FERC ¶ 61,084 (2004), reh’g denied, 111 FERC ¶ 61,189 (2005).

Docket Nos. RM05-17-000 and RM05-25-000 - 423 -

Texas Cooperatives argues that the Commission’s decision in East Texas Electric

Cooperative, Inc. v. Central and South West Services, Inc.,

425

applied an integration

requirement for customer facility credits that was different and stricter than the standard

applied to a transmission provider’s facilities.

741. Regarding the application of the integration component, FMPA argues that, in

order to avoid continued discrimination, it is important that the Commission reaffirm that

“additional benefits to the transmission grid in terms of capability, delivery options, and

reliability”

426

are benefits, regardless whether the transmission customers or the

transmission provider (or others) benefit. Similarly, FMPA continues, the requirement

that facilities must “be relied upon for the coordinated operation of the grid”

427

must

equally include operations that serve transmission providers, customers or others.

742. Comments on the comparability component of the proposed credits test for new

facilities range from several requesting that the Commission adopt a comparability-driven

analysis

428

to one asking the Commission to eliminate the comparability component in

favor of an integration-only analysis.

429

425

114 FERC ¶ 61,027 at P 42 (2006), appeal docketed, No. 06-1090 (D.C. Cir.

Mar. 10, 2006).

426

NOPR at P 256.

427

Id.

428

E.g., APPA, FMPA, and NRECA.

429

Entergy.

Docket Nos. RM05-17-000 and RM05-25-000 - 424 -

743. Some commenters argue that eligibility for credits should turn in the first instance

on the comparability standard set forth in the NOPR, otherwise the proposal does not

eliminate undue discrimination.

430

NRECA argues that this requirement does not

abandon integration because current Commission policy requires a Transmission

Provider’s facilities to be integrated for their cost to be rolled in to the transmission

provider’s annual transmission revenue requirement.

431

APPA would apply an

integration test only if the transmission facilities for which the customer seeks credits are

found not to be eligible under this comparability standard.

744. TAPS states that, by eliminating the integration test and simply providing that

customer-owned facilities would be eligible for credits to the extent they would be

included in the transmission provider’s rate base if they were owned by the transmission

provider (i.e.

, a comparability test), the Commission would avoid litigation over what (if

anything) the separate “integration” requirement adds in the proposed formulation. If the

integration terminology is retained in section 30.9, TAPS argues that the Commission at

least should clarify that the new integration test is truly different from the old integration

430

E.g., APPA, East Texas Cooperatives, FMPA, and NRECA.

431

NRECA compares North East Texas Electric Cooperative, Inc., 108 FERC

¶ 61,084 (2004), reh’g denied

, 111 FERC ¶ 61,189 (2005) (finding transmission provider

facilities integrated and rolling in their cost over transmission provider objection) with

Mansfield Municipal Electric Department v. New England Power Co.

, 97 FERC ¶ 61,134

(2001), reh’g denied

, 98 FERC ¶ 61,115 (2002) (finding transmission provider facilities

not integrated and rolling out their cost over transmission provider objection).

Docket Nos. RM05-17-000 and RM05-25-000 - 425 -

test and cannot properly be read as limiting the comparability requirement and that the

Commission will not follow precedents developed in credits cases decided under the

original section 30.9.

745. To provide a comparability baseline and eliminate the need for an integration test,

APPA recommends that transmission providers provide a detailed inventory of the

existing facilities owned by transmission provider and network transmission customers

that are included in their annual transmission revenue requirement. Network transmission

customers could use the inventory, which would be updated annually, to assess whether

they currently own transmission facilities comparable to those included in the

transmission provider’s transmission rate base, or to third-party transmission facilities for

which credits are being provided.

746. MDEA argues that proposed section 30.9 appears contrary to comparability

principles by imposing a standard for transmission facilities owned by customers that is

more stringent than the one applied to the transmission provider’s own facilities. In

MDEA’s view, the NOPR proposal is inconsistent with prior Commission precedent to

the extent comparability is not required in evaluating eligibility of existing facilities

owned by transmission providers for cost recovery.

432

MDEA cites Florida Power and Light Co., 116 FERC ¶ 61,013 (2006), and

notes that the Commission applied principles of comparability to a transmission

provider’s existing facilities.

Docket Nos. RM05-17-000 and RM05-25-000 - 426 -

747. TDU Systems ask that the Commission clarify that the comparability prong will be

aggressively enforced. For example, TDU Systems request that the Commission consider

a bright-line voltage criterion to address comparability, rather than leaving it to the

transmission provider’s discretion as to whether the facilities would be eligible for

inclusion in the transmission provider’s annual transmission revenue requirement.

748. Arguing against the use of the comparability component, Entergy contends that it

could cause significant confusion, and should in no way change the basic requirements

needed to show integration of network customer facilities. According to Entergy, a

network customer should be entitled to credits only when the transmission provider

cannot meet the transmission provider’s firm obligations without the customer’s

transmission facilities.

749. On reply, MDEA states that the principle of comparability requires that there be

no distinction based on ownership or between existing and new facilities. It further

asserts that Entergy attempts to draw a distinction between customer-owned transmission

facilities needed by the transmission provider to meet the transmission provider’s

obligations to native load and firm transmission customers (for which credits should be

available) and facilities that a network customer decides that it needs to meet its

obligations. Entergy argues that credits should be available only for the former type of

facility. According to MDEA, there is no justification for the distinction Entergy seeks to

draw or the standard it proposes to apply. Network customers pay a full load ratio share

of the embedded costs of the transmission grid, based on the premise that the entire grid

Docket Nos. RM05-17-000 and RM05-25-000 - 427 -

is available and required to support network loads. In this regard, there is no difference

between Entergy’s native load and network customer loads. Transmission facilities

required to meet network customer needs by definition are required to meet grid needs,

provided that such facilities are integrated with the transmission network.

750. Several commenters ask the Commission to consider crediting mechanisms other

than the NOPR proposal.

433

For example, Entergy and Exelon contend that new facilities

should be eligible for credit only if determined through the regional planning process that

such new facilities are needed, i.e.

, that a measurable system capability or reliability

benefit is provided. In their view, this will avoid litigation of cases addressing questions

of integration. Utah Municipals argue that the Commission should not discount the

potential evidentiary value of joint planning in assessing eligibility for customer credits.

Taking a more expansive view, APPA argues that network transmission customers also

should be able to obtain credits for transmission facilities they build pursuant to an open

and collaborative transmission planning process in their region or sub-region. This

additional opportunity for credits, according to APPA, would spur participation in the

transmission planning process and would be superior to litigating the proper application

of the integration standard.

751. Entegra argues that the Commission should make the crediting policy for network

customers consistent with the Commission’s policies for generator interconnection

433

E.g., Entergy, Exelon, and Utah Municipals.

Docket Nos. RM05-17-000 and RM05-25-000 - 428 -

facilities, and require credits to be available for facilities that are integrated with the

transmission grid, without any showing of additional benefits and irrespective of whether

the service in question is interconnection service, network service, or point-to-point

service. Entegra further argues that the Commission should allow customers to sell

transmission credits to obtain transmission service elsewhere on the transmission

provider’s system. By allowing the development of a more liquid market for such

credits, Entegra reasons, the Commission could increase the willingness of market

participants to fund upgrades to the transmission system.

752. TDU Systems request that the Commission recognize that inequities have occurred

and, if any upgrades are required to make network customers’ facilities comparable (or

comparably integrated), the costs of such network upgrades should be rolled into the

transmission providers’ rates.

Commission Determination

753. The Commission declines to adopt the credits test for new facilities proposed in

the NOPR. The intent underlying that proposal was to prevent application of the

integration test in a manner that exclusively benefits the transmission provider.

434

After

reviewing the comments, we conclude that the proposed test may not in fact accomplish

this objective. The test proposed in the NOPR may not effectively set forth the

relationship of the integration standard to the comparability requirement. We therefore

434

See NOPR at P 256.

Docket Nos. RM05-17-000 and RM05-25-000 - 429 -

revise the test as follows, to more accurately reflect the Commission’s intent as expressed

in the NOPR: a network customer shall receive credit for transmission facilities added

subsequent to the effective date of the Final Rule if such facilities are integrated into the

operations of the transmission provider’s facilities; provided however, the customer’s

transmission facilities shall be presumed to be integrated if the transmission facilities, if

owned by the transmission provider, would be eligible for inclusion in the transmission

provider’s annual transmission revenue requirement as specified in Attachment H of the

pro forma

OATT.

754. Under our precedent, a transmission provider’s facilities are presumed to provide

benefits to the transmission grid, whereas a transmission customer must make an

affirmative showing that its facilities provide benefits in order to qualify for credits.

435

Under the test we adopt in this Final Rule, a transmission customer will be required to

meet the integration standard under pro forma

OATT section 30.9 in order to receive a

credit for its facilities.

436

Because joint planning will no longer be required in order to

435

See e.g., North East Texas Electric Cooperative, Inc., 108 FERC ¶ 61,084; East

Texas Electric Cooperative, Inc. v. Central and South West Services, Inc., 114 FERC

¶ 61,027.

436

The integration standard, in brief, requires that to be eligible for credits under

pro forma

OATT section 30.9, the customer must demonstrate that its facilities not only

are integrated with the transmission provider’s system, but also provide additional

benefits to the transmission grid in terms of capability and reliability and can be relied on

by the transmission provider for the coordinated operation of the grid. Southwest Power

Pool, Inc., 108 FERC ¶ 61,078 at P 17 (2004) (citing Order No. 888-A at 30,271), reh’g

denied, 114 FERC ¶ 61,028 (2006). This policy is premised on the principle that “just as

(continued)

Docket Nos. RM05-17-000 and RM05-25-000 - 430 -

obtain credits, we find that it is particularly important in this context to require a showing

that a network customer’s facilities provide benefits to the transmission provider’s grid,

i.e.

, a transmission customer should not be eligible for credits for facilities that the

network customer may use to provide service for itself but that the transmission provider

does not need to use to provide transmission service to any other customer. However, to

ensure comparability, a presumption of integration will be afforded to transmission

customer facilities if it is shown that, if owned by the transmission provider, such

facilities would be eligible for inclusion in the transmission provider’s rate base.

c. Application of the New Test to Existing Facilities

Comments

755. Several commenters object to the Commission’s proposal to apply the new

comparability test in section 30.9 to new facilities, and not to existing facilities.

437

If the

Commission requires the same integration standard for both existing and new facilities,

the transmission provider cannot charge the customer for facilities not used to provide

transmission service, the customer cannot get credits for facilities not used by the

transmission provider to provide service.” Id.

at P 20 (citing Order No. 888-A at 30,271

& n.277); accord

East Texas Coop., Inc. v. Central & South West Services, Inc.,

108 FERC ¶ 61,079 at P 28 (2004), reh’g denied

, 114 FERC ¶ 61,027 (2006); Southern

California Edison Co., 108 FERC ¶ 61,085 at P 10 (2004); Northern States Power Co.,

87 FERC ¶ 61,121 at 61,488 (1999); Florida Municipal Power Agency v. Florida Power

& Light Co., 74 FERC ¶ 61,006 at 61,010 (1996), reh’g denied, 96 FERC ¶ 61,130 at

61,544-45 (2001), aff’d sub nom.

Florida Municipal Power Agency v. FERC, 315 F.3d

362 (D.C. Cir. 2003).

437

E.g., APPA, FMPA, MDEA, NRECA, and TAPS.

Docket Nos. RM05-17-000 and RM05-25-000 - 431 -

East Texas Cooperatives ask us to specify which integration standard – the pre-existing

integration standard, or the new standard that applies the integration standard comparably

– applies and explain the difference and the basis for that choice. MDEA, FMPA and

TAPS argue that no distinction is warranted between the treatment of new and existing

facilities and that the same standard should apply.

756. TAPS clarifies that it is not suggesting that the standard be applied retroactively to

past uses, but rather prospectively to existing facilities, with the key consideration being

when the claim for credits is brought and not when the facilities are constructed. TAPS

argues that it cannot be claimed that the revised standard should apply only to new

facilities because the comparability requirement is new. To the contrary, TAPS contends

that comparability has been the theme and bedrock foundation of the Commission’s

transmission open-access requirement since its inception.

757. APPA argues that the Commission effectively acknowledges in the NOPR that

transmission providers have failed to plan new facilities jointly with their transmission

customers for the last ten years under the current section 30.9, but offers no redress for

this past discrimination.

Commission Determination

758. We conclude that the new test for determining credits will apply only to

transmission facilities added subsequent to the effective date of this Final Rule. A

number of customer-owned transmission facilities have been developed, and resulting

credits negotiated and litigated, under the prior test which the Commission determined to

Docket Nos. RM05-17-000 and RM05-25-000 - 432 -

be just and reasonable at the time.

438

We find no basis for revisiting the Commission’s

determinations in those cases in this Final Rule. On a prospective basis, however, given

the increased planning and coordination we require in the Final Rule, we believe it

appropriate to apply the new test for determining credits.

d. Cost of Customer Facilities Automatically Included in

Transmission Provider Cost of Service Without a Rate

Filing

Comments

759. Several transmission providers argue that, contrary to the Commission’s proposal,

credits should be added automatically to the transmission provider’s cost of service.

439

760. MidAmerican argues that requiring the transmission provider to defer including

the cost of the transmission credit until its next filed transmission rate case penalizes the

transmission provider’s shareholders who must unfairly bear the cost of providing the

credit until the next rate case. If the Commission does not allow automatic rate recovery

of the incremental cost of credits, MidAmerican continues, the Commission should

clarify that the customer will not be allowed transmission facility credits until the rate

adjustments are filed and accepted by the Commission. MidAmerican explains that such

filings would examine only the new revenue requirements to be added and should not

438

See East Texas Electric Cooperative v. Central and South West Services, Inc.,

114 FERC ¶ 61,027 (2006).

439

E.g., Allegheny, EEI, MidAmerican, and Nevada Companies.

Docket Nos. RM05-17-000 and RM05-25-000 - 433 -

require a general rate case for the transmission provider’s entire revenue requirement.

Nevada Companies likewise argues that credits should not be granted to network

customers if the recovery of those credits is not provided for in the revenue requirement.

761. TAPS agrees with the Commission’s conclusion that it would not be appropriate in

this rulemaking to allow transmission providers to automatically add costs of credits to

their cost of service, and that such costs should continue to be evaluated as part of a

regular transmission rate case (or recovered through an approved formula rate). APPA

expresses concern that transmission providers may attempt to use the Commission’s

decision not to allow them to add the costs of credits associated with customer-owned

transmission facilities automatically to their costs of service as a pretext for not granting

such credits in the first instance (at least until they decide to file a new rate case). APPA

continues that a transmission provider’s decision not to exercise the option to file under

FPA section 205 a new rate case or an automatic adjustment clause should not serve as a

reason to allow it to decline to provide credits.

762. EEI explains that the customary basis for not allowing single-issue rate

adjustments for new transmission facilities is that while one aspect of the transmission

provider’s costs may have increased, others may have decreased or load may have

increased. This is not the case with respect to the inclusion of the transmission costs

related to customer-owned facilities, EEI continues, since the existence of customer-

owned facilities does not have any impact on the transmission provider’s own cost of

service. EEI concludes that a transmission provider should not be forced into what is

Docket Nos. RM05-17-000 and RM05-25-000 - 434 -

essentially re-justifying its transmission cost of service simply because a customer

receives a credit for the integration of its own facilities.

763. Some commenters also address the option currently open to transmission providers

to add an automatic adjustment clause to their rates through a rate filing with the

Commission.

440

EEI argues that if the concept of an automatic adjustment clause is just

and reasonable for one transmission provider, it is equally just and reasonable for all

transmission providers, and there is no need to adopt a case-by-case approach. EEI

further requests that the Commission clarify that its policy is to accept rate adjustments

that incorporate the costs that transmission providers incur to provide credits related to

customer-owned facilities, provided that the rate adjustment methodology is just and

reasonable. MidAmerican contends that the revenue requirement of the transmission

provider and those of transmission customers should not be co-mingled, rather, consistent

with Commission precedent, the burden is on the transmission-owning customer to

demonstrate to the Commission that its cost of service and revenue requirement used to

establish the amount of the credit are just and reasonable before it can receive credits. As

for nonjurisdictional entities, MidAmerican explains that they may file for a declaratory

ruling from the Commission regarding their revenue requirement.

764. Allegheny argues that if the Commission continues to deny transmission providers

an automatic adjustment clause for these credits, it should, at a minimum, assure

440

E.g., Allegheny, EEI, Exelon, and MidAmerican.

Docket Nos. RM05-17-000 and RM05-25-000 - 435 -

transmission providers that transmission credits will be recognized as a cost of service in

FPA section 205 rate proceedings.

765. Entergy argues that the Commission should recognize that any filed agreement

providing for payments of credits would be subject to the filed-rate doctrine.

Commission Determination

766. We are not persuaded to generically allow automatic recovery of the costs of

credits associated with integrated transmission facilities to the transmission provider’s

cost of service. These costs typically are considered and evaluated as part of a regular

cost of service review process. Automatic recovery of the costs of credits would be

contrary to our long-standing policy concerning single-issue rate adjustments, a policy we

decline to modify here.

441

Nevertheless, transmission providers continue to have the

option to propose an automatic adjustment clause in their rates under FPA section 205 to

address the time lag between incurring costs associated with credits and the transmission

provider’s next rate case.

767. Contrary to EEI’s assertions, customer credits do not warrant an exception to the

Commission’s general policy regarding single-issue rate adjustments. EEI argues that

customer credits should be treated differently because the existence of customer owned

facilities, in EEI’s view, does not have any impact on the transmission providers’ own

441

See, e.g., City of Westerville, Ohio v Columbus Southern Power Co.,

111 FERC ¶ 61,307 (2005).

Docket Nos. RM05-17-000 and RM05-25-000 - 436 -

cost of service. Even if true, this fact would not obviate the Commission’s policy.

Regardless of whether the customer credit is deemed to impact the transmission

provider’s own cost of service, the costs it imposes may be offset by cost decreases in

other areas, by load growth, or both. Allowing single-issue rate adjustments would

enable a utility to increase the total rate charged by focusing solely on a single cost

element, while avoiding scrutiny of all other determinants of the rate. The Commission

has an obligation to ensure the justness and reasonableness of the total rate and it would

be improper to allow a utility to raise rates by selectively focusing only on particular

elements of its costs, while avoiding scrutiny of other rate inputs. The Commission has

refused to allow such rate treatment except in the most limited of circumstances and we

find no basis for deviating from that policy in this context. As explained above, a

transmission provider that wishes to add an automatic adjustment clause to its rates may

seek Commission approval for its methodology in a filing submitted under FPA section

205.

e. Point-to-Point Customers Not Eligible for Credits on Generic

Basis

Comments

768. Several commenters support the Commission proposal to not make credits

generically available to point-to-point customers that own transmission facilities.

442

E.g., APPA, Bonneville, EEI, Exelon, FirstEnergy, Nevada Companies, and

TAPS.

Docket Nos. RM05-17-000 and RM05-25-000 - 437 -

APPA argues that if the frequency of cases seeking credits for facilities owned by point-

to-point customers is high, then the Commission should reconsider its decision to use a

case-by-case approach.

769. Some commenters encourage the Commission to clarify that point-to-point

transmission customers that pay for upgrades should be compensated if such upgrades

benefit the system.

443

PGP argues that customers be given credits if they meet the same

conditions as network customers who would qualify. Additionally, Entegra contends that

denying credits for upgrades funded by point-to-point customers would overlook the

Commission’s past warnings that a customer funding any new facilities integrated with

the grid should be entitled to credits because a transmission system “cannot be

dismembered” or examined piecemeal.

444

Commission Determination

770. The Commission adopts the NOPR proposal not to make credits generically

available for point-to-point customers that own transmission facilities. As the

Commission explained in the NOPR, a network customer takes a usage-based service

which integrates its resources and loads and pays on the basis of its total load on an

ongoing basis. The transmission provider includes the network customer’s resources and

loads in its long-term planning horizon and the two parties coordinate operations of their

443

E.g., FirstEnergy, Seattle, and Suez Energy NA.

444

Citing Nevada Power Co., 101 FERC ¶ 61,036 at P 8 (2002).

Docket Nos. RM05-17-000 and RM05-25-000 - 438 -

facilities through a network operating agreement. In this way, network service is

comparable to the service that the transmission provider uses to serve its own retail native

load, and credits for certain integrated network facilities are appropriate. The point-to-

point customer, however, does not purchase integration service, nor does it sign a

network operating agreement with the transmission provider. Because of the inherent

differences between point-to-point and network service, we therefore decline to require

that transmission providers make credits generically available to point-to-point customers

that own transmission facilities. If a particular facility owned by a point-to-point

customer meets all the criteria for credits, we will continue to address such situations on a

fact-specific, case-by-case basis consistent with the Commission's statement in Order No.

888.

445

f. RTO and ISO Issues

Comments

771. Several RTOs or ISOs assert that they should not be required to comply with the

crediting provisions because their respective planning processes and procedures are

superior to or obviate the need for those set forth in the NOPR.

446

CAISO states that it

does not oppose the Commission’s proposal, provided that the Commission confirms that

445

Order No. 888 at 31,742; Order No. 888-A at 30,271.

446

E.g., Indicated New York Transmission Owners, ISO New England, PJM, and

SPP.

Docket Nos. RM05-17-000 and RM05-25-000 - 439 -

facilities cannot be integrated into CAISO’s operations unless they are under CAISO’s

operational control, consistent with the Commission’s prior rulings.

772. In Xcel’s view, an RTO has no incentive to refuse to jointly plan to avoid paying a

credit and there is thus good cause to allow an RTO to deviate from the language in the

pro forma

OATT relating to joint planning of new facilities in order to be considered for

a facility credit. Xcel and International Transmission argue that RTOs should be allowed

to incorporate network customer-owned facilities into RTO rates in the same manner as if

they were constructed by a transmission owner, while ensuring against double recovery

of both revenue requirements and network credits.

Commission Determination

773. The Commission concludes that it would not be appropriate at this time to

generically exempt all ISOs and RTOs from the Final Rule requirements regarding

credits for network transmission customers. We will address issues relating to network

transmission customers credits in the RTO and ISO context in orders addressing OATT

reform compliance filings submitted by each RTO and ISO. The Commission

determined previously that the existing tariffs of certain RTOs and ISOs provide

opportunities for transmission customers to receive credit or the equivalent (e.g.

Transmission Congestion Contracts, Firm Transmission Rights or Auction Revenue

Rights) for building facilities or upgrades that are consistent with or superior to Order

Docket Nos. RM05-17-000 and RM05-25-000 - 440 -

No. 888 requirements.

447

Each RTO and ISO will have the opportunity to show on

compliance that this continues to be the case given the reforms adopted in this Final Rule.

Other issues

Comments

774. East Texas Cooperatives argue that the Commission should clarify that a network

customer is entitled to transmission credits for its own transmission facilities and the

facilities of member utilities for which the network customer arranges and pays for

network transmission services. East Texas Cooperatives explain that a recent

Commission decision

448

allows transmission credits only for facilities owned by the

generation and transmission cooperative (G&T) and not for its individual members,

which in its view is contrary to past Commission precedent.

447

For example, NYISO’s tariff provides that a facilities study will contain a non-

binding estimate as to the feasible Transmission Congestion Contracts (TCCs) resulting

from the construction of new facilities. There, upon completion of the transmission

upgrade and the first subsequent centralized TCC auction, the NYISO will determine the

incremental TCCs associated with the upgrade. See

section 19.4 “Facilities Study

Procedures” of NYISO’s tariff. Similarly, PJM’s tariff provides that an interconnection

customer that undertakes responsibility for constructing or completing network upgrades

and/or local upgrades to accommodate its interconnection request will be entitled to

receive the incremental Auction Revenue Rights associated with such facilities and

upgrades subject to conditions. See

section 46.1 “Right of Interconnection Customer to

Incremental Auction Revenue Rights” of PJM’s tariff.

448

East Texas Electric Cooperative, Inc. v. Central and Southwest Services, Inc.,

108 FERC ¶ 61,077 at P 21-23 (2004), reh’g denied

, 114 FERC ¶ 61,027 at P 43-44

(2006), appeal docketed

, No. 06-1090 (D.C. Cir. Mar. 10, 2006)

Docket Nos. RM05-17-000 and RM05-25-000 - 441 -

775. FMPA asks that the Commission affirmatively state that it will exercise its

jurisdiction to ensure that public power entities are compensated for transmission

investment (including joint transmission projects) in the event of dispute with

jurisdictional transmission providers. FMPA explains that the proposed revisions to

section 30.9 may be insufficient to address all problems that may arise, especially in

regions without an RTO or an existing compensation method. NRECA asks the

Commission to prohibit RTOs and ISOs from using a non-public utility’s transmission

facilities without compensating the entity simply because it has not joined the RTO or

ISO. NRECA argues that comparable treatment requires compensation for use of a

transmission owner’s facilities, whether the owner is subject to Commission jurisdiction

or not, and the Commission should not consider a transmission tariff to be just and

reasonable if it allows unlawful trespass and conversion.

776. TAPS asks the Commission to include language in section 30.9 of the pro forma

OATT that affirmatively states customers’ eligibility for rate incentives for new facilities

under recently established Commission policy. TAPS further requests that the

Commission guard against a transmission provider blocking such incentive based credits

by refusing to engage in joint development of transmission projects with its customers.

Commission Determination

777. The Commission finds that there is not enough evidence on the record to make a

generic determination on these issues and, instead, will address them on a case-by-case

basis in response to appropriate filings under FPA sections 205 and 206. With regard to

Docket Nos. RM05-17-000 and RM05-25-000 - 442 -

incentives for new facilities, the Commission has already addressed incentives for

transmission infrastructure investment in Order No. 679.

449

There the Commission

identified specific incentives that it will allow when justified in the context of individual

proceedings. With regard to FMPA’s concerns regarding potential disputes over

compensation for transmission investment by non-public utilities, we note that section 12

of the existing pro forma

OATT contains dispute resolution procedures. This Final Rule

also requires transmission providers to propose a dispute resolution process as part of the

coordinated planning process. Additionally, the Commission’s Dispute Resolution

Service is available to assist in developing a dispute resolution process, as well as the

Commission via a formal complaint filed pursuant to section 206 of the FPA.

4. Capacity Reassignment

778. In Order No. 888, the Commission concluded that a transmission provider’s

pro forma

OATT must explicitly permit the voluntary reassignment of all or part of a

holder’s firm point-to-point capacity rights to any eligible customer.

450

With respect to

the rate for capacity reassignment, the Commission concluded it could not permit

reassignments at market-based rates because it was unable to determine that the market

for reassigned capacity was sufficiently competitive so that assignors would not be able

449

Promoting Transmission Investment through Pricing Reform, Order No. 679,

71 FR 43294 (Jul. 31, 2006), FERC Stats. & Regs. ¶ 31,222 (2006), order on reh’g

, Order

No. 679-A, 72 FR 1152 (Jan. 10, 2007), FERC Stats. & Regs. ¶ 31,236 (2007).

450

See Order No. 888 at 31,696; pro forma OATT section 23.1.

Docket Nos. RM05-17-000 and RM05-25-000 - 443 -

to exert market power. Instead, the Commission capped the rate at the highest of (1) the

original transmission rate charged to the purchaser (assignor), (2) the transmission

provider’s maximum stated firm transmission rate in effect at the time of the

reassignment, or (3) the assignor’s own opportunity costs capped at the cost of expansion

(price cap). The Commission further explained that opportunity cost pricing had been

permitted at “the higher of embedded costs or legitimate and verifiable opportunity costs,

but not the sum of the two (i.e.

, ‘or’ pricing is permitted; ‘and’ pricing is not).”

451

Order No. 888-A, the Commission explained that opportunity costs for capacity

reassigned by a customer should be measured in a manner analogous to that used to

measure the transmission provider’s opportunity cost.

452

NOPR Proposal

779. In the NOPR, the Commission noted that capacity reassignment does not appear to

have developed into a competitive alternative to primary capacity since the issuance of

Order No. 888. To facilitate development of this market, the Commission proposed to

remove the price cap on capacity reassignment and allow negotiated rates for

transmission capacity reassigned by transmission customers. The Commission explained

that, because the price cap appears to have reduced customers’ transmission options,

removal of the cap may be warranted without a market-by-market analysis. Due to

451

Id. at 31,740.

452

Order No. 888-A at 30,224.

Docket Nos. RM05-17-000 and RM05-25-000 - 444 -

market power concerns, however, the Commission proposed to retain the price cap for

capacity reassigned by the transmission provider’s merchant function or its affiliates.

780. The Commission proposed to monitor the market for reassigned capacity by

requiring regular OASIS postings and quarterly reports from transmission providers using

information submitted by reassigning customers. First, the Commission proposed

retaining the existing posting and filing requirements for reassigned capacity transactions

to ensure that capacity is equally available to all customers and to protect against undue

discrimination and the potential exercise of market power.

453

Second, the Commission

asked several questions regarding OASIS postings and the data that should be required in

quarterly reports related to capacity reassignments: (1) what information should be

required in the quarterly reports and OASIS postings, i.e.

, information about the capacity

released, the original rate paid for that capacity, the price charged to the assignee for the

capacity, and the term of the assignment; (2) whether other information was necessary for

operational and reliability purposes; (3) whether additional reports by assignors to the

transmission provider are necessary and, if so, what information should be reported by

assignors; (4) should the Commission establish a new quarterly reporting process with a

453

The existing OASIS posting requirements for reassigned capacity already

require, if selling on OASIS, for sellers to include data elements such as the path name,

point of receipt, point of delivery, source, sink, capacity requested, capacity granted, start

time, stop time, and offer price. See

18 CFR 37.6(c)(5).

Docket Nos. RM05-17-000 and RM05-25-000 - 445 -

new form, or use the existing Electric Quarterly Report procedures; and (5) how

frequently should OASIS postings be made.

Comments

Lifting the price cap for all transmission customers

781. Some commenters support eliminating the price cap for reassignment of

transmission capacity in the secondary market.

454

For example, EPSA states that the

Commission is correct to recognize that negotiated rates are dynamic and provide a

market discipline on the price for reassigned capacity. Entegra argues that the

Commission’s removal of rate caps on releases of natural gas pipeline capacity increased

available peak capacity and facilitated the movement of capacity into the hands of those

that value it most highly, proving that an uncapped capacity release market can be both

competitive and result in just and reasonable rates for customers.

455

Exelon supports

eliminating the price cap, but asserts that, since the transmission customer is seeking to

reassign the capacity, it is likely the capacity is not useful in gaining access to load and

therefore is not very valuable. BP Energy contends that transparent competition between

the transmission provider (marketing primary and subscribed but unutilized capacity) and

transmission customers, with monitoring by the Commission and prospective capacity

454

E.g., Allegheny, AWEA, Constellation, EEI, Entegra, EPSA, Exelon, Morgan

Stanley, PPL, Seattle, Suez Energy NA, and TranServ.

455

Citing Natural Gas Pipeline Negotiated Rate Policies and Practices, 114 FERC

¶ 61,034 (2006) (Brownell, Comm’r concurring).

Docket Nos. RM05-17-000 and RM05-25-000 - 446 -

purchasers, will moderate if not eliminate the potential exercise of market power and

encourage the release of capacity that is not otherwise used or useful. As a result, BP

Energy urges the Commission to require transmission providers to facilitate a competitive

capacity reassignment process, similar to that used for capacity release on natural gas

pipelines.

782. Some commenters support the proposal to retain the price cap for transmission

providers and their affiliates.

456

Seattle states that the Commission is correct to continue

to cap prices for the transmission provider since the transmission provider is a regulated

monopoly. In its reply, Entegra states that the Commission has found that having a pro

forma OATT mitigates but does not eliminate a transmission provider’s ability to

leverage its monopoly power in transmission into market power in generation markets.

457

Entegra further contends that Southern, Entergy, and other transmission providers have

monopoly power in transmission markets in their service territories and without a cap

would exploit that market power in the secondary market. Moreover, Entegra argues that

allowing transmission providers and their affiliates to charge market-based rates for

transmission capacity in the primary or secondary market would exacerbate the skewed

456

E.g., APPA, AWEA, NRECA, Seattle, TAPS, and TDU Systems.

457

Citing Public Service Electric & Gas Company, 78 FERC ¶ 61,119 at 61,455

(1997) (granting market-based rate authority based in part on the adequate “mitigation of

market power” as evidenced by a pro forma

OATT).

Docket Nos. RM05-17-000 and RM05-25-000 - 447 -

incentives that already operate to discourage construction of much needed transmission

facilities in many markets.

783. Many commenters contend that lifting the price cap for reassignment of

transmission capacity only for unaffiliated transmission customers would be

unreasonable.

458

For example, Entergy argues that for the wholesale markets to work all

wholesale market participants, including the transmission provider’s affiliated marketers,

must be treated comparably under the pro forma

OATT. EEI contends that lifting the

price cap can result in a more robust secondary market for transmission capacity and will

reduce any risks that transmission customers may associate with being required to

purchase transmission service for five-year terms in order to obtain rollover-rights. In

addition, Manitoba Hydro asserts that changing the current one-year minimum term

creates additional risks for transmission customers and therefore having the ability to re-

sell the transmission capacity at market-based rates would assist transmission customers

to better manage the financial risks involved with holding longer term contracts.

784. Some commenters support lifting the price cap for affiliates if caps are removed

for non-affiliates, but are only generally supportive of lifting the price cap.

459

If the

Commission does lift the price cap, Southern argues that it should also lift the price caps

458

E.g., Community Power Alliance, EEI, Entergy, FirstEnergy, Imperial,

Manitoba Hydro, MidAmerican, Progress Energy, and Salt River.

459

E.g., MidAmerican, PNM-TNMP and South Carolina E&G.

Docket Nos. RM05-17-000 and RM05-25-000 - 448 -

for the transmission provider and its affiliates as well in order to counter efforts to corner

the market and other related unforeseen consequences. MidAmerican agrees, asking the

Commission to retain the cap for all transmission customers if the transmission provider

and its affiliates are not allowed to resell capacity at market-based rates.

785. Several commenters argue that the Commission’s justification for eliminating the

price cap – namely, reducing the ability of non-affiliated customers to exercise market

power in the secondary market through competition among releasing customers,

monitoring the market via quarterly reports, and continuing rate regulation of primary

capacity – applies to energy and marketing affiliates as well.

460

First, several commenters

argue that the Standards of Conduct and existing pro forma

OATT rules ensure that

transmission provider affiliates have no more ability to obtain information about the

transmission system or to reserve point-to-point transmission capacity than unaffiliated

customers.

461

Entergy contends that, although the Commission correctly concludes

elsewhere in the NOPR that functional unbundling and Standards of Conduct

requirements, if properly enforced are sufficient to address affiliate abuse concerns, the

Commission seems to assume that those same protections cannot be effective where the

reassignment of transmission capacity is concerned.

460

E.g., EEI, Entergy, MidAmerican, PNM-TNMP, Progress Energy, Southern,

and South Carolina E&G.

461

E.g., Community Power Alliance, Entergy, Imperial, Manitoba Hydro, Salt

River, South Carolina E&G, and Southern.

Docket Nos. RM05-17-000 and RM05-25-000 - 449 -

786. Second, some commenters question the Commission’s assertion that permitting

transmission provider’s energy and marketing affiliates to resell or reassign transmission

capacity would give them the ability to favor their own generation.

462

For example, EEI

contends that transmission providers have no control over the reassignment process, and

transmission customers have complete freedom to reassign transmission capacity to any

customer they choose. Entergy points out that under Order No. 888 the assignor of

capacity may deal directly with an assignee and without involvement of the transmission

provider.

463

787. Third, some commenters disagree with the Commission’s statement that lifting the

price cap for affiliates may dampen transmission investment.

464

These same commenters

argue that there is no relationship between the transmission provider’s obligation to build

transmission facilities to accommodate third party requests for transmission service and

the ability of marketing and energy affiliates to resell unused transmission capacity at

market-based rates. For example, Progress Energy and others contend that the

transmission provider is obligated under the pro forma

OATT to construct transmission

facilities to meet all requests for transmission service.

465

Progress Energy and EEI

462

E.g., EEI, Entergy, MidAmerican, and Progress Energy.

463

See Order No. 888 at 31,697.

464

E.g., EEI, MidAmerican, and Progress Energy.

465

E.g., EEI, Entergy and MidAmerican.

Docket Nos. RM05-17-000 and RM05-25-000 - 450 -

contend that the transmission customer will decide to purchase secondary market

transmission capacity if it meets the reasonable needs of customers so long as the

capacity is priced below the higher of the embedded cost of transmission service or the

cost of expansion. EEI argues that the customer can require the transmission provider to

construct additional capacity to accommodate the customer’s request for service if

secondary market service – whether offered by the transmission provider’s marketing and

energy affiliates or by a third party customer – is priced above the cost of expansion. In

such situations, EEI and Progress Energy contend that the cost of expansion serves as a

cap on the price at which both third party customers and the transmission provider’s

marketing and energy affiliates can resell transmission capacity. Moreover, Entergy

argues that this is the same justification that the Commission relies upon to conclude that

transmission customers would not hoard secondary capacity, and it is arbitrary for the

Commission to ignore that principle in concluding that a transmission provider would

hoard capacity.

788. Additionally, some commenters argue that lifting the price cap for affiliates will

encourage transmission investment.

466

NorthWestern contends that allowing

transmission providers to collect more than their ceiling price when the market is willing

to pay a higher price could further the Commission’s goal of encouraging transmission

investment to maintain reliability and keep pace with load growth. NorthWestern

466

E.g., Entegra and NorthWestern.

Docket Nos. RM05-17-000 and RM05-25-000 - 451 -

suggests that the Commission could place restrictions on the proceeds in excess of the

ceiling price such that, within some specified period, the dollars must be reinvested into

transmission facilities or be refunded back to customers.

789. Several commenters contend that lifting the price cap only for non-affiliates could

dampen participation in the secondary market and place affiliates at a competitive

disadvantage.

467

Community Power Alliance argues it is unfair for the Commission to

now say that their separated marketing affiliates, which have abided by Commission rules

like any other market participant, cannot now compete on an equal footing with other

participants in the secondary market for transmission capacity. Rather than prohibit

transmission providers’ affiliates from reselling capacity, Manitoba Hydro suggests that a

more equitable approach would be for the Commission to lift the price cap for all resold

transmission capacity, except for transmission capacity administered by an affiliate’s

transmission provider.

790. To the extent the Commission adopts the proposed restriction on affiliate

reassignments, MidAmerican seeks guidance on whether the transmission provider is

expected to assure that the assignee is a valid eligible customer under the pro forma

OATT. Similarly, Southern encourages the Commission to carefully identify and

evaluate the possible adverse effects of lifting any reassignment price caps. Southern

467

E.g., Community Power Alliance, EEI, FirstEnergy, Imperial, Northwest IOUs,

Southern, and TVA.

Docket Nos. RM05-17-000 and RM05-25-000 - 452 -

asserts that such effects could include expanded involvement and influence by financial

players driven exclusively by profit motives and who may not be subject to Commission

regulation.

791. Several commenters contend that the Commission should retain the price cap for

the reassignment of transmission capacity for all customers, not just affiliates of the

transmission provider.

468

APPA argues that allowing the resale of such a scarce and

valuable service to those who value the capacity more highly is a recipe for undue

discrimination and unjust and unreasonable transmission rates, at the expense of end-use

customers. While NRECA opposes the Commission proposal to remove the price cap,

NRECA would support the proposal to retain the price caps for affiliates. Similarly,

TAPS supports the decision not to lift the price caps for affiliates; however, TAPS urges

the Commission to rethink the NOPR’s proposal to otherwise lift the price cap for non-

affiliates.

792. Several commenters argue that lifting the cap for any transmission customers

would encourage the exercise of market power, including hoarding, and discourage

transmission investment.

469

If removal of the cap were effective in making reassignment

more profitable, TAPS contends it would encourage hoarding of capacity on key paths

468

E.g., Alcoa, APPA, International Transmission, Nevada Companies, NRECA,

PJM, Public Power Council, TAPS, and WAPA.

469

E.g., APPA, Nevada Companies, Northwest IOUs, NRECA, PJM, TAPS, and

WAPA.

Docket Nos. RM05-17-000 and RM05-25-000 - 453 -

that would run afoul of the directive in FPA section 217(b)(4) to ensure the ability of

LSEs to secure long-term rights for their long-term power supply arrangements.

Northwest IOUs argue that lifting the price cap would encourage non-affiliated

transmission customers to buy transmission capacity at cost and resell it at market, in an

effort to reduce the amount of transmission capacity available for resource development

and other long-term uses. PJM argues that the final rule should include a requirement

that appropriate hoarding mitigation procedures be implemented should the price cap be

removed. APPA argues that, if no transmission capacity is available in the short run from

the transmission provider, and an LSE needs additional capacity to serve load within the

next day or week, the fact that the transmission provider could build capacity in future

years at an incremental rate has little if any bearing on the price that LSE is willing to pay

for the next day, week, or month to avert a looming supply problem. TVA asserts that

transportation prices rose drastically during periods of high demand or constraint after the

price cap for resale of gas transmission capacity was removed in Order No. 637 for

everyone except pipelines and their affiliates. TVA states that this benefited entities that

could afford to hold capacity, but harmed those that had to buy additional capacity on a

short-term basis.

793. Alcoa and Nevada Companies argue that there is a significant potential for abuse

in connection with the removal of the cap, particularly in load pockets. Alcoa argues that

it is not clear at this point that there are sufficient safeguards in place to prevent and

monitor the exercise of market power, something that must be assured before the cap is

Docket Nos. RM05-17-000 and RM05-25-000 - 454 -

lifted on transmission capacity resale. Nevada Companies contend the proposal to

remove the cap may actually reduce utilization of the grid, contrary to its intended

purpose. For example, Nevada Companies state that transmission customers who have

locked up capacity in constrained markets will likely wait to the very last minute to make

that capacity available in order to drive up the price, which will often result in the

capacity not being utilized if transactions cannot occur quickly enough. Some

commenters contend that, like LMP in organized markets, allowing price signals via

lifting the cap may not encourage transmission investment, but rather create entrenched

interests that profit from the existence of congestion and oppose efforts to eliminate such

congestion through transmission expansion.

470

If transmission providers are forced to

purchase capacity at higher prices on the secondary market, Imperial argues that their

native load customers be harmed by such higher prices, which may in turn hamper

transmission expansion contrary to the Commission’s stated goals for promoting

transmission investment.

794. In addition, some commenters are skeptical of the Commission’s assertion that

existing market mechanisms are a sufficient deterrent to anticompetitive behavior.

471

WAPA and TAPS argue that, while eliminating the price cap might increase customers’

470

E.g., APPA, International Transmission, NRECA, Public Power Council, and

Seattle.

471

E.g., Alcoa, APPA, Bonneville, TAPS, and WAPA.

Docket Nos. RM05-17-000 and RM05-25-000 - 455 -

transmission options, the Commission still needs to conduct case-by-case market power

analyses prior to lifting the cap.

472

As a result, WAPA argues, it is critical for the

Commission to identify and aggressively mitigate all transmission market power on an ex

ante

basis, rather than utilizing an ex post monitoring scheme as proposed in the NOPR.

If the Commission lifts the price cap, certain commenters argue that the Commission

should establish competitive bidding transaction standards.

473

For example, Seattle

asserts that a standards organization such as NAESB will need to establish bid/ask

transaction standards and reporting formats and the Commission must periodically

validate the assumption that the secondary market is workably competitive.

Application of the price cap to members of ISOs/RTOs

795. Some commenters request clarification that, if the Commission retains the price

cap for capacity reassigned by affiliates, that it not apply to entities that have turned over

control and operation of their transmission facilities to an RTO, ISO or independent

entities.

474

For example, Constellation requests that the Commission clarify that the

472

Citing Farmers Union Cent. Exch., Inc. v. FERC, 734 F.2d 1486, 1508-10

(D.C. Cir. 1984) (concluding that “undocumented reliance on market forces is

insufficient to satisfy the Commission’s regulatory responsibilities.”); California ex. Rel.

Lockyer v. FERC, 383 F.3d 1006, 1013 (9

Cir. 2004).

473

E.g., BP Energy, Seattle, and TranServ.

474

E.g., Ameren, Constellation, SPP, and TranServ. ISO New England and PJM

argue that, as providers of transmission service, they have no affiliates and likewise are

not bound by the Commission’s reassignment proposal.

Docket Nos. RM05-17-000 and RM05-25-000 - 456 -

revised pro forma

OATT does not impose the cap on affiliates of transmission owners

that have turned their transmission facilities over to an RTO/ISO when they reassign

transmission capacity on facilities operated by the RTO/ISO. While MISO takes no

position on whether the Commission should retain its cap for stand-alone transmission

providers and their affiliated customers, it argues that the cap makes no sense in the

context of capacity reassignments administered by RTOs and ISOs. MISO observes that

the NOPR cites affiliate preference and market power concerns as the basis for retaining

the cap on reassignments by transmission providers and their affiliated customers, which

MISO argues are not applicable in the RTO/ISO context. Further, MISO argues that the

ownership of transmission assets in an RTO/ISO is divorced from the provision of

transmission service, and RTO transmission owners are transmission customers no

different from any other customer class.

796. On the contrary, APPA notes that the issue is whether the transmission customer

holding transmission rights over a constrained path has the ability to exercise market

power and charge unjust and unreasonable rates if the cap is lifted. APPA argues that the

issue is the same in both RTO and non-RTO regions. In APPA’s view, whether the

public utility transmission provider has joined an RTO, does not affect the ability of its

merchant affiliate to extract unjust and reasonable rents for the resale of scarce

transmission rights.

Docket Nos. RM05-17-000 and RM05-25-000 - 457 -

Alternative price cap proposals

797. Some commenters propose alternatives to negotiated pricing of transmission

capacity in the secondary market.

475

While APPA supports retaining the current rate cap,

it contends that firm point-to-point customers should be allowed to collect demonstrable

out-of-pocket costs in addition to the maximum capped rate. Alcoa suggests that the

Commission could stimulate the secondary market for transmission capacity by

increasing the cap and allowing parties to charge a percentage over the original price

paid. Seattle contends that the existing Commission policy could be incrementally

modified to permit recovery of remarketing costs and recognize that, for many customers,

the transmission right is held at a much higher per unit cost than the primary rate stated in

the transmission provider’s pro forma

OATT (due in part to the fact that a customer may

not use all of the capacity for which it has contracted).

798. Sacramento proposes that prices for released capacity be capped at the amortized

and rate-based cost of a transmission upgrade. Seattle states that costly redirect

processes, including system impact studies, may be needed to create a reassignment

product that has value to other customers, given that the point of receipt, point of delivery

or both typically change in a reassignment. While the current pro forma

OATT pricing

model differentiates transmission rates based on term and time of day (monthly, weekly,

daily, hourly), Seattle asserts that seasonal variations in the value of transmission rights

475

E.g., Alcoa, APPA, Manitoba Hydro, PGP, Sacramento, and Seattle.

Docket Nos. RM05-17-000 and RM05-25-000 - 458 -

offered for short-term reassignment are also worthy of consideration, especially in a

region like the Northwest, where power production varies seasonally.

799. MISO states that it believes the Commission should further strengthen its pro-

competitive policy by permitting RTO/ISO transmission providers to offer firm point-to-

point transmission service for drive-out/drive-through transactions at market-based rates,

including “rollover” transactions. MISO states that the principles for allocating firm

capacity on such interfaces should be the same as for reassigning capacity within an

RTO: i.e.

, permitting customers that value the capacity more highly to benefit from it.

MISO asserts that allowing market participants to compete based strictly on price on

external interfaces would resolve many inefficiencies stemming from the cumbersome

queue administration procedures currently used on such facilities. MISO states that the

final rule should encourage RTOs and ISOs to introduce such competitive practices in

their footprints.

800. PGP proposes two alternative approaches. First, PGP proposes that the

Commission could wait until a regional approach for pricing reassignments is developed

in those areas of the country that still rely on reassignments of point-to-point capacity to

create a secondary market in transmission service. Second, PGP proposes that any

decision to remove the price cap could be made on a case-by-case basis after a filing by a

point-to-point customer at the Commission, in which the applicant must meet standards

developed by the Commission that demonstrate the lack of market power in relevant

transmission or generator markets.

Docket Nos. RM05-17-000 and RM05-25-000 - 459 -

801. South Carolina E&G requests that the Commission clarify how the cap is

calculated if the Commission chooses to retain the price cap. International Transmission

asserts that the Commission should lift the price cap, on an experimental basis, similar to

the approach followed in the natural gas industry. Similarly, WAPA recommends that

the Commission either retain the price cap or institute a separate rulemaking proceeding

for the purpose of establishing detailed market analysis criteria for eliminating the price

cap for specific transmission segments or paths.

Posting and Filing Requirements

802. Some commenters support the proposal to require transmission providers to

submit quarterly reports and make OASIS postings regarding reassignments of

transmission capacity.

476

Bonneville asserts that, at a minimum, transmission customers

should be required to provide a downloadable file to the transmission provider for posting

on the transmission provider’s OASIS that identifies the assignee, the amount of capacity

assigned or transferred, the date of the offer of assignment, and the rate and duration of

the assignment. Other commenters argue that transmission customers should be given

greater reporting responsibility.

477

Southern contends that transmission providers should

not be burdened with submitting quarterly reports and making OASIS postings based on

476

E.g., Bonneville, FirstEnergy, and PJM.

477

E.g., EEI, Entergy, Nevada Companies, PNM-TNMP, South Carolina E&G,

Southern, and TVA.

Docket Nos. RM05-17-000 and RM05-25-000 - 460 -

assignment information provided to them by other assignors/assignees. Rather, Southern

and EEI argue that assignment information should be filed by the respective assignors

and assignees in connection with their Electric Quarterly Report filings and not by the

transmission provider. PNM-TNMP contend that the Commission should prescribe

specific reporting obligations and associated deadlines to the assignors and reporting

obligations should also include appropriate consequences for non-compliance on the part

of the assignor. Nevada Companies ask that a system be put in place to charge relevant

transmission customers for the additional reporting if the transmission provider is

required to do the reporting, either on the OASIS or through some other mechanism.

803. Some commenters argue that more information should be posted on OASIS

beyond what was proposed in the NOPR.

478

EEI asserts that the details the transmission

customers should report on the OASIS and in the quarterly reports include: the identity of

the primary market seller; the identities of the secondary market seller and purchaser; the

points of receipt and delivery; the term of reassigned service; the quantity of the

reassigned service; and the charge for the reassignment, expressed in dollars per MW-

month, week, day, or hour as appropriate. Other commenters contend that the existing

quarterly report is appropriate and a new report should not be instituted.

479

TranServ

argues that the existing OASIS posting template query and audit functions are sufficient

478

E.g., EEI, PJM, and Seattle.

479

E.g., PJM, PNM-TNMP, and TranServ.

Docket Nos. RM05-17-000 and RM05-25-000 - 461 -

and no new obligations should be required. As to frequency of OASIS postings, Seattle

suggests seven days after a transaction and NorthWestern proposes that the OASIS

postings be no more frequent than monthly.

804. Other commenters raise confidentiality concerns or state that business practice

standards for capacity reassignment posting requirements would be required.

480

Because

these negotiated rates will be market sensitive, Allegheny asks the Commission not to

require reporting and OASIS posting until the term of the reassignment has expired.

NAESB states that capacity reassignment, including removing the price cap and allowing

negotiated rates, could require posting standards for OASIS sites and the addition of

significant functions to support such postings.

805. NAESB states that capacity reassignment including removing the price cap and

allowing negotiated rates could require posting standards for the OASIS site, and

significant functions added to support such postings. NAESB asserts that this will

require a more comprehensive standards solution, which may include data aggregation by

the transmission provider, reports prepared and posted quarterly including how the

information is communicated between the transmission provider and marketer for

collection, submittals of quarterly reports from the transmission provider to the

Commission, changes to the OASIS S&CP, and determination of informational content

and design of templates. NAESB states that posting is more complicated if the

480

E.g., Allegheny, Morgan Stanley, NAESB, Seattle, and TranServ.

Docket Nos. RM05-17-000 and RM05-25-000 - 462 -

transmission provider is required to post information given to it by a marketer on its non-

standard products and requests Commission guidance regarding posting requirements.

Other Issues

806. Some commenters argue that price caps are not limiting capacity reassignment

under the current pro forma

OATT.

481

Williams contends that other non-price limitations

on capacity reassignment, such as the requirement that the assignee utilize the same

source and sink as the original customers, are the real reasons there has not been more

capacity reassignment. Williams acknowledges that this bars network customers from

reassigning transmission capacity and requests that Commission clarify that classification

of a transmission customer as a network or point-to-point customer does not restrict the

purchase or reassignment of transmission capacity. Sacramento similarly complains that

one of the chief impediments to capacity reassignment is that network integration service

customers are not permitted either to assign their capacity or to utilize it to make off-

system sales. Sacramento contends that a point-to-point customer may utilize otherwise

unused capacity to make sales “off-system” to third parties, while network customers

cannot make full use of the transmission capacity for which they are paying.

807. Some commenters contend that timelines for the release of capacity should be

clearly stated.

482

APPA argues that section 13.8 of the pro forma OATT provides too

481

E.g., Powerex, Sacramento, TAPS, and Williams.

482

E.g., APPA, Powerex, and SPP.

Docket Nos. RM05-17-000 and RM05-25-000 - 463 -

little time for LSEs attempting to make firm power supply arrangements to obtain even

daily firm point-to-point service using the capacity left unscheduled by other firm point-

to-point customers. Powerex and SPP also ask the Commission to set out clear rules,

including timelines, for releasing unused transmission capacity for non-firm use to better

encourage full and economically efficient use of the existing transmission grid.

Commission Determination

808. To foster the development of a more robust secondary market for transmission

capacity, the Commission concludes that it is appropriate to lift the price cap for all

transmission customers reassigning transmission capacity. In Order No. 888, the

Commission found that allowing holders of firm transmission capacity rights to reassign

capacity would help parties manage the financial risks associated with their long-term

commitments, reduce the market power of transmission providers by enabling customers

to compete, and foster efficient capacity allocation.

483

Over the past ten years, however,

it has become clear that capacity reassignment has failed to develop into a competitive

alternative to primary capacity. In particular, the price cap has served to reduce

customers’ transmission options and impaired the development of a secondary market for

transmission capacity. In order to achieve the goals originally stated in Order No. 888,

we therefore lift the price cap for reassigned capacity. We believe this will allow

capacity to be allocated to those entities that value it most, thereby sending more accurate

483

Order No. 888 at 31,696.

Docket Nos. RM05-17-000 and RM05-25-000 - 464 -

price signals to identify the appropriate location for construction of new transmission

facilities to reduce congestion.

809. We decline to adopt the NOPR proposal to retain price caps for capacity resold by

a transmission provider’s merchant function or its affiliates.

484

After reviewing the

comments submitted in response to the NOPR, and further considering our ten years of

experience regulating capacity reassignments, we conclude that retaining the price caps

for this portion of the market would continue to impair development of the secondary

market and is not otherwise necessary to ensure just and reasonable rates. We find there

are no significant market power concerns to justify retaining the price caps for any

transmission customer. Indeed, the Commission did not distinguish between affiliated

and non-affiliated transmission customers when it initially found in Order Nos. 888 and

888-A that excess capacity reserved could be reassigned.

485

The Commission instead

placed a price cap on all reassignments of capacity out of a concern that the entire market

for reassigned capacity was not sufficiently competitive.

486

We now find that market

forces, combined with the requirements of the pro forma

OATT as modified in this Final

484

Because Order Nos. 888 and 888-A require a separation of a public utility’s

transmission function and its wholesale generating marketing (merchant) function, a

transmission provider will take service under its OATT through its merchant function or

affiliate.

485

Order No. 888 at 31,696-97; Order No. 888-A at 30,219-25.

486

Order No. 888 at 31,697.

Docket Nos. RM05-17-000 and RM05-25-000 - 465 -

Rule, will limit the ability of assignors to exert market power, including affiliates of the

transmission provider. First, competition among reassigning customers will restrict the

exercise of market power. Second, the continued regulation of rates for primary capacity

will act as a further check to ensure rates for reassigned capacity remain just and

reasonable. Finally, the amended rules we adopt below to govern the reassignment of

capacity will increase our regulatory oversight of the secondary capacity market,

allowing us to effectively monitor the secondary capacity market. There is thus no need

to retain the existing price caps on reassigned capacity for any market participant.

810. Our decision to lift the price caps for capacity reassignments by all transmission

customers is motivated by growing concerns regarding the decrease in transmission

investment and the corresponding increase in congestion costs, as described more fully in

section III.C of this Final Rule. The Commission believes it is important to take every

opportunity to explore more efficient use of the grid by industry participants, whether

they are affiliates of the transmission provider or not. Eliminating the price cap for

reassigned capacity will provide greater flexibility to respond to changing system

conditions and alternatives for customers that value the capacity more highly. As

commenters suggest, lifting the price cap will enhance the ability of customers that

reserve long-term capacity for five-year terms in order to obtain rollover rights to resell

Docket Nos. RM05-17-000 and RM05-25-000 - 466 -

that capacity if their needs change.

487

Other customers may determine that it is more

economic to acquire reassigned capacity reflecting market rates than reserve long-term

capacity. In either case, lifting the price cap will help ensure that, during peak demand

periods, transmission capacity will be used by those that value it the most. Establishing a

competitive market for secondary transmission capacity will thus send more accurate

price signals that promote efficient use of the transmission system by fostering the

reassignment of unused capacity.

811. While some commenters argue that lifting the cap encourages the exercise of

market power, including hoarding, and discourages transmission investment, we find that

competition among reassigning customers, continuing rate regulation of the transmission

provider’s primary capacity, and reforms to the secondary capacity market adopted

below, combined with enforcement proceedings, audits, and other regulatory controls,

will assure just and reasonable rates. The Commission discussed the possibility of

transmission capacity hoarding in Order No. 888. The Commission noted that

unscheduled firm capacity is available on a non-firm basis to other customers and, thus,

there is little practical possibility of hoarding. Instead, the capacity reassignment

provisions of the pro forma

OATT provide an economic incentive to make that capacity

487

As explained in section V.D.3, the Final Rule extends from one year to five

years the minimum term required to obtain a rollover right.

Docket Nos. RM05-17-000 and RM05-25-000 - 467 -

available to third parties.

488

This applies even when the entity obtaining transmission

capacity under the pro forma

OATT is the transmission provider.

489

It is equally in the

corporate interests of a transmission provider and its affiliates not to over-reserve or

“hoard” transmission capacity. Under the pro forma

OATT, the affiliate – and therefore

the upstream corporate parent of the affiliate and the transmission provider – bears the

cost responsibility for transmission capacity that it reserves but does not use to make

wholesale sales. If the affiliate attempts to hoard transmission capacity, its upstream

corporate parent loses revenues just like the non-affiliate. Like any other customer, an

affiliate of the transmission provider should find it in its overall corporate interest to

reassign transmission capacity to others with higher valued uses at negotiated rates.

490

812. We reject the suggestion in the NOPR that lifting the price caps for the

transmission providers’ merchant function or affiliates will provide disincentives to build

488

Order No. 888 at 31,693.

489

See Southwestern Public Service Company, 80 FERC ¶ 61,245 at 61,905

(1997).

490

Moreover, Order No. 889 required that all public utilities establish or

participate in an OASIS that meets certain specifications and comply with Standards of

Conduct designed to prevent employees of a public utility (or any employees of its

affiliates) engaged in wholesale power marketing functions from obtaining preferential

access to pertinent transmission system information. The Standards of Conduct mitigate

the ability of an affiliate to hoard capacity or collect rates that are inconsistent with

market conditions. As a result, we are less concerned in this instance about affiliates

competing on the same terms as non-affiliates. To the extent problems arise from

affiliate participation in the secondary capacity market, we will revisit our decision here

to lift the price caps for transmission providers and their affiliates.

Docket Nos. RM05-17-000 and RM05-25-000 - 468 -

or expand the transmission system. Without congestion, the transmission provider’s rate

on file will serve as the de facto

price cap and, if congestion exists, the “incremental rate”

reflecting the transmission provider’s cost of expanding the system should act as a price

ceiling for long-term transactions. It would be unreasonable to expect a transmission

customer to pay a rate for reassigned capacity that is higher than the cost of expansion

when it could simply exercise its rights under the pro forma

OATT as a cheaper

alternative. To the extent there is a lag-time between the request for new transmission

service and the date on which new facilities would be available, the adoption of

conditional firm service and modifications to redispatch service elsewhere in this Final

Rule will mitigate the exercise of market power during the interim period. We believe

that the reforms to rules governing reassignments of capacity discussed below, along with

associated reporting obligations, will adequately limit the ability of capacity holders to

exercise market power in the limited circumstances when neither primary transmission

capacity nor these additional services are available.

813. Several commenters raise concerns that lifting of the price ceiling could lead to

speculative pricing. If high prices occur during periods of peak demand it is a legitimate

reaction to supply and demand forces. As we explained in Order No. 637-A, “[a] surge

in the price of candles during a power outage is not evidence of monopoly in the candle

market.”

491

To the extent that capacity is not being anticompetitively withheld from the

491

Order No. 637-A at 31,595.

Docket Nos. RM05-17-000 and RM05-25-000 - 469 -

market, high prices are the competitive responses to market conditions and should result

in a more efficient allocation of capacity to those customers valuing it the most and a

resulting expansion of transmission facilities.

814. We emphasize that we are not deregulating or otherwise adopting market-based

rates for the provision of transmission service under the pro forma

OATT. Transmission

providers will continue to be obligated to make ATC available to customers, including

ATC associated with purchased but unused capacity. Transmission providers also will

continue to be obligated to construct new facilities to satisfy a request for service if that

request cannot be satisfied using existing capacity. The pro forma

OATT therefore does

not, and will not, permit the withholding of transmission capacity in an effort to exercise

market power. Furthermore, the rates for transmission service provided under the pro

forma OATT will continue to be determined on a cost-of-service basis unless the

transmission provider can demonstrate, on a case-specific basis, that it lacks market

power. Nothing in this Final Rule affects the obligations of transmission providers to

offer service under the pro forma

OATT at cost-based rates. The only reform being

adopted concerns the resale

of capacity by transmission customers. Given that traditional

regulation will continue to govern the sale of primary capacity under the pro forma

Docket Nos. RM05-17-000 and RM05-25-000 - 470 -

OATT, we no longer believe that cost-of-service regulation is necessary or appropriate

for secondary capacity.

492

815. As with any innovative rate program, however, the Commission will monitor the

secondary capacity market to ensure that participants are not exercising market power.

To enhance oversight and monitoring by the Commission, we adopt reforms to the

underlying rules governing capacity reassignments. First, we require that all sales or

assignments of capacity be conducted through or otherwise posted on the transmission

provider’s OASIS on or before the date the reassigned service commences. The

Commission thus eliminates the current ability of transmission customers to assign the

transmission rights to another party with subsequent notification to the transmission

provider.

493

The mechanisms for negotiating a reassignment remain the same. The

transmission customer may either request that the transmission provider make the

capacity available on its OASIS or the transmission customer may negotiate the terms of

an assignment bilaterally. In either instance, however, the resulting sale or assignment

must be posted by the transmission provider on its OASIS prior to the date the reassigned

service commences. We require transmission providers working through NAESB to

492

Our findings here address the particular circumstances associated with the

electric utility industry and are not intended to suggest that corresponding changes should

be made to the rates for capacity release by customers of natural gas transportation

capacity. Any such changes would be considered only after notice and comment and

based on a record applicable to the natural gas industry.

493

See Order No. 888 at 31,697.

Docket Nos. RM05-17-000 and RM05-25-000 - 471 -

develop appropriate OASIS functionality to allow such postings. Transmission providers

need not implement this new OASIS functionality and any related business practices until

NAESB develops appropriate standards.

816. Second, we require that assignees of transmission capacity execute a service

agreement prior to the date on which the reassigned service commences. Under the

current pro forma

OATT, transmission customers that have executed service agreements

may negotiate and implement assignments of capacity without involving the transmission

provider, subject to after-the-fact reporting and posting, provided the transmission

customer has a market-based rate tariff on file.

494

In order to increase our oversight of

reassigned capacity, we find that all reassignments must instead be accomplished by the

assignee executing a service agreement with the transmission provider that will govern

the provision of reassigned service.

495

This will effectively return the specified capacity

to the transmission provider for the purpose of reassignment to the assignee.

496

The

494

See Order No. 888 at 31,697 n.394; Order No. 888-A at 30,224 n.151.

495

The pro forma Form of Service Agreement for the Resale, Reassignment or

Transfer of Long-Term Firm Point-to-Point Transmission Service is set forth in a new

Attachment A-1 to the pro forma

OATT.

496

As reformed in this Final Rule, the structural mechanism for reassigning

transmission capacity will be similar to the mechanism for releasing pipeline capacity.

While parties may be able to negotiate the prices applicable to assigned capacity, the

assignee will execute a service agreement directly with the transmission provider and,

thus, there will no longer be a need for the assigning party to have on file with the

Commission a rate schedule governing reassigned capacity. See

Order No. 888 at 31,697

n. 324. The transmission provider’s OATT will govern the reassigned service. The

(continued)

Docket Nos. RM05-17-000 and RM05-25-000 - 472 -

assignment shall be only to the specified assignee, without any obligation that the

capacity be made available to third parties, and shall not be subject to any queuing by the

transmission provider since the assignee is merely accepting the assignor’s already-

approved service for a specified period.

497

All of the non-rate terms and conditions that

otherwise would apply to the transmission provider’s sale of transmission capacity

continue to apply in the case of a reassignment.

498

817. Third, in addition to existing OASIS posting requirements, we require

transmission providers to aggregate and summarize in an electronic quarterly report the

data contained in these service agreements. As proposed in the NOPR, the use of

quarterly reports will assist the Commission in gathering data to ensure the effectiveness

of market forces and regulatory requirements to mitigate the exercise of market power.

assignee will pay the transmission provider for service at the negotiated rate and the

transmission provider will bill or credit the assignor with any the difference between the

negotiated rate and the assignor’s original rate. As noted above, however, there will be

no requirement for the transmission provider to create an auction for reassigned

transmission capacity similar to the pipeline capacity reassignment program, since the

underlying price caps are being removed for electric transmission capacity.

497

To the extent the assignee desires to change its points of receipt or delivery, the

limitations set forth in section 23.2 shall apply.

498

See Commonwealth Edison Co., 78 FERC ¶ 61,312 at 62,336 (1997); Boston

Edison Co., 81 FERC ¶ 61,372 at 62,768 (1997); Southwestern Public Service Co.,

80 FERC ¶ 61,245 at 61,905 (1997). The non-rate terms and conditions of reassigned

service will therefore conform to the pro forma

OATT. As a result, there is no

requirement to file with the Commission service agreements for reassigned transmission

service.

Docket Nos. RM05-17-000 and RM05-25-000 - 473 -

The Commission directs that this quarterly report be submitted electronically in

spreadsheet format consistent with the electronic filing system used for Electric Quarterly

Reports so that it is readily accessible to the Commission and the public.

499

818. Taken together, these reforms to the rules governing reassigned capacity will

increase transparency and facilitate our monitoring of the secondary market for

transmission capacity. We do not believe it is necessary to require a market power

analysis as a condition to exercising the right to reassign transmission capacity. Although

market power analyses are one method for ensuring that market-based rates remain just

and reasonable, they are not the only method.

500

To achieve the Commission’s original

goals for capacity reassignment expressed in Order No. 888, we adopt a more flexible

approach in this area and rely on posting requirements and other regulatory controls to

ensure that rates for reassigned transmission capacity remain just and reasonable. As

noted above, we find that a market power analysis is not required because transmission

499

The transmission provider should identify capacity reassignments in the

Contracts tab of the EQR using the Product Type Name “CAPACITY

REASSIGNMENT.” All terms must be fully described and rates provided. If no Product

Name adequately captures the nature of a given aspect of the capacity reassignment, the

assignor may use the Product Name “OTHER,” but that aspect must be fully described in

the Rate Description field. If that description is over 150 characters, the transmission

provider may use multiple Contract Product lines to describe it. General instructions on

how to file the EQR may be found at http://www.ferc.gov/docs-filing/eqr.asp

500

See Alternatives to Traditional Cost-of-Service Ratemaking for Natural Gas

Pipelines and Regulation of Negotiated Transportation Services of Natural Gas Pipelines,

74 FERC ¶ 61,076 (1996).

Docket Nos. RM05-17-000 and RM05-25-000 - 474 -

providers continue to be obligated to satisfy requests for service – whether out of existing

capacity or new facilities – at cost-based rates. Transmission capacity therefore cannot

be withheld in an effort to exercise market power. Moreover, the posting and filing

requirements adopted herein provide the Commission the necessary information to ensure

that, even if an entity sought to exercise market power in the secondary market, such an

attempt could be effectively detected.

819. We therefore disagree with commenters who assert that lifting the cap on

reassignment contradicts judicial and Commission precedent. In Order No. 637-A, the

Commission explained at length why Farmers Union

501

and other precedent did not

prevent the Commission from adopting negotiated rates for secondary capacity as part of

a regulatory scheme that provides safeguards to ensure that rates remain just and

reasonable.

502

The court affirmed the Commission’s removal of price ceilings for short-

term capacity release shippers in the natural gas market established in Order Nos. 637

and 637-A, recognizing that non-cost factors such as the need to lift price ceilings to

facilitate movement of capacity into the hands of those who value it most and the

negotiated rates only to the secondary market distinguished the case from Farmers

501

Farmers Union Central Exchange v. FERC, 734 F.2d 1486, 1501 (D.C. Cir.

1984) (Farmers Union

) (finding that Commission failed to justify relaxation of cost-based

regulation of oil pipeline companies because it did not ensure rates would remain within

the zone of reasonableness).

502

Order No. 637-A at 31,558-72.

Docket Nos. RM05-17-000 and RM05-25-000 - 475 -

Union

503

The same is true here, given the non-cost factor advantages of lifting the price

cap and the use of monitoring and enforcement of remedies to mitigate the exercise of

market power.

820. The Commission directs staff to closely monitor the reassignment-related data

submitted by transmission providers in their quarterly reports to identify any problems in

the development of the secondary market for transmission capacity and, in particular, the

potential exercise of market power. We direct staff to prepare, within six months of

receipt of two years of quarterly reports, a report summarizing its findings. To inform

our analysis, we encourage market participants to provide feedback regarding the

development of the secondary capacity market and, in particular, to contact the

Commission’s Enforcement Hotline

504

with any particular concerns as this market

develops.

821. Although several commenters argue that additional posting and filing

requirements could be too burdensome and costly, the Commission does not believe this

burden will be great. All capacity reassignments must be conducted or otherwise posted

on OASIS and each assignee will be required to submit an executed service agreement

503

Interstate Natural Gas Association of America v. FERC, 285 F.3d 18 (D.C. Cir.

2002).

504

Market participants may contact the Commission’s Enforcement Hotline via

telephone (202) 502-8390, toll-free 1-888-889-8030, fax (202) 208-0057, or at

http://www.ferc.gov/contact-us/enforce-hot.asp.

Docket Nos. RM05-17-000 and RM05-25-000 - 476 -

for reassigned service. The transmission provider thus will have ready access to data

necessary for the OASIS postings and electronic quarterly transaction reports. In any

event, the Commission’s access to this data is vital to ensure effective monitoring and

oversight and, thus, we find that any burden on the transmission provider is outweighed

by the need for transparency. To the extent the transmission provider incurs costs to

maintain or report this information, Order No. 889 made clear that all OASIS users,

including the transmission provider, pay all of the fixed costs of OASIS-related activities

in wholesale rates and pay usage-related variable costs and fees.

505

822. With regard to confidentiality concerns, the Commission finds that the disclosure

of reassigned capacity information is necessary for the Commission and market

participants to effectively monitor transactions for undue discrimination and preference.

Consistent with our determination in Order No. 2001, where similar concerns were raised

regarding disclosure of information, we believe that disclosure will promote competition

and make the market operate more efficiently.

506

Moreover, public reports will provide

customers with a certain level of price transparency to help them make informed

decisions regarding the relative value of capacity on a particular path.

823. We decline requests to require implementation of electronic auctions for

reassigned capacity. While such mechanisms are in place in RTO and ISO markets, we

505

Order No. 889 at 31,625.

506

See Order No. 2001 at P 94-129.

Docket Nos. RM05-17-000 and RM05-25-000 - 477 -

conclude that it would be too great a burden to impose electronic auctions on other

transmission providers simply to facilitate capacity reassignments. The continued use of

OASIS, combined with the posting and service agreement requirements adopted here,

should be sufficient to facilitate more efficient use of the grid and mitigate the exercise of

market power.

824. With regard to the requests that the Commission institute alternative specific

timelines and other rules for the reassignment of capacity rights to ensure efficient use of

the grid, we will not revise the rules set forth in the pro forma

OATT. We do not have

sufficient evidence in this proceeding to suggest that public utilities’ existing scheduling

timelines generally hinder customers from reselling unused transmission capacity or lead

to capacity withholding.

825. With regard to requests for network customers to reassign transmission capacity,

we affirm our finding in Order Nos. 888 and 888-A that capacity reassignments are

available only to point-to-point customers.

507

Point-to-point service under the pro forma

OATT clearly sets forth defined capacity rights and is therefore reassignable. In

comparison, there are no specific capacity rights associated with network service and,

thus, that service is not reassignable. Network service provides a network customer with

a right to integrate its designated resources with its designated loads, in a generation

pattern primarily determined by the customer. As a result, it would be difficult to

507

Order No. 888 at 31,696; Order No. 888-A at 30, 223

Docket Nos. RM05-17-000 and RM05-25-000 - 478 -

determine at any moment in time exactly what portion of network service could be

resold, because the network customer does not have a discrete capacity reservation and its

usage of the transmission system varies as it attempts to most economically use its

resources to meet its loads. To the extent an entity elects network service, it does so with

the understanding that the service is not reassignable because there are no specific

capacity rights to reassign.

5. “Operational” Penalties

a. Unreserved Use Penalties

NOPR Proposal

826. In the NOPR, the Commission proposed to clarify that unreserved use penalties

apply to any circumstance where a transmission customer uses transmission service that it

has not reserved.

508

Specifically, the transmission customer would be subject to an

unreserved use penalty in circumstances where the transmission customer has a

transmission service reservation, but uses transmission service in excess of its reserved

capacity. A transmission customer also would be subject to an unreserved use penalty if

the transmission customer uses transmission service where it does not have a

transmission service reservation. The Commission also proposed that a transmission

customer would not be subject to an unreserved use penalty in circumstances where the

508

In the NOPR, we referred to an unreserved use penalty as an “unauthorized use

penalty.” For the purpose of the Final Rule, we adopt the term “unreserved use penalty”

as it more clearly articulates the nature of the penalty.

Docket Nos. RM05-17-000 and RM05-25-000 - 479 -

transmission customer inappropriately uses a network service reservation to support an

off-system sale.

827. The Commission sought comment on whether the current policy that limits

unreserved use penalties to twice the standard rate for the entire service period has

resulted in penalties that are not just and reasonable and, if so, it sought further comment

regarding provisions that would yield unreserved use penalties that are just and

reasonable.

(1) Unreserved Use of Transmission Service

Comments

828. Several commenters express general support for the Commission’s proposed

clarification that unreserved use penalties apply to any circumstance where a

transmission customer uses transmission service that it has not reserved.

509

Several

commenters support the Commission’s proposed clarification, but suggest that the

transmission provider should only assess unreserved use penalties when a transmission

customer repeatedly uses transmission service that it has not reserved.

510

For instance,

PNM-TNMP believes penalty assessment should be optional and should be imposed on

transmission customers that do not change their practices regarding transmission use and

OATT compliance after being advised of their non-compliance.

509

E.g., APPA and Bonneville.

510

E.g., MidAmerican, Southern, and PNM-TNMP.

Docket Nos. RM05-17-000 and RM05-25-000 - 480 -

829. Several commenters argue that transmission customers with special circumstances

should not be subject to unreserved use penalties in the same manner as other

transmission customers. For instance, Seattle believes unreserved use penalties can result

in charges that are unjust and reasonable for intermittent resources, such as wind

generators, that can not precisely schedule power in future periods, but are capable of

controlling output. Seattle believes that unreserved use penalties should not apply if the

transmission provider is able to operate the transmission system reliably. Seattle argues

that an unreserved use penalty should only apply if scheduling parties have failed to

respond to dispatchers’ orders stating that system conditions necessitate curtailment of

output. Southern disagrees with Seattle and states that, as a general principle, unreserved

use penalties should not be based on whether reliability is threatened. TDU Systems

recommend that the Commission consider treating inadvertent use of point-to-point

transmission service in excess of reservations by an entity serving native load in multiple

control areas as an energy imbalance in the control area in which the energy imbalance

occurs, rather than an unreserved use of point-to-point service. In their reply comments,

EEI and PNM-TNMP disagree with TDU Systems. EEI argues that energy imbalance

charges compensate generators for the additional expense they incur to compensate for

the customer’s failure to schedule sufficient energy to serve its load and do not

compensate the transmission provider for the use of the transmission system. EEI asserts

that customers that use more transmission service than they schedule should be required

to pay for that transmission service just like any other user of the system.

Docket Nos. RM05-17-000 and RM05-25-000 - 481 -

830. Duke opposes the Commission’s proposed clarification and suggests that an

effective means of deterring and punishing unreserved use of transmission service is to

charge the customer for the point-to-point service necessary to support the transaction

and, additionally, to make the customer subject to a civil penalty in cases of intentional or

repeated unreserved use. TDU Systems argue on reply that a transmission provider

should not be allowed to charge unreserved use penalties unless it employs software

technology designed to identify unreserved use prior to operation.

831. Several commenters suggest modifications to the manner by which transmission

providers determine when unreserved use penalties should be assessed. TDU Systems

believes unreserved use penalties should only be applied with prior Commission approval

after notice and opportunity for hearing in order to limit the transmission provider’s

discretion in applying such penalties. To encourage regulatory certainty, Seattle suggests

that the Commission implement tariff provisions that state a clear basis for application of

unreserved use penalties.

832. Several commenters ask that the Commission delete the proposed language added

to section 30.4 of the proposed revised pro forma

OATT regarding the unreserved use of

a network resource beyond its designated capacity.

511

In the event the Commission elects

to retain this language, these commenters ask the Commission to clarify the language to

expressly permit use of the undesignated portion of a remote network resource under

511

E.g., APPA, TAPS, TDU Systems, and EEI Reply.

Docket Nos. RM05-17-000 and RM05-25-000 - 482 -

secondary non-firm service (as a non-network resource) and to preserve the customer’s

right to use the undesignated portion of the resource for other purposes (e.g.

, to serve its

load on systems other than the host transmission provider or to make off-system sales).

In its reply comments, Duke notes that the fact that a generator is designated as a network

resource for a network load on one system does not prohibit a network load on a second

system from obtaining non-firm energy from that same generator using point-to-point and

secondary network resource. Duke points out that the proposed revised section 30.4

prohibits a network customer from using its firm network service to schedule power in

excess of the DNR amount. Finally, TAPS asks the Commission to modify the language

added to section 30.4 so that its terms are consistent with the terms used in the rest of the

pro forma

OATT.

833. EEI recommends that a customer that takes unreserved transmission service, but

that does not have a service agreement with the transmission provider, be deemed to have

consented to the transmission provider’s filing of a service agreement, so that the

transmission provider has a basis for imposing both the prevailing OATT rate and the

penalty charge on the customer. EEI also recommends that the Commission clarify that a

customer that uses more transmission service than it has reserved also is subject to

charges for ancillary services.

Commission Determination

834. The Commission adopts the NOPR proposal that a transmission customer will be

subject to unreserved use penalties in any circumstance where the transmission customer

Docket Nos. RM05-17-000 and RM05-25-000 - 483 -

uses transmission service that it has not reserved. Specifically, a transmission customer

will be subject to an unreserved use penalty in circumstances where a transmission

customer has a transmission service reservation, but uses transmission service in excess

of its reserved capacity. A transmission customer also will be subject to an unreserved

use penalty if the transmission customer uses transmission service where it does not have

a transmission service reservation, including the situations described in the Arizona

Public Service Company (APS) audit report.

512

We note that the transmission provider is

subject to the same penalties when it takes transmission service under its OATT.

835. Our decision to clarify the application of unreserved use penalties will eliminate a

potential source of discretion in the implementation of the pro forma

OATT and will

assist the Commission in its enforcement of the OATT obligations. The unreserved use

penalty itself will help discourage disorderly use of transmission service. Charging a

transmission customer for just the unreserved transmission service used, as suggested by

Duke, would not provide a sufficient incentive to procure adequate transmission service,

even with the threat of possible civil penalties. In addition, an operational penalty rather

512

Arizona Public Service Co., 109 FERC ¶ 61,271 at P 6 (2004) (APS). APS

contained two findings that Commission audit staff characterized as unauthorized use of

transmission service.

In the first finding, APS’s wholesale merchant function did not

request and pay for point-to-point service to support some of the off-system power sales

it made at trading hubs where APS system resources were directly connected. In the

second finding, APS incorrectly treated the Phoenix Valley 230kV system as a single

node on its transmission system. As a result, off-system sales made by generators

connected to the Phoenix Valley system should have been, but were not, supported by

point-to-point service.

Docket Nos. RM05-17-000 and RM05-25-000 - 484 -

than a civil penalty is a more appropriate default remedy, even though certain

circumstances may warrant a civil penalty in addition to an operational penalty. In most

instances, an unreserved use penalty can be applied in a relatively mechanical manner.

As a result, an operational penalty has a relatively low administrative burden and still

provides a clear signal to transmission customers regarding the cost of non-

compliance.

513

We do not agree with TDU Systems’ proposal that a transmission

provider be required to employ software designed to identify unreserved use if the

transmission provider wants to charge unreserved use penalties. As we explain below,

we adopt reforms in this Final Rule that will reduce the level of unreserved use penalties

for instances of inadvertent unreserved use. For instance, we reduce the period over

which a one-time inadvertent use will be penalized from one month to one day. We

believe that this and other reforms are sufficient to address TDU Systems’ concerns.

836. We will not adopt Seattle’s suggestion to add provisions to the pro forma

OATT

that specify all circumstances that constitute use of transmission service without a

transmission service reservation. Any list of transmission customer actions that would be

deemed to constitute use of transmission service without a transmission service

reservation will necessarily be incomplete and out-of-date given the dynamic manner by

which trading patterns and practices evolve. We believe that Commission actions, such

513

The unreserved use penalties thus work in conjunction with imbalance penalties

described in section V.C.2 of this Final Rule to reduce incentives to take actions that

impair the reliability of the transmission system.

Docket Nos. RM05-17-000 and RM05-25-000 - 485 -

as in APS

, will provide a sufficient guide to circumstances that constitute use of

transmission system without a transmission service reservation. We also reject TDU

Systems’ suggestion that unreserved use penalties be applied only after Commission

approval. As mentioned above, an unreserved use penalty can be assessed in a relatively

straightforward manner in most cases. As a result, there will typically be little need for

the Commission to become involved. That said, a transmission customer can always file

a complaint with the Commission protesting an unreserved use penalty.

837. We will not exempt any class of transmission customer from the potential

assessment of unreserved use penalties. We do not agree with Seattle’s assertion that

unreserved use penalties can result in charges that are unjust and reasonable for

intermittent resources, such as wind generators, that can not precisely schedule power in

future periods. Unreserved use penalties are based on the transmission capacity reserved

rather than the transmission service scheduled, so an intermittent resource’s inability to

precisely schedule power in future periods is irrelevant, as long as the resource has

reserved sufficient transmission capacity to deliver the resource’s full output. We also do

not agree with TDU Systems’ suggestion that unreserved use of transmission service by

an entity serving native load in multiple control areas should be treated as an energy

imbalance in the control area in which the energy imbalance occurs, rather than an

unreserved use of point-to-point service. In this regard, we agree with EEI that energy

imbalance charges compensate the transmission provider for the additional expense it

incurs to compensate for a transmission customer’s failure to schedule sufficient energy

Docket Nos. RM05-17-000 and RM05-25-000 - 486 -

to serve its load and do not compensate the transmission provider for the use of the

transmission system.

838. We will not limit unreserved use penalties to instances where the unreserved use

jeopardizes the reliable operation of the transmission system. Unreserved use penalties

are intended, in part, to give transmission customers an incentive to reserve and pay for

the appropriate level of transmission service so that transmission service is allocated in an

orderly fashion. A transmission customer that uses unreserved transmission service

requires the transmission provider to take some action to accommodate the additional use

of the system. Some penalty is warranted even in those instances when the transmission

provider’s accommodations are sufficient to avoid curtailment of transmission service to

other transmission customers. Absent a penalty in all instances, transmission customers

would have an increased incentive to under-reserve transmission service, which would

lead to an increase in the likelihood that system reliability would be impaired. In

addition, a transmission customer that uses more transmission service than it has

reserved, even in periods when system reliability has not been impaired, has nonetheless

disturbed the orderly allocation of transmission service.

839. In response to comments requesting that we remove the language added to section

30.4 of the proposed revised pro forma

OATT regarding the unreserved use of a network

resource beyond its designated capacity, we clarify our intent in modifying section 30.4.

The Commission has identified instances when a transmission provider has scheduled

delivery of off-system non-designated short-term purchases using transmission capacity

Docket Nos. RM05-17-000 and RM05-25-000 - 487 -

reserved for designated network resources.

514

The intent of the language added to section

30.4 of the pro forma

OATT was to clarify that network customers are subject to

unreserved use penalties when they schedule delivery of off-system non-designated

purchases using transmission capacity reserved for designated network resources. We

clarify, however, that a network customer may use the undesignated portion of a remote

network resource to serve network load using secondary network service and may use the

undesignated portion of the resource for other non-network service purposes, such as

third-party sales, as long as the network customer acquires the appropriate point-to-point

transmission service. Moreover, because a transmission provider does not have to “take

service” under its own OATT for the transmission of power that is purchased on behalf of

bundled retail customers, it is free to use the undesignated portion of a remote network

resource to serve its bundled retail customers.

515

If the transmission provider desires to

use a remote network resource for non-native load purposes, such as third-party sales, it

must acquire the appropriate point-to-point transmission service.

516

840. In order to ensure that the transmission provider has a basis for charging an

unreserved use penalty, we modify section 13.4 of the pro forma

OATT to provide that a

customer that takes unreserved point-to-point transmission service and does not have a

514

See MidAmerican Energy Co., 112 FERC ¶ 61,346 (2005); PacifiCorp,

118 FERC ¶ 61,026 (2007).

515

See Order No. 888-A at 30,216-17.

516

See id. at 30,217

Docket Nos. RM05-17-000 and RM05-25-000 - 488 -

service agreement with the transmission provider is deemed to have executed the

transmission provider’s form of service agreement for point-to-point service. In addition,

we clarify that a customer that uses more transmission service than it has reserved is also

subject to charges for ancillary services. The ancillary service charges will be based on

just the period of unreserved use. For instance, if a transmission customer has unreserved

use during two hours on the same day, the customer must pay the ancillary service

charges for those two hours, rather than for the entire day. This modification is

appropriate, as the transmission provider is entitled to compensation for the ancillary

services it provides when it provides transmission service. We also will modify section 3

of the pro forma

OATT to reflect this rule.

(2) Treatment of Inappropriate Use of Network Service as an

Unreserved Use of Point-to-Point Transmission Service

Comments

841. A few commenters argue that a transmission customer that inappropriately uses a

network service reservation to support an off-system sale should be subject to unreserved

use penalties.

517

Other commenters request clarification or modifications to the

Commission’s proposal regarding the treatment of transmission customers that

inappropriately use a network service reservation to support an off-system sale. TAPS

asks the Commission to clarify that a transmission provider that inappropriately uses

517

E.g., APPA and PNM-TNMP.

Docket Nos. RM05-17-000 and RM05-25-000 - 489 -

network service to support an off-system sale is required to pay for point-to-point service

to support the off-system sale and potentially is liable for civil penalties, as the

Commission proposed in the NOPR. Suez Energy NA suggests that an affiliate of the

transmission provider that violates network tariff provisions by making unauthorized

sales should also disgorge unjust profits from such sales. TDU Systems urges the

Commission not to impose civil penalties for inadvertent use of network service by an

LSE when it serves its own native load on a neighboring system.

Commission Determination

842. The Commission declines to adopt the NOPR proposal to exempt a network

customer or transmission provider that inappropriately uses network transmission service

to support off-system sales from unreserved use penalties. As mentioned above, one of

the purposes of unreserved use penalties is to encourage orderly use and acquisition of

transmission service. A network customer or transmission provider that inappropriately

uses network transmission service to support off-system sales potentially uses or acquires

transmission service that should be allocated to other transmission customers. In

addition, the network customer or transmission provider has not paid for transmission

service as required. Therefore, we conclude that a network customer or transmission

provider inappropriately using network transmission service to support off-system sales

should be subject to unreserved use penalties. We will evaluate the appropriateness of

civil penalties in addition to unreserved use penalties on a case-by-case basis and will not

exempt, as a matter of general policy, inadvertent use of network service by an LSE when

Docket Nos. RM05-17-000 and RM05-25-000 - 490 -

it serves its own native load on a neighboring system as suggested by TDU Systems. A

network customer or transmission provider that inappropriately uses network

transmission service to support off-system sales also may be required to disgorge unjust

profits from such sales, as the Commission may determine on a case-by-case basis.

(3) Penalty Rate for Unreserved Use of Transmission Service

Comments

843. Transmission providers generally assert that the Commission’s current policy of

limiting unreserved use penalties to twice the standard rate for the entire service period

has yielded just and reasonable rates.

518

EEI contends that if the customer is required to

pay an unreserved use charge only for the period of unreserved use, the customer would

have an incentive to reserve service for less than its maximum expected use and simply

pay unreserved use charges in the hours in which it exceeds that usage. EEI concedes,

however, that the maximum period for which the unreserved use charge should be

assessed is one month. For example, EEI acknowledges that it would be unreasonable to

charge a customer that takes yearly service a penalty for an entire year because of, for

instance, a single hour of unreserved use. In addition, EEI suggests several modifications

to the current unreserved use penalty policy. EEI suggests the Commission include, in

the pro forma

OATT, provisions stating that the penalty charge for unreserved use of

518

E.g., EEI, Bonneville, MidAmerican, Nevada Companies, and PNM-TNMP

Reply.

Docket Nos. RM05-17-000 and RM05-25-000 - 491 -

transmission service is equal to twice the standard rate for transmission service. EEI

recommends that the Commission establish a policy that a customer that uses

transmission service without a reservation must pay a penalty equal to twice the rate for

transmission service for the greater of the period of unreserved use or one month.

844. Transmission customers generally assert that unreserved use penalties should be

limited to twice the standard rate for the period of unreserved use.

519

Transmission

customers who take this position argue that using the service period rather than the period

of unreserved use as the basis for the penalty charge discriminates against transmission

customers with longer term transmission service reservations.

520

For instance, AWEA

believes that applying an unreserved use penalty based on the reservation period rather

than the period of unreserved use has resulted in charges that are not just and reasonable.

AWEA asserts that such a policy would also be discriminatory because, if the customer

causing the unreserved use had made a shorter reservation, its penalty would be much

lower. TDU Systems argue in its reply comments that there is little to be gained from

charging inadvertent unreserved use more than twice the standard rate for the period of

unreserved use.

845. Several commenters suggest that unreserved use penalty charges greater than

twice the standard rate for the entire service period should be limited to instances of

519

E.g., APPA, AWEA, TAPS, and TDU Systems.

520

E.g., APPA, AWEA, TAPS, and TDU Systems Reply.

Docket Nos. RM05-17-000 and RM05-25-000 - 492 -

intentional unreserved use.

521

Nevada Companies note that there are some marketing

entities that are consistently abusing the current policy and recommends that the

Commission consider more severe penalties for continuous carelessness in tagging or a

repeated pattern of unreserved use of the transmission system. Southern believes the

transmission provider should be permitted to charge increased unreserved use penalties if

a transmission customer consistently uses transmission services it has not reserved. TDU

Systems disagree on reply comments, arguing that a penalty equal to twice the applicable

charge is sufficient to deter unreserved use of transmission service.

Commission Determination

846. We will continue giving transmission providers discretion in setting their

unreserved use penalty rates, although those rates will need to be consistent with this

Final Rule. Penalty charges must be based on the period of unreserved use rather than

the period for which service is reserved, subject to the following principles. First, the

unreserved use penalty for a single hour of unreserved use will be based on the rate for

daily firm point-to-point service, even if the transmission provider has a rate for hourly

firm point-to-point transmission service on file. Second, as a general rule, more than one

assessment for a given duration (e.g.

, daily) will increase the penalty period to the next

longest duration (e.g.

, weekly). The unreserved penalty charge for multiple instances of

unreserved use (i.e.

, more than one hour) within a day will be based on the rate for daily

521

E.g., NRECA, Nevada Companies, and Southern.

Docket Nos. RM05-17-000 and RM05-25-000 - 493 -

firm point-to-point service. The unreserved penalty charge for multiple instances of

unreserved use isolated to one calendar week would result in a penalty based on the

charge for weekly firm point-to-point. The unreserved use penalty charge for multiple

instances of unreserved use during more than one week during a calendar month will be

based on the charge for monthly firm point-to-point.

522

847. Our determination is based, in part, on agreement with those commenters arguing

that using the period for which a transmission customer has reserved service rather than

the period of unreserved use as the basis for the penalty charge discriminates against

transmission customers with longer term transmission service reservations. We are

mindful, however, that basing unreserved use penalties on only the period of unreserved

use could give the transmission customer an incentive to reserve service for less than its

maximum expected use and simply pay unreserved use charges in the hours in which it

exceeds that usage. We believe the unreserved penalty regime we articulate in this Final

522

There are a number of possible permutations of these principles. For instance,

a transmission customer that has 25 MW of unreserved use in two hours on one day

during the first week of the month and 50 MW of unreserved use in two hours on one day

during the last week of the month will pay an unreserved use penalty based on the rate for

25 MW of daily firm point-to-point service and 50 MW of daily firm point-to-point

service. A transmission customer that has 25 MW of unreserved use on two separate

days during the first week of the month and 50 MW of unreserved use in two hours on

one day during the last week of the month will pay an unreserved use penalty based on

the rate for 25 MW of weekly firm point-to-point service and 50 MW of daily firm point-

to-point service. A transmission customer that has 25 MW of unreserved use on two

separate days during the first week of the month and 50 MW of unreserved use on two

separate days during the last week of the month will pay an unreserved use penalty on 50

MWs of monthly firm point-to-point service.

Docket Nos. RM05-17-000 and RM05-25-000 - 494 -

Rule will provide a reasonable incentive to ensure that transmission customers reserve the

appropriate level of transmission service without unduly charging a transmission

customer for inadvertent unreserved use. In addition, transmission customers will

continue to be subject to civil penalties on a case-by-case basis, so attempts to game this

penalty regime could result in additional penalties depending on the specific facts at

issue. We reject the suggestion in some comments that the transmission provider should

only assess unreserved use penalties where a transmission customer repeatedly uses

transmission service that it has not reserved. Rather, we find that penalties are

appropriate for all unreserved uses of the system. Because we are allowing penalties to

be based on the period of unreserved use, not the reservation period, such penalties do not

unduly charge a transmission customer for inadvertent unreserved use. This penalty

regime will apply to all instances where a transmission customer has an unreserved use of

transmission service, regardless of whether the transmission customer had an existing

relevant transmission service reservation but for a lesser amount of service.

848. A transmission provider that wants to charge unreserved use penalties must

explicitly state the penalty rate in its tariff. The Commission retains the current policy

established in Allegheny

that the unreserved use penalty rate may not be greater than

twice the firm point-to-point rate for the period of unreserved use, as defined above.

523

Allegheny Power System, Inc., 80 FERC ¶ 61,143 at 61,545-46 (1997)

(Allegheny

Docket Nos. RM05-17-000 and RM05-25-000 - 495 -

We continue to believe that penalties up to twice the relevant firm point-to-point rate are

just and reasonable, given the new definition for the penalty period. As a result, we

establish a rebuttable presumption that unreserved use penalties no greater than twice the

firm point-to-point rate for the penalty period defined above are just and reasonable. As

we discuss above, the transmission customer must face a penalty in excess of the firm

point-to-point transmission service charge it avoids through unreserved use of

transmission service or the transmission customer will have no incentive to reserve the

appropriate amount of service.

849. The Commission thus concludes that a penalty of twice the standard rate is not

excessively punitive, particularly given the definition of the penalty period established in

this Final Rule. Without evidence to the contrary, we believe an unreserved use penalty

equal to twice the applicable rate should create the appropriate incentive to transmission

customers to purchase the correct amount of transmission service. Nonetheless, we will

allow transmission providers to make a filing under section 205 of the FPA to propose a

unreserved use penalty in excess of twice the relevant firm point-to-point rate for

pervasive unreserved use. Transmission providers that propose such a rate must establish

that a higher penalty rate is required to combat pervasive unreserved use of transmission.

In arguing for such a higher penalty rate, the transmission provider must address why the

standard penalty rate that penalizes repeated unreserved use is not adequate to discourage

repeated instances of unreserved use of transmission service.

Docket Nos. RM05-17-000 and RM05-25-000 - 496 -

b. Distribution of Operational Penalties

NOPR Proposal

850. In the NOPR, the Commission proposed to have the transmission provider

distribute to non-offending, unaffiliated transmission customers operational penalties

incurred by the transmission provider’s merchant function or its affiliates.

524

For those

transmission providers subject to operational penalties, the Commission proposed to

require the transmission provider to make an annual compliance filing to notify the

Commission of the amounts of such operational penalties incurred during the year and to

propose a method to identify non-offending, unaffiliated transmission customers to which

the transmission provider would distribute penalty amounts. In addition, the Commission

also proposed to allow a transmission provider to avoid an annual compliance filing by

making a one-time filing to propose a mechanism through which it would identify non-

offending, unaffiliated transmission customers and a method by which it would distribute

the operational penalties it or its affiliates have incurred to the identified transmission

customers. Finally, the Commission proposed to prohibit transmission providers from

recovering for ratemaking purposes or through any service or facility under the

524

An operational penalty explicitly defines the charge associated with a set of

pre-defined activities (e.g.

, unreserved use of transmission service, completing request

studies outside of the 60-day due diligence deadline) that are not in compliance with

specific provisions of the OATT.

Docket Nos. RM05-17-000 and RM05-25-000 - 497 -

Commission’s jurisdiction any cost it incurs when it or an affiliate pays an operational

penalty.

Comments

851. Transmission customers along with several other commenters support the

Commission’s proposal to distribute operational penalties paid by the transmission

provider’s merchant function to non-offending, unaffiliated transmission customers.

525

Entegra and Morgan Stanley advocate extending the proposal so that the transmission

provider distributes operational penalties paid by all transmission customers to non-

offending unaffiliated transmission customers. Entegra also notes that the Commission’s

policy in the natural gas setting is that pipelines must credit all penalty revenues back to

non-offending shippers. Entegra argues that the precedent the Commission cited in

proposing that operational penalties paid by the transmission provider be distributed to

non-offending, unaffiliated transmission customers applies equally to penalties paid by

affiliated and unaffiliated transmission customers.

526

852. With regard to unreserved use penalties, NRECA and TDU Systems argue that the

Commission should encourage transmission providers to supervise inadvertent

unreserved use and notify the customer of such occurrence rather than rely on large

525

E.g., APPA, ELCON, Entegra, TAPS, TDU Systems, Sacramento, and Seattle.

526

Entegra cites Carolina Power & Light Co. and Florida Power Corp., 103 FERC

¶ 61,209 at P 24 (2003) (Carolina Power & Light

Docket Nos. RM05-17-000 and RM05-25-000 - 498 -

unreserved use penalties. They argue it is better to prevent unnecessary costs than to

approve post hoc

penalties for unintentional unreserved use that could have been

prevented.

853. A number of transmission providers oppose the portion of the Commission’s

proposal that would prohibit their non-offending affiliates from receiving a portion of the

operational penalties the transmission provider incurs.

527

For instance, PNM-TNMP

asserts that the Commission should allow the transmission provider’s non-offending

affiliates, which are abiding by the same rules as other transmission customers in

accordance with Standards of Conduct, to be eligible to receive a portion of the

operational penalties the transmission provider incurs. In the specific case of unreserved

use penalties, Southern does not support distributing penalties imposed on a transmission

provider’s affiliate to other OATT customers. Southern argues that such a proposal is

predicated upon the false assumption that such penalties are not of true financial

consequence. Southern asserts that penalties paid by an affiliate do, in fact, represent a

real cost to the wholesale business of that affiliated entity. In its reply comments, TDU

Systems disagrees with comments that suggest that non-offending affiliates should be

allowed to receive a load ratio share of penalty revenues when a transmission provider or

one of its affiliates incurs an operational penalty. TDU Systems argue that allowing any

member of the corporate family to retain any portion of the penalty revenues incurred by

527

E.g., EEI, MidAmerican, Nevada Companies, and PNM-TNMP.

Docket Nos. RM05-17-000 and RM05-25-000 - 499 -

another member of the corporate family will dilute the incentive inherent in the

Commission’s proposal.

854. Seattle suggests that compliance monitoring and enforcement to ensure that the

transmission provider appropriately assesses penalties to its affiliates will be as important

as correctly accounting for and distributing the revenues from penalties collected from

affiliates.

855. Most commenters were supportive of the Commission’s proposal to have

transmission providers notify the Commission of the amounts of all operational penalties

they incurred during the year through either an annual compliance filing or a one-time

filing.

528

Several commenters expressed a preference for a one-time filing by

transmission providers.

529

For instance, Ameren states that it prefers the use of a one-

time filing to propose a mechanism through which the transmission provider would

identify non-offending, unaffiliated transmission customers and a method by which the

transmission provider would distribute the operational penalties it or its affiliates have

incurred to the identified transmission customers. Ameren believes this would be less

burdensome than an annual repeated compliance filing. TDU Systems, on the other hand,

prefer the Commission’s proposal to require an annual reporting of penalties levied and

penalty revenues credited in order to foster greater transparency on this matter. TDU

528

E.g., EEI, Suez Energy NA, Sacramento, TAPS, and Wisconsin Electric.

529

E.g., Ameren and PNM-TNMP.

Docket Nos. RM05-17-000 and RM05-25-000 - 500 -

Systems believe greater transparency through improved reporting requirements would

provide greater opportunities for detecting abuses by transmission providers or their

affiliates, either in imposing inappropriate penalties on transmission customers or in

failing to penalize their own or their affiliates’ transgressions. In addition, TDU Systems

suggest that this reporting requirement should include details on the amount of penalties

levied, whether on customers or the transmission provider or its affiliates, for all

violations. With regard to the annual reporting requirements (for those companies that do

not propose a standard mechanism to handle the distribution of penalties), Nevada

Companies suggest that a standard template be proposed so that all companies are

following the same reporting format.

856. Several commenters make recommendations that they argue will ease the

administrative burden of distributing operational penalties paid by the transmission

provider to non-offending, unaffiliated transmission customers. MidAmerican suggests

that excluding short-term firm and non-firm transactions from the distribution

methodology would avoid the need to develop a costly and administratively difficult

program. TVA suggests that the amount of any such operational penalties should simply

be a credit against the transmission provider's transmission revenue requirement, thereby

more efficiently reducing the cost of transmission service to transmission customers.

857. Several commenters argue that the transmission provider must be made whole

before it distributes any penalty revenues. For instance, EEI supports the Commission’s

proposal to the extent penalty revenues exceed the cost of transmission service. Nevada

Docket Nos. RM05-17-000 and RM05-25-000 - 501 -

Companies assert that it is the transmission provider’s native load that incurs the cost of

correcting for the offending customer’s intentional deviation from schedule or for a

transmission customer’s self-provided reserves being unavailable. Therefore, Nevada

Companies contend that any penalties should be returned to the native load to offset its

cost of generation.

858. Sacramento and WPS Companies’ reply comments support the Commission’s

proposal to prohibit a transmission provider from recovering any cost it incurs when it or

an affiliate pays an operational penalty through jurisdictional rates or services.

Commission Determination

859. The Commission agrees with those commenters recommending that we broaden

the NOPR proposal, which required transmission providers to distribute to non-offending,

unaffiliated transmission customers only the unreserved use penalties the transmission

provider’s merchant function incurs. Consistent with our conclusion regarding imbalance

penalties, we conclude that it would be more appropriate for transmission providers to be

required to distribute all

unreserved use penalties they collect, whether from the

transmission provider’s merchant function or other transmission customers. The

penalties the transmission provider pays for late studies are penalties that, by their nature,

are fully distributed only to non-affiliated transmission customers. Requiring the

transmission provider to distribute the unreserved use penalty charges that its merchant

function incurs will ensure that the transmission provider faces a meaningful financial

consequence when its merchant function incurs an operational penalty. Extending the

Docket Nos. RM05-17-000 and RM05-25-000 - 502 -

NOPR proposal to all unreserved use penalty revenues the transmission provider collects

maintains the incentive structure of the unreserved use penalty and prevents the

transmission provider from retaining revenues above those it should reasonably be

allowed to earn.

530

This determination is consistent with the Final Rule for imbalance

penalties and the Commission’s decision in Order Nos. 637 and 637-A.

531

860. We agree with those commenters that suggest that non-offending affiliates of the

transmission provider, including the transmission provider’s native load customers,

should be eligible to receive a portion of the unreserved use penalties that the

transmission provider collects. Unreserved use penalties are assessed against

transmission customers and should, therefore, be distributed to all non-offending

transmission customers, whether affiliated with the transmission provider or not. Given

the distribution of unreserved penalties articulated above, the transmission provider’s

530

As we explain further below, the transmission provider will be allowed to

retain the base firm point-to-point transmission service charge when it assesses an

unreserved use penalty.

531

Regulation of Short-Term Natural Gas Transportation Services, and Regulation

of Interstate Natural Gas Transportation Services, Order No. 637, 65 FR 10156 (Feb. 25,

2000), FERC Stats. & Regs. ¶ 31,091 at 31,309 (2000) (“…to effectively shift pipelines

to the use of the non-penalty mechanisms described above to solve and prevent

operational problems, it will be necessary to eliminate the pipelines’ financial incentive

to impose penalties and OFOs. Thus, the Commission is requiring pipelines to credit the

revenues from penalties and OFOs to shippers.”); order on reh’g

, Order No. 637-A,

65 FR 35706 (Jun. 5, 2000), FERC Stats. & Regs. ¶ 31,099 at 31,609 (2000) (“The goal

of the Commission’s new policy on penalties is to encourage pipelines to rely less on

penalties and more on non-penalty mechanisms to manage their systems….”).

Docket Nos. RM05-17-000 and RM05-25-000 - 503 -

corporate profit is reduced if one of the transmission provider’s wholly-owned marketing

affiliates pays an operational penalty to the transmission provider. This is so because the

corporate shareholders ultimately pay the marketing affiliate’s penalty, while the

transmission provider distributes the revenues to non-offending transmission customers.

861. The Commission requires the transmission provider to make an annual compliance

filing and to propose in that filing a mechanism through which it will identify non-

offending, transmission customers and a method by which it will distribute the

unreserved use penalties revenue it receives to the identified transmission customers.

This rule is consistent with our determination regarding the distribution of imbalance

penalties. The transmission provider must also indicate in its compliance filing how it

will distribute late study penalties to unaffiliated transmission customers. In addition, the

transmission provider is required to make an annual filing with the Commission,

described further below, that provides information regarding the penalty revenue the

transmission provider has received and distributed. We will not allow the transmission

provider to make an annual filing to propose a distribution method for unreserved use and

late study penalties, as proposed in the NOPR. We agree with Ameren that restricting the

transmission provider to proposing a distribution method through the transmission

provider’s compliance filing will reduce the administrative burden of distributing

operational penalties. We believe that we can accomplish the goals underlying a

mandatory annual filing to propose a distribution method – to detect inappropriate

penalties and failure to penalize the transmission provider’s affiliates – by requiring an

Docket Nos. RM05-17-000 and RM05-25-000 - 504 -

annual informational filing. As suggested by Seattle, compliance monitoring and

enforcement by Commission staff will provide a measure of assurance that the

transmission provider appropriately assesses penalties.

862. All point-to-point and network transmission customers, including the transmission

provider’s native load, will be eligible to receive a portion of the penalty revenues

distributed by the transmission provider. As a result, we will not adopt MidAmerican’s

proposal that we exclude short-term firm and non-firm transmission customers to reduce

the burden to the transmission provider. Given the steps we have taken to manage the

transmission provider’s burden of distributing penalty revenues, we believe it more

equitable to allow all transmission customers subject to operational penalties to be

eligible to receive a portion of the distributed penalty revenues. In response to TVA’s

suggestion that the amount of any such operational penalties be credited against the

transmission provider's transmission revenue requirement, we note that the transmission

provider is free to propose this mechanism, with assurances that offending customers will

not benefit, and we will decide the appropriateness of the proposal on a case-by-case

basis.

863. We agree with those commenters that assert that the transmission provider must be

made whole before it distributes any penalty revenues. With regard to unreserved use

penalties, we will allow the transmission provider to retain the base firm point-to-point

transmission service charge, but require it to distribute any revenue collected above the

base firm point-to-point transmission service charge. For instance, if a transmission

Docket Nos. RM05-17-000 and RM05-25-000 - 505 -

customer has unreserved use that results in a penalty equal to twice the rate for firm

weekly point-to-point service, then the transmission provider can retain an amount equal

to the rate for firm weekly point-to-point transmissions service. A transmission provider

will be required to distribute the entire amount it pays for completing service request

studies on an untimely basis.

864. We will not require transmission providers that make an annual compliance filing

to use a standard template, as suggested by Nevada Companies. Transmission providers

are in the best position to determine the least burdensome way to present the information

required. We will provide guidance, however, on the information that transmission

providers must provide in their annual informational filings. Transmission providers

must provide: (1) a summary of penalty revenue credits by transmission customer, (2)

total penalty revenues collected from affiliates, (3) total penalty revenues collected from

non-affiliates, (4) a description of the costs incurred as a result of the offending behavior,

and (5) a summary of the portion of the unreserved penalty revenue retained by the

transmission provider.

865. Transmission providers are prohibited from recovering for ratemaking purposes or

through any service under the Commission’s jurisdiction any amount it or an affiliate

pays as an operational penalty. This will ensure that the transmission provider faces a

true financial consequence when it or an affiliate incurs an operational penalty.

Docket Nos. RM05-17-000 and RM05-25-000 - 506 -

c. Applicability of Operational Penalties Proposal to RTOs

and Other Independent or Non-Profit Entities

866. The Commission did not address the degree to which RTOs and other independent

entities would be subject to operational penalties in section V.C.4 (Operational Penalties)

of the NOPR. For the most part, the discussion in that section of the final rule addressed

how a transmission provider should distribute operational penalties it incurs when it takes

transmission service under its own tariff. In the section V.D.5 (Acquisition of

Transmission Service) of the NOPR, the Commission separately addressed whether

RTOs should pay operational penalties for failure to complete request studies on a timely

basis.

Comments

867. Several RTOs and RTO members asked that the Commission clarify that RTOs

are not subject to any operational penalties.

532

Entergy opposes the Commission’s

proposal to assess operational penalties against non-RTO transmission providers, but not

RTOs. However, if the Commission maintains this distinction, Entergy asks that it

clarify that independent entities – such as Entergy’s Independent Coordinator of

Transmission – and the transmission providers that allow independent entities to process

transmission service requests will have the same protection from operational penalties as

RTOs. PGP argues that, in the case of non-profit transmission providers, requiring the

532

E.g., ISO New England, PJM, MISO, SPP, and Ameren.

Docket Nos. RM05-17-000 and RM05-25-000 - 507 -

transmission provider to pay “non-offending” customers when the provider incurs

operational penalties is self-defeating, because there is no one other than the customers to

bear the cost of the penalty. PGP cites Bonneville as an example and notes that

Bonneville must recover all costs from its customers.

Commission Determination

868. This section of the Final Rule primarily addresses how transmission providers

should distribute operational penalties they incur when taking transmission service under

their own tariff. RTOs and independent transmission coordinators do not take

transmission service, so most of the discussion in this section of the Final Rule is simply

not applicable to either RTOs or independent transmission coordinators. RTOs and

independent transmission coordinators are bound however by the requirement to

distribute revenues they receive when they assess operational penalties. We address

whether RTOs or independent transmission coordinators are subject to operational

penalties due to processing transmission service request studies on an untimely basis in

section V.C.5.a of this Final Rule. We address whether RTOs are subject to civil

penalties in section 0 of this Final Rule.

869. We do not agree with those arguing that a non-profit transmission provider should

be exempt from the requirement to distribute unreserved use penalties it pays when

taking service under its own tariff. To the extent that a not-for-profit transmission

provider incurs an operational penalty as a result of its activities as a transmission

customer, it is still required to distribute penalties to non-offending customers. A non-

Docket Nos. RM05-17-000 and RM05-25-000 - 508 -

profit transmission provider would only incur an operational penalty as the result of its

wholesale marketing operations. As such, a non-profit transmission provider would pay

for any operational penalty it incurs by using the profit it has earned through its

wholesale marketing operations.

6. “Higher of” Pricing Policy

870. As noted in the NOPR, the Commission is concerned that some transmission

providers may not be applying our existing pricing policies consistently and, as a result,

customers may be quoted prices that are not consistent with the “higher of” policy.

533

The practice of quoting customers an incremental rate as a lump sum payment is

inconsistent with our ratemaking policy and has the potential to discourage customers

from proceeding with service requests.

534

Under the Commission’s “higher of” pricing

policy, when the requested transmission service requires network upgrades, the

transmission provider should calculate a monthly incremental cost transmission rate using

the revenue requirement associated with the required upgrades and compare this to the

533

In Order No. 888, the Commission stated that system expansions should be

priced at the higher of the embedded cost rate (including the expansion costs) or the

incremental cost rate, consistent with the Transmission Pricing Policy Statement. See

Inquiry Concerning the Commission’s Pricing Policy for Transmission Services Provided

by Public Utilities Under the Federal Power Act, Policy Statement, 59 FR 55031 at 55037

(Nov. 3, 1994), FERC Stats. & Regs. ¶ 31,005 at 31,146 (1994), order on reconsideration

71 FERC ¶ 61,195 (1995) (Transmission Pricing Policy Statement).

534

Southwest Power Pool, Inc., 100 FERC ¶ 61,096 (2002) (designing a rate to

include a balloon payment is not a substitute for a properly designed rate).

Docket Nos. RM05-17-000 and RM05-25-000 - 509 -

monthly embedded cost transmission rate, including the expansion costs.

535

This

incremental rate should be established by amortizing the cost of the upgrades over the life

of the contract.

536

NOPR Proposal

871. As a result of the Commission’s concerns regarding application of the “higher of”

pricing policy, the Commission sought comments in the NOPR on whether changes to the

pro forma

OATT are necessary to ensure that incremental cost transmission rates are

presented as monthly rates for service.

Comments

872. Several commenters agree that incremental cost rates must be expressed as

monthly rates, but do not believe that imposing this requirement requires changes to the

pro forma

OATT.

537

To ensure transparency, Bonneville recommends that transmission

providers post on their OASIS the methodology used to calculate incremental rates.

APPA suggests that the Commission simply state in the preamble to the Final Rule that

the transmission provider must include a proposed incremental rate in its offer of service.

535

Southwest Power Pool, Inc., 112 FERC ¶ 61,319 at P 33 (2005).

536

See Southwest Power Pool, Inc., 98 FERC ¶ 61,256 at 62,026, reh’g denied in

pertinent part, 100 FERC ¶ 61,096 (2002) (“We agree with SPP that the amortization

period for upgrade costs should match the contract period … As the customer is only

obligated to take service for the term of the contract, it is reasonable that the costs only be

amortized over the term of the contract.”).

537

E.g., APPA, Bonneville, and Public Power Council.

Docket Nos. RM05-17-000 and RM05-25-000 - 510 -

873. Other commenters see no need for clarification at this time. Southern states that it

is not aware of problems regarding the calculation of incremental rates. Southern

requests that the Commission consider allowing deviations to the Commission’s “higher

of” pricing policies and to allow all transmission providers, not just RTOs, to utilize

participant funding. MidAmerican suggests the Commission defer consideration of

possible changes to the pro forma

OATT regarding this issue until the Commission

undertakes comprehensive transmission pricing reform.

874. Other commenters support changes to the pro forma

OATT that will ensure that

incremental costs are presented as monthly rates for service.

538

EPSA suggests that the

Final Rule include an example of an appropriate monthly revenue requirement

calculation and the upgrade costs included in the monthly rate. Suez Energy NA supports

this proposed change but requests that the transmission provider be required to provide in

a clear format the existing transmission rate, the lump sum cost of the upgrades, and the

incremental rate.

875. Some commenters ask the Commission to further clarify, or establish additional

requirements, regarding incremental rates. Entegra states that the incremental rate should

be stated as both a monthly unit rate and a lump sum representing the net present value of

the upgrade costs with all inputs and assumptions in the calculation disclosed. Entegra

further contends that the customer should be allowed to choose between paying the

538

E.g., ELCON, Constellation, FirstEnergy, NorthWestern, PGP, TDU Systems.

Docket Nos. RM05-17-000 and RM05-25-000 - 511 -

incremental rate, the lump sum, or some combination of the two (e.g.

, to pay an

incremental rate over some period of time and then to pay the balance of the upgrade

costs as a lump sum). While Morgan Stanley supports the Commission’s clarification

that the transmission provider may not demand a lump sum payment as a condition of

providing the requested service, it asks that transmission providers not be precluded from

offering a lump sum payment option, or any other mutually agreeable approach, to

customers.

876. MidAmerican, EEI and Allegheny recommend that the Commission clarify that

the transmission provider is not currently limited to charging the customer the rate per

MW-month specified in the facilities study for the entire term of service if the customer

pays the incremental cost of the network upgrades. These commenters explain that the

transmission provider’s revenue requirement with respect to the incremental cost of

network upgrades will vary over the customer’s term of service in the same way as its

embedded cost of service will vary, including the cost of capital, operations and

maintenance expense and administrative and general expense. EEI argues that the

transmission provider should have the same right to modify a rate based on incremental

costs pursuant to section 205 that it has to modify embedded cost rates and that the

transmission provider should be permitted to present an incremental cost rate as a

formula rate.

877. Seattle states that incremental costs may require more rigorous treatment than

simply stating a monthly rate, since the cost of expansion is very path specific and often

Docket Nos. RM05-17-000 and RM05-25-000 - 512 -

the expansion will affect multiple beneficiaries. According to Seattle, the “higher of”

pricing policy will often hinge on contestable assumptions regarding the beneficiaries of

discrete expansion projects and the grey area that separates reliability related aspects of

new transmission projects from projects intended to provide commercial benefits.

878. Great Northern requests that the Commission clarify that a transmission customer

may adjust the term of its requested transmission service contract to provide a longer

period for amortizing the cost of necessary system upgrades once the incremental cost of

expansion is disclosed by the transmission provider, as the Commission seems to suggest

in the NOPR.

539

In contrast, Allegheny states that the amortization period for the cost of

an upgrade should not exceed the requested term of the contract, even if exercise of the

rollover option by the customer is anticipated because transmission providers must have

assurances of cost recovery for upgrades necessitated by customer decisions.

879. TAPS and EEI recommend that the Commission modify sections 19.3 and 19.4 of

the pro forma

OATT to specify that the transmission provider must present the

incremental costs of transmission service on a $/MW month basis contemporaneous with

providing the facilities study to the customer. TAPS further states that similar changes

should be made to sections 32.3 and 32.4 of the pro forma

OATT, to ensure that network

customers are not scared off by inappropriate presentations of network upgrade costs.

539

See NOPR at P 285 (“Presenting the incremental charge in the form of a

monthly rate allows a customer seeking a lower rate to choose to request a longer

transaction term.”)

Docket Nos. RM05-17-000 and RM05-25-000 - 513 -

TAPS explains that, while more complex, it believes that “higher of” pricing can work in

the context of network service if applied in a comparable manner to the transmission

provider’s treatment of the upgrades needed for service to its retail native load.

540

880. ISO New England and PJM state that the Commission’s pricing concerns are not

present for their respective markets and, therefore, any rule promulgated in this

proceeding should not apply to these RTOs.

881. TAPS argues that creditworthiness or security requirements associated with

network upgrades for a transmission customer (in sections 19.4 and 32.4 of the pro forma

OATT) must be distinguished from the incremental cost or pricing of the upgrade.

Otherwise, the customer may mistake a demand for security for a request for upfront

payment of the entire cost of the upgrade.

882. In reply comments, EEI states that it continues to support the Commission’s

proposed modification to the way in which the transmission provider presents

information on the incremental cost of network upgrades and asserts that nothing in the

initial comments justifies a change in the Commission’s policies with respect to the

pricing of transmission service. EEI states that changes in transmission pricing policy,

such as NRECA’s proposal to require rolled-in pricing for network customers and

540

Citing Midwest Indep. Transmission Sys. Operator, Inc., 109 FERC ¶ 61,085,

P 57 (2004) (applying Order 2003 crediting mechanism to network customers).

Docket Nos. RM05-17-000 and RM05-25-000 - 514 -

TAPS’s proposal to exempt network customers from security for the payment of costs

related to network upgrades, are outside the scope of this proceeding.

Commission Determination

883. In the NOPR, the Commission sought comments on the narrow issue of whether

changes to the pro forma

OATT are necessary to ensure that, consistent with our “higher

of” policy, incremental cost transmission rates are presented as monthly rates for service.

The Commission did not propose any changes to the underlying pricing policy.

Commenters’ proposals to change or clarify the Commission’s transmission pricing

policy are therefore outside the scope of this proceeding.

541

Other comments are directed

toward the application of our “higher of” policy in individual cases. These include the

comments of Seattle (on the need to accurately identify the beneficiaries of the network

upgrades), TAPS (on the use of “higher of” pricing in the context of network service),

and EPSA (asking the Commission to present an example calculation of costs and rates).

We will not address those comments here because they involve issues that are largely

fact-specific that are best addressed on a case-by-case basis.

884. Based on the remaining comments received, the Commission concludes that

changes to the language of the pro forma

OATT to address this matter are not needed at

this time. We believe that the existing pricing policy provides sufficient information for

541

Comments that fall into this category include those of Entegra, Suez Energy

NA, Morgan Stanley, MidAmerican, EEI (regarding the right to modify incremental

rates) and Allegheny.

Docket Nos. RM05-17-000 and RM05-25-000 - 515 -

transmission customers to make an informed decision regarding a request for service.

542

Transmission providers must continue to include a proposed monthly incremental rate

with their offer of service whenever the transmission provider proposes to charge the

customer an incremental rate, as well as cost support indicating the derivation of the rate

calculation consistent with the cost support that the transmission provider would provide

to the Commission in a section 205 rate filing. Because transmission providers are

required to explain the calculation of their incremental rate, we conclude that the

transmission provider need not post on its OASIS the calculation methodology, as

recommended by Bonneville. Similarly, in response to TAPS’s concern about security

payments, the transmission provider’s explanation should allow the customer to clearly

distinguish between any security requirements associated with the service and the

incremental cost of the service.

885. We will not adopt Great Northern’s recommendation to require the transmission

provider to permit the customer to opt for a longer contract term (to obtain a longer

amortization period and a lower rate) once the incremental cost of the upgrades has been

determined. The specific upgrades required to provide transmission service may depend

542

Because the Commission declines to adopt changes to the pro forma OATT

regarding the “higher of” pricing policy, the requests of ISO New England and PJM to

exempt ISOs and RTOs from tariff changes related to that policy are moot. Procedures

regarding implementation of the Final Rule by ISOs and RTOs are otherwise discussed in

section IV.C.

Docket Nos. RM05-17-000 and RM05-25-000 - 516 -

on the time period over which the service is provided; therefore, allowing the customer to

opt for a longer contract term may trigger a need for additional, or different, upgrades.

7. Other Ancillary Services

886. Other than the pricing of imbalances, the NOPR did not address pricing issues

related to ancillary services required under the pro forma

OATT. A few commenters

nonetheless proposed revisions to the pro forma

OATT regarding the pricing and

procurement of, and other issues related to, ancillary services.

a. Demand Response

Comments

887. Alcoa submits that load resources (i.e.

, demand response) should be permitted to

self-supply and, under certain circumstances, sell ancillary services to third parties.

Alcoa states that large customers such as aluminum smelters are capable of providing, for

themselves and third parties, some ancillary services so long as they are not required to

subrogate their aluminum business functions to the needs of the ancillary service markets.

In Alcoa’s view, demand resources such as Alcoa's smelter loads should be appropriately

compensated as providers of ancillary services, recognizing their ability to contribute

significantly to the operational flexibility of energy markets and the stability of the grid.

Alcoa asserts that industrial loads’ contribution to the reliability of the grid was

demonstrated during the August 2003 Blackout, when Alcoa's smelters remained in

operation and facilitated the restoration of the system. Accordingly, Alcoa asks the

Commission to require transmission providers to recognize that demand response

Docket Nos. RM05-17-000 and RM05-25-000 - 517 -

resources can be a substitute for ancillary services such as Energy Imbalance, Operating

Reserve and Spinning Reserve.

Commission Determination

888. With respect to Alcoa’s concern regarding a transmission customer’s own use of

ancillary service, we note that the existing pro forma

OATT requires transmission

providers to permit transmission customers to purchase ancillary services from third

parties or make alternative comparable arrangements for the provision of all ancillary

services except for scheduling, system control and dispatch service and reactive supply

and voltage control service. Regarding the sale of other ancillary services including

energy imbalance, operating reserve and spinning reserve by load resources, we agree

that such sales should be permitted where appropriate on a comparable basis to service

provided by generation resources. Comparable treatment of load resources is consistent

with Staff’s August 2006 Assessment of Demand Response & Advanced Metering

Report

543

as well as provisions of EPAct 2005.

544

We note that some RTOs and ISOs

543

In the Demand Response Report, staff recommended that federal and state

regulators consider whether to allow appropriately designed demand response resources

to provide all ancillary services including spinning reserve, regulation, and any new

frequency responsive reserves. Demand Response Report at 97-100.

544

Section 1252 (f) of EPAct 2005 states: “It is the policy of the United States that

time-based pricing and other forms of demand response, whereby electricity customers

are provided with electricity price signals and the ability to benefit by responding to

them, shall be encouraged, the deployment of such technology and devices that enable

electricity customers to participate in such pricing and demand response systems shall be

(continued)

Docket Nos. RM05-17-000 and RM05-25-000 - 518 -

already allow demand response resources to participate in certain ancillary services

markets, while participation of such resources in other ancillary services markets is being

studied. We therefore modify Schedules 2, 3, 4, 5, 6, and 9 of the pro forma

OATT to

indicate that Reactive Supply and Voltage Control, Regulation and Frequency Response,

Energy Imbalance, Spinning Reserves, Supplemental Reserves and Generator Imbalance

Services, respectively, may be provided by generating units as well as other non-

generation resources such as demand resources where appropriate.

b. Procurement and Pricing of Ancillary Services Generally

Comments

889. Steel Manufacturers Association contends that the pro forma

OATT’s approach to

other generation-based ancillary services should recognize that regional ancillary services

markets do a better job of ensuring system reliability and holding down ancillary services

costs than ancillary services provided on a control area by control area basis. Steel

Manufacturers Association cites to MISO and SPP reports that provide evidence that

ancillary services provided across large geographical regions are more effective and

economical than when those services are provided by single utilities. For example, Steel

Manufacturers Association notes that the SPP report concluded that, if a single Area

Control Error were used for SPP, energy used for regulation service could be reduced by

facilitated, and unnecessary barriers to demand response participation in energy, capacity

and ancillary service markets shall be eliminated.”

Docket Nos. RM05-17-000 and RM05-25-000 - 519 -

approximately 30 percent. Steel Manufacturers Association contends that, although

ancillary services markets in the organized markets have proven successful at ensuring

reliability and at keeping ancillary services costs low and predictable, utilities outside of

the RTO and ISO markets continue to provide ancillary services primarily from their own

limited pools of generation resources.

890. Occidental and Steel Manufacturers Association propose that transmission

providers should be required, if feasible, to competitively procure ancillary service

products if there are suppliers of such services other than the vertically integrated

merchant function. Occidental argues that such procurement will result in just and

reasonable rates for these generation-related ancillary services that reflect their cost-

effective market based competitive supply. In Occidental’s view, competitive

procurement of ancillary services will also help assure non-discriminatory treatment of

transmission customers since transmission providers will have less incentive to favor

their merchant function in the provision of generation-related ancillary services.

Occidental notes that such procurement should be conducted in a manner consistent with

reliability.

891. Alcoa argues that the transmission provider’s costs of providing ancillary services

for the network as a whole should not be socialized on a MWh basis without regard to the

relative cost burden that specific customers impose on the transmission system. Alcoa

contends that, while a particular consumer may use a considerable quantity of energy, the

cost of serving that customer beyond the per-unit energy cost may be much less than it

Docket Nos. RM05-17-000 and RM05-25-000 - 520 -

would be for other individual customers or groups of customers.

Commission Determination

892. The Commission recognizes that there can be possible economic and reliability

benefits to larger geographic markets for ancillary services, as suggested by Steel

Manufacturers Association. However, as stated in the NOPR and repeated above the

purpose of this rulemaking is to strengthen the pro forma

OATT to ensure that it achieves

its original purpose – remedying undue discrimination – not to create new market

structures or, as proposed here, to modify existing market structures. We do not believe

that altering the scope of the current ancillary services markets is needed to remedy

undue discrimination at this time.

893. Similarly, we conclude that a fundamental overhaul of the current procurement

and pricing of ancillary services, as proposed by Occidental and Steel Manufacturers

Association, is beyond the scope of this proceeding.

545

The pro forma OATT already

permits transmission customers to make alternative arrangements to satisfy certain of

their ancillary services obligations. Therefore, transmission customers are free to seek

out competitive providers for those ancillary services other than scheduling, system

control and dispatch service and reactive supply and voltage control service from third

545

We note, however, that the rates charged for these ancillary services must be

just and reasonable under the Commissions standard of review. Thus, if less expensive

options to supply ancillary services (including from demand side resources) are available,

we would expect the transmission provider to examine such options.

Docket Nos. RM05-17-000 and RM05-25-000 - 521 -

party suppliers. We also find Alcoa’s contention that the transmission provider’s costs of

providing ancillary services for the network as a whole should not be socialized on a

MWh basis without regard to the relative cost burden that specific customers impose on

the transmission system, to be beyond the scope of this Final Rule.

c. Pricing and Procurement of Reactive Power

Comments

894. Several commenters

546

suggest that the Commission consider the need for reform

of the methods of compensation for the provision of reactive power.

895. Alcoa argues that ancillary services pricing should recognize the efficiency

contributions made by load as a result of their demand response capabilities and the

contribution that load located near generators makes to the provision of reactive power in

particular. Alcoa states that the localized supply of reactive power near load centers can

alleviate transmission constraints and allow cheaper real power to be delivered into a load

center, as the provision of such reactive power increases the available flow for real power

between two points. Alcoa argues that the pro forma

OATT should recognize and credit

the manner in which certain loads’ location and load profile allows for the provision of

reactive power and contributes to real power transfer capability.

896. Occidental objects to the existing requirement that transmission customers

purchase reactive power service from the transmission provider, arguing that numerous

546

E.g., SPP, Alcoa, and Occidental.

Docket Nos. RM05-17-000 and RM05-25-000 - 522 -

independent generators provide reactive supply and voltage control to support

transmission service in competitive wholesale markets. Occidental states that the

Commission should formalize the policy of compensating generators on a comparable,

non-discriminatory basis for several ancillary service, particularly providing reactive

power capability, by requiring changes to the pro forma

OATT to mirror the changes

accepted by the Commission to the PJM and MISO tariffs. Occidental contends that

amending the pro forma

OATT to formalize this policy would be consistent with the FPA

and achieving non-discriminatory access to transmission. Occidental notes that PJM and

MISO amended their tariffs to provide equal compensation to affiliated and non-affiliated

generators based on the generation owner’s monthly revenue requirement for reactive

supply and voltage control as accepted by the Commission. Occidental also notes that,

when addressing generator interconnection agreements in Order No. 2003-A, the

Commission stated that “if the Transmission Provider pays its own or its affiliated

generators for reactive power within the established [power factor] range, it must also pay

[the interconnecting, independent generator].”

547

897. SPP requests that the Commission reform its reactive power pricing methodology,

which has grown out of AEP Serv. Corp

548

SPP contends that the Commission can

reduce uncertainty and litigation surrounding the pricing of reactive power by acting

547

See Order No. 2003-A at P 416.

548

Opinion No. 440, 88 FERC ¶ 61,141 (1999).

Docket Nos. RM05-17-000 and RM05-25-000 - 523 -

generically in a rulemaking rather than causing the industry to litigate reactive power

pricing issues on a case-by-case basis. SPP argues that, based on its studies, it does not

expect to call upon IPPs to provide reactive power; and therefore, it should not be

required to pay for reactive power. SPP questions whether paying all IPPs a reservation

charge, regardless of any determination of need or of the location of the plant and the

locational need for reactive power, provides the appropriate siting incentives. SPP

contends that the Commission can reduce the uncertainty and litigation by acting

generically rather than causing the industry to fully litigate these issues in numerous

cases before various courts. In addition, SPP challenges whether the AEP pricing method

for reactive power continues to be appropriate. SPP suggests the Commission consider

alternative pricing options, such as: tying compensation to the actual provision of

reactive power; eliminating compensation for the ninety-five percent leading/lagging

band contained in most interconnection agreements, as such costs may be considered as a

cost of interconnection and included in the power sales price; or, allowing compensation

only outside of the band or perhaps when a sale is displaced.

Commission Determination

898. In Order No. 2003 et al.

, the Commission found that interconnection customers

must be treated comparably with the transmission provider and its affiliates in terms of

reactive power compensation. The Commission required the transmission provider to

pay interconnecting generators for providing reactive power within the specified range if

Docket Nos. RM05-17-000 and RM05-25-000 - 524 -

the transmission provider so pays its own generators or those of its affiliates.

549

Commenters seeking reform of the methods of compensation for the provision of reactive

power have not demonstrated that such reforms are needed at this time to remedy undue

discrimination or that the current compensation method does not provide a comparable

result. Accordingly, we do not believe that acting generically on pricing reactive power

is needed at this time and we will continue to resolve compensation issues for reactive

power to qualifying generators on a case-by-case basis based on the circumstances

presented.

899. In response to SPP’s specific proposals for the treatment of reactive power, we

note that the Commission recently found that it is unduly discriminatory and non-

comparable for SPP to apply a “needs” test to reactive power capability for independent

power producers to receive compensation that is not also applied to all other generating

plants in its vicinity.

550

The Commission also found that parties may make a separate

FPA section 205 filing with the Commission with criteria, applied comparably and

prospectively, that would determine which generators would receive reactive power

compensation.

900. Finally, Alcoa’s assertion that certain loads’ location and load profile allows for

the provision of reactive power to the transmission system is consistent with Staff’s

549

See Order No. 2003-B at P 119.

550

See Calpine Oneta Power, L.P.,116 FERC ¶ 61,282 (2006).

Docket Nos. RM05-17-000 and RM05-25-000 - 525 -

February 2005 report, Principles for Efficient and Reliable Reactive Power Supply and

Consumption,

551

as well as the above-cited provisions of EPAct 2005. As previously

discussed, we have modified Schedule 2 of the pro forma

OATT to allow for the

provision of Reactive Supply and Voltage Control from demand resources where

appropriate.

D. Non-Rate Terms and Conditions

1. Modifications to Long-Term Firm Point-to-Point Service

a. Planning Redispatch and Conditional Firm Options

901. The current pro forma

OATT requires the transmission provider to provide two

types of redispatch service: planning redispatch and reliability redispatch.

552

Planning

redispatch is a product that Order No. 888 required transmission providers to use, in

certain circumstances, to create additional transmission capacity to accommodate a

551

See Staff Report: Principles of Efficient and Reliable Reactive Power Supply

and Consumption (Docket No. AD05-1-000), available at

http://www.ferc.gov/EventCalendar/Files/20050310144430-02-04-05-reactive-power.pdf

Staff noted that in many cases load response and load-side investment could reduce the

need for reactive power capability in the system and that increasing reactive power at

certain locations (usually near a load center) can sometimes alleviate transmission

constraints and allow cheaper real power to be delivered into a load pocket. See

id. at 4,

108. The report also noted that distributed generators have the same reactive power

characteristics as large generators, with both producing dynamic reactive power, and that

the amount of reactive power does not necessarily decrease when voltage decreases. Id.

at 27.

552

In Order No. 888, the Commission referred to planning redispatch as economic

redispatch. Here we avoid the term economic redispatch because in the last ten years it

has taken a different meaning in the industry and because we will no longer require that

planning redispatch be capped at the cost of expansion.

Docket Nos. RM05-17-000 and RM05-25-000 - 526 -

request for firm transmission service. Specifically, the existing pro forma

OATT requires

the transmission provider to expand or upgrade its transmission system or, if it is more

economical, plan to redispatch its resources to provide requested firm point-to-point

service, provided redispatch does not (1) degrade or impair the reliability of service to

native load customers, network customers and other transmission customers taking firm

point-to-point service or (2) interfere with the transmission provider’s ability to meet

prior firm contractual commitments to others.

553

The transmission provider must first

identify planning redispatch options in the system impact study in conjunction with

identifying relevant system constraints that impact the service request.

554

When a system

impact study and facilities study identify planning redispatch as a more economical

means of relieving a transmission constraint than a transmission upgrade, the customer is

obligated to pay the costs of redispatch consistent with Commission policy.

902. Reliability redispatch is required, when feasible, to relieve system constraints that

would otherwise cause curtailment of the network customer or transmission provider

loads. To provide reliability redispatch, the transmission provider redispatches all

network resources and transmission provider resources on a least-cost basis. The

553

See pro forma OATT section 13.5.

554

See pro forma OATT section 19.3.

Docket Nos. RM05-17-000 and RM05-25-000 - 527 -

transmission provider and network customers each pay a load ratio share of these

redispatch costs.

555

NOPR Proposal

903. In the NOPR, the Commission stated its belief that current practices for evaluating

long-term firm point-to-point service may not be comparable to the manner in which

transmission service is planned for bundled retail native load and may no longer be just,

reasonable and not unduly discriminatory. The Commission described two potential

solutions: modifications to the planning redispatch provisions and conditional firm point-

to-point service.

556

The Commission proposed to modify the existing planning redispatch

option by (1) accelerating the study of planning redispatch in the transmission request

study process, (2) requiring an estimate of the number of hours of redispatch that may be

required to accommodate the requested service, (3) requiring a preliminary estimate of

the cost of planning redispatch, and (4) pricing planning redispatch services to facilitate

increased availability of the service.

557

The Commission suggested that conditional firm

service could also be used to accommodate additional transactions, defining the service

555

See pro forma OATT sections 33.2-33.3.

556

Conditional firm point-to-point service (hereinafter conditional firm service)

and planning redispatch point-to-point service (hereinafter planning redispatch service)

are options available under long-term firm point-to-point service.

557

The Commission did not propose to modify the reliability redispatch provisions

that exist in the network integration transmission sections of the pro forma

OATT.

Docket Nos. RM05-17-000 and RM05-25-000 - 528 -

as a form of firm point-to-point service that includes less-than-firm service in a defined

number of hours of the year when firm point-to-point service is unavailable. The

Commission sought comment on its preliminary view that planning redispatch is the

superior option because, in part, it is comparable to the way the transmission provider

plans for bundled retail native load.

904. The Commission’s October 12 Technical Conference focused, among other things,

on issues related to the planning redispatch and conditional firm proposals in the NOPR.

On November 15, 2006, the Commission issued a notice (November 15 Notice)

requesting supplemental comments on a transparent redispatch proposal submitted by

Transparent Dispatch Advocates (TDA proposal)and certain aspects of the conditional

firm option.

558

The Commission also requested comments regarding the conditional firm

option, including whether it is a complementary service to planning redispatch, whether it

should be available for all long-term requests or limited to a request where the customer

agrees to pay for upgrades, potential modeling problems, and requirements for defining

the conditions under which the service would be curtailable.

559

558

The following summary reflects comments received as initial and reply

comments to the NOPR, as well as supplemental comments received in response to the

November 15 Notice. Some commenters have changed their positions over time and

these summaries reflect the most recent position expressed by commenters.

559

Questions relating to the TDA proposal are discussed later in this section.

Docket Nos. RM05-17-000 and RM05-25-000 - 529 -

Comments

905. Some commenters agree with the Commission’s preference for modifications to

planning redispatch over development of conditional firm service.

560

They state that the

attributes of conditional firm service are not clearly defined and key implementation

issues are unresolved. They state that using planning redispatch to the maximum degree

feasible, while not interfering with reliability, is inherent in maximizing the efficient use

of the transmission system and should be fully evaluated before undertaking expensive

expansion of the transmission system. Other commenters state that conditional firm

service will create significant complications for transmission providers and disincentives

to build transmission in exchange for limited and questionable benefits for new point-to-

point customers or LSEs.

561

EEI, Indianapolis Power and Ameren express doubt that

customers would agree to be curtailed during peak usage periods. In response, AWEA

contends that existing resources serving load would be able to manage curtailment risks

so long as they could reasonably predict the curtailed hours.

906. Most independent power producers and a few other entities support the inclusion

of both services in the pro

forma OATT, stating that the services are required to remedy

560

E.g., Exelon, FirstEnergy, ELCON, MidAmerican, Arkansas Commission,

MISO, and East Texas Cooperatives.

561

E.g., EEI, Indianapolis Power, Ameren, and Northwest IOUs.

Docket Nos. RM05-17-000 and RM05-25-000 - 530 -

undue discrimination and provide for comparable transmission service.

562

Western

Governors believe that the planning redispatch and conditional firm options are important

to fully use the existing transmission grid and to enable new intermittent generation

resources to reach markets. To build the case for transmission expansion, the Western

Governors argue, it is important to demonstrate that the existing grid is being effectively

utilized; approval of both options will help make this necessary demonstration. EPSA

and AWEA state that, while they believe transmission providers should be required to

offer both services, conditional firm service may be simpler and less costly to implement

because it involves the transmission provider directing the customer to turn off its

resources during a contingency. Similarly, Bonneville suggests that conditional firm

service is a reasonable alternative to planning redispatch where a transmission provider

cannot provide both options. Commenters state that the Commission should require

transmission providers to offer conditional firm service and planning redispatch and

allow customers to choose the option that best suits the physical, commercial and

economic circumstances of the request.

563

562

E.g., EPSA, AWEA, Entegra, BP Energy, Newmont Mining, Sempra Global,

Suez Energy NA, PPM, Utah Municipals, Williams, Morgan Stanley, PPL, Project for

Sustainable FERC Energy Policy, California Commission, CREPC, TranServ, South

Carolina E&G, Constellation, Barrick Supplemental, Xcel Supplemental, and Bonneville

Supplemental.

563

E.g., California Commission Supplemental, Williams Supplemental,

Constellation Supplemental, and Barrick Supplemental.

Docket Nos. RM05-17-000 and RM05-25-000 - 531 -

907. On the other hand, many commenters argue that the Commission should not

require either option because the services are unnecessary, operationally unworkable, and

legally unjustified, or because they would harm reliability and the quality of existing

network service and provide disincentives for transmission investment.

564

Several

commenters state that these services would make curtailments of existing firm service

more likely and limit opportunities for use of secondary network service, thereby

harming native load protections and reducing reliability, contrary to FPA sections 215

and 217 respectively.

565

Others opposing both options put forth primarily reliability, cost

causation and comparability arguments. For example, Duke states that the two options

are antithetical to reliable grid operation because they would require a transmission

provider to grant a long-term request with the prior knowledge that it cannot be

accommodated. International Transmission states that the grid is already operating at

capacity and that requiring the transmission provider to accommodate additional

megawatt-hours of service during periods of system stress would increase the likelihood

of system failure. While it recognizes that conditional firm service has been successful in

564

E.g., Ameren, Duke, Entergy, Imperial, International Transmission, LPPC,

Progress Energy, Santee Cooper, Salt River, Southern, Tacoma, TDU Systems,

Community Power Alliance, Northwest IOUs, NorthWestern, NPPD, NRECA, Public

Power Council, TVA, SPP Reply, South Carolina E&G Supplemental, E.ON

Supplemental, MISO Supplemental, and APPA Supplemental.

565

E.g., Duke, EEI, LPPC, NRECA, NPPD, Progress Energy, Southern, Utah

Municipals Reply, and Duke Reply.

Docket Nos. RM05-17-000 and RM05-25-000 - 532 -

parts of the Western Interconnection, NRECA contends a mandate would undermine

responsible planning and expansion of the transmission grid by harnessing the

transmission provider’s planning and dispatch functions to frame more and more

elaborate service conditions for conditional firm service. APPA, Southern and Progress

Energy argue that both services may require adoption of a form of organized LMP

market, an action that raises significant political opposition and would be contrary to the

Commission’s commitment in the NOPR to avoid such restructuring. Similarly, other

commenters contend that the planning redispatch option is only appropriate for

transmission providers who are members of an RTO, ISO or who have an independent

administrator of their transmission system.

566

Some of the commenters that urge

rejection of both options state that a properly structured conditional firm service is

preferable to the modified planning redispatch service should the Commission implement

one of the services.

567

908. Several commenters prefer the development of conditional firm service over the

modifications to the planning redispatch service because of the complexities surrounding

566

E.g., CREPC, TVA, and East Texas Cooperatives.

567

E.g., EEI, Entergy, Ameren, Progress Energy, Santee Cooper, TAPS, E.ON

Supplemental, TDU Systems Supplemental, LPPC Supplemental, Tacoma Supplemental,

and PNM-TNMP Supplemental.

Docket Nos. RM05-17-000 and RM05-25-000 - 533 -

redispatch costs and protocols.

568

For example, in supplemental comments, EEI and

Community Power Alliance state that, while not ideal, conditional firm service would

provide an opportunity to meet customers’ transmission needs and is preferable to

Transparent Dispatch Advocates’ redispatch proposal.

569

They also contend that the

conditional firm option would provide faster provision of service and relative certainty of

timing and costs for a new customer and its lenders, while ensuring reliability and

promoting infrastructure expansion, so long as transmission providers are permitted to

work with their customers to devise appropriate service parameters. Entergy believes

conditional firm service can provide benefits to transmission customers without unfairly

socializing costs to native load and network customers of the transmission provider.

Overall, a majority of commenters express support for some form of conditional firm

service.

570

568

E.g., Manitoba Hydro, Nevada Companies, Sacramento, Pinnacle, East Texas

Cooperatives, Barrick Reply, APPA Supplemental, Community Power Alliance

Supplemental, Entergy Supplemental, and TAPS Supplemental.

569

Section V.D.1.b contains a summary and in-depth discussion of the TDA

proposal.

570

The following entities expressed some level of support for conditional firm

service: EPSA, AWEA, Entegra, BP Energy, Newmont Mining, Sempra Global, Suez

Energy NA, PPM, Utah Municipals, Williams, Morgan Stanley, PPL, Project for

Sustainable FERC Energy Policy, California Commission, Western Governors, CREPC,

TranServ, Constellation, Manitoba Hydro, Nevada Companies, Sacramento, Pinnacle,

PNM-TNMP, Bonneville, EEI, Entergy, Ameren, Progress Energy, Southern, Santee

Cooper, Seattle, LPPC, Salt River, and TAPS.

Docket Nos. RM05-17-000 and RM05-25-000 - 534 -

909. Several commenters argue that, if the services are required, the Commission

should add to the services the following requirements: the services should not adversely

affect reliability and service to firm customers or provide unduly preferential service to

point-to-point customers; the services should be an interim option until transmission

upgrades are in place to provide firm service; and, planning redispatch and conditional

firm customers should bear the actual costs of the services received, including costs

associated with system operational changes needed to accommodate the services.

571

910. A few commenters believe that the Commission should allow for regional

differences in development of the new services.

572

Commission Determination

911. The Commission has determined that modifications to the current planning

redispatch requirement and creation of a conditional firm option are both necessary for

provision of reliable and non-discriminatory point-to-point transmission service. The

planning redispatch and conditional firm options represent different ways of addressing

similar problems. They can be used to remedy a system condition that occurs

infrequently and prevents the granting of a long-term firm point-to-point service. These

options also can be used to provide service until transmission upgrades are completed to

571

E.g., EEI, Southern, TAPS, Seattle, APPA, LPPC Supplemental, Tacoma

Supplemental and E.ON Supplemental. Issues related to pricing of planning redispatch

service are addressed in paragraphs V.D.1.a.3.c below.

572

E.g., California Commission, PGP, Pinnacle, and Imperial.

Docket Nos. RM05-17-000 and RM05-25-000 - 535 -

provide fully firm service. Planning redispatch involves an ex ante

determination of

whether out-of-merit order generation resources can be used to maintain firm service.

Conditional firm involves an ex ante

determination of whether there are limited

conditions or hours under which firm service can be curtailed to allow firm service to be

provided in all other conditions or hours. As we explain below, both techniques are

currently used under certain conditions by transmission providers to serve native load

and, hence, it is necessary to make comparable services available to transmission

customers in order to avoid undue discrimination.

912. We therefore find these options are complementary services that can remedy

undue discrimination, facilitate the provision of long-term transmission service and

provide customers with greater flexibility in choosing resources to meet their needs.

There is support in the comments for development of some type of conditional firm

service that would allow for a longer-term use of the grid when transmission is projected

to be unavailable for a small portion of the year. Additionally, we note that both options

could help integrate new generation more quickly. For example, when there is a lag

between the time that a new generation resource becomes operational and the time that

transmission upgrades can be built to accommodate the resource, these options allow

power to reach customer loads at an earlier date. This can be particularly beneficial to

renewable resources, such as wind, that can be constructed more quickly than the

transmission upgrades necessary to deliver their power on a firm basis over the long-run.

Docket Nos. RM05-17-000 and RM05-25-000 - 536 -

913. We recognize, however, that both options raise reliability concerns. The proposal

in the NOPR for planning redispatch service would require the transmission provider to

predict system conditions for the term of the service request, a task that becomes more

difficult, and hence less accurate, with longer-term requests. This poses several related

problems. Because longer-term forecasts are inherently uncertain and the further into the

future the forecasts, the less accurate they are, the provision of planning redispatch

service can threaten the reliability of service to native load unless very conservative

assumptions are used. This incentive to use conservative assumptions to protect native

load, in turn, increases the likelihood that planning redispatch service will be denied.

This, in turn, will increase the number of disputes as to whether the denials were

discriminatory. Such disputes would pose enforcement problems because they will turn

on long-term projections regarding load growth, generation resource additions, etc.

, that

by definition involve some degree of subjectivity. Moreover, as we discuss below, there

is evidence suggesting that, while transmission providers use planning redispatch to serve

native load, they do not use it as a long-term tool to avoid future upgrades indefinitely.

914. In balancing the foregoing considerations, the Commission will modify the

approach proposed in the NOPR in two principal respects. First, given the ability of both

services to address similar problems, we have reconsidered the proposal that only one of

the options should be required. We find that availability of both planning redispatch and

conditional firm in the short-run is necessary to ensure that competitive power suppliers

have comparable access to the grid. As discussed below, we will continue to require that

Docket Nos. RM05-17-000 and RM05-25-000 - 537 -

transmission providers offer to provide planning redispatch under certain circumstances

in which the transmission providers determine that there is insufficient ATC. If

customers request study of planning redispatch, transmission providers have an

obligation to seriously evaluate the provision of planning redispatch from their own

resources and provide customers with information on the capabilities of other generators

to provide planning redispatch. If planning redispatch is unavailable from the

transmission provider’s resources or inadequate to meet customers’ needs, transmission

providers have an independent obligation to offer conditional firm, if available, as part of

the firm point-to-point service.

573

Customers will have the choice of whether to request

study of the planning redispatch option, the conditional firm option or both.

915. Second, we will not impose a planning redispatch or conditional firm obligation

over the long-run. Such an obligation is not, as described below, necessary to remedy

undue discrimination and would otherwise pose reliability problems, put the transmission

provider at risk for estimating the costs of long-term redispatch, and undermine

incentives to upgrade the transmission grid. Therefore, we will limit the availability of

both service options so that their duration is for a time period over which service can be

573

Application of planning redispatch and conditional firm service obligations to

RTO and ISO transmission providers is discussed in section V.D.1.a.3.B.i below.

Docket Nos. RM05-17-000 and RM05-25-000 - 538 -

reasonably provided without impairing reliability.

574

This limitation scales back the

existing planning redispatch requirement in section 13.5 of the pro forma

OATT that

could, in practice, allow for an open-ended obligation to provide planning redispatch in

lieu of upgrading the transmission system (e.g.

, involving forecasts up to 30 years).

916. We discuss in detail the comparability and reliability findings that support these

decisions below.

(1) Comparability

NOPR Proposal

917. In the NOPR, the Commission expressed its preliminary view that current

practices for evaluating long-term firm point-to-point service may not be comparable to

the manner in which transmission service is planned for bundled retail native load and

may no longer be just, reasonable and not unduly discriminatory.

575

574

As explained in more detail below, we adopt limitations that are tailored to the

two types of customers that may request the options. First, for customers that agree to

support the construction of new transmission facilities, redispatch and conditional firm

point-to-point service will be available as a bridge until such time as those facilities are

constructed and the relevant conditions must be specified in the initial service agreement

and are not subject to change. Second, for customers that do not agree to support the

construction of new facilities, the transmission provider will be able to re-evaluate the

conditions under which services are provided every two years.

575

The Commission did not propose to modify the reliability redispatch provisions

that exist in the network integration transmission sections of the pro forma

OATT.

Docket Nos. RM05-17-000 and RM05-25-000 - 539 -

Comments

918. Some commenters challenge the Commission’s authority to order planning

redispatch or conditional firm service as a remedy for potential undue discrimination.

EEI and others argue that planning redispatch is not necessary to eliminate actual or

perceived undue discrimination because many transmission providers do not rely on

redispatch in planning to serve native load.

576

However, EEI also states that when

transmission providers do incorporate redispatch into their system planning, they do so

generally only when the cost of redispatch is lower than the cost of network upgrades and

system reliability is not impacted. Some transmission providers state that they do not

currently use planning redispatch in lieu of transmission construction in order to

designate their network resources.

577

On the other hand, Entergy and Southern state that

they currently use or have used planning redispatch of their own resources on the same

basis that they allow any network customer to redispatch from the network customer’s

resources. For example, Southern states that it has used the redispatch potential of its

generators during off-peak/shoulder periods on an interim basis until completion of

transmission upgrades to designate network resources that otherwise might be

576

E.g., EEI, TDU Systems, NRECA, Southern, and Duke Reply.

577

E.g., Southern, Duke, and Progress. Duke suggests that the Commission

exempt transmission providers from the obligation to provide redispatch if they commit

not to use redispatch as a planning tool for native load, network customers or merchant

functions.

Docket Nos. RM05-17-000 and RM05-25-000 - 540 -

undeliverable.

578

Entergy disagrees that there is undue discrimination because this

service is not available to point-to-point customers, stating that network and point-to-

point service are not similarly situated services. TDU Systems state that conditional firm

service does not ensure comparability among types of transmission service or between

transmission providers and transmission customers. NRECA and others argue that the

Commission requires a better understanding of the degree to which comparability is a

problem in providing point-to-point service before the Commission makes changes to

point-to-point service.

579

In supplemental comments, EEI contends that the record in this

proceeding does not demonstrate that conditional firm service is necessary to remedy

undue discrimination.

919. Others assert that it is not within the Commission’s jurisdiction to order planning

redispatch for point-to-point customers because this type of redispatch requires use of the

transmission provider’s generation resources.

580

LPPC states that the comparability

principle is wrongly applied to the use of generation by a transmission provider. In Salt

River’s view, the Commission proposal sets up its own form of discrimination by making

redispatch of the transmission provider’s resources mandatory while making redispatch

578

Southern states that it offered this service on a comparable basis to a non-

affiliated transmission customer.

579

E.g., TDU Systems and EEI Reply.

580

E.g., LPPC, NPPD, Progress Energy, and Salt River.

Docket Nos. RM05-17-000 and RM05-25-000 - 541 -

of generation using firm point-to-point reservations and generation in other control areas

voluntary.

920. Those that support development of both services support the Commission’s

statement in the NOPR that “transmission owners may evaluate transmission availability

to serve long-term transmission service request in a manner that is not comparable with

the method they use to evaluate transmission needs for bundled retail native load.”

581

They argue that this divergent treatment of internal transmission needs versus external

transmission requests is unduly discriminatory and violates the FPA. EPSA states that

the fact that point-to-point service requests can be rejected due to a few hours of

predicted reliability problems in a year is “evidence of a poor use of existing transmission

capacity and display clear discrimination against non-affiliated generation and its

customers.”

582

TransAlta states that its actual experience with planning redispatch in the

Pacific Northwest demonstrates that planning redispatch is used discriminatorily to the

benefit of some customers and the detriment of others.

921. In support of conditional firm service, Manitoba Hydro and Tacoma reiterate their

experience that long-term transmission service requests are being denied due to

constraints occurring during a small percentage of the time within the requested period of

581

E.g., AWEA, Utah Municipals, Project for Sustainable FERC Energy Policy,

EPSA, and Barrick Reply citing

NOPR at P 300.

582

EPSA Reply.

Docket Nos. RM05-17-000 and RM05-25-000 - 542 -

service. EPSA and AWEA similarly state that a transmission provider will reject a long-

term firm service request unless it can satisfy every element of the request. Manitoba

Hydro and others state that, in an era of transmission under-investment, optimizing the

capacity usage is paramount to system reliability.

583

EPSA and AWEA further explain

that the concept of turning off a generator to avoid system upgrades is not new; Maine

Independence Station avoided expensive system upgrades by installing automatic

switching devices to take it offline during certain system conditions. Seattle states that,

according to the Seams Steering Committee of the Western Interconnection, utilization

on most constrained paths is limited for only a few hundred hours per year and, therefore,

it is highly likely that service under a conditional firm product could be offered for even a

baseload plant without significantly impacting the capacity factor. Santee Cooper states

that, unlike the planning redispatch option, conditional firm service is presumptively

within the subject matter jurisdiction of the Commission.

922. Entergy states that the most comparable service for long-term point-to-point

transmission customers is not a requirement that a transmission provider redispatch its

own or network customers' resources to grant long-term firm point-to-point transmission

service. The most comparable service instead is a service that allows the transmission

provider to curtail the service granted, while permitting the point-to-point customer to

obtain alternative, deliverable resources if and when such curtailments occur in real-time.

583

E.g., EPSA, AWEA, and Project for Sustainable FERC Energy Policy.

Docket Nos. RM05-17-000 and RM05-25-000 - 543 -

Commission Determination

923. We reject arguments that planning redispatch service is unnecessary to remedy

undue discrimination as a collateral attack on Order No. 888. The obligation to provide

planning redispatch was established in Order No. 888. The modifications proposed in the

NOPR did not increase the obligation placed on transmission providers to use their

generation resources to provide planning redispatch to point-to-point customers. Rather,

the proposed modifications merely added specificity to the redispatch information already

required in a system impact study and adjusted the timing of when the transmission

provider must study planning redispatch options.

584

Therefore, many of the arguments

raised, including arguments pertaining to the Commission’s jurisdiction over

transmission provider generation resources, are impermissible collateral attacks on the

current planning redispatch obligation in Order No. 888. Entergy’s argument that

planning redispatch should not be available to point-to-point customers because they are

not similarly situated to be able to provide redispatch from their own units thus ignores

the current obligation for each transmission provider to provide redispatch from the

transmission provider’s resources, if available, in evaluating a request for long-term

point-to-point service.

585

584

See pro forma OATT section 19.3.

585

See pro forma OATT section 13.5.

Docket Nos. RM05-17-000 and RM05-25-000 - 544 -

924. Additionally, information in the comments counters the assertion that transmission

providers do not use planning redispatch or service analogous to the conditional firm

option for their own loads. Entergy and Southern volunteer that they have planned for

redispatch of their own resources in order to designate network resources when ATC was

unavailable.

586

As a caveat, Southern states that it has planned for the use of redispatch

only for an interim period until upgrades could be constructed to make the transmission

service from the designated resource fully firm. Entergy states that it offers planning

redispatch service to network customers that plan to use their own resources to provide

redispatch in real time. Contrary to EEI’s assertion about the record in this proceeding,

commenters, such as EPSA and AWEA, explain that some transmission providers

already employ automatic devices, such as special protection systems (SPS), to take

resources offline during certain system conditions. In a way that is analogous to the

proposed conditional firm service, these protection schemes are used to increase native

loads’ firm uses of the transmission system until a contingency occurs that reduces

available transmission.

587

This information, taken together, provides ample evidence to

586

Entergy and Southern. EEI’s comments also indicate that at least a few

transmission providers do rely on redispatch in planning to serve their native loads.

587

SPS, also known as remedial action schemes , are used to varying degrees in

every NERC reliability region. For example, there are about 65 SPS in the Western

Interconnection. See

Western Electricity Coordinating Council Operating Procedures,

Index, V-1 to V-5 (revised July 2, 2002). There are 8 SPS used by Florida Power and

Light in FRCC. See

Florida Power and Light Control Area Readiness Audit Report, 19

(March 10-11, 2004). Two SPS are used in the Southern Subregion of SERC. Reliability

(continued)

Docket Nos. RM05-17-000 and RM05-25-000 - 545 -

support our finding that transmission providers currently evaluate transmission

availability to serve long-term firm point-to-point transmission service requests in a

manner that is not comparable with the method they use to evaluate their own

transmission needs and to integrate their resources to serve bundled retail native load.

925. Furthermore, we wish to emphasize that, in making these findings in support of a

conditional firm option, we are not relying on the findings to create a new service. This

Final Rule retains the two services adopted in Order No. 888 – point-to-point service and

network service. Conditional firm service is not a third service, but rather represents a

modification to the existing procedures for granting long-term point-to-point service and

the curtailment priorities for that service. The primary purpose of conditional firm is to

address the “all or nothing” problem associated with the current procedures for requesting

long-term point-to-point service. Currently, a request can be denied because firm service

is unavailable in a very few hours of the year. For a customer who needs long-term

point-to-point service to support a long-term transaction, this leaves the customer in the

position of trying to cobble together a collection of shorter-term requests to effectuate its

transaction, e.g.

, arranging firm service in the periods when it is available and non-firm

service in the other periods. Such a customer also risks interruption of the non-firm

portion of its service for economic reasons, e.g.

, a day of non-firm service for the

Coordinator Readiness Audit Report Southern Subregion Reliability Coordinator

, 19

(March 27–30, 2006).

Docket Nos. RM05-17-000 and RM05-25-000 - 546 -

customer combining firm and non-firm service could be interrupted for another customer

seeking one month of non-firm service. We do not believe such an approach is just and

reasonable. It makes little sense to ask the customer to cobble together a collection of

firm and non-firm requests when the transmission provider has better information about

when the service may be available or unavailable. It is therefore appropriate to require

the transmission provider to grant the service on a conditional basis, as we explain further

below.

926. We are however modifying the planning redispatch obligation, and similarly

limiting the conditional firm option, to better reflect the manner in which redispatch or

special protections schemes are used by transmission providers, in recognition of certain

legitimate reliability concerns and the inherent difficulty of long-term projections in this

area. This Final Rule limits transmission providers’ planning redispatch obligations by

removing the current obligation to provide planning redispatch for an indefinite period as

long as the redispatch is cheaper than the relevant transmission upgrades. We also limit

the conditional firm option by linking it to the transmission upgrades or a biennial

assessment of the conditions.

927. We find such an open-ended obligation to provide this service is not necessary to

remedy undue discrimination, nor is it consistent with the need to maintain system

reliability. As indicated above, transmission providers temporally limit their use of

planning redispatch and curtailment of resources and there is no evidence that

transmission providers use these options on a prolonged basis, e.g.

, for more than a few

Docket Nos. RM05-17-000 and RM05-25-000 - 547 -

years, without upgrading their transmission systems. Rather, over the long run,

transmission providers generally will construct sufficient transmission to integrate their

resources on a firm basis. This is consistent with transmission planning requirements and

the emphasis placed upon transmission expansion in this Final Rule. The modifications

to long-term point-to-point service we adopt are consistent and comparable to the existing

use of these options by transmission providers’ bundled retail native loads. Thus, the

planning redispatch and conditional firm options will be available primarily as interim

measures until transmission systems are upgraded to meet the transmission service

request. We believe this limitation will have the added benefit of lessening disincentives

to provide the service so that more planning redispatch is offered to transmission

customers by transmission providers.

928. We disagree with TDU Systems’ statement that conditional firm service does not

ensure comparability among types of transmission service or between transmission

providers and transmission customers. TDU Systems’ assertion is unsupported by any

explanation or examples of how the conditional firm service would degrade

comparability. Nevertheless, we believe the argument is essentially a collateral attack on

Order No. 888. Order No. 888, not this rulemaking, created the distinction between

point-to-point transmission service and network integration service. We did so to

recognize the different ways in which transmission providers typically use their system.

The two services are not precisely the same, nor were they intend to be identical.

Nothing in this Final Rule changes these distinctions. Indeed, we are not changing the

Docket Nos. RM05-17-000 and RM05-25-000 - 548 -

relative priorities applicable to firm point-to-point service, network integration service

and service to bundled native load.

588

These services do, and will continue to, share the

same priority – the highest priority of firm service on the transmission provider's system.

The only change, as it relates to the conditional firm option, is to allow the customer to

elect to have its long-term firm transmission service interrupted under certain defined

circumstances. This does not harm other firm customers. Indeed, it has precisely the

opposite effect: it permits an interruption to maintain firm service to other customers.

Moreover, we find, as indicated above, that conditional firm service is necessary to

remedy undue discrimination.

929. The addition of conditional firm service therefore does not significantly alter the

existing balance between the point-to-point and network service. Customers of network

service retain flexibility that is not enjoyed by point-to-point customers. Moreover,

conditional firm does not reduce the availability of secondary network service or the

ability of network customers to temporarily undesignate network resources any more than

short-term firm point-to-point service already reduces the availability of these network

customer options. We therefore reject TDU Systems’ arguments and find that the

addition of conditional firm service is necessary to remedy undue discrimination and will

otherwise increase utilization of the grid without impairing system reliability.

588

See supra section V.D.5.b.

Docket Nos. RM05-17-000 and RM05-25-000 - 549 -

(2) Reliability

(A) Ability to Predict Redispatch Opportunities and System

Conditions in the Long Run

Comments

930. Some commenters state that redispatch, used as a planning tool rather than as

short-term operational tool, is overly complex, prone to causing disputes, reduces

reliability and thus should not be included in the pro forma

OATT.

589

Southern asserts

that planning redispatch should not be required where it reduces reliability by reducing a

utility’s reserve margin, shifting the operational, reliability and economic risks from the

new customer to native load, or causing a single contingency to overload the system.

Additionally, Xcel states that pledging a network resource to support planning redispatch

carries a risk of penalties for inadequate resources in some areas. MISO states that

contingency conditions must be considered and respected when evaluating planning

redispatch options so that there is no reliance on curtailment of service. MidAmerican

and Progress Energy conclude that the customer must accept the risk of selecting

planning redispatch service over transmission construction.

931. Several commenters request modification of the existing planning redispatch

provisions of the pro

forma OATT.

590

They state that the Commission should clarify that

589

E.g., Duke, Entergy, WAPA, NRECA, NPPD, LPPC, and Southern.

590

E.g., EEI, Indianapolis Power, Public Power Council, Southern, Seattle,

Sacramento, and LPPC.

Docket Nos. RM05-17-000 and RM05-25-000 - 550 -

the current section 13.5 does not require planning redispatch when it would adversely

affect system reliability or service to native load, network customers and other firm point-

to-point customers or impair other contractual obligations. Indianapolis Power states that

the Commission should modify section 13.5 to require all reasonable

redispatch options

be examined by the transmission provider.

932. In its reply comments, Southern explains that transmission providers fail to

provide the currently required planning redispatch service to point-to-point customers

because the service is impractical and would harm reliability. Southern contends that a

redispatch scenario identified in a transmission plan may not be available in real time due

to outages or loop flow. Southern is also concerned about the complications in planning

and modeling that would occur if the transmission provider is required to redispatch

multiple resources in order to accommodate multiple planning redispatch customers.

933. Similar to their arguments in favor of conditional firm, EPSA and AWEA state

that planning redispatch is necessary because a transmission provider will reject a long-

term firm service request unless it can satisfy every element of the request, even if

reliability violations occur in only a few hours of the year. In its reply comments, EEI

responds that there is no evidence to support the assertion that a transmission provider

will reject a long-term firm service request unless it can meet every element of that

request. EEI states that in such a situation the transmission provider must offer partial

service, offer to perform a system impact study, and exercise due diligence in

constructing needed upgrades to accommodate the request. EEI adds that the potential

Docket Nos. RM05-17-000 and RM05-25-000 - 551 -

customer can also request short-term service. Finally, EEI states that there is no evidence

that transmission providers are refusing to redispatch in response to customer request

when redispatching resources would have no impact on reliability. In its reply

comments, MISO states that denial of service complained of by EPSA and AWEA is a

consequence of the customer’s economic decision not to build upgrades.

934. Many transmission providers assert that the costs and inequities of achieving the

proposed planning redispatch outweigh any new benefits for point-to-point customers.

591

They state that the Commission’s proposal is based on an erroneous assumption that

redispatch is nearly always feasible; instead when redispatch is most desirable, generators

operating at peak would not be available for redispatch.

592

Southern also explains that

problems of insufficient transmission capacity cannot be avoided by redispatching

generation because there is no guarantee that a redispatch solution will be available

during real-time operations. Imperial argues that the personnel and modeling costs to

transmission providers of calculating planning redispatch costs prior to a facilities study

are too excessive. Xcel concludes from a NERC experiment on market redispatch that

redispatch involving non-market-based or bilateral coordination with third parties to

protect a delivery path is cumbersome, inefficient, and does not promote reliability.

591

E.g., Duke, Entergy, Imperial, International Transmission, Salt River, Seattle,

Southern, Tacoma, Northwest IOUs, Sacramento, Progress Energy, E.ON, Xcel, TVA,

and EEI Reply.

592

E.g., Sacramento and TVA.

Docket Nos. RM05-17-000 and RM05-25-000 - 552 -

935. Xcel states that its estimate of hours of planning redispatch is unlikely to be

accurate given that it uses a static power flow that is created for a specific peak hour and

a specific off-peak hour in a given year. Commenters state that planning redispatch

service should not be a guaranteed service because generation or transmission

availability, system loads, loop flows from adjoining systems, weather, and fuel

availability all entail a component of risk that should not be pushed back on the

transmission provider or its native load.

593

936. Operators of systems that rely primarily on hydroelectric resources argue that

planning redispatch should not be considered a viable option for their systems and they

should be exempt from OATT planning redispatch obligations because hydroelectric

operators are unable to make long-term commitments that a resource will be available to

relieve transmission constraints.

594

Bonneville states that the variability in water flows

and the interdependence of the generating units contribute to the inability to predict

future redispatch ability. Bonneville, WAPA and Bureau of Reclamation state that

planning redispatch can conflict with federal obligations to operate federal dams and

reservoirs in a manner that does not impact project purposes and provide preference in

the sale of hydropower to its preference customers. Tacoma states that planning

redispatch must be linked to market price indexes to work in a hydro-based system.

593

E.g., Progress Energy, E.ON, WAPA, Entergy, and MidAmerican.

594

E.g., Bonneville, Seattle, Public Power Council, and WAPA.

Docket Nos. RM05-17-000 and RM05-25-000 - 553 -

Seattle states that in hydro-dominant systems fuel availability and fuel price risk

undermine the feasibility of providing long-run redispatch cost estimates that reasonably

reflect future costs. Seattle adds on reply that planning redispatch fails to address costs

pertaining to fish species preservation, recreation and flood control impacts, increased

risk of spill, or replacement power that are associated with hydroelectricity.

937. Morgan Stanley argues on reply that the Commission should not exempt

hydroelectric system operators from providing planning redispatch; instead, factors

unique to hydroelectric systems should be taken into account in determining how much

planning redispatch a transmission provider can provide. In supplemental comments,

PPM agrees with Morgan Stanley and adds that hydro-based systems, such as

Bonneville’s, are flexible enough for a transmission provider to use planning redispatch

to create additional firm capacity.

938. In their reply comments, Utah Municipals and EPSA state that planning redispatch

would not impair reliability because the OATT provisions do not require transmission

providers to permit intentional overloading of lines. Since transmission providers are

already required to provide planning redispatch now, Utah Municipals contend that any

change in the sequence for studying the option cannot have an impact on reliability.

EPSA argues that claims of adverse reliability impacts should be dismissed because

transmission providers do not make these same claims when they redispatch to enable

transmission service to meet their own load obligations. Utah Municipals state that

reliability would be most enhanced by completely restricting access to the grid, a policy

Docket Nos. RM05-17-000 and RM05-25-000 - 554 -

that Utah Municipals do not recommend because it would be extraordinarily costly and

promote discrimination. In its reply comments, Entegra states that customers seeking

planning redispatch are not seeking to shift a disproportionate share of the risks or costs

to native load or other users of the system.

939. In its reply comments, EPSA further argues that the Commission should place the

burden of showing unreliability in a particular instance on the transmission provider.

EPSA also argues that transmission providers should not be allowed to delay service

through feasibility studies. EPSA contends that planning redispatch will not delay

needed system upgrades and, instead, will ensure optimized use of the existing system

that will provide additional information about the system’s capabilities to regional

planning initiatives. In its reply comments, Morgan Stanley states that the Commission

should establish clear standards as to the degree of expected reliability that appends to a

firm transmission sale and allow transmission providers to sell as much of the system as

can be sold on a firm basis, consistent with maintaining the reasonable standard.

940. EEI and some transmission providers add that the conditional firm product could

result in an oversubscription of a transmission system in violation of NERC reliability

standards that require the transmission system to be planned to meet all firm needs.

595

ELCON states that conditional firm service may not truly support long-term contracts for

firm power but may lead to a greater volume of short-term trading.

595

E.g., Ameren, Southern, and EEI.

Docket Nos. RM05-17-000 and RM05-25-000 - 555 -

Commission Determination

941. Many commenters are concerned that the options described in the NOPR will

impair system reliability. We have taken these comments into account and have tailored

the modifications to long-term point-to-point service so as to not impair system

reliability. There are two important limitations that provide such protections. First, we

make clear that transmission providers are not

required to offer planning redispatch or

conditional firm service if doing so would impair system reliability.

596

Second, as

explained above and discussed in further detail below, we are limiting the time period

under which either option is offered. We do so because forecasts of potential redispatch

or interruption options become more speculative over time and to require a transmission

provider to commit for a substantial period of time, subject to the uncertainty inherent in

such long-term projecting, has the potential to degrade reliability. With these two

limiting conditions, we find that neither the planning redispatch nor conditional firm

option will degrade reliability and, as discussed above, that both are necessary to remedy

undue discrimination.

596

A transmission provider may not be able to provide conditional firm service

without impairing the reliability of its system if it is required, for example, to manage

many conditional firm point-to-point reservations across the same path. The ability of

system operators to track, tag and manage curtailment of multiple conditional firm

reservations is necessarily limited by time, human resources and other reliability-related

duties of the operators.

Docket Nos. RM05-17-000 and RM05-25-000 - 556 -

942. We agree with a majority of commenters that over the long term, new resources

should be supported by sufficient transmission capacity to deliver their output reliably.

Imposing a planning redispatch or conditional firm obligation over the long-run would

not be consistent with the need to increase the reliability of the grid or otherwise

necessary to remedy undue discrimination. Rather, it would tend to degrade reliability

over time, contrary to the public interest and the underlying goals of EPAct 2005.

Projections of planning redispatch options and conditional firm conditions are more

accurate in the near term and, hence, should facilitate the efficient use of existing

resources without impairing reliability.

943. We therefore impose limits on the transmission provider’s current planning

redispatch obligations. We do so by removing the obligation to provide planning

redispatch for an indefinite period as long as the redispatch is less expensive than the

relevant transmission upgrades. Section 13.5 of the pro forma

OATT could, in

conjunction with rollover rights, allow for an extremely long-term obligation to provide

planning redispatch in lieu of upgrading the transmission system. We find that this

existing obligation may unreasonably harm reliability and provides incorrect incentives to

delay necessary grid expansion. We emphasize that the obligation to provide planning

redispatch applies only when the service can be provided reliably.

944. We also limit the time period over which a transmission provider must predict the

system conditions or conditional hours that would apply to customers using the

conditional firm option. We do so in recognition of the difficulty in attempting to

Docket Nos. RM05-17-000 and RM05-25-000 - 557 -

forecast curtailment options over the long-term and the fact that there is no evidence that

transmission providers perform similar forecasts for their native load customers. We do

not, however, eliminate entirely the risk of predicting future system conditions or shift it

in whole to the requesting transmission customer as requested by certain commenters.

We believe that the transmission provider should retain responsibility for incorporating

reasonable assumptions into its transmission models so that it can manage this risk, just

as it currently manages the prediction risk in its ATC models.

945. We will now turn to certain clarifications and other issues raised by the

commenters. We acknowledge that planning redispatch to support annual service may

require redispatch of generation during the peak month or months. Since transmission

providers plan their generation to meet their peak native load plus reserves, the

transmission provider’s resources may, in some cases, be fully employed to meet the

needs of bundled retail native load and thus may not be available to provide redispatch

during the peak period.

597

In such an instance, the unavailability of such resources to

provide redispatch service will constitute a legitimate basis for denying planning

redispatch service. However, we will not excuse the existing obligation that requires

transmission providers to study any available planning redispatch, including redispatch

that might provide some but not all of the service requested. Given that some

597

See, e.g., Arizona Public Service Co. v. Idaho Power Co., 95 FERC ¶ 61,081

at 61,241 (2001) (resources projected to be unavailable during system peak month to

provide planning redispatch).

Docket Nos. RM05-17-000 and RM05-25-000 - 558 -

transmission providers have acknowledged their own use of planning redispatch for their

network resources,

598

the service must continue to be available to those seeking point-to-

point service to ensure comparability.

946. We reiterate that the transmission provider remains obligated to provide planning

redispatch from its resources as long as the planning redispatch does not (1) degrade or

impair the reliability of service to native load customers, network customers and other

transmission customers taking firm point-to-point service or (2) interfere with the

transmission provider’s ability to meet prior firm contractual commitments to others.

599

We continue to believe these are the appropriate exceptions and will not adopt a broad

and undefined reasonableness standard as suggested by Indianapolis Power. We agree

with Southern that the transmission provider may consider the impact of the planning

redispatch service in reducing its reserve margin below that necessary to maintain

reliability or causing a single contingency to overload the system in determining whether

the service can be reliably provided.

947. Further we will not excuse transmission providers from the obligation to manage

multiple planning redispatch or conditional curtailment obligations simply because some

commenters express concerns about planning and modeling impacts. While we do not

take these concerns lightly, we believe they can be managed by transmission providers.

598

E.g., Entergy.

599

See also Morgan Stanley.

Docket Nos. RM05-17-000 and RM05-25-000 - 726 -

the corresponding planning and construction obligations of transmission providers. We

also believe that an increase to a five-year term is consistent with the native load

protections contained in new section 217 of the FPA, primarily because requiring longer-

term agreements ensures that the rollover right is used by transmission customers with

long-term obligations to purchase capacity.

749

Accordingly, the Commission adopts a

five-year minimum contract term in order for a customer to be eligible for a rollover

right. At the end of its initial five-year contract term, a transmission customer must,

within the one-year notice period (discussed more fully below), agree to another five-year

contract term or match any longer-term competing request in order to be eligible for a

subsequent rollover.

1232. Our decision to adopt a five-year minimum term will remedy many of the

problems associated with the current policy. Under our current policy, a customer can

secure transmission service for one year and, in so doing, require the transmission

provider to plan and upgrade its system on the assumption the rollover right will be

continually renewed. For example, if a transmission provider’s planning horizon is 10

years, a one-year reservation would require the transmission provider to plan and upgrade

749

See EPAct 2005 sec. 1233(a) (to be codified at section 217(b)(4) of the FPA,

16 U.S.C. 824q), which provides that “[t]he Commission shall exercise the authority of

the Commission under [the FPA] in a manner that facilitates the planning and expansion

of transmission facilities to meet the reasonable needs of load-serving entities to satisfy

the service obligations of the load-serving entities, and enables load-serving entities to

secure firm transmission rights (or equivalent tradable or financial rights) on a long term

basis for long term power supply arrangements made, or planned, to meet such needs.”

Docket Nos. RM05-17-000 and RM05-25-000 - 727 -

the system as if the customer had purchased 10 years’ service (i.e.

, would exercise its

rollover right every year during that 10-year period). Because of this, the customer

receives a guarantee of service beyond what it has contracted to pay for and the

transmission provider must plan for service that may not actually be used.

1233. By failing to link the customer’s rights and obligations with those of the

transmission provider, the current policy can have several detrimental effects. For

example, it requires the transmission provider to plan and construct facilities that may not

be necessary to serve load. Given the difficulty of siting new transmission, it is

inappropriate to require transmission providers to use finite resources to finance and

construct facilities that may not be necessary. Additionally, the current policy harms

OATT customers by allowing rollover customers to tie up capacity that may be needed

by other customers. This is because the current policy allows a rollover customer to lock

up existing capacity, regardless of whether the rollover customer intends to use that

capacity. This reduces the availability of existing capacity for other customers and, in

turn, reduces competitive alternatives for customers.

1234. Some commenters have argued that the Commission should use a shorter period,

such as three years, that is more aligned with auctions in retail access markets or existing

commercial practices. We disagree. The purpose of our reform of the rollover rights

policy is to ensure that the rights and obligations of the customer are better aligned with

the planning and construction obligations of the transmission provider. It is not to link

the term of the rollover right to any particular commercial practice in any particular

Docket Nos. RM05-17-000 and RM05-25-000 - 728 -

region. We do not believe that such a policy could be fairly implemented in any event.

Commercial practices vary between the regions and change over time, and it would

therefore be impractical to tailor the rollover rights in the OATT to the varying

commercial practices across the country.

1235. We also do not believe that adopting a five-year minimum term will have an

adverse effect on participation in retail auctions that use three-year solicitations. At the

outset, we note that retail auctions use solicitations of varying length and, hence, the fact

that some states may use three-year auctions does not provide a basis to establish a

generic standard for rollover rights under the OATT. Some states use shorter term

auctions (e.g.

, one year) and, as indicated, we cannot reasonably tailor an OATT rollover

obligation to the varying commercial practices across the country. We also do not

believe that our policy will have an adverse effect on any such auctions. The winners in a

retail solicitation are determined anew in each auction, based on the bids submitted in

that auction. A prospective bidder therefore does not need a “rollover right” to compete

in an auction. It only needs transmission service over the term of the solicitation (e.g.

three years). The fact that it may not have an automatic right to transmission capacity in

the next auction simply places it on the same footing as any other bidder.

1236. In response to those commenters who argue that transmission customers making

this long-term commitment must also be permitted to change their designated resources

and receipt points as their power supply needs change, we believe that such an approach

is unworkable. Allowing rollover customers to change their designated resources and

Docket Nos. RM05-17-000 and RM05-25-000 - 729 -

receipt points in this manner would inappropriately result in rollover customers having

priority over other transmission customers in the queue that may have already requested

service over a given transmission path. This could result in substantial disruptions to

transmission service to higher-queued customers requesting long-term service over these

paths.

750

Moreover, transmission customers are not currently guaranteed the ability to

turn to other suppliers at other designated resources and receipt points and, therefore, we

do not understand how simply increasing the minimum contract term to five years should

necessarily result in allowing transmission customers this increased flexibility. Likewise,

we do not understand why an increase in the minimum contract term should result, as

argued by APPA, TAPS, and others, in a transmission customer not having to compete

with other transmission customers for firm capacity whenever its contract comes up for

renewal. As discussed below, we will continue to require transmission customers to

match competing requests for service as to term and rate, ensuring that transmission

customers that value the service the most receive it.

1237. We reject TAPS’ proposal to exempt all small customers from the five-year

minimum, since this would interfere with transmission providers’ ability to plan their

systems to meet their customers’ needs. As EEI points out, the aggregated loads of

750

We agree with EEI that requiring transmission providers to ensure rollover

customers the ability to change their designated resources and receipt points without

disrupting service to other customers would, taken to its logical conclusion, require

transmission providers to construct the transmission system with sufficient redundancy to

permit any customer to take service from any resource.

Docket Nos. RM05-17-000 and RM05-25-000 - 730 -

several small customers can have a substantial impact on the system. We therefore

believe it would be inappropriate to categorically exempt small customers. We also

reject TAPS’ proposal to exempt all full and near-full requirements customers, because it

would force transmission providers to provide preferential service to certain groups of

customers. Additionally, we reject TAPS’ proposal to allow customers to exercise

rollover rights with only one-year contracts if there is no competing request. Without a

competing request, a rollover right is not necessary in order to continue service as long as

capacity remains available. Additionally, allowing a rollover for a one-year contract

would continue to impose planning and construction obligations on the transmission

provider that bear no reasonable relation to the rights and obligations of the rollover

rights customer. We further reject TDU Systems’ proposal that transmission providers

demonstrate the availability of long-term supplies before moving to a five-year term. To

do so would effectively require transmission providers to engage in the business of

procuring supplies for their transmission customers, which is clearly outside the scope of

their obligation to provide transmission service, and could implicate Standards of

Conduct issues.

1238. We also reject the proposal of EPSA and others that all currently effective one-

year power supply contracts be grandfathered because this would disrupt transmission

planning. For example, such an approach would require that a large portion of existing

capacity be planned for on a significantly different timeline than that subject to the

reformed rollover right. This also would detract from one of the primary goals of

Docket Nos. RM05-17-000 and RM05-25-000 - 731 -

rollover reform, which is to improve transmission planning and encourage longer-term

contracting. As discussed below, existing transmission contracts will be permitted to roll

over under their existing terms until the first such rollover opportunity following the

effectiveness of the reforms required by this Final Rule.

1239. Lastly, we note that many of the reforms adopted elsewhere in this Final Rule will

be beneficial to customers that no longer receive rollover rights, as well as to customers

with rollover rights that wish to use their rollover rights to turn to alternative suppliers

using different transmission paths. First, greater consistency and transparency in ATC

calculations will provide greater assurance of nondiscriminatory access to existing

transmission capacity. Second, our reforms relating to conditional firm and redispatch

service will help to maximize the use of existing capacity, consistent with reliability,

thereby providing customers without rollover rights greater flexibility to purchase

existing transmission capacity. Third, our clarifications regarding our policy on redirects

should improve the ability of transmission customers to redirect their service to new

receipt or delivery points. Fourth, lifting the price cap on reassigned transmission

capacity should assist transmission customers in reassigning any capacity that may not be

needed on a given path because of a change in suppliers that requires service over new

transmission paths. This will also necessarily result in the unneeded capacity being freed

up for use by other transmission customers, thereby further assisting them in obtaining

capacity that they need to access alternative suppliers. Lastly, and most importantly,

greater openness and coordination in transmission planning should provide all customers

Docket Nos. RM05-17-000 and RM05-25-000 - 732 -

better information regarding future resource options and access to competitive

alternatives. We also believe that improved transmission planning should help to address

allegations made by certain transmission customers (e.g.

, Williams) that even though they

have signed up for ten years of service, they have not seen their needs planned for

adequately.

b. One-Year Notice Provision

Comments

1240. Many commenters support an increase in the notice period to one year or some

other greater time period.

751

Most support the increase based on the argument that the

current 60-day notice period makes it very difficult to plan the system, because

transmission providers often do not know until 60 days before the end of a contract

whether a transmission customer will roll over its service, resulting in potential

overbuilding of the system (e.g.

, because a transmission provider must plan its system

assuming a transmission customer will roll over but sometimes it does not). They also

argue that it is difficult to re-market capacity in only 60 days if rollover is not sought and

751

E.g., Ameren, Barrick Reply, Bonneville, Community Power Alliance,

Constellation, Dominion, Duke, East Texas Cooperatives, EEI, E.ON, Entegra, Entergy,

FirstEnergy, Great Northern, Imperial, LDWP, LPPC, MidAmerican, MISO, MISO

Transmission Owners, Nevada Commission, Nevada Companies, North Carolina

Commission Reply, NorthWestern, Northwest IOUs, NRECA, PGP, Pinnacle, PNM-

TNMP, Progress Energy, Public Power Council, Salt River, Santa Clara, Southern, South

Carolina E&G, SPP, Tacoma, TranServ, TVA, Utah Municipals, and Xcel. Both APPA

and TAPS support a one-year notice provision, but only on the condition that the

clarifications and modifications they suggest are made.

Docket Nos. RM05-17-000 and RM05-25-000 - 733 -

that potential transmission customers are often unnecessarily turned away because

transmission providers are unaware of the availability of capacity until 60 days before the

end of a contract subject to a rollover right. In general, these commenters view a one-

year notice period as an improvement. However, many of these same commenters do not

believe one-year notice is appropriate if the transmission provider must construct

facilities to accommodate a rollover and, therefore, the notice should instead be tied to

the start date for any necessary upgrades.

752

1241. EEI, for example, believes that notice should be tied to the start date of any

necessary transmission upgrades, because the transmission provider may be left with

stranded transmission capacity if it must begin construction on upgrades necessary to

accommodate a rollover before the transmission customer has even indicated whether it

will in fact seek a rollover. EEI also argues that a competing customer could be required

to pay an incremental rate for network upgrades that could have been avoided if the

rollover customer had provided earlier notice of its intention not to seek a rollover. EEI

further contends that some state commissions will not allow upgrades where there is only

the potential for a rollover. Finally, EEI states that a one-year notice period does not

ensure that the transmission provider will be able to re-market the capacity, forcing other

transmission customers to bear the increased costs associated with the newly constructed

752

E.g., Barrick Reply, Duke, EEI, Entergy, Indianapolis Power Reply, LPPC,

Nevada Commission, Nevada Companies, Pinnacle, Progress Energy, South Carolina

E&G Reply, Southern, and TVA.

Docket Nos. RM05-17-000 and RM05-25-000 - 734 -

transmission facilities. EEI proposes that a date be included in the initial service

agreement by which the transmission customer must exercise its rollover rights if

upgrades are needed to accommodate the rollover. If there is a pre-confirmed competing

request or newly projected growth in native load, EEI suggests that the rollover customer

must exercise its rollover and match by the later of the project start date for any new

transmission facilities needed or 60 days after the transmission provider notifies the

transmission customer of the competing request.

753

Additionally, if more than one-year

notice is required because of the need for upgrades, EEI proposes that the transmission

provider be required to notify the transmission customer if subsequent events delay the

project start date, in which case the notice period would be revised. EEI asserts that any

disputes can be dealt with by protesting the filing of an unexecuted agreement. EEI

stresses that better, more inclusive planning, and more transparent ATC calculations, will

provide transmission customers with greater assurances that project start dates are

accurate.

1242. Southern suggests that partial rollover be permitted if notice is not given in time

for construction of an upgrade needed to provide full service. Duke, Nevada

Commission, and Southern suggest that providing for one-year notice without a link to

the start date for any upgrades falls short of the native load protections found in section

753

Ameren, Pinnacle, Southern, and TranServ agree that the submission of a

competing request should trigger an accelerated timeline for the original customer to

exercise or release its rollover rights.

Docket Nos. RM05-17-000 and RM05-25-000 - 735 -

217 of the FPA. As an alternative, the Nevada Commission suggests tying the notice

requirement to the amount of capacity subject to rollover, i.e.

, below a certain threshold,

one year would be deemed per se

sufficient.

1243. APPA argues in reply that many customers may not know even one year in

advance if they will have firm power supplies under contract that would enable them to

roll over their corresponding firm transmission agreement and, therefore, requiring them

to exercise their rollover rights even earlier in the contract term would only exacerbate an

already impossible situation. In their replies, NRECA, TAPS, TDU Systems, and Utah

Municipals urge the Commission to reject the recommendation that notice periods be

expanded to be commensurate with construction lead times. They argue, among other

things, that LSE transmission customers need a reasonable amount of certainty so that

they may plan their power supply arrangements without fear that they may become

unraveled due to unforeseeable circumstances. Utah Municipals also assert that the

proffered justification for the proposal – to prevent overbuilding – is questionable at best

as even the current policy which requires only a one-year contract minimum for rollover

and 60-days notice has not resulted in wasteful overbuilding of the system. TDU

Systems also point out that under section 28.2 of the pro forma

OATT, transmission

providers should be planning and expanding their systems to accommodate their network

customers’ current and future needs.

Docket Nos. RM05-17-000 and RM05-25-000 - 736 -

1244. The one-year notice provision is opposed by several commenters, who argue that

having to give one-year notice constitutes an undue burden.

754

In general, these

commenters argue that under current market conditions, transmission customers do not

typically renew supply contracts one year in advance of expiration.

755

Alberta

Intervenors argue that a one-year notice provision does not aid in re-marketing capacity,

as any unused long-term firm service is already re-marketed as short-term firm or non-

firm service. Alberta Intervenors also argue that the increased lead time increases risk

and creates uncertainty making it less likely that customers will enter into long-term

contracts. EPSA and Exelon suggest a flexible notice rule that depends on the length of

the underlying contract or requiring more than 60-days notice if there is insufficient

capacity for a new long-term firm transmission service request, as is done in PJM. They

also suggest PJM’s approach whereby a transmission customer must inform PJM whether

it will roll over within thirty days of being notified of a competing request. PPM and

Wisconsin Electric suggest a six-month notice period, which complements their

alternative suggestion of a three-year minimum contract term.

754

E.g., Alberta Intervenors, Alcoa, Arkansas Municipal, EPSA, Exelon, Manitoba

Hydro, Morgan Stanley, PPM, TransAlta, Williams, and Wisconsin Electric.

755

E.g., Arkansas Municipal, Williams, and Wisconsin Electric.

Docket Nos. RM05-17-000 and RM05-25-000 - 737 -

Commission Determination

1245. The Commission finds that the current 60-day notice period should be modified to

reflect the longer term (five years) of the rollover rights. Currently, a customer with a

one-year rollover right has 60 days to provide notice of whether it intends to rollover its

capacity. This 60-day period was reasonable for a rollover right of short duration (one

year), but it is no longer reasonable for a rollover right with a minimum five-year term.

1246. In selecting a new notice period, the Commission has attempted to balance the

circumstances faced by customers in renewing power supply contracts and the interests of

transmission providers in attempting to plan their system. The Commission recognizes

that no single notice period can perfectly balance these considerations, but chooses the

one-year notice period as most appropriate under the circumstances. Given that the

minimum rollover term has been lengthened to five years, it is reasonable to expect that

customers will consider renewing such long term obligations in advance of 60 days prior

to the expiration of their current obligation. We do not believe it is reasonable to fashion

our notice period for customers that wait until the last minute to evaluate whether to

extend their long-term contracts.

1247. Many transmission providers argue that a one-year notice period is too short

because it is not consistent with the transmission provider’s planning horizon. We

disagree. The Commission is extending the minimum term for rollover rights to five

years to ensure greater consistency between the customer’s rights and obligations and the

planning and construction obligations of the transmission provider. We believe that this

Docket Nos. RM05-17-000 and RM05-25-000 - 738 -

modification satisfies the principal concerns of transmission providers regarding the

current policy on rollover rights. We recognize that a one-year notice period is shorter

than the typical planning horizon, but we decline to extend the notice period to a time that

coincides with the typical planning horizon or the time it takes to construct new facilities.

Doing so would effectively eliminate rollover rights altogether, given that the resulting

notice period could be three-to-five years. We do not believe it is reasonable to expect

customers to have decided on new sources of supply three years in advance of the

expiration of their current contracts. We therefore find that a one-year notice period most

appropriately balances the interests of customers and transmission providers.

c. Matching and Rollover Restrictions Based On Native and

Network Load Growth

Comments

1248. As noted above, the Commission proposed to maintain the requirement that an

existing rollover transmission customer match competing offers as to term and rate.

Some commenters argue that a competing customer be required to execute a contingent

service agreement that becomes effective if the rollover customer does not match.

756

Given the increase in the minimum contract term to five years in order to be eligible for a

rollover right, TAPS argues that matching must be structured to recognize that a network

customer must extend its power supply by at lease five years as well, in order to match a

756

E.g., MidAmerican and Powerex.

Docket Nos. RM05-17-000 and RM05-25-000 - 739 -

competing point-to-point customer that can simply extend its reservation. To ensure that

network customers are not disadvantaged by matching, TAPS suggests that the

Commission restrict reservations qualified to compete against a network customer’s

reservation to customers with long-term power contracts, so they are on more equal

footing with network customers. TAPS also proposes a cut-off for requests with which

the network customer will need to compete, such as three months prior to when the

network customer exercises its rollover right, so that the network customer can structure

its power supply commitments with some degree of advance knowledge of the competing

requests. In its reply, Bonneville suggests allowing network transmission customers to

compete based on the duration of their network transmission service request rather than

on the duration of their resource commitments. As such, the transmission provider would

assume that existing designated resources would continue to be used after the rollover

unless informed otherwise.

1249. The Commission also discussed in the NOPR whether native load restrictions

should be reevaluated with each rollover and, if so, whether native load should then be

required to compete with rollover customers for the capacity. Several commenters argue

that a transmission provider’s native and network loads should not be forced to compete

with other transmission customers, as opposed to allowing the transmission provider to

continue to reserve capacity for its native and network load at the time of granting a

Docket Nos. RM05-17-000 and RM05-25-000 - 740 -

rollover.

757

Most also stress that requiring a transmission provider to compete would

violate the native load protections in section 217 of the FPA. LDWP contends that there

should be no limitation on a transmission provider’s right to recall capacity based on

revised forecasts of native load growth.

1250. APPA contends on reply that transmission customers could find it very difficult to

line up a new firm power supply of a term long enough to match the power supply

arrangements of its vertically-integrated investor-owned transmission provider (which is

likely to have owned, rate-based generation in its power supply portfolio and, therefore,

could agree to a very long-term transmission agreement). TDU Systems argue that

transmission providers should be forced to compete for capacity and that this is, in fact,

required by section 217 of the FPA, as the native load preference does not distinguish

between the retail native loads of transmission providers and the native loads of other

LSEs dependent on their systems. Powerex and PPM also support requiring transmission

providers to compete. NorthWestern and Southern support requiring transmission

providers to compete, but only when a restriction is not included in the original

agreement. APPA also notes in its reply comments that, if Southern included LSEs’

loads in its transmission planning and construction program along with its own native

757

E.g., Allegheny, Entergy, FirstEnergy, Imperial, Nevada Companies, Progress

Energy, Salt River, Santa Clara, and Seattle.

Docket Nos. RM05-17-000 and RM05-25-000 - 741 -

load, there would be no need to reclaim the LSEs’ capacity at the close of the initial

contract term or the renewal terms.

1251. Several commenters also addressed the Commission’s request for comment on

whether there is a sufficiently clear, consistent, and transparent method that could be

implemented on a generic basis to address the need for a transmission provider to

demonstrate its forecast of native load growth and its effect on capacity reserved by

rollover customers. Many of these commenters support the development of a clear and

transparent method for demonstrating native load growth.

758

Some commenters point to

the need for accurate and transparent ATC calculations to aid in this process.

759

If the

transmission provider’s calculation of ATC is consistent with the requirements the

Commission adopts in this proceeding yet there is insufficient capacity to accommodate

the customer’s rollover, EEI recommends that the provider may include in the service

agreement a limitation of rollover rights. AWEA recommends that transmission

providers adopt the same transparent and consistent methods used to compute the

Existing Transmission Capacity component of ATC to develop native load growth

reservations that support rollover restrictions. AWEA, NorthWestern, and TAPS suggest

posting forecast information on the OASIS, and TAPS goes on to stress that this

758

E.g., AWEA, Duke, EEI, Entergy, EPSA, Imperial, Nevada Commission,

Powerex, Salt River, Seattle, South Carolina E&G, Southern, SPP Reply, and TAPS.

759

E.g., AWEA, EEI, EPSA, and MISO.

Docket Nos. RM05-17-000 and RM05-25-000 - 742 -

information should be included in state planning documents as well as the transmission

provider’s coordinated and regional planning process. EPSA stresses that native load

capacity must follow native load and not only be made available for the transmission

provider and its affiliates. EPSA believes this is required by the native load protections

found in FPA section 217.

1252. Duke asks the Commission to address the possibility that capacity subject to a

rollover right might be needed to serve native load outside of the ten-year planning

horizon. The Nevada Commission and Southern suggest that the Commission give

deference to state resource planning processes in attempting to verify native load growth

forecasts. Southern also asks that the Commission clarify that rollover rights can be

restricted based on rollover rights belonging to higher-queued transmission customers. If

transmission studies show no problems without the presence of a rollover, but then

problems are identified with the rollover included, Southern contends that placing a

corresponding limitation in the service agreement would be appropriate. Pinnacle

requests clarification that when rollover rights are restricted based on native load growth,

the transmission customer must pay for upgrades to continue its service.

1253. Several commenters also suggest that transmission providers should be permitted

to evaluate rollover restrictions at the time of each rollover.

760

These commenters argue

that it is impossible to identify all potential limitations upfront as system conditions

760

E.g., Nevada Companies, South Carolina E&G, and Southern.

Docket Nos. RM05-17-000 and RM05-25-000 - 743 -

change in unforeseeable ways (e.g.

, fluctuations in fuel prices can change dispatch

decisions). They also argue that allowing a re-evaluation is consistent with the native

load protections in FPA section 217.

1254. In its reply, TAPS argues that a transmission provider should not be permitted to

avoid its planning and expansion obligations by treating load growth not anticipated and

documented in the original service agreement as a competing request to be matched.

TAPS points out that section 217 of the FPA treats all LSEs – whether they are

transmission providers or transmission-dependent utilities – the same, without distinction,

and therefore provides no basis to allow one LSE to claim transmission rights currently

used by another LSE.

761

Lastly, TAPS argues that when a provider is reclaiming capacity

for load growth reserved in the initial service agreement, rollover customers should be

allowed to match the request, thereby imposing an additional requirement on the

provider.

Commission Determination

1255. The Commission will not adopt any changes to its matching policies at this time.

At the time of rollover of their contracts, transmission customers will continue to be

required to match competing requests for service as to term and rate in order to roll over

their service. This preserves the current policy goal of providing a mechanism for

awarding capacity to those who value it most, as well as providing for a tie-breaking

761

See also APPA Reply and TDU Systems Reply.

Docket Nos. RM05-17-000 and RM05-25-000 - 744 -

mechanism when needed that gives priority to existing customers so that they may

continue to receive transmission service.

762

Absent the requirement that the customer

match the contract term of a competing request, transmission providers could be forced to

enter into shorter-term arrangements that could be detrimental from both an operational

standpoint (i.e.

, system planning) and a financial standpoint.

763

We clarify, however, that

transmission customers must also enter into a transmission contract of at least five years

in order to obtain a subsequent rollover right in the absence of a competing request for a

longer term.

1256. The Commission will continue to require rollover restrictions based on reasonable

forecasts of native load growth or preexisting contracts that commence in the future to be

included in the initial transmission service agreement. This will remain the only

appropriate way to restrict a rollover right. We also will continue to evaluate a

transmission provider’s native load growth forecasts on a case-by-case basis, as no

commenter has provided us with a sufficiently clear, consistent, and transparent method

that could be implemented on a generic basis that ensures that the demonstration of native

load growth is accurate and is tied to a need for the specific capacity reserved by a

762

See Order No. 888-A at 30,197.

763

Id.

Docket Nos. RM05-17-000 and RM05-25-000 - 745 -

rollover customer.

764

Because we will continue to require rollover restrictions to be

included in the initial transmission service agreement, we necessarily reject the

suggestion that transmission providers be permitted to restudy for rollover restrictions at

the time of each rollover. Accordingly, it is unnecessary for us to address whether it

would be appropriate for a transmission provider’s native or network load to compete

with a rollover customer if a new study at the time of the rollover indicated a native or

network need for the capacity.

1257. In response to the suggestions of some commenters, we believe that consideration

should be given in our case-by-case evaluations of native load growth forecasts to state-

approved integrated resource plans that show a native load need for the capacity.

765

Moreover, we believe that the ATC and planning reforms that we are adopting in this

Final Rule will provide greater transparency and assurance that transmission providers’

forecasts of native load growth are accurate. We emphasize that we expect the forecasts

utilized in transmission planning to be consistent with the forecasts utilized to support a

rollover restriction. Lastly, the coordinated and regional planning process required by

764

While the Commission has not to date accepted any native load growth

showing made by a transmission provider, it has recently set for hearing several such

showings. See, e.g.

, Southern Co. Servs., Inc., 116 FERC ¶ 61,050 (2006); Nevada

Power Co., 116 FERC ¶ 61,093 (2006).

765

We note that this is consistent with the Commission’s evaluation of rollover

restrictions proposed by transmission providers in the past. See, e.g.

, Nevada Power Co.,

97 FERC ¶ 61,324 at 62,493 n.17 (2001).

Docket Nos. RM05-17-000 and RM05-25-000 - 746 -

this Final Rule is designed to improve the availability of transmission service by, among

other things, increasing transparency and providing customers a meaningful opportunity

to participate in the planning process. Accordingly, we believe that improved planning

should help to reduce the need to restrict rollovers in the future.

d. Other Issues

Comments

1258. A number of comments relate to the applicability of the rollover-related reforms to

RTOs and ISOs. CAISO asks the Commission to confirm that the rollover reforms do

not apply to CAISO as its current tariff does not have such a provision and rollover is, in

fact, incompatible with CAISO’s transmission service model. Sacramento, however, asks

the Commission to clarify that rollover rights apply to long-term firm service provided by

RTOs and ISOs under Order No. 681 under what it terms the “as good as or superior to”

standard.

766

Organization of MISO and PJM States assert that any changes for RTOs

should be made through the stakeholder process. In its reply, Williams opposes

permitting RTO stakeholders to determine changes in rollover rights policy in RTO

regions, as it would result in disparate rules and practices and increased opportunities for

766

In its reply, CAISO argues that this request to expand the requirements of

Order No. 681 is inappropriate both because the Commission and courts have already

recognized that rollover rights under the pro forma

OATT do not apply to entities like

CAISO that do not offer traditional Order No. 888 network and point-to-point

transmission services and because the Commission has already rejected such a

requirement in Order No. 681 itself.

Docket Nos. RM05-17-000 and RM05-25-000 - 747 -

discrimination, and therefore, the Commission should adopt a single policy applicable to

all rollover rights.

1259. Other commenters raise different discrete issues. Morgan Stanley asks the

Commission to amend pro forma

OATT section 2.2 to include existing policy

determinations with respect to the manner in which a transmission provider can curtail or,

alternatively, must honor and accommodate rollover requests. Duke asks the

Commission to abandon its existing policy prohibiting the restriction of rollover rights

based on the potential exercise of other customers’ rollover rights. Salt River asks the

Commission to clarify that the proposal to extend the minimum term to five years does

not change the definition in section 1.20 of the pro forma

OATT that one year constitutes

a long-term contract. AWEA, Constellation, and EPSA ask the Commission to allow

transmission customers to waive their rollover rights.

Commission Determination

1260. As we explain in section IV.C above, RTOs and ISOs must submit a filing

showing that their practices are consistent with or superior to the modifications made in

the Final Rule. This does not necessarily mean that entities such as CAISO must create

rollover rights if they do not have them already. Arguments regarding the applicability of

rollover reform may be raised pursuant to the process described in section IV.C. We also

clarify that our decision to extend the minimum term to five years does not change the

definition in section 1.20 of the pro forma

OATT that one year constitutes a long-term

Docket Nos. RM05-17-000 and RM05-25-000 - 748 -

contract. Commenters have not offered sufficient justification for further clarifications to

our rollover policies or amendments to section 2.2 at this time.

e. Effectiveness Upon Acceptance of Coordinated and

Regional Planning Process and Transition

Comments

1261. Several transmission customers and other commenters support a linkage between

rollover reform and planning, but do not support making rollover reforms effective upon

acceptance of a transmission provider’s coordinated and regional planning process, but

rather on successful implementation of that process.

767

While both TAPS and TDU

Systems support the link to planning generally, TAPS goes further and advocates holding

transmission providers accountable for failing to plan and construct facilities needed to

meet transmission customer needs. TDU Systems point out that the linkage to planning

does not remedy concerns that the current market does not generally provide for five-year

supply contracts.

1262. Some commenters, however, oppose linking the effectiveness of rollover reform to

planning, arguing that rollover reform is needed as quickly as possible.

768

For example,

Duke, Progress Energy, and Southern argue that FPA section 217 provides no indication

767

E.g., AWEA, Constellation, EPSA, Exelon, PGP, and PPM.

768

E.g., Bonneville, Duke, EEI Reply, North Carolina Commission Reply,

Northwest IOUs, PNM-TNMP Reply, Progress Energy, Public Power Council, South

Carolina E&G Reply, and Southern.

Docket Nos. RM05-17-000 and RM05-25-000 - 749 -

that the native and network load protections inherent in rollover reform should be subject

to conditions such as waiting for the Commission to accept a planning process.

Moreover, Duke argues that developing a planning process will be time-consuming and

that holding rollover reform hostage to it could motivate stakeholders with contracts

shorter than five years to endlessly try to convince the Commission to delay acceptance

of a transmission provider’s planning process.

1263. Some commenters contend that linking planning and rollover reform will create

differences in tariffs, with each transmission provider having a different effective date for

rollover reforms.

769

MISO argues in its reply that the Commission should clarify in the

Final Rule that its requirement that the new policy becomes effective upon acceptance of

the transmission provider’s coordinated and regional planning process is already met in

regions where RTOs or ISOs provide service, as they already have Commission-approved

regional transmission planning mechanisms in place. Bonneville argues in its reply for a

consistent implementation date across all transmission providers so as to avoid another

degree of complexity for customers requiring rollover capacity across multiple

transmission providers’ systems.

1264. As for the transition period proposed in the NOPR, a variety of commenters point

out that, depending on the status of any given contract, making the one-year notice

provision effective on acceptance of a transmission provider’s planning process could

769

E.g., Northwest IOUs, Duke Reply and EEI Reply.

Docket Nos. RM05-17-000 and RM05-25-000 - 750 -

leave some transmission customers unable to provide one-year notice if there is less than

one year remaining on their contracts.

770

FirstEnergy, Exelon, Great Northern, and TAPS

emphasize that existing transmission customers should be permitted one more rollover

under the current rules, because the parties to such agreements have relied on the current

rules in meeting their transmission needs. APPA and TAPS point out that transmission

customers will need a sufficient amount of time to secure five-year power agreements to

meet the new requirements. AWEA argues generally for a transition period during which

existing customers can maintain or relinquish their existing rollover rights under current

rules and become subject to new requirements only at the end of the transition period.

Commission Determination

1265. The Commission adopts the NOPR proposal to make rollover reform effective at

the time of acceptance by the Commission of a transmission provider’s coordinated and

regional planning process also required by this Final Rule. We believe that rollover

reform and transmission planning are closely related, because according to our

longstanding policy, transmission service eligible for a rollover right must be set aside for

rollover customers and included in transmission planning. We believe that it is necessary

that reforms in both areas proceed together, and therefore, we reject the suggestion of

some commenters that rollover reform proceed independent of transmission planning

reform. We understand that our approach may result in differences in transmission

770

E.g., APPA, FirstEnergy, Northwest IOUs, PGP, and Public Power Council.

Docket Nos. RM05-17-000 and RM05-25-000 - 751 -

providers’ OATTs, with some having a different effective date for rollover reforms.

However, because the effectiveness of rollover reform will be tied to acceptance of a

transmission provider’s coordinated and regional transmission planning process, rollover

reforms in any given region generally should be effective within the same time period.

1266. We reject the arguments by some commenters that rollover reform be made

effective upon the “successful” implementation, as opposed to acceptance by the

Commission, of a transmission provider’s coordinated and regional planning process.

We believe that utilizing a subjective deadline, such as the successful implementation of

the planning process, could result in significant confusion in the industry as to when

rollover reforms should be effective. Furthermore, an existing filed and accepted

transmission planning process, such as those that may be on file for RTOs and ISOs, does

not trigger the effectiveness of rollover reform for transmission providers using the

process. Such RTOs and ISOs and their transmission-owning members must, as

discussed elsewhere in this Final Rule, comply with the planning reforms required by the

Final Rule through the compliance filing procedures identified in section IV.C. It is

Commission acceptance of these compliance filings that will trigger effectiveness of

rollover reform for these transmission providers, assuming rollover reform is applicable

to their tariff services in the first instance.

1267. In response to commenters’ concerns that, depending on the effective date of

rollover reform, certain customers may not have a year or more left on their contracts

such that they can comply with the one-year notice provision, we emphasize that existing

Docket Nos. RM05-17-000 and RM05-25-000 - 752 -

contracts with a rollover right at the time of effectiveness of rollover reform may exercise

their next rollover based on the existing notice rules. It is only a rollover contract entered

into or renewed after the effectiveness of rollover reform that must comply with the new

rollover provisions, including the one-year notice requirement.

4. Modification of Receipt or Delivery Points

1268. Section 22 of the pro forma

OATT provides that a transmission customer taking

firm point-to-point service may modify its receipt and delivery points, i.e.

, redirect its

service, on either a non-firm or a firm basis. Section 22.1 (Modifications on a Non-Firm

Basis) provides that, subject to certain conditions, a firm point-to-point customer may

request transmission service on a non-firm basis over receipt and delivery points other

than those specified in its service agreement (known as secondary receipt and delivery

points) in amounts not to exceed its firm capacity reservation, without incurring an

additional non-firm point-to-point service charge or executing a new service agreement.

Section 22.2 (Modifications on a Firm Basis) provides that any request to modify receipt

and delivery points on a firm basis shall be treated as a new request for service in

accordance with section 17 of the pro forma

OATT (Procedures for Arranging Firm

Point-to-Point Transmission Service), except that the transmission customer shall not be

obligated to pay any additional deposit if the capacity reservation does not exceed the

amount reserved in the existing service agreement. While such new request is pending,

the transmission customer retains its priority for service at the existing firm receipt and

delivery points specified in its service agreement.

Docket Nos. RM05-17-000 and RM05-25-000 - 753 -

1269. In Order No. 676, the Commission adopted the “Standards for Business Practices

and Communication Protocols for Public Utilities” developed by the NAESB’s

Wholesale Electric Quadrant (WEQ).

771

Order No. 676 incorporated the aforementioned

standards by reference into the Commission’s regulations, required public utilities to

implement the standards by July 1, 2006, and required public utilities to file revisions to

their OATTs to include these standards.

772

The WEQ Standards include a number of

standards addressing requirements for dealing with redirects on both a firm and non-firm

basis.

773

All of the WEQ Standards dealing with redirects were adopted by the

Commission in Order No. 676, except for WEQ Standard 001-9.7, which addresses the

impact of a firm redirect on a long-term firm transmission customer’s rollover rights

under section 2.2 of the pro forma

OATT. The Commission directed the WEQ to

reconsider WEQ Standard 001-9.7 and to adopt a revised standard consistent with the

771

The WEQ was established by NAESB in response to a Commission order

requesting the wholesale electric power industry to develop business practice standards

and communication protocols by establishing a single consensus, industry-wide standards

organization for the wholesale electric industry. See

Order No. 676 at P 3-4.

772

The standards will hereinafter be referred to as the WEQ Standards. The

Commission adds a reference to the WEQ Standards in section 4 of the pro forma

OATT,

which identifies the Commission’s regulations containing the terms and conditions

relevant to the OASIS and standards of conduct.

773

The requirements for dealing with redirects on a firm basis are found at WEQ

Standard 001-9, et seq.

, and the requirements for dealing with redirects on a non-firm

basis are found at 001-10, et seq.

Docket Nos. RM05-17-000 and RM05-25-000 - 754 -

Commission’s policies.

774

The Commission also offered guidance to assist the WEQ in

developing a standard that is consistent with Commission policy.

775

NOPR Proposal

1270. In response to the NOI, commenters raised various concerns regarding redirects.

Among other things, customers complained of difficulties obtaining redirected service,

while transmission providers complained of a lack of clarity in the rules governing

redirects. In the NOPR, the Commission stated its belief that a number of these concerns

appeared to have been resolved by the adoption of the WEQ Standards in Order No. 676,

which was issued after the NOI. The Commission sought comment on whether parties

believed the WEQ Standards in fact addressed those concerns adequately.

1271. The Commission also stated its expectation that a number of other concerns raised

in response to the NOI, while perhaps not yet addressed (or addressed fully) by a WEQ

Standard, are nevertheless the types of issues that are appropriate for the WEQ process.

The Commission therefore proposed that each commenter that continued to believe

additional reform is necessary with regard to redirects evaluate whether its concerns

would more appropriately be addressed by the WEQ as it considers its next version of its

774

Order No. 676 at P 52.

775

Id. at P 53-61.

Docket Nos. RM05-17-000 and RM05-25-000 - 755 -

standards.

776

The Commission noted that WEQ was in the process of reevaluating WEQ

Standard 001-9.7, dealing with redirects and rollovers, so that it is consistent with the

Commission’s guidance given in Order No. 676. The Commission requested comment

on whether the WEQ process, along with the guidance provided by the Commission in

Order No. 676, is sufficient to address the concerns of commenters that seek clarification

on the interplay between redirects and rollovers.

1272. In the NOPR, the Commission acknowledged that there were additional, more

fundamental concerns with regard to section 22 raised in response to the NOI. Customers

generally argued that their ability to redirect to new points is stymied by a lack of ATC at

the new points or the need for major upgrades, or that transmission providers take too

long to process the redirect request. Transmission providers, on the other hand,

complained of the administrative burdens and complexity (particularly with regard to

reliability) of processing transmission customers’ short-term changes in service and that

there is often not enough time for the market to respond to capacity made available on a

customer’s original path. The Commission stated its belief that other proposed reforms in

the areas of process, transmission planning, and ATC calculation should address

transmission customer concerns regarding redirects. The Commission encouraged

776

The Commission noted in this regard that the WEQ’s procedures ensure that all

industry members can have input into the development of a business practice standard,

whether or not they are members of NAESB, and each standard it adopts is supported by

a consensus of the five industry segments: transmission, generation, marketers/brokers,

distribution/load-serving entities, and end-users. See

Order No. 676 at P 5 & n.5.

Docket Nos. RM05-17-000 and RM05-25-000 - 756 -

interested parties to submit a specific proposal, along with proposed revised pro forma

OATT language, to the extent they believe the proposed reforms will not adequately

address their concerns.

1273. The Commission also noted in the NOPR that several transmission providers had

posted business practices that allow network customers either to substitute an off-system

non-designated resource for a designated resource or to redirect the point of receipt

associated with an existing network resource. The Commission proposed that network

customers not be permitted to redirect network transmission service because network

service involves no identified contract path and therefore should not be treated as a

directable service.

a. Proposed Reliance on WEQ Process and Other OATT

Reforms

Comments

1274. Commenters generally agree with the Commission that issues with respect to

redirects of firm and non-firm transmission service are best addressed through the WEQ

as established by NAESB, in accordance with Order No. 676 and the WEQ process for

creating new standards.

777

Seattle argues that the NAESB standard setting process has

worked well thus far and, as a result, other redirect issues should be first referred to

NAESB as a standard-setting request. MISO states that it has serious concerns with the

777

E.g., EEI, Imperial, NorthWestern, Southern, and Suez Energy NA.

Docket Nos. RM05-17-000 and RM05-25-000 - 757 -

WEQ process and the Commission’s unwarranted deference to NAESB to develop what

will become binding business standards and practices.

1275. Nevada Companies recommend the following improvements for the NAESB

process: use of a professional facilitator to keep discussions focused and moving; and

mandatory surveys breaking down the sections on proposed NAESB standards after the

first round of comments are received to determine if consensus exists on the proposed

standards, since it appears that there are relatively few participants at NAESB meetings

where standards are being drafted and relatively few commenters on those draft

standards.

1276. Several commenters state that they agree with the Commission’s proposal to rely

on other proposed reforms in the NOPR to resolve the remaining redirect issues.

778

Seattle generally agrees that the reforms proposed in the NOPR should improve the

ability to assign and use transmission on a firm basis. EEI and NorthWestern state that

the NOPR proposal to increase transparency in the calculation of ATC should assist

transmission customers in both selecting transmission paths that may be available for

redirect and understanding why certain paths cannot accommodate redirect transactions.

Commission Determination

1277. The Commission concludes that the proposed method for addressing remaining

concerns with redirects – i.e.

, relying on other reforms adopted in this Final Rule and in

778

E.g., EEI, NorthWestern, and Seattle.

Docket Nos. RM05-17-000 and RM05-25-000 - 758 -

the Order No. 676 proceeding – is adequate to ensure that transmission providers do not

engage in undue discrimination when a customer seeks to modify its receipt and delivery

points on a firm basis. As explained throughout this Final Rule, the reforms adopted

herein address the remaining opportunities for undue discrimination. Planning and ATC

reforms will give transmission customers more accurate and complete ATC information

when evaluating their redirect options. Increased transparency will give transmission

customers the information they need to evaluate a transmission provider’s denial of a

request to redirect. Modifications to the process for requesting and securing firm point-

to-point service will improve the ability to redirect transmission service to new points

pursuant to section 22 and ensure complete and timely responses from transmission

providers. The Commission therefore concludes that no further reforms specific to

redirects are necessary at this time.

1278. The Commission also concludes that the NAESB WEQ is the appropriate

standard-setting body for developing business practices and implementing the

Commission’s redirect policy. The Commission will refrain from commenting here on

the NAESB process itself because we believe that the industry is best situated to

determine how to structure the standard-setting process to provide for the widest possible

participation and consensus. We nevertheless clarify that, consistent with precedent,

Docket Nos. RM05-17-000 and RM05-25-000 - 759 -

NAESB is charged with implementing Commission policy through business practices.

779

The Commission finds that the NAESB WEQ is an acceptable standards development

process, representing a cooperative effort by industry participants to develop business

practices that enhance the efficiency of the electric grid.

780

Where necessary, NAESB

participants may seek clarification of Commission policy so that NAESB may develop

the appropriate standards.

b. Redirects and Rollovers Rights

Comments

1279. Regarding the interaction between redirects and rollovers, some commenters

request that the Commission clarify what they view as an inconsistency between Order

No. 676, the Commission’s existing pro forma

OATT, and the rollover proposal in the

NOPR. Specifically, Bonneville, MISO, and Southern argue that, contrary to the pro

forma OATT and NOPR, Order No. 676 improperly suggested in an example that a short-

term redirect of a long-term service agreement gives the customer rollover rights for the

new path. TranServ supports placing the following two conditions on the receipt of

rollover rights for redirects: a redirect on a firm basis must be for one year or longer, and

779

See Standards for Business Practices of Interstate Natural Gas Pipelines, Order

No. 587-N, FERC Stats. & Regs. ¶ 31,125 at P 23 (2002).

780

See Order No. 676 at P 12.

Docket Nos. RM05-17-000 and RM05-25-000 - 760 -

the redirect must be for the entire remaining term of the parent (original) request.

781

these conditions are met, TranServ contends that the customer will be granted rollover

rights on the redirect path and lose the rollover rights held on the original path. If the

customer wishes to retain rollover rights on the original path, TranServ continues, it will

have the option to submit multiple redirect requests of less than one year in duration for

the term desired. With respect to WEQ Standard 001.9.7, MISO incorporates by

reference its opposition to the Commission’s adoption of the proposed transfer of rollover

rights on the redirected path in its request for rehearing of Order No. 676. There MISO

argued that there should be no rollover rights on a redirect path and that the guidance in

Order No. 676 requiring the transmission provider “to offer rollover rights to a customer

requesting a firm redirect if rollover rights are available on the redirect path” was

inconsistent with the pro forma

OATT.

Commission Determination

1280. Commission policy allows a redirect of firm, long-term service to retain rollover

rights, even if the redirect is requested for a shorter period. In other words, the rollover

right follows the redirect, regardless of the duration of the redirect. Contrary to the

comments of Bonneville, MISO, and Southern, the Commission did not impose this

requirement for the first time in Order No. 676, but merely provided guidance to the

781

TranServ explains that these are two primary features in a revised WEQ 001-

9.7 standard that was open for public comment.

Docket Nos. RM05-17-000 and RM05-25-000 - 761 -

industry by restating Commission policy on this matter. The Commission has explained

in prior orders that a transmission customer making a firm redirect request does not

convert its original long-term firm transmission service to short-term service, nor does it

lose its rollover rights under its long-term firm transmission service agreement. The

Commission’s concern underlying this policy is that long-term customers should not need

to choose between redirecting on a firm basis and maintaining rollover rights, rather their

rollover rights should be retained consistent with the long-term nature of their service.

1281. In Commonwealth Edison Co.

, the Commission explained that a “request to

change a delivery point on a firm basis for one month and then to revert to its original

delivery point does not convert its existing long-term firm transmission service

agreement into two separate short-term transmission service agreements.”

782

The

Commission stated that section 22.2 was intended to provide flexibility to transmission

customers to permit them to react in a competitive market and that some amount of this

flexibility would be lost if a long-term firm transmission customer seeking to modify its

delivery points would lose its rollover rights.

783

782

95 FERC ¶ 61,027 at 61,083 (2001).

783

The Commission, however, recognized that this flexibility was not unlimited –

any change to a delivery point is treated as a new request for service for purposes of the

availability of capacity.

Docket Nos. RM05-17-000 and RM05-25-000 - 762 -

1282. The Commission affirmed this policy in American Electric Power Service Corp.

784

In that case, a long-term transmission customer (Exelon) had been granted a short-term

redirect, but denied rollover rights on the redirected path. The Commission found the

denial of rollover rights was improper, since the “redirect request made by Exelon did not

convert Exelon’s long-term firm transmission service to short-term service, and,

therefore, did not affect Exelon’s rollover rights under its long-term firm transmission

service agreement.”

785

Thus, there is no inconsistency between the Commission’s

redirect policy and Order No. 676.

c. Redirects as New Requests for Service

Comments

1283. With respect to the provision in section 22.2 of the pro forma

OATT specifying

that requests to redirect on a firm basis be considered new requests for service, LPPC and

NPPD ask that this provision be modified to ensure that a customer redirecting its service

will retain a higher priority for service in the transmission provider’s queue than new

customers. LPPC argues that it is inequitable to require customers to compete for

capacity as though their loads were incremental to the system when they are simply

changing their receipt points as a matter of necessity (since suppliers may commence

serving other loads or cease doing business). EEI argues on reply that, if LPPC’s

784

97 FERC ¶ 61,207 at 61,905-06 (2001).

785

Id.

Docket Nos. RM05-17-000 and RM05-25-000 - 763 -

proposal would give customers priority at new points of receipt and delivery regardless of

whether the redirected service creates system impacts different from the old service, the

proposal would replace “first-come, first-served” priority with a system in which

customers would never know for sure whether their own requests for service would be

displaced by subsequent requests for redirected service. EEI cautions that the

transmission system simply cannot be planned and constructed with enough spare

capacity to allow any customer to redirect service to any point that it chooses at any time.

1284. Bonneville similarly argues that a redirect request should meet the same term and

notice requirements as a new request given that the transmission provider’s planning

horizon and the amount of time needed to remarket unused capacity is no different for a

redirect and a new transmission service request. APPA argues on reply that it is unclear

how Bonneville’s request would affect load-serving transmission customers that cannot

obtain power supply agreements of a term sufficient to dovetail with the term

requirements for a new request. Imperial recommends that redirects be evaluated using

ATC at the time of the redirect request, like any other new request for service, but that

the transmission provider be given additional time to determine whether native load

growth will prevent rollover rights for the redirects.

Commission Determination

1285. Section 22.2 of the pro forma

OATT provides that redirects “shall be treated as a

new request for service in accordance with section 17,” except that the transmission

customer may not be required to pay an additional deposit in certain circumstances.

Docket Nos. RM05-17-000 and RM05-25-000 - 764 -

Therefore, a redirect right does not grant the customer access to system capacity or queue

position different from other customers submitting new requests for service. A redirect

request must be evaluated in accordance with section 17 using the same system

assumptions and analysis applicable to any other new request for service, including

whether sufficient ATC exists to accommodate the request. The Commission concludes

it would be inappropriate, and contrary to the pro forma

OATT, to grant redirects special

queue treatment.

1286. Regarding Imperial’s request that transmission providers be given additional time

to determine whether native load growth will prevent rollover rights for the redirects, we

find that redirects should be studied like any other new request for firm point-to-point

service. Transmission providers must examine whether any request, a firm redirect

request or a new service request, would be affected by future native load growth resulting

in possible rollover rights restrictions, so we see no need to provide additional time for

transmission provider analysis of firm redirect request.

d. Pricing for Redirects

Comments

1287. TranServ requests that the Commission resolve a disagreement among WEQ

participants regarding the pricing of redirects as requests for new service. TranServ asks

whether the failure to charge an incremental uplift between the original and redirected

rate (e.g.

, respectively, the monthly rate and daily on-peak rate) would constitute the

offering of a discount for daily service that in turn must be posted for all other paths to

Docket Nos. RM05-17-000 and RM05-25-000 - 765 -

the same point of delivery. TranServ argues that it is reasonable to charge an incremental

uplift such that the rate paid by the redirect customer would be on par with that paid by

any other transmission customer reserving (daily) short-term firm service of like duration

(i.e.

, a “new request for service”), and the customer would pay the difference between the

daily on-peak rate and 1/30th of the monthly rate.

1288. Southern argues that, with respect to the price for redirects, if redirected hourly

firm service is more valuable than firm service, economic theory would dictate that

customers should be required to pay for that added value.

Commission Determination

1289. The Commission has not established a single, industry-wide pricing policy for

redirects and did not propose a pricing policy in the NOPR. As a result, a uniform

pricing method for redirects is beyond the scope of this proceeding. Nevertheless, we

note that the Commission explained in a recent order that its policy does not allow

transmission providers to collect additional charges when a firm point-to-point customer

redirects on a non-firm basis.

786

The Commission concluded that it would not subject

non-firm redirects to the Appalachian

Method of pricing,

787

which is premised on the

assumption that a customer using the transmission system for the 16 peak hours of the

786

Midwest Independent Transmission System Operator, Inc., 118 FERC ¶ 61,095

at P 79-85(2007).

787

See Appalachian Power Co., 39 FERC ¶ 61,296 (1987).

Docket Nos. RM05-17-000 and RM05-25-000 - 766 -

day should pay the same contribution to fixed costs as a customer who has reserved

capacity on a daily basis. This is because the redirecting customer already would have

paid for firm service over all on-peak and off-peak hours during the reservation period of

its service, therefore, there is no need to ensure that the customer pays a premium for the

opportunity to cherry pick the best hours each day. Furthermore, because the

Commission is not requiring the provision of hourly firm service, Southern’s argument

regarding redirected hourly firm service is now moot.

e. Other Issues

Comments

1290. EEI agrees with the Commission’s proposal to clarify that network customers may

not redirect network transmission service. Alberta Intervenors contend that undue

discrimination remains because the flexibility to modify points of receipt and delivery

that the network customer enjoys through “parking” and “hubbing” is not likewise

granted to a point-to-point customer. Alberta Intervenors recommends that the pro forma

OATT either make a common service available to all participants (not just network

customers) or prohibit network customers from using point-to-point services for parking

and hubbing.

1291. Imperial asks the Commission to clarify that a transmission customer should not

be able to make multiple redirects. Imperial explains that this clarification would address

two concerns: multiple short-term changes raise reliability concerns and often there is

insufficient time for the released capacity to be used by another customer; and the burden

Docket Nos. RM05-17-000 and RM05-25-000 - 767 -

on properly scheduling for reliability increases exponentially when there are redirects of

redirects.

1292. MISO/PJM States argue that because RTOs are not likely to engage in

discrimination with respect to redirects, the Commission should not modify RTO redirect

policies in the instant rulemaking proceeding.

Commission Determination

1293. The Commission adopts the NOPR proposal and finds that network customers

may not redirect network service in a manner comparable to the way customers redirect

point-to-point service. Unlike point-to-point service, network service involves no

identified contract path and thus is not a directable service. A network customer seeking

to substitute one resource for another already has the ability under the pro forma

OATT

to terminate its existing designation and designate a new resource on an as-available

basis. If necessary, the network customer may then request to redesignate its original

network resource by making a request to designate a new network resource.

Alternatively, the network customer could use secondary network service if it wants to

substitute a non-designated network resource for a designated network resource on an as-

available basis.

1294. For similar reasons, the Commission denies Alberta Intervenors’ request. The

Commission has explained that customers must choose between point-to-point and

Docket Nos. RM05-17-000 and RM05-25-000 - 768 -

network services, each of which has its own advantages and risks.

788

The Commission

declined to implement a single form of transmission service in Order No. 888, concluding

that point-to-point and network services are the appropriate base-line services under the

pro forma

OATT, and Alberta Intervenors offer no justification for departing from that

approach now. Alberta Intervenors parking and hubbing related arguments alleging that

network service is commonly used to purchase power intended for sales to third parties is

addressed in section V.D.7 of this Final Rule. Although we deny Alberta Intervenors’

request, we expect that the reforms adopted in this Final Rule will provide point-to-point

customers with increased service options and flexibility.

1295. Implementing Imperial’s proposal would prevent customers from redirecting for a

short period or periods of time and then redirecting back to their original points, making

redirects a less valuable option for customers. Multiple redirects are allowed only if the

customer can meet the scheduling and other requirements for new requests for service

under the pro forma

OATT. As long as the customer meets these requirements, the

Commission believes that the ability to redirect service does not present an unreasonable

burden to transmission providers. As for applicability to RTOs and ISOs, we explain our

compliance requirements in section IV.C of this Final Rule. To the extent an RTO’s or

ISO’s redirect policy does not conform to the pro forma

OATT, as amended by this Final

Rule, the RTO or ISO must demonstrate that its policy is consistent with or superior to

788

Order No. 888-A at 30,260.

Docket Nos. RM05-17-000 and RM05-25-000 - 769 -

the pro forma

provisions in accordance with the compliance procedures set forth in that

section.

5. Acquisition of Transmission Service

a. Processing of Service Requests

1296. The pro forma

OATT includes requirements that transmission providers process

requests for transmission service in a timely fashion. Section 17.5 (Response to a

Completed Application) and section 18.4 (Determination of Available Transmission

Capability) of the pro forma

OATT provide that following the receipt of a completed

application for service, the transmission provider must respond to transmission customer

requests for determinations of the availability of firm and non-firm transmission capacity

on a timely basis. The transmission provider must make the determination as soon as

reasonably practicable after receipt but no later than certain specified time periods (or

such time periods generally accepted in the region).

1297. Section 19 (Additional Study Procedures for Firm Point-to-Point Transmission

Service Requests) of the pro forma

OATT provides deadlines that transmission providers

must adhere to in issuing system impact study agreements and facilities studies

agreements and that transmission customers must abide by in responding to these study

agreements. Section 19 requires transmission providers to use due diligence to complete

system impact studies and facilities studies within 60 days. Section 32 of the pro forma

OATT (Additional Study Procedures for Network Integration Transmission Service

Docket Nos. RM05-17-000 and RM05-25-000 - 770 -

Requests) contains similar due diligence deadlines for completing system impact studies

and facilities studies associated with requests for network service.

(1) Posting Performance Metrics

NOPR Proposal

1298. In the NOPR, the Commission proposed to require transmission providers to post

on their OASIS sites metrics that track their performance in processing system impact

studies and facilities studies associated with requests for transmission service. The

Commission proposed that transmission providers calculate the proposed performance

metrics separately for affiliates and non-affiliates and for requests for short-term and

long-term transmission service.

1299. In addition, the Commission proposed to require a notification filing and the

posting of additional metrics if a transmission provider completes more than 20 percent

of non-affiliates’ studies outside of the 60-day due diligence deadline in the pro forma

OATT for two consecutive quarters. Starting the quarter after a notification filing, the

transmission provider would be required to post the following information on OASIS:

(1) the average, across completed system impact studies, of the employee-hours

expended per completed system impact study, (2) the average, across completed facilities

studies, of employee-hours expended per completed facilities study, (3) the number of

employees devoted to processing system impact studies, and (4) the number of

employees devoted to processing facilities studies. The Commission proposed that

transmission providers post these additional performance metrics until they process at

Docket Nos. RM05-17-000 and RM05-25-000 - 771 -

least 90 percent of all system impact and facilities studies within 60 days after the study

agreement has been executed. The additional performance metrics also would be

calculated separately for affiliates’ and non-affiliates’ requests for transmission service

and for short-term and long-term transmission service.

Comments

Standard Performance Metrics

1300. Transmission customers and a number of other commenters generally support or

do not oppose the Commission’s proposal to require transmission providers to post

performance metrics.

789

1301. Southern and Salt River oppose the proposal, arguing that most of the data needed

to compute the metrics is already available on OASIS. Southern asserts that the NOPR

does not explain why the currently available information is inadequate or how the

proposed metrics would not be duplicative and, thus, does not fully justify the need for

reform. Southern also argues that the Commission’s proposal will impose costs and

burdens on transmission providers, and ultimately those who use their services, that do

not correspond with the limited benefits that might be gained. Salt River believes that

performance tracking requirements should be established on a case-by-case basis in

response to complaints. NorthWestern believes the 60 days should be a target, but not a

789

E.g., ELCON, Suez Energy NA, Powerex, Seattle, TAPS, Constellation,

Entegra, NRECA, TDU Systems, Regional Electricity Committee, MISO, MidAmerican,

FirstEnergy, Tacoma, EEI, Nevada Companies, and TranServ.

Docket Nos. RM05-17-000 and RM05-25-000 - 772 -

deadline, and, as such, transmission providers should not be required to report

performance metrics that summarize the time they take to perform the studies.

1302. Several commenters requested clarification on certain features of the

Commission’s proposal. Nevada Companies asks the Commission to be very specific as

to what statistical data items are to be reported on the OASIS so that transmission

providers do not inadvertently violate the confidentiality of their transmission customers.

PNM-TNMP requests clarification that the standards set out in the NOPR are solely

applicable to processing of transmission delivery service requests, and not to

interconnection service requests. Insofar as the Commission determines that performance

metrics should be posted, Southern asks the Commission to clarify that the proposed

posting of performance metrics also would be required of RTOs and ISOs.

1303. A number of commenters suggest that the Commission modify the performance

metrics that transmission providers are required to post. EEI suggests that NAESB

develop the metrics that transmission providers are required to post, using the metrics

contained in the NOPR as guidance. EEI and MidAmerican suggest that the performance

metrics include information about the degree to which transmission customers delay the

study process. MISO suggests that transmission providers post metrics related to the time

transmission customers take to respond to the results of completed system impact studies

and facilities studies. Southern asserts that fewer metrics should be required and that

they should relate directly to the study-timing concerns raised in the NOPR. Bonneville

and MISO argue that transmission providers should not have to post information about

Docket Nos. RM05-17-000 and RM05-25-000 - 773 -

the cost of transmission system upgrades recommended in the request studies.

Bonneville believes that the average cost of recommended upgrades is misleading

because it will mask the wide variation in such costs. MISO suggests that transmission

providers also report the standard deviation for study completion times. Southern asserts

further that the OATT does not specifically provide for a system impact study or facilities

study to be performed on a short-term basis, so any metrics required as part of OATT

reform should not include short-term requests. CREPC suggests that performance

metrics be calculated separately for renewable resources.

1304. Several commenters suggest that transmission providers post additional

information to further enhance transparency. A number of commenters suggest that the

Commission require the posting of the disposition of all transmission service requests,

including those not requiring studies.

790

TDU Systems suggest that the Commission

require transmission providers to post the parameters of each denied request. MISO

suggests that transmission providers provide a narrative to explain any anomalous study

costs that may affect the posted average cost. If a transmission provider anticipates that it

will miss the study deadline date, NRECA suggests that it should post that information,

the expected finish date, and a reason for not being able to meet the deadline.

790

E.g., CREPC, MISO, Constellation, and TDU Systems.

Docket Nos. RM05-17-000 and RM05-25-000 - 774 -

1305. EEI recommends that the Commission delegate to NAESB the responsibility for

developing the Standard and Communications Protocols, business practices and OASIS

modifications that will be necessary to provide the metrics.

Additional Performance Metrics (after two quarters of late studies)

1306. EEI and Southern oppose the Commission’s proposal to require transmission

providers that fail to complete studies in a timely manner to post additional performance

metrics that measure the labor input used to complete studies. EEI asserts that there is

little value to be gained from posting the additional information that the Commission

proposes. EEI believes the information concerning the number of employees who

perform studies will not be determinative of responsibility for the delay because the

significant issue is whether the number of studies that the transmission provider is

required to perform or the total amount of time needed to perform studies has increased

significantly or whether customers caused the delays. Southern questions the

Commission’s legal authority to require transmission providers that do not complete

studies in a timely manner to post additional performance metrics, citing Cal. Ind. Sys.

Operator Corp. v. FERC.

791

Southern characterizes the Commission’s proposal as a

punishment for delays in processing request studies.

1307. Several other commenters suggest changes to the Commission’s proposal.

Southern believes the submission of a notification of extenuating circumstances should

791

372 F.3d 395, 404 (D.C. Cir. 2004).

Docket Nos. RM05-17-000 and RM05-25-000 - 775 -

suspend the obligation to post the additional metrics proposed in the NOPR. EEI and

Southern argue that the Commission should be certain that it is collecting such

information only from those transmission providers that, for no other reason except

themselves, fail to consistently evaluate studies within the 60-day due diligence period.

Therefore, if a transmission provider demonstrates that delays in completing studies are

due to extenuating circumstances, then EEI and Southern believe the Commission should

not require the transmission provider to post the additional metrics. MISO believes the

Commission should exempt RTOs from the additional employee performance metrics

proposed in the NOPR for the same reason that the Commission proposed to exempt

RTOs from operational penalties for untimely completion of studies, as MISO claims the

additional posting requirements are in the nature of penalty. Bonneville believes the

proposed metrics will be misleading whenever a transmission provider employs outside

consultants to perform or assist with studies. Therefore, Bonneville suggests that the

Commission add two other metrics, the number of studies performed entirely by

consultants and, in the case of studies performed by a combination of employees and

consultants, the average percentage of the study performed by consultants.

Commission Determination

Standard Performance Metrics

1308. The Commission will require transmission providers to post the performance

metrics proposed in the NOPR, as modified by this Final Rule. The proposed metrics

will enhance the transparency of the study process and shed light on whether

Docket Nos. RM05-17-000 and RM05-25-000 - 776 -

transmission providers are processing request studies in a non-discriminatory manner.

We also agree with comments by MidAmerican and EEI that transmission providers

should be able to track delays in the study process caused by transmission customers.

Doing so will allow the Commission and market participants to determine the extent to

which delays by transmission customers are causing transmission providers to process

request studies on an untimely basis, which will add needed transparency to the study

process. Therefore, we will revise the performance metrics transmission providers are

required to post to include metrics that track delays by transmission customers.

1309. Transmission providers will be required to post the performance metrics, outlined

below, for each calendar quarter. Transmission providers will be required to begin

tracking their performance upon the effective date of this Final Rule and keep the

quarterly performance metrics posted on their OASIS sites for three calendar years. The

transmission provider will be required to post the quarterly performance metrics within

15 days of the end of the quarter. The performance metrics outlined below must be

calculated separately for affiliates’ and non-affiliates’ requests, in order to identify

potential instances when the transmission provider is processing requests on a

discriminatory basis. The transmission provider is required to aggregate studies

associated with requests for short-term and long-term transmission service when

calculating the metrics defined below. While a transmission provider could offer to study

a request for short-term firm point-to-point transmission service, we acknowledge that the

transmission customer often is unwilling to pay for such a study. Therefore, to ease the

Docket Nos. RM05-17-000 and RM05-25-000 - 777 -

reporting burden, the transmission provider is not required to report the performance

metrics defined below separately for requests for short-term and long-term firm point-to-

point transmission service. A transmission provider is also required to post performance

metrics for studies that it conducts for RTOs.

1310. A transmission provider is required to post the following set of performance

metrics on a quarterly basis:

• Process time from initial service request to offer of system impact study

agreement pursuant to sections 17.5, 19.1 and 32.1 of the pro forma

OATT

o Number of new system impact study agreements delivered to

transmission customers

o Number of new system impact study agreements delivered to the

transmission customer more than 30 days after the transmission

customer submitted its request

o Average time (days) from request submittal to change in request status

o Average time (days) from request submittal to delivery of system

impact study agreement

o Number of new system impact study agreements executed

• System impact study processing time pursuant to sections 19.3 and 32.3 of the

pro forma

OATT

o Number of system impact studies completed

o Number of system impact studies completed more than 60 days after

receipt of executed system impact study agreement

o Average time (days) from receipt of executed system impact study

agreement to date when completed system impact study made available

to the transmission customer

o Average cost of system impact studies completed during the period

• Service requests withdrawn from system impact study queue

o Number of requests withdrawn from the system impact study queue

o Number of system impact studies withdrawn more than 60 days after

receipt of executed system impact study agreement

o Average time (days) from receipt of executed system impact study

agreement to date when request was withdrawn from the system impact

study queue

Docket Nos. RM05-17-000 and RM05-25-000 - 778 -

• For all system impact studies completed more than 60 days after receipt of

executed system impact study agreement, average number of days study was

delayed due to transmission customer’s actions (e.g.,

delays in providing

needed data)

• Process time from completed system impact study to offer of facilities study

pursuant to sections 19.4 and 32.4 of the pro forma

OATT

o Number of new facilities study agreements delivered to transmission

customers

o Number of new facilities study agreements delivered to transmission

customers more than 30 days after the completion of the system impact

study

o Average time (days) from completion of system impact study to

delivery of facilities study agreement

o Number of new facilities study agreements executed

• Facilities study processing time pursuant to sections 19.4 and 32.4

o Number of facilities studies completed

o Number of facilities studies completed more than 60 days after receipt

of executed facilities study agreement

o Average time (days) from receipt of executed facilities study agreement

to date when completed facilities study made available to the

transmission customer

o Average cost of facilities studies completed during the period

o Average cost of recommended upgrades for facilities studies completed

during the period

• Service requests withdrawn from facilities study queue

o Number of requests withdrawn from the facilities study queue

o Number of facilities studies withdrawn more than 60 days after receipt

of executed facilities study agreement

o Average time (days) from receipt of executed facilities study agreement

to date when request was withdrawn from the facilities study queue

• For all facilities studies completed more than 60 days after receipt of executed

facilities study agreement, average number of days study was delayed due to

transmission customer’s actions (e.g.

, delays in providing needed data)

1311. In response to Nevada Companies request that we clarify the statistical data items

that are to be reported on OASIS pursuant to the Commission’s proposal, we reiterate

Docket Nos. RM05-17-000 and RM05-25-000 - 779 -

that transmission providers are required to provide summary data as defined above. We

do not believe these data will violate the confidentiality of any transmission customer,

even in the event the transmission provider has worked on a limited number of studies.

We clarify that the performance metrics posting requirement discussed above is solely

applicable to processing of transmission delivery service requests, and not to

interconnection service requests. Finally, we clarify that RTOs and ISOs also are

required to post the performance metrics described above. As we discuss below, we

believe all transmission providers should be subject to the same reporting requirements.

1312. We disagree with Southern and Salt River which argue that the data already on

OASIS is sufficient to accomplish our goal to enhance transparency of the transmission

provider’s request study processing. First, the data available on the OASIS template

transstatusaudit

does not contain the information necessary to calculate all of the

performance metrics proposed in the NOPR.

792

For instance, transstatusaudit allows one

to determine when a request was moved from “received” to “study” and then to

“accepted” or “counteroffer”. Depending on when the transmission provider moves the

request into “study,” this information does not allow one to determine either whether the

792

The OASIS template transstatusaudit is defined in the Standards and

Communications Protocols section of NAESB’s WEQ Business Practice Standards. The

template transstatusaudit

is the audit component to OASIS template transstatus and, as

such, contains information regarding the type of transmission service requested, affiliate

status, date and time the transmission service was requested, and the date and time of all

changes in request status (e.g.

, place in study mode, confirmed or withdrawn).

Docket Nos. RM05-17-000 and RM05-25-000 - 780 -

transmission provider provided a system impact study agreement within 30 days or

whether the transmission provider completed the system impact study within 60 days. In

addition, the transmission provider is required to make the data in transstatusaudit

available on OASIS for only 90 days and available by request for three years.

793

As a

result, market participants would be required to calculate the performance metrics they

desire on a quarterly basis if they want to use just the data posted on OASIS. Finally,

downloading transstatusaudit

data for specific OASIS requests that required a system

impact study or feasibility study can be cumbersome due to the manual nature of the

download process. The transmission provider has the data necessary to calculate the

proposed performance metrics readily available. We believe it is more efficient for a

single transmission provider to calculate the performance metrics for its system rather

than have multiple interested parties calculate the performance statistics for each

transmission provider of interest.

1313. We also disagree with Southern’s assertion that the costs and burdens to

transmission providers are not justified by the benefits that might be gained. We are

concerned that, under the existing pro forma

OATT, transmission providers do not have

adequate incentives to conduct studies on a timely and nondiscriminatory basis. First,

transmission providers have incentives to discriminate against third parties and in favor

of their affiliates (i.e.

, to delay the study requests of nonaffiliates, but act more quickly on

793

18 CFR 37.7(b).

Docket Nos. RM05-17-000 and RM05-25-000 - 781 -

those of its affiliates). Second, transmission providers also can lack incentives to provide

sufficient staff resources to support increasing demands in the study process. Given that

most of the costs associated with the study process are operational, transmission

providers, at most, will recover those costs without profit (i.e.

, a return) and, if the

demands of the study process are increasing, fail to recover such cost increases if the

transmission provider is between rate cases. We therefore believe that there are several

reasons that greater transparency is required to provide the correct incentives to comply

with the pro forma

OATT provisions respecting studies.

1314. We also note that virtually all commenters agree with our proposal to require

transmission providers to calculate the above performance metrics. This support stems,

in part, from transmission customers’ perception that transmission providers do not exert

sufficient effort to complete requests in a timely manner.

794

Delays in processing study

requests can cause customers to incur material financial damage. Moreover, the data

needed to calculate the required performance statistics is readily available to the

transmission provider and, therefore, the cost to the transmission provider will be small

relative to the benefits of enhanced transparency and assurance that the transmission

provider is processing request studies in a timely and non-discriminatory fashion.

794

E.g., Constellation, EPSA NOI Comments, Arkansas Cities NOI Comments,

APPA NOI Reply Comments, and Powerex NOI Reply Comments

Docket Nos. RM05-17-000 and RM05-25-000 - 782 -

1315. Based on our experience and the comments received in response to the NOI and

NOPR, the Commission believes the steps we take here are necessary to increase

transparency for the processing of service requests by all transmission providers. It

would be inappropriate, as some commenters suggest, to wait for specific complaints

about specific transmission providers before requiring the transmission provider to

calculate the performance metrics defined above. We conclude that the reporting

requirements adopted in this Final Rule must be applied to all transmission providers in

order to enhance the transparency of the study process and ensure that transmission

provider processes study requests in a timely and non-discriminatory fashion for all

transmission customers. The fact that the 60-day time frame in the pro forma

OATT is a

target and not a deadline does not change the fact that requiring all transmission providers

to post the performance metrics defined above will enhance the transparency of the study

process.

1316. We will not adopt any of the changes to the proposed performance metrics

requested by commenters, other than adding metrics to track delays by customers as

discussed above. The Commission is in a better position to determine the specific

performance metrics that will achieve our policy goals and thus we will not request that

NAESB develop the metrics to be posted.

795

We believe the set of performance metrics

795

As noted in P 1318, we direct public utilities working through NAESB to

develop protocols for posting the performance metrics required here so they will be

posted in a consistent fashion.

Docket Nos. RM05-17-000 and RM05-25-000 - 783 -

we have chosen strike the appropriate balance between requiring information that will

enhance transparency and help ensure that the transmission provider is processing request

studies in a timely and non-discriminatory fashion while limiting the burden the

transmission provider faces. For instance, we believe the performance metrics that

address the cost of system impact studies and facilities studies as well as the cost of any

proposed transmission upgrades can be calculated with relatively little effort by the

transmission provider and should provide meaningful benefits to transmission customers.

The transmission provider readily knows the cost of studies it completes and the costs of

proposed system upgrades and summaries of this information should enhance the

transmission customer’s ability to decide whether to submit a request for service that may

result in a study offer.

1317. We do not believe the relative benefits and burdens justify requiring the

transmission provider to post performance metrics beyond those adopted in this Final

Rule. For instance, requiring the transmission provider to calculate additional summary

information or post long narratives to explain anomalous upgrade costs do not appear

necessary at this time to achieve our stated policy goals, particularly since transmission

customers can request data associated with completed system impact studies and facilities

studies pursuant to section 37.6(b)(2)(iii) of the Commission’s regulations.

796

addition, we do not believe transmission customers, beyond the transmission customer

796

18 CFR 37.6(b)(2)(iii).

Docket Nos. RM05-17-000 and RM05-25-000 - 784 -

directly affected, would benefit from the information NRECA suggests the transmission

provider should be required to post when it anticipates that it will not complete a study

within the 60-day due diligence time frame. Section 19.3 of the pro forma

tariff already

requires the transmission provider to notify the affected transmission customer when it

will not be able to complete a study within the 60-day due diligence time frame, provide

an expected completion date, and explain why additional time is needed. We do not

believe other transmission customers would benefit enough from this information to

justify requiring the transmission provider to post it. Similarly, we do not believe the

benefit to market participants justifies the burden of requiring transmission providers to

calculate performance metrics separately for renewable resources.

1318. We agree, however, with EEI’s recommendation that the Commission delegate to

NAESB the responsibility for developing the Standard and Communications Protocols,

business practices and OASIS modifications that will be necessary to provide the

performance metrics adopted above. NAESB is in the best position to develop the

standards and the processes by which the performance metrics are posted.

Additional Performance Metrics (after two quarters of late studies)

1319. The Commission also adopts the NOPR proposal to require transmission providers

to submit a notification filing with the Commission in the event the transmission provider

processes more than 20 percent of non-affiliates’ studies outside of the 60-day due

diligence deadlines in the pro forma

OATT for two consecutive quarters. This filing

must be filed within 30 days of the end of the second quarter during which the

Docket Nos. RM05-17-000 and RM05-25-000 - 785 -

transmission provider processes more than 20 percent of non-affiliates’ studies outside of

the 60-day due diligence deadlines in the pro forma

OATT. For the purposes of

calculating this notification trigger, the transmission provider is required to aggregate all

system impact studies and facilities studies that it completes during the quarter for non-

affiliates.

797

The transmission provider may explain in its notification filing that it

believes there are extenuating circumstances that prevented it from meeting the deadlines

in the pro forma

OATT.

1320. As the Commission proposed in the NOPR, starting the quarter following a

notification filing, the transmission provider will be required to post: (1) the average,

across completed system impact studies, of the employee-hours expended per completed

system impact study; (2) the average, across completed facilities studies, of employee-

hours expended per completed facilities study; (3) the number of employees devoted to

processing system impact studies; and (4) the number of employees devoted to

processing facilities studies. The transmission provider is not required to post these

additional performance metrics separately for affiliates’ and non-affiliates’ requests for

transmission service and for short-term and long-term transmission service. The

797

For instance, if the transmission provider completes 4 non-affiliates’ system

impact studies during the quarter with 2 completed more than 60 days after the system

impact study agreement was executed and completes 2 non-affiliates’ facilities studies

during the quarter with none completed more than 60 days after the facilities study

agreement was executed, then the transmission provider will be deemed to have

completed 2 out of 6 (33 percent) studies outside of the deadlines in the pro forma

OATT.

Docket Nos. RM05-17-000 and RM05-25-000 - 786 -

transmission provider is instead required to aggregate studies associated with requests for

short-term and long-term transmission service when calculating these additional metrics.

The transmission provider is not required to post the additional metrics if the

Commission concludes that delays in completing studies are due to extenuating

circumstances. However, the transmission provider is required to post the additional

metrics while the Commission considers the transmission provider’s notification filing

arguing that extenuating circumstances prevented it from processing request studies on a

timely basis. Based on the timing described in this Final Rule, the transmission provider

will be required to post the additional performance metrics approximately two months

after the provider makes its notification filing. The Commission will have this time to

evaluate the transmission provider’s contention that it was unable to complete request

studies due to extenuating circumstances. As a result, we expect the transmission

provider with legitimate extenuating circumstances typically will not have to post any

additional metrics.

1321. We disagree with those arguing that information concerning the number of

employees who perform studies will not be determinative of responsibility for the delay.

The transmission provider will have the right to establish that it is unable to perform

studies in a timely manner because of factors outside its control. We received a number

of comments to the NOPR and NOI that suggest that transmission customers believe

transmission providers fail to complete studies on a timely basis because they do not have

Docket Nos. RM05-17-000 and RM05-25-000 - 787 -

sufficient staff to perform the studies.

798

As explained above, this is one of the concerns

that has led us to adopt these reforms. The additional metrics will serve to shed light on

the transmission provider’s resource commitment, enhance the transparency of the study

process, and increase the transmission provider’s incentive to staff its study function

appropriately.

1322. The additional posting requirement is not a penalty or a punishment. We opted

not to require the transmission provider to post these additional performance metrics on a

regular basis out of a desire to limit the transmission provider’s reporting burden.

However, once the transmission provider has stopped completing studies on a timely

basis, we believe the enhanced transparency justifies the additional reporting burden. As

a result, ISOs and RTOs also will be required to post the additional performance metrics

described above. We disagree with Southern’s argument that we lack jurisdiction to

require additional posting. The posting requirements are directly related to pro forma

OATT obligations that are necessary to remedy undue discrimination and, hence,

necessarily derive from our broad discretion in fashioning remedies to undue

discrimination. We are not attempting to dictate a transmission provider’s internal

staffing decisions; rather, we illuminate the transmission provider’s compliance with its

798

E.g., Constellation, EPSA NOI Comments, Arkansas Cities NOI Comments,

APPA NOI Reply Comments, and Powerex NOI Reply Comments

Docket Nos. RM05-17-000 and RM05-25-000 - 788 -

pro forma

OATT obligations to perform studies within certain deadlines and on a

nondiscriminatory basis.

1323. We will not add the two other metrics suggested by Bonneville regarding the

number of studies performed entirely by consultants and, in the case of studies performed

by a combination of employees and consultants, the average percentage of the study

performed by consultants. Rather, transmission providers should include the time spent

by consultants on studies in the performance metrics defined above.

(2) Operational Penalties for Late Studies

NOPR Proposal

1324. The Commission proposed to impose operational penalties when transmission

providers routinely fail to meet the 60-day due diligence deadlines prescribed in sections

19.3, 19.4, 32.3 and 32.4 of the pro forma

OATT. Under the proposal, a transmission

provider who processes more than 20 percent of non-affiliates’ studies outside of the 60-

day due diligence deadlines in the pro forma

OATT for two consecutive quarters would

be required to notify the Commission. In this notification filing, the transmission

provider may explain that it believes there are extenuating circumstances that prevented it

from meeting the deadlines in the pro forma

OATT. The transmission provider would be

subject to an operational penalty if it continues to be out of compliance

799

with the

799

The transmission provider would be deemed to be out of compliance if it

completes 10 percent or more of non-affiliates’ system impact studies and facilities

studies outside of the deadlines prescribed in the pro forma

OATT.

Docket Nos. RM05-17-000 and RM05-25-000 - 789 -

deadlines prescribed in the pro forma

OATT for each of the two quarters following its

notification filing.

1325. The Commission proposed that the operational penalty be assessed on a quarterly

basis, starting with the quarter following the notification filing and continuing until the

transmission provider completes at least 90 percent of all studies within 60 days after the

study agreement has been executed. For any system impact study or facilities study

completed during that quarter and more than 60 days after the study agreement was

executed, the Commission proposed a penalty equal to $500 for each day the

transmission provider takes to complete the study beyond 60 days. For any system

impact study or facilities study that is still pending at the end of the quarter and that has

been in the study queue for more than 60 days, the Commission proposed a penalty equal

to $500 for each day the study has been in the study queue beyond 60 days.

1326. In addition to the proposed operational penalties, the Commission indicated that it

would order other remedial actions, consistent with the Policy Statement on Enforcement,

to be determined on a case-by-case basis. The Commission proposed that RTOs not be

subject to this penalty regime because of the RTOs’ independence.

Docket Nos. RM05-17-000 and RM05-25-000 - 790 -

Comments

1327. Transmission providers generally oppose the Commission’s proposal.

800

Some

opponents argue that, to the extent the Commission is going to impose penalties, it should

do so on a case-by-case basis.

801

Opponents cite a number of reasons the Commission

should not impose the proposed operational penalty regime. Several opponents caution

that imposing a penalty may lead transmission providers to either prematurely deny a

request or accept a request to the detriment of system reliability.

802

Several opponents

argue that many transmission requests introduce unique complexities into the study

process, so a firm 60-day deadline is not workable in practice.

803

Several opponents

argue that the Commission’s proposed penalty regime is inconsistent with the new

requirements the Commission has proposed for regional planning and requirements to

consider redispatch in the system impact study.

804

In its reply comments, EEI argues that

due process requires that the Commission not impose penalties on transmission providers

for study delays because, in EEI’s view, it is highly likely that the delays will have been

800

E.g., EEI, MidAmerican, Entergy, Southern, Imperial, NorthWestern, PNM-

TNMP, Salt River, and Bonneville Reply.

801

E.g., EEI, Southern, and PNM-TNMP Reply.

802

E.g., MidAmerican, Southern, Imperial, and EEI Reply.

803

E.g., MidAmerican, Southern, NorthWestern, Northwest IOUs, and PNM-

TNMP Reply.

804

E.g., MidAmerican, Southern, and EEI Reply.

Docket Nos. RM05-17-000 and RM05-25-000 - 791 -

caused by factors or events that were beyond the transmission provider’s control.

Southern asserts that any scheme of operational penalties associated with the processing

of studies cannot be implemented fairly unless and until the problem surrounding the

submission of multiple requests is addressed. Southern argues that the Commission

would violate a transmission provider’s due process rights if it were to impose penalties

for delays caused by transmission customers. CREPC proposes that transmission projects

that cross seams not be subject to penalties, arguing that such an exception will create a

level playing field for those transmission providers in the West working with the CAISO

and foreign transmission owners to resolve transmission service requests.

1328. A number of commenters ask the Commission to clarify specific elements of the

proposed operational penalty regime. Several commenters argue that the proposal does

not clearly provide for an exemption from operational penalties if the failure to meet the

timeliness criteria is a result of extenuating circumstances or customer caused delays,

thereby denying transmission providers due process.

805

Several commenters ask the

Commission to clarify that a transmission provider is not subject to operational penalties

if the transmission provider’s failure to meet the compliance threshold following its

notification filing is due to extenuating circumstances.

806

Southern asks that the

Commission clarify that the submission of a notification of extenuating circumstances

805

E.g., EEI, Southern, Northwest IOUs, and MidAmerican.

806

E.g., EEI and MidAmerican.

Docket Nos. RM05-17-000 and RM05-25-000 - 792 -

would suspend the obligation of a transmission provider to process at least 90 percent of

the study requests within the proposed deadlines, until such time as the Commission

issues a final determination on the notification of extenuating circumstances. Tacoma

asks the Commission to ensure that the processing time is measured from the point that

the customer provides complete information.

1329. EEI recommends that the Commission hold a technical conference to determine

the extent to which studies are not being completed within 60 days, the principal causes

of delays in completing studies within 60 days and whether the increased planning and

coordination requirements proposed by the Commission will result in additional time

being needed to complete the studies. EEI believes the Commission is far more likely to

arrive at a reasonable conclusion concerning these issues after a technical conference than

if it simply imposes penalties for failures to complete all studies within 60 days. Seattle

believes the proposed penalties should not be implemented until providers and customers

have had at least one year of experience working with the performance metrics.

1330. Transmission customers generally support the Commission’s proposal to impose

operational penalties when a transmission provider routinely fails to meet the 60-day due

diligence deadlines.

807

In its reply comments, Entegra argues that the question is not

whether a transmission provider has sufficient margins of flexibility, but whether the

807

E.g., Suez Energy NA, TAPS, Constellation, Entegra, TDU Systems, CREPC,

and Nevada Companies.

Docket Nos. RM05-17-000 and RM05-25-000 - 793 -

transmission provider has any stake in meeting the deadlines. Occidental argues that

transmission providers may have little incentive to meaningfully address customers’

issues without the prospect of a prospective remedy. Responding to EEI’s due process

argument, TDU Systems in reply assert that imposition of penalties in this instance raises

no more due process concerns than those operational penalties that transmission

customers are routinely subjected to under the OATT. TDU Systems argue that, should

the Commission determine that transmission providers are entitled to challenge any

operational penalty for failure to process service requests in a timely manner, then those

challenges must be on terms and conditions that are comparable to those available to

transmission customers – a complaint pursuant to FPA section 206. TDU Systems

believe that the proposed “explanatory statement” contemporaneous with any notification

filing is a form of expedited review that is clearly not comparable to the treatment of

customers under the tariff.

1331. Several transmission customers question whether the proposed penalty level is

sufficient to ensure compliance.

808

Constellation recommends a penalty of up to $10,000

per day per violation. Entegra suggests the Commission set the penalty equal to the

higher of the lost opportunity cost to the customer resulting from the delay, if any, or

$1,000 for each day. Entegra also suggests that penalties should be assessed

automatically, without a notification filing to the Commission. In its reply comments,

808

E.g., TAPS, Constellation, and Entegra.

Docket Nos. RM05-17-000 and RM05-25-000 - 794 -

EEI argues that the total penalty for delayed studies will be far higher than $500 per day

if the transmission provider is processing more than five requests per 60-day period,

which EEI asserts is extremely likely.

1332. Constellation asks the Commission to consider whether to require the transmission

provider to engage an independent transmission administrator to the extent a transmission

provider’s posted performance metrics are not accurate or the transmission provider

persistently fails to adhere to the relevant timelines.

1333. Several commenters suggest that the Commission extend the study completion

deadlines, such as to 120 or 180 days, at least for the purposes of assessing penalties.

809

Bonneville suggests that the Commission change the service request study process to

match the interconnection study process as articulated in the Large Generator

Interconnection Procedures. Imperial recommends that instead of mandating a

nationwide study schedule, each of the NERC regions should establish a schedule taking

into account the various needs of the region. Southern suggests restarting the 60-day due

diligence period for any study that experiences a delay that cannot properly be attributed

to the transmission provider. In contrast to the suggestions to increase the study time,

Entegra suggests that the Commission consider changing the due diligence deadlines to

30 days to further the goal of encouraging timeliness in completing required studies.

809

E.g., Bonneville, MidAmerican, Progress Energy, NorthWestern, Northwest

IOUs, and EEI Reply.

Docket Nos. RM05-17-000 and RM05-25-000 - 795 -

1334. Several commenters suggest methods for distributing the operational penalties the

transmission provider pays for late studies. TAPS believes that penalty revenues should

go to victims of study delay. Similarly, Entegra believes the penalty should take the form

of a credit against the transmission customer’s obligation to reimburse the transmission

provider for study costs, with any amount in excess of the study costs payable to the

transmission customer, in recognition of the harm to transmission customers when

required studies are not completed expeditiously. CREPC asks the Commission to clarify

how it plans to determine which unaffiliated transmission customers will receive

operational penalty payments. CREPC also asks the Commission whether the $500 per

day penalty is a flat rate that would be pro-rated among eligible non-offending,

unaffiliated transmission customers or if the $500 is a rate paid to each eligible

transmission customer.

1335. Commenters affiliated with RTOs and one transmission customer support the

Commission’s proposal to exempt RTOs from penalties for late studies.

810

MISO asserts

that RTOs do not have incentives to delay the processing of transmission service

requests, as they have no affiliates to favor and because their Commission-approved

design and internal procedures ensure their independence. MISO argues further that all

transmission service requests benefit some RTO member and, as a result, RTOs have no

disincentive to approve service so long as reliability is maintained. MISO/PJM States

810

E.g., MISO, MISO/PJM States, TDU Systems, and Indianapolis Power Reply.

Docket Nos. RM05-17-000 and RM05-25-000 - 796 -

asserts that the NOPR proposal to exempt RTOs from operational penalties for late

studies is appropriate because a penalty does not serve a useful purpose with respect to

RTOs. TDU Systems state that an RTO should not be financially penalized for late

studies because RTO independence should minimize incentives for affiliate preference

and RTO members indirectly pay for all RTO incurred costs in any event.

1336. Most of those commenters not affiliated with an RTO oppose the proposal to

exempt RTOs from penalties for late studies.

811

Southern argues that given that the

Commission is seeking to increase transparency in the system, the Commission would

undercut that goal by omitting a significant segment of the industry. TAPS argues that

RTOs may still fail to complete studies on a timely basis due to competing internal

priorities or bureaucratic indifference. Progress notes that the Commission has found that

RTOs and ISOs should be subject to penalties for failure to meet reliability standards.

Salt River argues that RTOs should be subject to operational penalties because the impact

on the customer is identical if the request processing deadline is not met regardless of the

type of provider conducting the study. Xcel notes that, historically, transmission owners

need to complete facility studies in concert with RTOs, thereby giving the customer the

most up-to-date and coordinated analysis. Consequently, Xcel believes it is imperative

that both transmission owners and RTOs operate under the same rules, reporting

obligations, and performance metrics in the OATT.

811

E.g., Southern, TAPS, Progress Energy, Salt River, and Xcel.

Docket Nos. RM05-17-000 and RM05-25-000 - 797 -

1337. In its reply comments, WPS disagrees with the Commission’s proposal to exempt

RTOs from penalties for their repeated failure to meet the 60-day due diligence

requirements. WPS asserts that the Commission should impose penalties and prohibit the

recovery of associated revenue where appropriate. WPS argues that RTO independence

does not guarantee RTO competence or compliance in every instance. WPS believes

imposing reporting obligations and penalties for failure to comply with tariff

requirements, particularly tariff deadlines, will help to motivate compliance by ensuring

that RTOs devote resources to tariff compliance. WPS acknowledges that a non-profit

RTO has no dividends to cancel and likely no property to liquidate to cover these

shortfalls, yet believes that such organizations can exercise cost-cutting measures,

especially regarding rewards for employee performance, and thereby bear some financial

responsibility and accountability for their operational violations. In the event of a

penalty, WPS believes the Commission could require an RTO to take steps to cover its

penalty-related revenue shortfall by cutting its budget, eliminating management bonuses

and demonstrating that it has taken reasonable corrective steps before the Commission

permits recovery of the remaining penalty revenue from its members and customers. To

the extent some portion of an RTO’s penalties are passed through to its market

participants, including transmission owners, WPS argues that those market participants

would be in a position to take actions similar to the actions taken by shareholders of a

publicly traded company to motivate the RTO either by changing the RTO’s processes or

its Board of Directors.

Docket Nos. RM05-17-000 and RM05-25-000 - 798 -

1338. TAPS states that some adaptation of the penalties may be necessary to make them

appropriate and effective in the non-profit RTO/ISO context, for example, by requiring a

reduction in management compensation. TDU Systems recommend that RTOs be subject

to the notification filing requirement that is part of the Commission’s penalty proposal,

regardless of whether RTOs are subject to pay penalties. TDU Systems believe this

reporting requirement would provide an objective measure of RTO efficiency. APPA

believes steps should be taken to remedy tardy RTO processing of service requests,

suggesting that performance incentives for RTO employees, if carefully designed, could

be useful. In its reply comments, Duke argues that although transmission owners in

RTOs should not pay the price for RTOs failures to abide by the tariff, RTOs lack of

performance should be addressed by the Commission, perhaps in a separate proceeding.

1339. Transmission providers that have retained an independent tariff administrator

suggest that these independent entities should also be exempt from operational penalties

related to study completion times.

812

In their view, these independent entities also have

no incentive to discriminate when completing service request studies. Similarly,

NorthWestern argues that a transmission provider without an affiliate that could benefit

from a delay in completing service request studies also should be exempt from paying the

proposed operational penalties.

812

E.g., Duke, MidAmerican, and TranServ.

Docket Nos. RM05-17-000 and RM05-25-000 - 799 -

Commission Determination

1340. The Commission adopts the NOPR proposal to subject transmission providers to

operational penalties when they routinely fail to meet the 60-day due diligence deadlines

prescribed in sections 19.3, 19.4, 32.3 and 32.4 of the pro forma

OATT. Transmission

providers must have a meaningful stake in meeting study time frames. As discussed

above, a transmission provider will be required to make a notification filing with the

Commission indicating that it has not completed request studies on a timely basis and

may present evidence that extenuating circumstances prevented it from completing

studies on a timely basis. The transmission provider then will be subject to an

operational penalty if the transmission provider continues to be out of compliance with

the deadlines prescribed in the pro forma

OATT for each of the two quarters following its

notification filing and the Commission determines that no extenuating circumstances

exist to excuse the transmission provider’s non-compliance. The transmission provider

will be deemed to be out of compliance if it completes 10 percent or more of non-

affiliates’ system impact studies and facilities studies outside of the deadlines prescribed

in the pro forma

OATT. The operational penalty will be assessed on a quarterly basis,

starting with the quarter following the notification filing and continuing until the

transmission provider completes at least 90 percent of all studies within 60 days after the

study agreement has been executed. For any system impact study or facilities study

completed during that quarter and more than 60 days after the study agreement was

executed, the penalty will equal $500 for each day the transmission provider takes to

Docket Nos. RM05-17-000 and RM05-25-000 - 800 -

complete the study beyond 60 days. For any system impact study or facilities study that

is still pending at the end of the quarter and that has been in the study queue for more

than 60 days, the penalty will equal $500 for each day the study has been in the study

queue beyond 60 days.

1341. The late study penalty regime described in this Final Rule will become effective at

the same time as the rest of the new pro forma

OATT. The penalty regime is designed so

that the transmission provider has to be out of compliance for at least three quarters

before it is subject to late study penalties. We believe nine months is sufficient time for

the transmission provider to adjust its operations to the new requirements in this Final

Rule, including penalties for late studies. That is, we believe transmission providers

should be able to reallocate employees to study requests for service and hire new staff, to

the extent these steps are necessary, by the time the transmission provider will be subject

to civil penalties.

1342. The procedures underlying the operational penalty regime adopted in this Final

Rule ensure that the due process rights of transmission providers are protected. In their

notification filing, transmission providers will have the right to document and describe

any unique complexities that particular requests introduce into the study process and that

prevent the transmission provider from completing the study within a the 60-day due

diligence time frame. Thus the 60-day time frame will continue to be a flexible deadline,

especially given that the transmission provider is not required to complete all studies

Docket Nos. RM05-17-000 and RM05-25-000 - 801 -

within 60 days. These due process rights provide a de facto case-by-case review of the

transmission provider’s efforts to complete studies on a timely basis.

1343. On review of a notification filing, we will waive operational penalties if a

transmission provider establishes that its non-compliance is the result of factors or events

that are truly beyond its control, including delays caused by the transmission customer.

We will not, however, exempt all transmission projects that cross seams from operational

penalties, as CREPC urges. We will consider the specific facts surrounding studies of

such projects based on a transmission provider’s notification filing. In response to TDU

Systems, we acknowledge that the procedures for addressing a transmission provider’s

failure to conform to the 60-day time frame are not the same as the procedures applicable

to a transmission customer that is assessed an operational penalty under the pro forma

OATT. We believe such different procedures are justified in this instance. The other

operational penalties in the pro forma

OATT are assessed for failure to remain in

compliance with strict requirements, while the study time frame is based on the

transmission provider using its due diligence to complete studies within 60 days. The

Commission recognizes that the transmission provider must have flexibility, within

reason, to complete studies outside of this time frame. At the same time, the notification

and penalty procedures we adopt in this Final Rule will ensure that this flexibility is not

abused.

1344. We do not find the remaining comments in opposition to the operational penalty

for late studies to be compelling, particularly given the flexibility built into our penalty

Docket Nos. RM05-17-000 and RM05-25-000 - 802 -

regime. We would not expect a transmission provider to prematurely deny a request for

service simply to avoid an operational penalty. According to section 17.5 of the

pro forma

OATT, a transmission provider must either grant service or offer the

transmission customer a system impact study. The transmission provider does not have

the option to simply deny the request for service. We therefore interpret comments that

the transmission provider may prematurely deny a request to mean that the transmission

provider will not explore all possible system upgrades or redispatch options as required

by section 19.3 of the pro forma

OATT or any conditional firm options discussed in

section V.D.1. Such behavior would be a tariff violation that should be brought to our

attention. The transmission provider is required under the pro forma

OATT to provide a

complete study and corresponding work papers to the transmission customer. If a

transmission customer feels a system impact study is incomplete, it has recourse to call

the Commission’s Enforcement Hotline or file a formal complaint with the Commission.

1345. We also do not expect a transmission provider to accept a transmission service

request to the detriment of system reliability simply to meet the study time frame. First,

the transmission provider is not required to complete every request study within 60 days.

Second, to the extent our new requirements that the transmission provider consider

conditional firm options and participate in regional planning cause study delays, the

transmission provider can document and describe such delays in its notification filing.

Finally, the transmission provider has been required to consider redispatch in the system

impact study since Order No. 888 was issued, so the 60-day due diligence time frame

Docket Nos. RM05-17-000 and RM05-25-000 - 803 -

should continue to be consistent with the long standing requirement to consider

redispatch in the system impact study.

1346. As we discuss below, we believe NAESB’s queue hoarding and queue flooding

business practices, as well as additional reforms adopted in this Final Rule, will address

the problem surrounding the submission of multiple requests. With regard to requests for

a technical conference or further procedures to consider the effect of our operational

penalty regime, we believe the commenters’ proposals would largely provide anecdotal

information and speculation on the impacts of the new planning and coordination

requirements. Our experience from the last ten years, and the comments provided in

response to the NOI and NOPR, provide a sufficient basis to develop a penalty regime.

In addition, the very requirement that transmission customers post performance metrics

and submit notification filings prior to assessment of operational penalties will provide

actual experience with the new regime. As explained above, the notification procedures

adopted today will ensure that we will not assess a penalty for late studies unless justified

by the circumstances. We can propose additional changes to the study process or penalty

regime based on the actual experience under this Final Rule if our experience warrants it.

1347. As described above, we adopt the proposal to set the operational penalty for late

studies equal to $500 per day per late study. We believe $500 per day per late study is in

line with the cost the transmission provider would incur to focus additional resources on

processing requests studies. In addition, the penalty for being one month late, $15,000, is

in line with the overall cost of the study. We conclude that the $500 per day per late

Docket Nos. RM05-17-000 and RM05-25-000 - 804 -

study penalty is high enough to provide the incentive to transmission providers to comply

with study processing deadlines in the pro forma

OATT, while not being unnecessarily

punitive. We believe that a penalty in the range of $10,000 per day per late study would

be unnecessarily punitive. The proposal to set the penalty equal to the higher of the lost

opportunity cost to the customer resulting from the delay, if any, or $1,000 for each day

is administratively cumbersome and could result in administrative costs that are not

justified. Finally, we believe the due process afforded the transmission provider is an

important element of the penalty regime, so we decline to impose penalties automatically,

without a notification filing to the Commission.

1348. As indicated in the NOPR, we may order other remedial actions in addition to the

operational penalties described above, consistent with the Policy Statement on

Enforcement. We will determine any other remedial action on a case-by-case basis. The

decision to order other remedial actions will be based, among other things, on whether we

believe the transmission provider is using the same due diligence to complete studies for

non-affiliated customers as it uses to complete studies for itself. We do not believe it

would be appropriate, as a general matter, to require a transmission provider to engage an

independent transmission administrator to the extent its posted performance metrics are

not accurate. As a threshold matter, Commission audit staff may audit the accuracy of a

transmission provider’s posted metrics. If we are concerned about the accuracy of a

transmission provider’s metrics, we will evaluate the use of third-party audits at that time.

We will not prejudge which remedial actions we will consider if a transmission provider

Docket Nos. RM05-17-000 and RM05-25-000 - 805 -

persistently fails to adhere to the relevant timelines. Rather, we will review each such

instance on a case-by-case basis and determine the appropriate remedial action consistent

with the Commission’s Policy Statement on Enforcement.

1349. We clarify that a transmission provider is not subject to operational penalties if it

can make a showing that its failure to meet the compliance threshold following its

notification filing is due to extenuating circumstances, as we agree that the transmission

provider should not penalized for factors out of its control. The submission of a

notification of extenuating circumstances will not, however, suspend the obligation of a

transmission provider to process at least 90 percent of the study requests within the

proposed deadlines, until such time as the Commission issues a final determination on the

notification of extenuating circumstances. At the same time, we will not require the

transmission provider to distribute its operational penalty while we are still considering

the transmission provider’s notification filing. The transmission provider nonetheless

remains liable for paying the operational penalty for all request studies completed or

outstanding after the notification filing and not completed within 60 days. This timing

will balance the transmission provider’s due process rights with the need to provide an

incentive to the transmission provider to complete studies on a timely basis.

1350. We clarify that the processing time is measured from the point that the customer

returns its executed study agreement to the transmission provider. By the time the

transmission provider offers a system impact study agreement, it should have all the

information it needs to complete the study. Pursuant to section 17.4 of the pro forma

Docket Nos. RM05-17-000 and RM05-25-000 - 806 -

OATT, the transmission provider can deem a transmission service request deficient if the

transmission customer does not provide all information the transmission provider needs

to evaluate the request for service. We expect the transmission provider to use informal

means to communicate the information it needs from the transmission customer before it

deems a transmission service request deficient.

1351. We adopt the NOPR proposal to have the transmission provider distribute the

operational penalty for late studies to all non-affiliated transmission customers, as

discussed in section V.C.5.b of this Final Rule. We believe that a transmission provider

that is not processing studies on a timely basis potentially harms all transmission

customers, not just those with requests in the study queue. For instance, a transmission

customer may decide against requesting service that it believes will require a system

impact study if the transmission provider is not processing transmission service requests

on a timely basis. Therefore, we will not adopt suggestions to distribute penalty revenue

only to transmission customers that have request studies that are not completed within 60

days. We clarify that the penalty is $500 per day per late study, with the resulting total

penalty revenue distributed to unaffiliated transmission customers as discussed in section

V.C.5.b of this Final Rule. We clarify that the transmission provider will propose a

method to determine how unaffiliated transmission customers will receive operational

penalty payments, as discussed in section V.C.5.b of this Final Rule.

1352. We will not alter the 60-day study completion timeframe currently embodied in

sections 19.3, 19.4, 32.3 and 32.4 of the pro forma

OATT. We continue to believe,

Docket Nos. RM05-17-000 and RM05-25-000 - 807 -

absent concrete evidence to the contrary, that the existing time frame adequately balances

the need for expeditious resolution of request studies and the need to ensure that the

transmission provider can reliably accommodate the transmission service reserved.

Moreover, we believe the penalty regime defined in this Final Rule protects the

transmission provider in the event studies take longer to complete due to the new

planning requirements defined in section V.B of this Final Rule or the new requirement

to consider conditional firm options as defined in section V.D.1of this Final Rule. We

will not adopt the suggestion to restart the 60-day due diligence period for any study that

experiences a delay that can not properly be attributed to the transmission provider. We

reiterate that the transmission provider is not subject to penalties for late studies if it can

establish that delays are due to factors the transmission provider cannot control.

1353. The Commission declines to adopt the NOPR proposal to exempt RTOs from

operational penalties for completing studies on an untimely basis. We agree with those

commenters that argue that RTO independence does not guarantee RTO competence or

compliance in every instance and that RTOs may fail to complete studies on a timely

basis due to competing internal priorities or staffing issues. Imposing penalties for failure

to comply with the due diligence time frame for completing studies will provide RTOs an

appropriate incentive to comply with the pro forma

OATT requirements and ensure that

they devote adequate resources to tariff compliance. Finally, we note that subjecting

RTOs to operational penalties for late studies is consistent with the Commission’s

Docket Nos. RM05-17-000 and RM05-25-000 - 808 -

decision to subject RTOs and ISOs to penalties for failure to meet reliability standards.

813

We believe that all transmission providers, including RTOs, should operate under the

same rules, reporting obligations, and performance metrics in the OATT. We will

nonetheless keep in mind the nature of an RTO’s operations and the RTO’s unique

characteristics when we consider whether penalties would be appropriate. We agree that

RTOs do not have an incentive to discriminate (which is one of the bases for this policy)

and we agree that imposing a penalty raises the issue of cost recovery, as most RTOs are

not-for-profit entities. We will therefore consider these and all other relevant factors in

exercising our discretion whether to impose a penalty in a given circumstance.

1354. Consistent with the treatment of RTOs, we will not exempt independent entities

that provide tariff administration from penalties for late completion of studies. As with

RTOs, independence does not guarantee competence or compliance in every instance.

Independent entities have a similar incentive to limit the personnel committed to

processing request studies in an effort to reduce overhead costs. We believe that all

entities administering the tariff should operate under the same rules, reporting

obligations, and performance metrics in the pro forma

OATT.

813

Rules Concerning Certification of the Electric Reliability Organization; and

Procedures for the Establishment, Approval, and Enforcement of Electric Reliability

Standards, Order No. 672-A, 71 FR 19814 (Apr. 18, 2006), FERC Stats. & Regs.

¶ 31,212 at P 56 (2006) (“It is not arbitrary and capricious to treat all operators alike,

including RTOs and ISOs, in terms of their liability for violation of a Reliability

Standard.”).

Docket Nos. RM05-17-000 and RM05-25-000 - 809 -

(3) Recovery through Rates

NOPR Proposal

1355. The Commission proposed that a transmission provider cannot recover for

ratemaking purposes any operational penalty it pays for failing to process transmission

service studies on a timely basis.

Comments

1356. CREPC noted that, while it may be reasonable for an investor-owned utility to pay

penalties without being allowed to recover the penalties in rates, this approach will be

problematic for utilities that do not have shareholders.

Commission Determination

1357. We will prohibit all jurisdictional transmission providers from recovering

penalties for late studies from transmission customers. We believe that all entities

administering the tariff should operate under the same rules, reporting obligations, and

performance metrics in the pro forma

OATT. Non-profit transmission providers have

other sources of money to pay penalties beyond the revenue they collect for sales of

transmission service. Therefore, we require non-profit transmission providers to pay

operational penalties for late studies from their other sources of money. This

notwithstanding, we may consider factors such as an entity’s financial ability to absorb a

penalty in determining whether to impose penalties in the first instance.

Docket Nos. RM05-17-000 and RM05-25-000 - 810 -

(4) Fee for Multiple Self-Competing Transactions

NOPR Proposal

1358. In the NOPR, the Commission sought comment on a fee structure that could

provide a disincentive for transmission customers to submit duplicative requests without

penalizing transmission customers that have legitimate requests for transmission service.

The Commission asked for detailed recommendations, including any proposed tariff

language, regarding the standards it should use to identify requests that would be subject

to a fee. The Commission also sought recommendations on the level of a fee that

balances its policy goals to discourage requests for transmission service that the

transmission customer does not intend to confirm while not discouraging legitimate

requests for transmission service. Finally, the Commission sought comment regarding

the circumstances, if any, under which the processing fee would be refunded to or

credited to the transmission customer.

Comments

1359. A number of commenters express support for a fee for duplicative requests.

814

CREPC believes that queue blocking behavior should be discouraged so that legitimate

requests lower in the queue are not disadvantaged. MISO believes the transmission

provider should be allowed to charge a fee that is small enough to not create a barrier to

entry yet high enough to “add up” for anyone wishing to flood the queue. MISO and

814

E.g., MidAmerican, MISO, Seattle, Southern, TranServ, TAPS, and CREPC.

Docket Nos. RM05-17-000 and RM05-25-000 - 811 -

Seattle suggest that the fee be based on the transmission provider’s cost to review a

request and handle the initial processing. MISO also believes the transmission provider

should be able to charge a fixed dollar amount for any accepted requests that the

customer wants to retract. Southern suggests that the Commission consider a procedure

whereby transmission customers place a deposit with transmission providers to cover a

certain number of requests that is forfeited once the requests reach a certain threshold and

are deemed self-competing. TranServ suggests that the fee apply to requests for long-

term firm transmission service and be based on duration of the request and not capacity

requested as an incentive to the transmission customer to submit fewer combined requests

where possible. TranServ suggests this fee could be waived if the service request is

submitted pre-confirmed.

1360. Most of the transmission customers and some transmission providers oppose the

creation of a fee structure for duplicative requests for transmission service.

815

Several

commenters argue that the Commission should determine whether the newly-adopted

NAESB business practices and other reforms proposed in the NOPR can reduce the

number of requests that the transmission customer does not intend to confirm.

816

Nevada

Companies and Great Northern assert that the current deposit requirement serves to

discourage multiple self-competing requests. Constellation asserts that the Commission

815

E.g., EEI, Nevada Companies, Powerex, and Suez Energy NA.

816

E.g., EEI, Powerex, Suez Energy NA, and Entegra.

Docket Nos. RM05-17-000 and RM05-25-000 - 812 -

should focus on narrowly-tailored penalties to deter market participants from

intentionally jamming the queue.

1361. Several commenters suggest that a transmission provider that makes a showing

that it is experiencing a significant problem with respect to customers’ submission of

multiple competing requests should be allowed to propose a fee to combat the problem.

817

MISO notes that the Commission has rejected a fee for unconfirmed requests in the

past.

818

1362. TAPS believes the fee revenue should be shared with network customers on a

load-ratio share basis. TAPS also suggests that the fee apply to the transmission

provider’s merchant arm in a meaningful way.

1363. CREPC urges the Commission to adopt a simple, straightforward standard for

determining duplicative requests, such as the same points of receipt and delivery, same

source and sink, same time frame, and same firmness, as well as the same project at

multiple locations. Powerex recommends that the Commission be very specific in

describing the types of multiple transmission requests it believes to be a problem and the

fee structure that would be applied to such problematic requests. For example, Powerex

believes the Commission should clarify that requests subject to the fee must be multiple,

817

E.g., EEI and TAPS.

818

See Midwest Independent Transmission System Operator, Inc., 97 FERC ¶ 61,269

(2001) (rejecting a proposal to include a fee for non-confirmed transmission service

requests for firm point-to-point transmission service of one week or longer).

Docket Nos. RM05-17-000 and RM05-25-000 - 813 -

not pre-confirmed, and with identical quantity, point of receipt, point of delivery, start

time, end time, and firmness. In its reply comments, Santa Clara disagrees with Powerex.

Santa Clara urges the Commission to examine the practice of queue hoarding and punish

those entities that are acting in an anticompetitive and manipulative manner. Further,

Santa Clara urges the Commission to refrain from being too specific in its ruling, as a

more general explanation of the behavior to be avoided would go a long way in

preventing entities from making an end-run around a ruling against queue hoarding.

1364. MidAmerican believes that if a fee is imposed, the fee should not be refunded as

the administrative costs and difficulty of administering the refunds would be an

unreasonable burden on the transmission provider. CREPC believes refunding or

crediting the processing fee would defeat the purpose of having one in the first place,

although the processing fee could be refunded if the duplicative service request attached

to it actually comes to fruition. Suez Energy NA suggests that the processing fee be

refunded whenever the transmission provider exceeds the 60-day request study due

diligence deadline. TAPS suggests that the fee be structured to provide for exceptions

where the failure to confirm reflects a legitimate purpose, not jamming. TAPS cites as

examples transmission requests associated with requests for proposals, alternative sites

for planned generation, and the inability to secure timely confirmation of all legs of a

multi-system path. TAPS notes that the current pro forma

OATT accommodates multiple

submissions in relation to the same competitive solicitation in sections 19.2(ii) and

32.2(ii).

Docket Nos. RM05-17-000 and RM05-25-000 - 814 -

Commission Determination

1365. The Commission will not require transmission providers to charge a fee for

duplicative requests for transmission service. We will instead first consider whether the

newly adopted NAESB queue flooding and queue hoarding business practices reduce the

number of requests that the transmission customer does not intend to confirm. We are

concerned that benefits to market participants would not justify the administrative costs

of a new fee if the NAESB business practices can effectively discourage transmission

service requests the transmission customer does not intend to confirm. We also believe

that the current deposit mechanism in section 17.3 of the pro forma

OATT should have

the same effect as a fee based on the transmission provider’s cost to process the request

for transmission service, like the fee MISO and CREPC propose. Pursuant to section

17.3, in the event a transmission customer retracts or withdraws a request, the

transmission provider is allowed to deduct from the transmission customer’s deposit the

costs the transmission provider incurred to process the request. As a result, we do not

believe any other fee structure is necessary to make the transmission provider whole

when a transmission customer submits a transmission service request it does not expect to

confirm.

1366. A transmission provider that continues to experience problems related to

submission of multiple duplicative requests for transmission service is free to file a tariff

modification that includes a fee to combat the problem. This filing should explain why

the transmission provider is unable to handle the submission of multiple duplicative

Docket Nos. RM05-17-000 and RM05-25-000 - 815 -

requests for transmission service through NAESB’s queue hoarding and queue flooding

business practices.

(5) Clustering Transmission Service Request Studies

NOPR Proposal

1367. In the NOPR, the Commission sought comment regarding whether a transmission

provider should be required to study requests for transmission service in a group if the

transmission provider fails to complete studies on a timely basis. If so, the Commission

sought comment on the circumstances that should trigger such a requirement and the

appropriate method of implementing the requirement. The Commission sought further

comment regarding whether transmission providers should be required to study requests

for transmission service in a group if all the transmission customers in the group agree to

cluster their requests. Finally, the Commission sought comment regarding how to select

the requests that belong to a cluster so that transmission customers cannot “cherry-pick”

clusters to avoid transmission system upgrade costs.

Comments

1368. A few commenters, primarily transmission customers, believe transmission

providers should be required to study requests for transmission service in a group.

819

CREPC believes transmission providers should have the discretion to develop the criteria

for clustering so that transmission customers do not have the opportunity to “cherry pick”

819

E.g., CREPC, Powerex, and Suez Energy NA.

Docket Nos. RM05-17-000 and RM05-25-000 - 816 -

study clusters. If transmission providers are required to study requests in a group,

Powerex believes customers should be given the option of paying the transmission

provider to perform an individual study. Suez Energy NA believes studying requests that

are clustered voluntarily will partially incorporate the value of counterflows in the study

process. PGP believes transmission customers should have the opportunity to join a

cluster, but only if the customer is bound to accept the study results.

1369. A number of commenters, primarily transmission providers, state that transmission

providers should be allowed, but not required, to study requests for transmission service

in a group.

820

Bonneville argues that the transmission provider is in the best position to

determine whether requests should be studied individually or in groups. EEI asserts that

clustering does not necessarily ensure timely completion of transmission studies.

FirstEnergy believes each transmission service request should stand on its own merits and

be directly assigned costs associated with its own request so that requests in one part of

the request queue do not end up subsidizing requests in another part of the request queue.

MISO believes giving the transmission provider discretion to cluster requests will address

the Commission’s concerns with respect to transmission customers cherry-picking

clusters to avoid paying upgrade costs. Arkansas Commission and East Texas

Cooperatives suggest that the Commission allow clustering through an open season

820

E.g., Bonneville, EEI, MISO, Nevada Companies, Southern, Entegra, and PNM-

TNMP.

Docket Nos. RM05-17-000 and RM05-25-000 - 817 -

procedure similar to the procedure SPP currently uses pursuant to Attachment Z of SPP’s

OATT.

Commission Determination

1370. The Commission will not require transmission providers to study transmission

requests in a cluster, although we encourage transmission providers to cluster request

studies when it is reasonable. We do, however, require transmission providers to

consider clustering studies if the customers involved request the cluster and the

transmission provider can reasonably accommodate the request. We believe clustering

request studies offers potential benefits as the needed transmission upgrades are

frequently large enough that the upgrade can accommodate more than one transmission

service request. In addition, jointly modeling transmission service requests can allow the

transmission provider to more efficiently design transmission system upgrades.

Clustering also allows the transmission provider to include, to the extent it is consistent

with good utility practice, the potential counterflows created by the clustered requests.

We do not agree, as suggested by commenters, that clustering necessarily leads to one set

of transmission customers subsidizing another set of transmission customers.

1371. We therefore require each transmission provider to include tariff language in its

compliance filing that describes how it will process a request to cluster request studies

and how it will structure the transmission customers’ obligations when they have joined a

cluster. We will give the transmission provider discretion to determine whether a

transmission customer can opt out of a cluster and request an individual study. We are

Docket Nos. RM05-17-000 and RM05-25-000 - 818 -

giving each transmission provider discretion to develop the clustering procedures it will

use because we believe the transmission provider is in the best position to determine the

clustering procedures that it can accommodate. We also believe that the transmission

provider is in the best position to develop a clustering procedure that prevents a

transmission customer from strategically selecting the clusters in which it participates in

an attempt to avoid responsibility for needed transmission system upgrades.

(6) Standardization of Business Practices for Study Queue

Processing

NOPR Proposal

1372. In the NOPR, the Commission sought comment on whether additional

standardization of request queue processing is necessary. If so, the Commission sought

comment on the specific issues commenters believe are not clearly prescribed in Order

No. 676 or the NOPR and that require additional mandatory queue processing business

practices.

Comments

1373. Several commenters identified issues where a transmission customer needs

coordinated responses across several transmission systems in order to serve its load.

821

Seattle and NRECA suggest that the Commission amend the pro forma

OATT so that a

customer's applications for service across multiple systems that are intended to serve a

821

E.g., NRECA, TDU Systems, and Seattle.

Docket Nos. RM05-17-000 and RM05-25-000 - 819 -

single sink from an identified resource will be considered a single application for

purposes of establishing the deadlines for rendering an agreement for service, revising

queue status, eliciting deposits and finally commencing service. Seattle believes the

Commission should permit coordination and implementation of these requirements by a

third party such as wesTTrans.net and sub-regional planning organizations. At a

minimum, these commenters ask the Commission to develop business practices to protect

a transmission customer caught between two systems with uncoordinated deadlines.

1374. Exelon states that the Commission should require all transmission providers to

allow transmission customers to link consecutive requests for service (e.g.

, monthly firm

service requests for December, January and February) and to evaluate such request as a

single request. Exelon argues that this service, which is currently provided by some

transmission providers, would increase uniformity and use of the transmission system,

and enhance competitiveness without burdening transmission providers or adding

administrative complexity.

1375. TDU Systems indicate that several of its members have experienced difficulty

related to the lack of standardized business practices, particularly in practices related to

timing, application requirements, and requirements relating to methods of proving that a

network customer has executed a power purchase agreement prior to designating the

power purchase agreement as a network resource.

1376. PNM-TNMP does not believe that additional clarity or business practices are

necessary beyond those already provided in Order No. 676. However, to the extent

Docket Nos. RM05-17-000 and RM05-25-000 - 820 -

additional issues arise, PNM-TNMP believes NAESB’s WEQ forum is the appropriate

place to address them. Similarly, NorthWestern recommends that transmission providers

work together within regional groups to develop a common set of business practices that

will be followed by all transmission providers within each region, instead of the

Commission using the NOPR comments it receives to develop a prescriptive set of

business practices by which all transmission providers must abide. In its reply

comments, Powerex argues that either the entire transmission process has to be integrated

via an RTO, or coordination of requests across multiple control areas has to be done

transmission provider by transmission provider. Powerex suggests that NorthWestern’s

suggestion for regional development of business practices may be a more pragmatic

approach to address concerns about coordination of requests across multiple systems.

Commission Determination

1377. The Commission agrees that transmission requests across multiple transmission

systems should be coordinated by the relevant transmission providers. We will not,

however, amend the pro forma

OATT to require such coordination. Rather, we require

transmission providers working through NAESB to develop business practice standards

related to coordination of requests across multiple transmission systems. In order to

provide guidance to NAESB, we will articulate the principles that should govern

processing across multiple systems. All the transmission providers involved in a request

across multiple systems should consider a request that requires studies across multiple

systems to be a single application for purposes of establishing the deadlines for rendering

Docket Nos. RM05-17-000 and RM05-25-000 - 821 -

an agreement for service, revising queue status, eliciting deposits and commencing

service. In order to preserve the rights of other transmission customers with studies in the

queue, the priority for the single application should be based on the latest priority across

the transmission providers involved in the multiple system request. We note that regional

entities like wesTTrans are already coordinating requests across multiple transmission

systems and we believe such coordination is an acceptable solution to this issue.

1378. We interpret Exelon’s request that we require all transmission providers to allow

transmission customers to link consecutive requests for firm point-to-point transmission

service and to evaluate such requests as a single request as asking us to (1) allow

transmission customers to require the transmission provider to either grant service for the

entire period, deny service for the entire period, or offer the same partial quantity for the

entire period and (2) require the transmission provider to consider the full duration of the

linked requests when determining reservation priority pursuant to sections 13.2 of the

pro forma

OATT (short-term firm point-to-point transmission service). We require

transmission providers working through NAESB to develop business practice standards

to allow a transmission customer to rebid a counteroffer of partial service so the

transmission customer is allowed to take the same quantity of service across all linked

transmission service requests. Transmission providers need not implement these business

practice standards until NAESB develops appropriate standards. We note that the

transmission customer should not be required to take the same quantity of service across

consecutive transmission service requests, it should simply have the option to do so. On

Docket Nos. RM05-17-000 and RM05-25-000 - 822 -

the second issue, we reiterate that, according to existing NAESB business practice

standard 001-4.16, the transmission provider is required to consider the full duration of

the linked requests when determining reservation priority pursuant to section 13.2 of the

pro forma

OATT.

1379. We believe most of the standardization issues TDU Systems raise (application

requirements, requirements relating to methods of proving that a network customer has

executed a power purchase agreement prior to designating the power purchase agreement

as a network resource, and timing) have been addressed in this Final Rule. In particular,

we describe the information a network customer is required to provide when designating

a new network resource in section V.D.6.b of this Final Rule. We also indicate in section

V.D.6.b that the transmission provider is not allowed to require a network customer to

provide contract terms and conditions when it designates a power purchase agreement as

a network resource. The network customer is required to provide a statement that attests,

among other things, that it has executed a power purchase agreement prior to confirming

its request to designate a new network resource. We will continue to give transmission

providers discretion in determining whether to impose restrictions on the earliest time at

which it will accept a request for transmission service. We believe the transmission

provider is in the best position to determine whether it needs to restrict the time at which

it will accept requests for transmission service in order to process transmission service

requests in an orderly fashion consistent with the requirements in the pro forma

OATT.

Docket Nos. RM05-17-000 and RM05-25-000 - 823 -

(7) Additional Processing Proposals

Comments

1380. A number of commenters propose changes to queue processing requirements that

were not addressed in the NOPR.

1381. Powerex believes that OASIS practices should be modified to ensure that short-

term firm and non-firm point-to-point service requests are processed based on the ATC

posted at the time the requests were queued. Powerex argues that a transmission provider

should not be permitted to grant transmission service requests at a time when its OASIS

indicates there is no ATC. In its view, any such requests should be automatically denied.

Powerex also suggests that confirmation time periods be shortened for short-term firm

point-to-point service requests to discourage behaviors that have the effect of delaying

queue processing. In its reply comments, Powerex asserts that requiring transmission

provider responses to be based on posted ATC, as well as increasing standardization in

transmission provider response time for short-term transmission requests, would enhance

a transmission customer’s ability to manage multiple transmission provider requests

within the context of the pro forma

tariff.

1382. Occidental suggests in reply that the Commission should introduce meaningful

tariff-based sanctions for unauthorized deviations from the standards and modeling

assumptions it proposes to include in Attachment C of the pro forma

OATT, the

transmission provider’s description of its ATC calculation methodology.

Docket Nos. RM05-17-000 and RM05-25-000 - 824 -

1383. Several commenters make suggestions to allow the transmission provider to

terminate idle transmission service requests. TDU Systems recommends that the

Commission provide a sunset date by which all requests not pursued by the transmission

customer would be terminated. MidAmerican and Northwest IOUs ask the Commission

to clarify in the Final Rule that the transmission provider may deem a transmission

service application withdrawn and terminated if a customer revises its application or if

such customer fails to timely pay the annual reservation fee pursuant to section 17.7 of

the pro forma

OATT.

1384. Constellation asks the Commission to require transmission providers to release

study results as soon as a study is completed, rather than holding them until the end of the

60 days.

1385. NorthWestern believes an appropriate modification to the study process would be

to allow the transmission provider to have an opportunity to verify and correct the system

impact study results at the beginning of the facilities study and again before construction

begins.

1386. With the exception of very short-term transmission service (for which a bid-based

system is impractical to manage), LDWP suggests that the queue process be transformed

into a competitive process in which awards of transmission service are allocated in a

manner similar to the provisions in section 4.4 of Order No. 638.

1387. TranServ notes that OASIS standards allow the customer to turn a request into a

pre-confirmed request, but not vice versa. If the Commission’s proposal on granting

Docket Nos. RM05-17-000 and RM05-25-000 - 825 -

priority to pre-confirmed requests is adopted, TranServ believes this capability should be

removed from OASIS as it would seem to invite gaming and confuse transmission

providers attempting to process requests in proper queue order.

1388. PGP states that OASIS platforms should be accessible from different computer

platforms using a variety of browsers, not just one operating system/browser combination

(Windows/Explorer), which is currently the case.

Commission Determination

1389. We will not adopt Powerex’s proposal to require the transmission provider to

accept or deny in all cases non-firm and short-term firm point-to-point transmission

service requests solely based on posted ATC. The issue Powerex raises is ultimately a

question of how the transmission provider is going to exercise its discretion under the

tariff. Under the pro forma

OATT, the transmission provider can use its knowledge of

the system to exercise its discretion to offer transmission service even if posted ATC is

not sufficient to accommodate the requested service. Alternatively, the transmission

provider can use its discretion to update posted ATC in response to a transmission

customer’s verbal request to update ATC.

822

In both situations, the transmission provider

may provide transmission service in instances when posted ATC is not sufficient to

accommodate a transmission service request at the time the transmission customer

requests service. We do not wish to discourage transmission providers from making

822

See, e.g., Florida Power Corp., 111 FERC ¶ 61,243 at P 5 (2005).

Docket Nos. RM05-17-000 and RM05-25-000 - 826 -

transmission service available at times when posted ATC is not accurate. Therefore, we

will continue to allow the transmission provider to accept transmission service requests in

instances when posted ATC is not sufficient but the transmission provider believes it can

accommodate the service. The transmission provider must use its discretion to grant

service when posted ATC is not sufficient on a non-discriminatory basis. In order to

ensure that it does so, we expect the transmission provider to log such instances as an act

of discretion and post the log as required in section 37.6(g)(4) of the Commission’s

regulations.

823

1390. We will not modify the pro forma

OATT to address requests to allow the

transmission provider to terminate idle transmission service requests. NAESB’s business

practice 001-4.11 allows the transmission provider to retract a request if the transmission

customer does not respond to an acceptance within the time established in NAESB

business practice standard 001-4.13. Therefore, we interpret TDU Systems comments to

refer to circumstances when a transmission customer fails to respond to the transmission

provider’s request for additional information during the course of a request study. As

discussed above, by the time the transmission provider offers a system impact study

agreement, it should have all of the information that it needs to complete the study.

Pursuant to section 17.4 of the pro forma

OATT, the transmission provider can deem a

transmission service request deficient if the transmission customer does not provide all of

823

18 CFR 37.6(g)(4).

Docket Nos. RM05-17-000 and RM05-25-000 - 827 -

the information the transmission provider needs to evaluate the request for service. We

will revise section 17.7 of the pro forma

OATT so that the transmission provider is able

to terminate a request for transmission service if a transmission customer that is

extending the commencement of service does not pay the required annual reservation fee

within 15 days of notifying the transmission provider that it would like to extend the

commencement of service. We will not change the pro forma

OATT to allow the

transmission provider to terminate a transmission service request if the transmission

customer changes its application for service. We believe the existing pro forma

OATT is

sufficient to allow a transmission provider to manage situations where the transmission

customer modifies its application for service to the point that the customer is requesting

transmission service that is meaningfully different than its initial request.

1391. We clarify that sections 19.3 and 32.3 of the pro forma

OATT require the

transmission provider to release study results as soon as a study is completed, rather than

holding them until the end of the 60 days.

1392. Commenters also suggest changes to the OASIS protocols, including prohibiting

transmission customers from changing a request into a pre-confirmed request and

requiring OASIS platforms to be accessible on non-Windows/Explorer computers. We

believe these issues are best addressed by NAESB.

1393. Commenters proposed a number of additional modifications to the pro forma

OATT that we do not believe are necessary. These proposals would (1) allow the

transmission provider to verify and correct studies between each step in the study

Docket Nos. RM05-17-000 and RM05-25-000 - 828 -

process, (2) transform the queue process into competitive process, (3) shorten the

confirmation time periods for short-term firm point-to-point service requests and

(4) introduce penalties when the transmission provider deviates from the ATC calculation

procedures detailed in Attachment C of the pro forma

OATT. We believe the pro forma

tariff is just and reasonable without such modifications and the commenters have not

demonstrated that reforms in these areas are required at this time to prevent the exercise

of undue discrimination.

b. Reservation Priority

1394. Section 13.2 of the pro forma

OATT requires transmission providers to process

requests for long-term firm point-to-point service on a first-come, first-served basis and

to process requests for short-term firm point-to-point service on a first-come, first-served

basis conditional on the duration of the request. Section 14.2 of the pro forma

OATT

requires transmission providers to process requests for non-firm point-to-point service on

a first-come, first-served basis conditional on the duration of the request to the extent

transmission capacity beyond that needed by native load customers, network customers

and firm point-to-point transmission customers is available. In the NOPR, the

Commission made a number of proposals and requested comment regarding various

aspects of the reservation priority rules.

Docket Nos. RM05-17-000 and RM05-25-000 - 829 -

(1) Priority for Pre-confirmed Requests

NOPR Proposal

1395. In the NOPR, the Commission proposed to change the priority rules to give

priority to pre-confirmed requests for firm point-to-point transmission service.

Specifically, the Commission proposed that a pre-confirmed short-term request for firm

transmission service would preempt any non-pre-confirmed short-term requests,

regardless of duration. Similarly, the Commission proposed that a pre-confirmed request

for long-term firm transmission service would preempt a request for long-term

transmission service that is not pre-confirmed. Under the Commission’s proposal, a pre-

confirmed request for short-term transmission service would not pre-empt a non-pre-

confirmed request for long-term transmission service.

Comments

1396. A number of commenters generally support the Commission’s proposal to give

priority to pre-confirmed requests.

824

Commenters who support the proposal note that

giving reservation priority to pre-confirmed requests for transmission service could help

alleviate the problems that arise when a transmission customer submits multiple identical

requests for service with no intention of confirming all accepted requests.

825

Supporters

824

E.g., Nevada Companies, Seattle, LDWP, PGP, PNM-TNMP, Salt River, and

Suez Energy NA.

825

E.g., Ameren, Santa Clara, Entegra, Entergy, and TVA.

Docket Nos. RM05-17-000 and RM05-25-000 - 830 -

of the proposal also note that the proposal would allow the transmission provider to focus

its attention on those requests that appear most likely to result in an actual reservation of

transmission service.

826

Although Nevada Companies do not oppose the proposal, they

note that concerns regarding withdrawal of pre-confirmed requests might otherwise be

alleviated by requiring a non-refundable deposit on requests.

1397. Several commenters suggest that establishing reservation priority first based on

pre-confirmation status and then based on duration would ultimately result in

transmission customers with relatively shorter term requests getting transmission service

instead of transmission customers with relatively longer term requests.

827

EEI asserts that

this result would be inconsistent with the Commission’s desire to promote longer-term

uses of the transmission system. Several transmission providers suggest that the

Commission modify its proposal to ensure that longer duration requests continue to have

a priority over shorter duration requests.

828

EEI suggests that the Commission should use

pre-confirmation as a tie-breaker for short-term requests for transmission service with the

same duration. Southern argues further that a pre-confirmed daily or hourly request

should not preempt a weekly request that has not been pre-confirmed.

826

E.g., Ameren and NorthWestern.

827

E.g., CREPC and EEI.

828

E.g., Entergy, Southern, and NorthWestern.

Docket Nos. RM05-17-000 and RM05-25-000 - 831 -

1398. Opponents of the proposal identify a number of operational difficulties in

implementing a system that gives priority to pre-confirmed requests. Several

commenters note that transmission customers are not bound to take service because they

pre-confirm a request for transmission service.

829

They argue, for instance, a

transmission customer is not bound to take service in the event the transmission provider

offers a study or counteroffers the request with a partial quantity of service. Similarly,

MidAmerican notes that a transmission customer may withdraw a pre-confirmed request

for transmission service at any time prior to acceptance by a transmission provider.

Opponents also argue that giving priority to pre-confirmed requests would disrupt the

study process.

830

This disruption would occur when a transmission provider receives a

pre-confirmed request for transmission service while it is actively studying a request for

service that has not been pre-confirmed. Under these circumstances, the transmission

provider would be required to suspend the study of one request in order to study a request

with a higher reservation priority. In its reply comments, Indianapolis Power asks the

Commission to clarify if this interpretation of the NOPR proposal is accurate. TranServ,

suggesting that the Commission has not proposed to give a priority to pre-confirmed

requests for non-firm transmission service, asserts that having different priority rules for

firm and non-firm transmission service introduces unnecessary complexity. Finally,

829

E.g., Bonneville and EEI.

830

E.g., Bonneville, EEI, and MidAmerican.

Docket Nos. RM05-17-000 and RM05-25-000 - 832 -

Southern believes that a pre-confirmed service request submitted within close proximity

to the actual commencement of service should not preempt an existing non-pre-

confirmed request, if doing so would be disruptive to the operations of the transmission

provider or to the reliability of the system itself.

1399. Opponents also argue that giving a priority to pre-confirmed requests would

unfairly disadvantage transmission customers who are not in a position to pre-confirm

their requests, such as those requesting service in response to a request for proposals.

831

EEI notes that the Commission addressed this issue when it issued Order No. 638 and

decided that giving priority to pre-confirmed requests would disadvantage customers who

are requesting service from multiple transmission providers.

832

In the event the

Commission decides to proceed with its proposal, TAPS suggests that the Commission

limit the priority for pre-confirmed requests to non-firm and short-term firm requests for

transmission service.

1400. Several commenters question whether a request that has been accepted but not

confirmed would be pre-empted by a new pre-confirmed request.

833

In a similar vein,

TDU Systems suggests that the Commission include a time window between acceptance

831

E.g., EEI, MISO, TAPS, Constellation, and TDU Systems.

832

Open Access Same-Time Information System and Standards of Conduct, Order

No. 638, 65 FR 17370, FERC Stats. & Regs., ¶ 1996–2000 ¶ 31,093 at 31,439 (2000).

833

E.g., MidAmerican and TranServ.

Docket Nos. RM05-17-000 and RM05-25-000 - 833 -

of a request and confirmation of the request, during which a request can not be preempted

by a pre-confirmed request for transmission service.

Commission Determination

1401. The Commission generally agrees with those commenters that argue that giving a

priority to pre-confirmed requests can increase the efficient utilization of the system by

giving priority to customers who are committed to purchase service over those who have

not so committed, including customers that submit multiple requests without any intent to

take service if each request is granted. However, we are mindful of concerns that doing

so could undermine the Commission’s desire to promote longer-term uses of the

transmission system, disrupt the study process, or disadvantage transmission customers

that are not in the position to pre-confirm their requests. As a result, we will modify the

NOPR proposal and give priority only to pre-confirmed non-firm point-to-point

transmission service requests and short-term firm point-to-point transmission service

requests. In addition, longer duration requests for transmission service will continue to

have priority over shorter duration requests for transmission service, with pre-

confirmation serving as a tie-breaker for requests of equal duration. This policy will still

give an advantage to pre-confirmed requests without imposing substantial

implementation difficulties or undermining the Commission’s goals to encourage longer-

term uses of the transmission system. Our revised policy on priority for pre-confirmed

requests thus addresses the comments that we should preserve the priority of longer

duration requests for transmission service over shorter duration requests for transmission

Docket Nos. RM05-17-000 and RM05-25-000 - 834 -

service. For instance, a pre-confirmed daily or hourly request will not preempt a weekly

request that has not been pre-confirmed. Pre-confirmed short-term service requests

therefore will not

have a priority superior to that of long-term service requests that have

not been pre-confirmed.

1402. We acknowledge that our revised policy on priority for pre-confirmed requests

may be less effective than the NOPR proposal in alleviating the problems that arise when

transmission customers submit multiple identical requests for service. However, we have

taken other steps – notably accepting the NAESB business practices on queue flooding

and queue hoarding

834

– that we believe will substantially reduce the instances of multiple

identical requests for service.

1403. The Commission also acknowledges the concerns expressed regarding operational

difficulties caused by giving priority to pre-confirmed requests and clarify our policy as

follows. First, we will prohibit transmission customers from withdrawing pre-confirmed

non-firm and short-term firm point-to-point transmission service requests prior to when

the transmission customer is offered service or a system impact study. This policy will

address MidAmerican’s concern that a transmission customer may withdraw a pre-

confirmed request for transmission service at any time prior to acceptance by a

transmission provider. We believe prohibiting withdrawal of a pre-confirmed request is

less administratively burdensome than the non-refundable deposit on requests proposed

834

See Order No. 676 at P 19

Docket Nos. RM05-17-000 and RM05-25-000 - 835 -

by Nevada Companies and achieves the same goals. The Commission will allow

transmission providers to invalidate a pre-confirmed request at the request of the

transmission customer in the very near term following submittal of the request, in the

event the transmission customer makes an inadvertent error in submitting its request. We

expect the transmission provider to log such occurrences as an act of discretion so we can

verify that transmission customers are not abusing this flexibility.

1404. Second, while the Commission recognizes that a customer submitting a pre-

confirmed request is not bound to take service when the transmission provider

counteroffers the transmission customer’s initial request, we do not believe this fact alone

warrants reversing our proposal to give a priority to pre-confirmed requests. We are

satisfied that a transmission customer that pre-confirms its request is obligated to take full

service in the event the transmission provider offers the service requested.

1405. The Commission also believes the revised priority policy will address Southern’s

comment that a pre-confirmed service request submitted within close proximity to the

actual commencement of service should not preempt an existing non-pre-confirmed

request if doing so would be disruptive to the operations of the transmission provider or

to the reliability of the system itself. A pre-confirmed request for transmission service

will not pre-empt an equal duration request that has already been confirmed. Therefore,

the effects of the priority for pre-confirmed requests will be resolved prior to the time

when the transmission provider would require an accepted request to be confirmed.

Docket Nos. RM05-17-000 and RM05-25-000 - 836 -

Handling priority for pre-confirmed requests should be no more disruptive than giving a

transmission customer time to confirm an accepted request.

1406. Excluding long-term requests for transmission service will mitigate many of the

concerns expressed by commenters who argued that giving a priority to pre-confirmed

requests will unfairly disadvantage transmission customers who are requesting service in

response to a request for proposals and are therefore not in a position to pre-confirm their

requests. Such requests for proposals typically involve long-term contracts for energy

and/or generating capacity and, therefore, would be linked most likely to long-term

transmission service requests. We disagree, however, with EEI’s characterization of the

Commission’s decision in Order No. 638 to give a priority to pre-confirmed requests for

non-firm service only if the request offers a higher price. The Commission’s decision in

that proceeding was driven by its interpretation that the proposed business practice

addressed in the part of Order No. 638 cited by Southern was not consistent with the

relevant section of the pro forma

tariff. In addition, the Commission’s experience since

Order No. 638 and the comments received to the NOPR proposal indicate the value of

giving a priority to pre-confirmed requests, despite concerns that some transmission

customers are not in a position to pre-confirm their requests for transmission service.

1407. In response to requests for clarification from MidAmerican and TranServ, we

clarify that a new pre-confirmed request for transmission service would preempt a request

of equal duration that has been accepted by the transmission provider but not yet

confirmed by the transmission customer. Thus, we decline to adopt TDU Systems’

Docket Nos. RM05-17-000 and RM05-25-000 - 837 -

suggestion that the Commission include a time window between acceptance of a request

and confirmation of the request, during which a request can not be preempted by a pre-

confirmed request for transmission service. This is consistent with our desire to give

transmission service first to those customers that are committed to taking the transmission

service if it is granted. In the case of monthly firm point-to-point transmission service,

the transmission customer has up to four days to confirm an accepted request. This is a

potentially long delay when there is another transmission customer that is willing to

commit to take the same service. Moreover, this policy is consistent with NAESB

business standard 001-4.25, which allows a pre-confirmed request for non-firm point-to-

point transmission service to preempt a request of equal duration and lower price that has

been accepted but not confirmed.

835

(2) Price as a Tie-Breaker

NOPR Proposal

1408. The NOPR also proposed to add price as a tie-breaker in determining reservation

queue priority when the transmission provider is willing to discount transmission service.

Under the Commission’s proposal, price would serve as a tie-breaker after pre-

confirmation for those requests that are not yet confirmed.

835

See Order No. 676.

Docket Nos. RM05-17-000 and RM05-25-000 - 838 -

Comments

1409. All of the commenters who address the Commission’s proposal to add price as a

tie-breaker support the proposal, although some request that it be modified or clarified.

Several commenters ask the Commission to clarify that an otherwise higher queued

request has a right to match the price offer of a request with a higher price.

836

With

regard to short-term service, WAPA believes that the Commission’s proposal to add price

as a tie-breaker would overly complicate matters after taking into account the many

complex timing restrictions on short-term service. As a result, WAPA proposes that the

Commission limit application of its proposal to requests for long-term transmission

service. MISO/PJM States suggest that the Commission consider requiring point-to-point

transmission customers to offer a reservation price at which they would be willing to sell

their transmission service.

Commission Determination

1410. The Commission adopts the NOPR proposal to add price as a tie-breaker in

determining reservation queue priority when the transmission provider is willing to

discount transmission service. As a result, price will serve as a tie-breaker after pre-

confirmation for those requests that have not yet been confirmed by the transmission

customer or have not yet been evaluated by the transmission provider. Consistent with

the principles currently embodied in the pro forma

OATT and articulated in Order No.

836

E.g., EEI and MidAmerican.

Docket Nos. RM05-17-000 and RM05-25-000 - 839 -

638, we clarify that, in the event a later queued short-term request for transmission

service preempts a conditional confirmed short-term request for transmission service

based on price, then the conditional confirmed request has a right to match the price offer

of the later queued request.

837

1411. We disagree with WAPA’s proposal to limit application of the NOPR proposal to

requests for long-term transmission service. We believe the addition of price as a tie-

breaker for discounted firm point-to-point transmission service is an economically

efficient policy for both short-term and long-term firm point-to-point transmission

service. We recognize that adding another element to the reservation priority criteria

adds additional complexity. However, we believe that the efficiency gains warrant any

additional complexity in the few cases in which transmission customers bid for

transmission service.

1412. We do not agree with MISO/PJM States’ suggestion that the Commission require

point-to-point transmission customers to offer a reservation price at which they would be

willing to sell their transmission service. The transmission provider may already make

unscheduled firm transmission service available to other customers on a non-firm basis

and we have adopted proposals that we believe will encourage transmission customers to

voluntarily offer to sell firm point-to-point transmission service on the secondary market

837

See Order No. 638 at 31,442.

Docket Nos. RM05-17-000 and RM05-25-000 - 840 -

as described in section V.C.4 of this Final Rule. As a result, we see no reason to require

a firm point-to-point customer to offer its reserved capacity for sale.

(3) Five-Minute Window for Requests

NOPR Proposal

1413. In the NOPR, the Commission responded to comments that transmission

customers that have the financial resources to purchase software and employ staff to

continually monitor OASIS sites have an unfair advantage under a first-come, first-served

approach by seeking comment on whether any such advantage would be mitigated if all

requests submitted within a five-minute window were deemed to have been submitted

simultaneously. The Commission also sought comment on whether transmission

customers could game a five minute equivalent priority standard to request transmission

service only after another transmission customer has made a request. The Commission

further sought comment on how to allocate limited transmission capacity among

equivalent priority requests of equal duration, in the event a five minute equivalent

priority standard is adopted.

Comments

1414. Many of the commenters in the West support the proposal to treat transmission

requests submitted within some specified period of time as submitted simultaneously.

Supporters of a time window within which all requests would be deemed to have been

submitted simultaneously argue that the proposal would give transmission customers who

are less sophisticated and have fewer financial resources equal access to transmission

Docket Nos. RM05-17-000 and RM05-25-000 - 841 -

service.

838

Other supporters argue that such a time window would be particularly

appropriate in circumstances when a tariff calls for requests to be submitted “no earlier

than” a specific deadline.

839

In its reply comments, NRECA argues that a customer

attempting to plan a request under such circumstances may miss being the first in time by

a matter of seconds because its computer is slower than another customer’s computer.

1415. Supporters of the proposal suggest a number of modifications to the Commission’s

suggested five-minute window. A number of commenters suggest a window longer than

five minutes.

840

For instance, Bonneville proposes a system similar to PJM’s 30 minute

window for monthly service. On the other hand, Manitoba Hydro suggests a shorter

window and a limit on the number and size of requests, claiming this would reduce the

potential for gaming and/or anti-competitive behavior. A number of commenters also

suggest that such a system should be limited to short-term transmission service

841

and/or

should not apply to requests for transmission service submitted close to the hour that

service commences.

842

In its reply comments, PNM-TNMP asserts that, if the

Commission implements a five-minute window policy, then the policy should not be

838

E.g., Bonneville and Santa Clara.

839

E.g., TDU Systems and NRECA.

840

E.g., Bonneville and CREPC.

841

E.g., Bonneville and Nevada Companies.

842

E.g., Bonneville and NRECA.

Docket Nos. RM05-17-000 and RM05-25-000 - 842 -

limited to long-term transactions. In its reply comments, NRECA argues that requests

submitted within a five-minute window should not be publicly available until the window

has closed in order to prevent competitors from requesting the same service simply to

disrupt the transmission service procurement process. Similarly, Bonneville suggests that

the reservation process should be conducted like a blind auction, so that requests are not

visible on OASIS until the window closes.

1416. Many of the large power marketers and transmission providers in the East oppose

the notion of a submittal window. Opponents of a time window within which all requests

would be deemed to have been submitted simultaneously suggest that the proposal is an

unnecessary complication and may actually be counterproductive to the Commission’s

ultimate goal due to issues regarding how transmission service would be allocated among

simultaneous requests.

843

EEI notes that there is no limit on how far in advance a

transmission customer may submit requests for firm transmission service, so the

likelihood that any two requests are submitted within the same five minute period is low.

Powerex argues that the simplicity of the first-come, first served approach limits the

number of disputes. In its reply comments, Powerex argues that none of the commenters

that favor a five-minute window addressed the operational problems that such a proposal

would generate.

843

E.g., EEI, MidAmerican, Ameren, Constellation, Entergy, NorthWestern,

PNM-TNMP, WAPA, Powerex, and Indianapolis Power Reply.

Docket Nos. RM05-17-000 and RM05-25-000 - 843 -

1417. Some commenters argue that a pro rata

allocation of simultaneous requests of

equal duration will result in all transmission customers acquiring less transmission

service than they need to complete their wholesale transactions.

844

As a result, these

commenters suggest that the need to provide transmission customers with usable

quantities of transmission service will necessarily lead to developing an allocation

protocol in addition to allocating based on time submitted and duration of request.

845

Powerex argues that any system that creates a time window within which all requests

would be deemed to have been submitted simultaneously will lead transmission

customers to inflate the quantity of service they request in order to get quantity of service

they actually desire. Other commenters make suggestions regarding the manner by

which transmission service should be allocated among simultaneously submitted

requests. Bonneville believes that each transmission provider should develop an

allocation method appropriate to its system. CREPC suggests that price be used as a

secondary tie-breaker after duration. TDU Systems argue that using duration as a tie-

breaker for simultaneous requests could discriminate against purchased power contracts

that are designated as network resources.

844

E.g., Powerex and TranServ.

845

Id.

Docket Nos. RM05-17-000 and RM05-25-000 - 844 -

Commission Determination

1418. Based on the comments received, it appears that the desire for a time window

within which all requests would be deemed to have been submitted simultaneously is

largely limited to market participants in the Western Interconnection. With one

exception, we will not mandate a change to our current first-come, first-served policy to

address an issue that appears to be regional in nature. Rather, we will allow transmission

providers to propose a window within which all transmission service requests the

transmission provider receives will be deemed to have been submitted simultaneously.

Transmission providers will have discretion to determine which transmission services

will be subject to a submittal window policy. We believe the transmission provider is in

the best position to determine whether it can accommodate a submittal window for a

specific transmission service and the need for such a window.

1419. In order to ensure that transmission service is not awarded in an arbitrary fashion

and to ensure that transmission customers who are less sophisticated and have fewer

financial resources have equal access to transmission service, we will require

transmission provider who set a “no earlier than” time for request submittal to treat all

transmission service requests received within a specified period of time as having been

received simultaneously. We agree with those commenters that argue that a time window

within which all requests would be deemed to have been submitted simultaneously is

particularly appropriate in circumstances when a tariff or business practice calls for

requests to be submitted no earlier than a specific deadline. As NRECA argues, there is

Docket Nos. RM05-17-000 and RM05-25-000 - 845 -

no meaningful difference between requests for transmission service that are identical in

all respects except that one request is received by the transmission provider seconds

ahead of another request because one customer’s computer is slower than another

customer’s computer. EEI is correct that NAESB’s uniform business practices do not

limit how far in advance a transmission customer may submit requests for firm

transmission service.

846

However, a number of transmission providers have modified

their tariffs or adopted business practices that mandate that requests can be submitted no

earlier than a specific deadline.

847

In these instances, multiple requests for transmission

service can be submitted at approximately the same time. We generally agree with

Powerex’s assertion that the simplicity of the current first-come, first served approach

limits the number of disputes. However, when a transmission provider establishes a “no

earlier than” deadline, submittals that are received by the transmission provider within a

matter of seconds can not be meaningfully differentiated. A transmission provider with

such a business practice or tariff provision will be required to modify its tariff to include

846

See NAESB Business Practice Standard 001-4.13.

847

For instance, Idaho Power Company has adopted a business practice that

requests for monthly firm transmission service can not be submitted earlier than 11

months prior to operation. Portland General Electric has adopted a business practice that

Daily Firm ATC on the California-Oregon Intertie will be posted at or about 7:11 a.m.

Pacific on the day prior to operation and that requests that are submitted prior to ATC

being posted will be refused. SPP has modified its tariff so that requests for monthly firm

transmission service can not be submitted more than 90 days prior to the first day of

operation.

Docket Nos. RM05-17-000 and RM05-25-000 - 846 -

its proposed specified period of time. We will evaluate each proposal on a case-by-case

basis, as described below.

1420. We will allow transmission providers to propose the period of time within which

all requests would be deemed to have been submitted simultaneously. We believe the

transmission provider is in the best position to identify the window it can operationally

accommodate. We expect the submittal window to be open for at least five minutes

unless the transmission provider can present a compelling rationale to justify a shorter

submittal window.

1421. We agree with NRECA and Bonneville’s suggestion that requests submitted

within a specified window should not be publicly available until the window has closed

in order to prevent competitors from requesting the same service simply to disrupt the

transmission service procurement process.

1422. We will require each transmission provider that is required to, or decides to, deem

all requests submitted within a specified period as having been submitted simultaneously

to propose a method for allocating transmission capacity if sufficient capacity is not

available to meet all requests submitted within the specified time period. We agree with

Bonneville that the transmission provider is in the best position to determine an allocation

that is appropriate to its system and that can not be gamed in the manner suggested by

Powerex and TranServ. We believe that transmission providers will be able to develop

allocation methods, like the method PJM uses to allocate monthly firm point-to-point

transmission service, that address the operational issues Powerex and TranServ raise.

Docket Nos. RM05-17-000 and RM05-25-000 - 847 -

(4) Right of First Refusal and Preemption

1423. While not specifically addressed in the NOPR, a few commenters use the

Commission’s proposed introduction of hourly firm service, discussed above, to argue

that the Commission should take the opportunity to clarify or revise the right of first

refusal for short term transmission service requests.

1424. To understand commenter concerns, it is useful to note the relevant components of

the reservation and scheduling process in the pro

forma OATT. Reservations for short-

term firm point-to-point transmission service are available on a first-come, first-served

basis and are conditional based upon the length of the requested transaction as explained

further below. If the transmission system becomes oversubscribed, longer-term service

may preempt shorter term service, up to a specified period. The shorter term reservation

holder has a right of first refusal to match the longer term reservation, but such right must

be exercised within 24 hours of being notified of the competing reservation, or earlier to

comply with the scheduling deadline.

Comments

1425. Salt River argues that the time required to administer the right of first refusal –

which includes contacting customers and allowing time to exercise the right of first

refusal – is overwhelming. Salt River argues that the current OASIS business practices

do not permit adequate time to implement these rules, and the industry lacks the software

to either streamline the effort or ensure quality control. Salt River contends that for

hourly, daily, and weekly requests, the complexity and potentially unjust results of

Docket Nos. RM05-17-000 and RM05-25-000 - 848 -

administering preemption and the right of first refusal rules outweighs any potential

benefits. Accordingly, Salt River recommends revisions to the pro forma

OATT that

make the right of first refusal available only to monthly requests for service.

1426. To address the complications arising from preemption and the right of first refusal,

Duke proposes several revisions to the pro forma

OATT: only pre-confirmed requests

would trigger preemption; confirmed requests could not be displaced by longer term

requests; only monthly customers subject to preemption would be given a right of first

refusal (Salt River proposes a similar OATT revision); and, profiled requests (i.e.

requests for transmission that may have different MW values for each hour of the day,

and may even include some hours where the MW value is zero) would not be granted

priority over confirmed reservations. TranServ also asks the Commission to provide

guidance establishing the earliest and latest submission times and maximum successive

or consecutive terms of service required. TranServ contends it is unreasonable that a

request for daily firm service could be submitted years in advance and then have a right

of first refusal to match any longer-term request for service.

1427. To eliminate the potential for more complexity, TranServ requests that the

Commission eliminate the conditional nature of short-term point-to-point service under

the OATT. Whether the Commission adopts this recommendation, TranServ further

recommends that the Commission revise the timing provisions for requesting short-term

point-to-point service to reduce overlap for submission of requests that would trigger the

need for preemption. TranServ and Duke recommend a reservation or bidding process in

Docket Nos. RM05-17-000 and RM05-25-000 - 849 -

which one increment of service (monthly, weekly, daily, and hourly) is available at a

time, with each successive shorter increment of service becoming available after the

reservation or bidding window for the preceding longer increment has closed.

1428. NorthWestern requests that the Commission clarify whether the terms

“reservation” and “request” used in section 13.2 (Reservation Priority) are used

interchangeably. If they are not used interchangeably, and “reservation” is meant to be a

confirmed request, while “request” is a queued request that has not been confirmed,

NorthWestern suggests that the sentence that includes the two uses of “reservation”

creates confusion because, if both requests are confirmed, then either sufficient capacity

exists to accept both requests, or the transmission provider accepted requests that exceed

the ATC. To avoid confusion, then NorthWestern recommends that the second use of

“reservation” should be changed to “request.” If so, to avoid the suggestion that the

section is attempting to distinguish between requests that have been confirmed from those

simply queued, NorthWestern recommends that the Commission consider changing all of

the “reservation” references to “request.”

Commission Determination

1429. Based on the issues raised in comments, we find that changing the “first come,

first served” nature of the reservation process and right of first refusal process is not

warranted at this time. The “first come, first served” principle facilitates the

administration of the reservation process and benefits customers because there can be

little confusion about how to comply with it.

Docket Nos. RM05-17-000 and RM05-25-000 - 850 -

1430. The remaining concerns regarding administering the right of first refusal are

addressed below. First, when a longer-term request seeks capacity allocated to multiple

shorter term requests, the shorter-term customers should have simultaneous opportunities

to exercise the right of first refusal. Duration, pre-confirmation status, price, and time of

response would then be used to determine which of the shorter term requests will be able

to exercise the right of first refusal, consistent with the Commission’s tie breaking

provision in section 13.2(ii). Second, to minimize the potential for gaming, a preempting

longer request must be for a fixed capacity over the term of the request.

1431. We agree with NorthWestern’s assertion that the sentence in section 13.2(iii) of

the pro forma

OATT that includes the two uses of “reservation” creates confusion.

Therefore, we clarify that the terms “reservation” and “request” are not used

interchangeably; “reservation” is meant to be a confirmed request, while “request” is a

queued request that has not been confirmed. To clarify the distinction between use of the

terms “request” and “reservation” in section 13.2(iii), we will revise that section so that

the sentence “Before the conditional reservation deadline, if available transfer capability

is insufficient to satisfy all Applications, an Eligible Customer with a reservation for

shorter term service has the right of first refusal to match any longer term reservation

before losing its reservation priority” is replaced by the sentence “Before the conditional

reservation deadline, if available transfer capability is insufficient to satisfy all

Applications, an Eligible Customer with a reservation for shorter term service has the

Docket Nos. RM05-17-000 and RM05-25-000 - 851 -

right of first refusal to match any longer term request

before losing its reservation

priority.”

6. Designation of Network Resources

a. Qualification as a Network Resource

1432. Taken together, the following sections of the pro forma

OATT describe the

resources a network customer can appropriately designate as a network resource. Section

30.1 of the pro forma

OATT describes network resources as all generation owned or

purchased by the network customer designated to serve network load under the tariff.

Section 30.1 also indicates that network resources may not include resources that are

committed for sale to non-designated third-party load or otherwise cannot be called upon

to meet the network customer's network load on a noninterruptible basis. Pursuant to

section 30.7 of the pro forma

OATT, the network customer must demonstrate that it owns

or has committed to purchase generation pursuant to an executed contract in order to

designate a generating resource as a network resource. Alternatively, the network

customer may establish that execution of a contract is contingent upon the availability of

network service. Section 29.2 requires the network customer to provide the following

information about a power purchase agreement that is to serve as a new designated

network resource: source of supply, control area location, transmission arrangements and

delivery point(s) to the transmission provider's transmission system.

1433. As the Commission noted in the NOPR, a number of orders address what types of

resources meet the criteria set out in sections 30.1 and 30.7 of the pro forma

OATT. In

Docket Nos. RM05-17-000 and RM05-25-000 - 852 -

MSCG

, the Commission stated that network resources must be generating resources

owned by the network customer or purchases of noninterruptible power under executed

contracts that require the network customer to pay for the purchase.

848

In WPPI, the

Commission found that a network customer can designate as a network resource a system

purchase that is not backed by a specific generator.

849

The Commission found that

Wisconsin Public Service Corporation (WPS) had appropriately designated a power

purchase as a network resource, even though the power purchase agreement did not

require WPS to take energy around the clock and allowed WPS to convert its energy

purchase to a discounted product that could be interrupted.

850

In addition, the

Commission stated that, because the pro forma

OATT requires a power purchase to be

noninterruptible, third-party transmission arrangements to deliver the resource to the

network have to be noninterruptible as well.

851

In Illinois Power, the Commission found

that a firm purchase need not be backed by a capacity purchase to qualify as a network

resource.

852

848

Morgan Stanley Capital Group v. Illinois Power Co., 83 FERC ¶ 61,204 at

61,911-12 (1998), order on reh’g

, 93 FERC ¶ 61,081 (2000) (MSCG).

849

Wisconsin Public Power Inc. v. Wisconsin Public Service Corp., 84 FERC

¶ 61,120 at 61,650-51 (1998) (WPPI

850

Id.

851

Id. at 61,660.

852

Illinois Power Co., 102 FERC ¶ 61,257 at P 14 (2003), reh'g denied, 108 FERC

¶ 61,175 (2004) (Illinois Power

Docket Nos. RM05-17-000 and RM05-25-000 - 853 -

NOPR Proposal

1434. In the NOPR, the Commission proposed to maintain its current policy regarding

the power purchase agreements that network customers may designate as network

resources. In particular, the Commission proposed that a network customer would

continue to be able to designate resources from system purchases not linked to a specific

generating unit, provided the power purchase agreement is not interruptible for economic

reasons, does not allow the seller to fail to perform under the contract for economic

reasons, and requires the network customer to pay for the purchase. In addition, the

Commission reiterated that third-party transmission arrangements to deliver the purchase

to the network must be noninterruptible.

1435. Regarding seller’s choice contracts, the Commission explained that a power

purchase agreement that is structured so that a network customer cannot specify all of the

information required by section 29.2(v) of the pro forma

OATT cannot be designated as a

network resource. Specifically, the Commission reiterated that a request to designate a

new network resource must provide the information including the source of supply,

control area location, transmission arrangements, and delivery point(s) to the

transmission provider’s transmission system. The Commission proposed that, when

designating a system purchase as a new network resource, a network customer must

identify the resource as a system purchase as well as the control area from which the

power will originate.

Docket Nos. RM05-17-000 and RM05-25-000 - 854 -

1436. In response to suggestions that liquidated damages (LD) products should not be

designated network resources because they are interruptible for economic reasons, the

Commission proposed to clarify that network customers may not designate as network

resources those power purchase agreements that give the seller a contractual right to

compensate the buyer instead of delivering power even if the seller is able to deliver

power. For instance, the Commission proposed that a network customer may not

designate as a network resource a purchase agreement that allows the seller to interrupt

sales under the purchase agreement for reasons other than reliability, but allows the buyer

to force delivery at a higher price. In addition, the Commission proposed that a network

customer may not designate as a network resource a purchase agreement that requires a

seller to pay the buyer’s cost of replacement power when the seller chooses not to deliver

energy for economic reasons.

Comments Overview

1437. Most commenters argue that the Commission must provide further clarification

than given in the NOPR, particularly with regard to the eligibility of firm LD power

products and the information required by section 29.2(v) of the pro forma

OATT for

seller’s choice contracts. Various commenters also argue that the Commission’s

precedent on this issue is contradictory and that the Commission’s policy with respect to

designation of network resources may violate section 217 of the FPA and conflict with

state jurisdiction.

Docket Nos. RM05-17-000 and RM05-25-000 - 855 -

(1) LD Contracts

Comments

1438. Many commenters express general support for some or all of the Commission’s

clarifications in the NOPR with regard to ineligibility of resources which are interruptible

for economic reasons and/or that allow the seller to compensate the buyer instead of

delivering power even if the seller is able to deliver power.

853

However, many

commenters express concern about the clarity of the policy.

854

1439. In particular, several parties contend that it is in fact the firmness of the contract

and not the mere existence of an LD provision describing the remedies in case of a failure

to perform that determines the eligibility of a power purchase agreement to be designated

as a network resource.

855

TAPS argues that, in order to determine the firmness of a

purchase, one must look at the criteria for excusing a failure to supply. AMP-Ohio,

MISO, and NCPA also express support for this position, pointing to the Commission’s

853

E.g., Ameren, BART, Constellation, Duke, Entegra, Entergy, Morgan Stanley,

MISO, NorthWestern, Progress Energy, Sempra Global, Southern, Suez Energy NA, and

TranServ.

854

E.g., AMP-Ohio, APPA, Duke, EEI, Entergy, Fayetteville, Morgan Stanley,

NCPA, Northwest IOUs, Northwest Parties, MISO/PJM States, PGP, Pinnacle, PNM-

TNMP, Salt River, Sempra Global, Southern, TAPS, Utah Municipals, and WSPP.

855

E.g., AMP-Ohio, Northwest IOUs, NRECA Reply, PGP, Pinnacle, Sempra

Global, Strategic Energy Reply, and TAPS.

Docket Nos. RM05-17-000 and RM05-25-000 - 856 -

finding in Dynegy

856

that the inclusion of an LD provision in EEI’s Master Power

Purchase and Sale Agreement’s Firm LD product (EEI’s Firm LD Product) does not

inherently make that product less firm.

1440. Several commenters argue that, when the Commission in Dynegy

considered the

acceptability of EEI’s Firm LD Product as a designated network resource, it neglected to

consider the presence of a provision which appears to contradict its decision.

857

They

point to the Commission’s statement in Dynegy

that EEI’s Firm LD Product “does not

permit the power to be interrupted for economic reasons, or at the discretion of either

party, but only if a force majeure occurs.”

858

Some contend that the Commission’s

conclusion ignored the fact that EEI’s Firm LD Product actually allows power to be

interrupted for any

reason, including economic reasons, after which the agreement then

provides LDs as a remedy if the interruption was not due to a force majeure event.

859

Duke and EEI note that contracts under EEI’s Firm LD Product agreement or similar

agreements have become commonplace since the Commission’s Dynegy

decision and

856

Dynegy Midwest Generation, 101 FERC ¶ 61,295 (2002), reh’g dismissed,

108 FERC ¶ 61,175 (2004) (Dynegy

857

E.g., Duke, Dynegy Reply, EEI, and Southern.

858

Dynegy at P 21.

859

E.g., Duke, EEI and Southern. EEI notes that its Firm LD Product is distinct

from its “System Firm” and “Unit Firm” products in its Master Power Purchase and Sale

Agreement, each of which excuses a failure to perform only for force majeure and neither

of which permits a party to fail to perform and pay liquidated damages.

Docket Nos. RM05-17-000 and RM05-25-000 - 857 -

that clarification regarding their use as network resources is required to address industry

confusion.

1441. Several commenters disagree that the EEI Firm LD Product gives parties the right

to interrupt for any reason, including economic reasons, provided that LDs are paid by

the non-performing party.

860

Hoosier argues on reply that EEI and Southern have

misunderstood the Commission’s intent in Dynegy

. Hoosier contends that the

Commission correctly found in Dynegy

that the EEI Firm LD Product does not permit

power to be interrupted for economic reasons, or at the discretion of either party, but only

if a force majeure event occurs. Thus, Hoosier argues, the EEI Firm LD Product does not

give the seller a right

to interrupt for any reason other than force majeure, and any seller

that interrupts for economic reasons is clearly in breach of its obligations to perform

under the contract and must pay damages. Hoosier acknowledges that a seller always has

the choice of not performing its obligations and paying damages, but that is not peculiar

to the EEI Firm LD Product. Hoosier maintains that any party to any contract has the

ability

, but not the right, to breach its obligations under the contract and pay damages.

According to Hoosier, the only difference in the case of the EEI Firm LD Product is that

the parties have stipulated beforehand as to the measure of the damages required of a

seller in breach, in order to minimize litigation over damages. This stipulation, Hoosier

argues, conveys no additional substantive rights on either party.

860

E.g., Hoosier Reply, Strategic Energy Reply, and Utah Municipals.

Docket Nos. RM05-17-000 and RM05-25-000 - 858 -

1442. Several parties note that firm LD contracts account for a significant number of

currently utilized products and that disallowing these product to be designated as network

resources may create significant disruption.

861

Commenters supporting continued use of

firm LD contracts as designated network resources argue that allowing products

structured on EEI’s Firm LD Product has not created reliability problems.

862

Southern

argues that the Commission should not set criteria that would place in jeopardy an array

of products that have a firm LD dimension. Southern further states that such products are

among the most reliable in instances where market prices are very high (where LDs could

be quite substantial) and that just about any power purchase/sale contract can be

financially settled in real-time or for a given period in lieu of physical delivery during

that period. The fact that some contracts set out in advance the terms of such settlement

(so to render commerce more efficient and liquid) does not, Southern argues, render those

contracts any less qualified for designation as network resources. Thus, Southern

encourages the Commission to reconsider its revised guidance regarding the ineligibility

of contracts structured after EEI’s Firm LD Product. Utah Municipals agrees, and

similarly requests that contracts under EEI’s Firm LD Product be allowed to qualify as

network resources.

861

E.g., APPA, Hoosier Reply, NCPA, Southern, Strategic Energy Reply, and

Utah Municipals.

862

E.g., EEI, Hoosier Reply, Southern and NCPA.

Docket Nos. RM05-17-000 and RM05-25-000 - 859 -

1443. Morgan Stanley argues that the notion that firm LD contracts do not contribute as

much to resource adequacy as contracts tied to individual physical resources is

inaccurate. Morgan Stanley contends that the incentive to ensure performance is far

greater with a firm LD obligation than with unit contingent and system firm contracts.

Morgan Stanley explains that unit contingent and system firm contracts require delivery

if the unit or group of units performs and excuses delivery if they do not, while a Firm

LD obligation requires delivery so long as it is physically possible to achieve delivery,

regardless of the cost of doing so. Thus, according to Morgan Stanley, firm LD products

can enhance supply security because they are not dependent upon the performance of an

individual unit or units, but rather put the burden and opportunity on the supplier to use

multiple physical resources to meet its obligations.

1444. APPA also requests reconsideration of this issue, arguing that its members are

often presented with power purchase agreements based on EEI’s Firm LD Product and

that they are not always successful in negotiating amendments to such agreements with

suppliers. APPA argues that an LSE can use a diverse resource portfolio, including firm

LD power purchase agreements, to serve its load economically, while meeting reliability

requirements and advancing other important policy objectives (diverse fuel mix, use of

Docket Nos. RM05-17-000 and RM05-25-000 - 860 -

renewable energy, etc.

). APPA urges the Commission to allow such use if it is consistent

with the commercial practices in a region.

863

1445. NCPA also opposes forbidding firm LD products without looking more fully into

their merits and the potential safeguards that could be built into them. NCPA recognizes

that firm LD contracts raise certain issues under the pro forma

OATT and also pose

issues for planning where a specific resource is not designated, but these problems are not

significantly different from the problems of a large transmission owner designating its

entire fleet as network resources for its entire load. Rather than ban LD contracts from an

important segment of the market, several commenters suggest that the Commission

convene a separate proceeding or conference to further investigate the issue.

864

1446. Other commenters argue against allowing the designation as network resources of

contracts that permit the interruption of power sales for reasons other than reliability as

long as LDs are paid.

865

Detroit Edison argues in its reply comments that a seller’s

decision to pay the “costs of ‘cover’” under these contracts is of no value to an LSE that

lacks deliverable alternatives. Detroit Edison further claims that, contrary to Southern’s

assumption that a failure to deliver under a firm LD contract would result in substantial

863

MISO/PJM States similarly argue that whether a particular contract with LD

provisions can serve as a designated resource should be decided within the RTO

stakeholder process.

864

E.g., APPA Reply, Morgan Stanley, and NCPA.

865

E.g., Duke, Dynegy, and Detroit Edison

Reply.

Docket Nos. RM05-17-000 and RM05-25-000 - 861 -

non-delivery penalties, one would expect a supplier afforded the option to divert power to

a higher priced market that produces a net financial gain would elect to interrupt service

under the power sales contract and pay the LDs. Detroit Edison contends that purchasers

would be left hanging during periods of supply shortage when firm physical supply is

most critical.

1447. In its reply comments, Duke asserts that allowing firm LD products to be

designated as network resources would result in network customers leaning on its system.

Although it has doubts about whether the EEI Firm LD Product actually contains

language that prohibits interruptions for economic reasons, Duke would find the inclusion

of such language in purchased power agreements to provide sufficient firmness to allow

the contract to be designated as a network resource. In its reply comments, Dynegy

argues that allowing designation of firm LD products is simply inconsistent with the

existing OATT requirements that a transmission customer either own, purchase or have

rights to generation.

1448. Northwest IOUs request that the Commission clarify whether the limitations for

qualification of a network resource, such as the presence or absence of an LD clause,

would prevent a transmission provider from using such a resource for service to its

bundled native load customers. Northwest IOUs state that, if the non-rate terms and

conditions do not apply directly by requirement of the Final Rule, but only under a

comparability test where there is a comparison to network customers, then that position

should be made clear. They further note that some transmission providers have no

Docket Nos. RM05-17-000 and RM05-25-000 - 862 -

comparable network service, or no service involving generating units within the

transmission provider’s control area. Accordingly, Northwest IOUs request that the

Commission clarify whether, in those instances, the limitations for qualification of a

network resource would apply.

1449. Many commenters also argue for the eligibility of service provided under the

WSPP Service Schedule C (Schedule C) agreement.

866

In particular, WSPP argues that

its Schedule C product satisfies the Commission’s requirements for designation as a

network resource because it requires the seller to deliver power except under very limited

circumstances, such as force majeure, and that the agreement itself clearly provides that it

is a firm product. However, WSPP notes that its product, like most if not all wholesale

power sales contracts, contains a damages provision which could be characterized as an

LD provision. WSPP contends that such provision is used simply to avoid the need to

litigate damages and not to permit a seller to ignore its delivery obligations by financially

settling a firm power sale. WSPP states that it is not intended that sellers be allowed to

refuse to deliver for economic reasons. Therefore, WSPP requests clarification that its

Schedule C product is eligible for designation as a network resource, and notes the

potential for significant disruptions in the market and WSPP member sales of firm

866

E.g., APPA, EEI, Entergy, Northwest Parties, Salt River, Utah Municipals, and

WSPP.

Docket Nos. RM05-17-000 and RM05-25-000 - 863 -

products if its Schedule C product is not considered eligible for designation as a network

resource.

1450. EEI and Northwest Parties note that, in some instances, both the sellers and buyers

of the Schedule C product designate that product as a network resource, since it appears

to meet the pro forma

OATT definition of a network resource for both parties because the

agreement allows interruptions to serve native loads. If only one party is found to be able

to designate the Schedule C product as a network resource, EEI argues that the other

party would run the risk of civil penalties for making an incorrect attestation and may

also lose the transmission rights that it needs to serve its native load or network load.

Northwest Parties request specific clarification as to whether power purchased under

Schedule C from a seller with public utility or statutory obligations to its customers is to

be considered power available to meet the purchaser’s network load on a non-

interruptible basis, given that the seller may interrupt service under the power sales

contract to meet its public utility or statutory obligations. If the Commission decides that

the Schedule C transactions cannot be designated as network resources, Northwest Parties

asks the Commission to state whether such transactions would be eligible if the WSPP

service agreement requires the seller to give the purchaser advance notice of an

interruption. Salt River also asks that, if Schedule C is found to be ineligible, the

Commission identify the specific changes needed to that contract to allow for

designation.

Docket Nos. RM05-17-000 and RM05-25-000 - 864 -

1451. Beyond the eligibility of contracts with LDs to be designated as network

resources, EEI and Duke also argue that there is a conflict between the policy guidance

given in Dynegy

(that a power purchase agreement which is interruptible for reasons

other than reliability is not eligible for designation as a network resource) and the

guidance given in WPPI

867

(that a power purchase agreement which permits curtailment

to serve the seller’s native load is eligible for designation as a network resource). Duke

argues that, since the type of contracts contemplated in WPPI

are clearly interruptible for

reasons other than reliability, WPPI

should no longer be deemed valid case law in light of

the Commission’s proposed clarifications in the NOPR. Duke argues that allowing such

contracts to be designated as network resources creates reliability risks and likely permits

two entities to designate the same generation as network resources. While Duke

acknowledges that exceptions to this rule may be necessary in the Western

Interconnection, it does not support an exception for the Eastern Interconnection. EEI

argues that the conflict between the Dynegy

and WPPI standards has resulted in different

transmission providers and customers using different standards for designation of

network resources. EEI therefore asks the Commission to clarify precisely what

contracts qualify as a network resource before it implements its proposed attestation

requirement.

867

WPPI, 84 FERC at 61,652.

Docket Nos. RM05-17-000 and RM05-25-000 - 865 -

Commission Determination

1452. Many commenters seek clarification of the eligibility of power purchase

agreements with LD provision to be designated as network resources. In clarifying our

policy concerning firm LD products, we turn first to the apparent confusion surrounding

the Commission’s findings in Dynegy

. Duke, Dynegy, EEI, and Southern argue that the

Commission incorrectly found in Dynegy

that the EEI Firm LD Product could not be

interrupted for economic reasons. These parties argue that the EEI Firm LD product

actually allows power to be interrupted for any

reason, including economic reasons, after

which LDs are assessed if the interruption was not due to a force majeure event. We

disagree. As Hoosier points out, the EEI Firm LD Product does not permit power to be

interrupted for economic reasons. While any party to any contract can choose to fail to

perform, that does not convey a contractual right to fail to perform. The EEI contract

clearly obligates the supplier to provide power, except in cases of force majeure. Thus,

the contract does not allow

interruption for economic reasons. The presence of an LD

provision in the EEI Firm LD Product does not permit the seller to violate the terms of

the contract, but rather merely specifies the damages that must be paid if the seller fails to

perform under the contract. As noted by many commenters, it is the firmness of a power

purchase contract, and not simply the presence or absence of an LD provision, that

determines the eligibility of that power purchase to be designated as a network resource.

1453. We conclude, however, that the firmness of an obligation to provide under a

contract with an LD provision is informed by the particular terms of the LD provision.

Docket Nos. RM05-17-000 and RM05-25-000 - 866 -

The type of LD provision commonly seen in firm LD products, such as the EEI Firm LD

Product, obligates the supplier, in the case of interruption for reasons other than force

majeure, to make the aggrieved buyer financially whole by reimbursing them for the

additional costs, if any, of replacement power. In contrast to this “make whole” type of

LD provision, other types of LD provisions establish penalties at a fixed-dollar amount,

cap penalties at some level, or are otherwise not equivalent to a general “make whole”

type provision. Under these other types of LD provisions, suppliers only need to

compare their savings from interrupting with the specified LD penalty when deciding

whether to interrupt power sales. Because such a consideration may not take into account

the cost of replacement power, such LD provisions could lead to inefficient supplier

interruption and economic harm to the buyer.

1454. We find that a “make whole” LD provision, such as that found in the EEI Firm LD

Product and in the WSPP Schedule C agreement, does not create incentives that are

incompatible with the firmness of the overall product. “Make whole” LDs require the

seller to consider the price of the replacement power, if it is available, to its original

buyer if the seller fails to perform under the contract. There could, of course, be

situations where the supplier is still presented with a net financial gain and has an

incentive to interrupt, but those incentives would seem to be the same incentives faced by

a designated network resource that is a specific generating plant owned by the network

customer. In such an instance, the network customer may determine, from time to time,

that it is more economic to substitute power from an alternate source in order to allow the

Docket Nos. RM05-17-000 and RM05-25-000 - 867 -

originally designated resource to either shut down or to sell its output into the wholesale

market. We find no reason to create financial incentives that make purchased power

designated as a network resource financially “more firm” than owned generation.

1455. Accordingly, we find that the inclusion of a “make whole” LD provision in a

power purchase agreement does not disqualify that agreement from being designated as a

network resource. However, other types of LD provisions may create incentives that are

incompatible with the firmness of a power purchase agreement. Thus, as of the effective

date of this Final Rule, power purchase agreements designated as network resources may

only contain LD provisions that are of the “make whole” type. Conversely, power

purchase agreements containing LD provisions that provide penalties of a fixed amount,

that are capped at a fixed amount, or that otherwise do not require the seller to pay an

aggrieved buyer the full cost of replacing interrupted power, are not acceptable. Any

contract which contains an unacceptable LD provision, but otherwise qualifies for

designation as a network resource and has been properly designated as a network

resource prior to the effective date of this Final Rule, will be grandfathered only until the

earlier of (1) the expiration of the current term of the power purchase agreement or

(2) an indefinite termination

868

of the power purchase agreement as a designated network

868

As discussed below, in section V.D.6.c, termination of network resource status

may either be temporary or indefinite. A firm LD contract that does not have a “make

whole” LD provision and which is grandfathered here may continue to be temporarily

terminated in order to make third-party sales without jeopardizing its eligibility to be

redesignated after a third-party sale. However, once a network resource is indefinitely

(continued)

Docket Nos. RM05-17-000 and RM05-25-000 - 868 -

resource pursuant to section 30.3 of the pro forma

OATT. In response to the many

comments received, we confirm that the LD provisions in both the EEI Firm LD Product

and the WSPP Schedule C agreement are acceptable.

869

1456. Detroit Edison argues that a seller's obligation to pay the cost of replacement

power under firm LD contracts is of no value to an LSE that lacks deliverable

alternatives. Detroit Edison appears to assume that, as long as an LSE purchasing power

had no deliverable alternatives from which to procure power, a designated supplier would

not be liable for damages if it chose to interrupt power sales to the buyer for reasons other

than force majeure. We disagree. Detroit Edison is addressing the fairly unusual

circumstance where a power supply is interrupted, there are no available alternatives in

the market, and firm load therefore must be interrupted. We fail to see why this

circumstance, and the difficulty of calculating damages for lost load when it occurs,

provides a reason why a particular network resource (an LD contract) should not qualify

under the pro forma

OATT as a network resource.

terminated, it must comport with the requirements for LD provisions, and all other

requirements for designation of network resources, before it can be redesignated.

869

As discussed below, however, we otherwise find that the WSPP Schedule C

agreement does not comply with the requirements for designation as a network resource

because it allows for interruption for reasons other than reliability. We therefore do not

need to address requests to clarify that both the buying and selling party to a WSPP

Schedule C contract can designate network resources associated with the contract.

Docket Nos. RM05-17-000 and RM05-25-000 - 869 -

1457. We also disagree with Dynegy’s argument that allowing the designation of firm

LD products is inconsistent with the existing OATT requirement that a transmission

customer own, purchase or have rights to generation. As discussed, firm LD contracts

that meet the Commission's requirements for designation do create for the buyer a

contractual right to generation and do not contain damage provisions which make the

actual incentives under such contracts incompatible with those present in owned

generation.

1458. In response to Northwest IOUs' request, we also clarify that the presence or

absence of an LD provision does not prevent a transmission provider from using such a

resource to serve its bundled native load customers. Rather, as we explain above, it is the

type of LD provision that is controlling. A power purchase contract with a “make whole”

remedy could be used to serve native load customers.

1459. We disagree with Duke and EEI's argument that there is a conflict between the

policy guidance given in Dynegy

(that a power purchase agreement which is interruptible

for reasons other than reliability is not eligible for designation as a network resource) and

the guidance given in WPPI

(that a power purchase agreement which permits curtailment

to serve the seller's native load is eligible for designation as a network resource). We

reiterate the Commission's finding in WPPI

that a power purchase agreement properly

designated as a network resource may permit curtailment

to serve the seller's native load.

Consistent with the long-standing definition in Order No. 888, “curtailment”

Docket Nos. RM05-17-000 and RM05-25-000 - 870 -

contemplates a reduction in service as a result of system reliability conditions, not

economic reasons.

1460. Although we find that the LD provision contained in the WSPP Schedule C

agreement does not impair the firmness of that agreement, we note that the agreement

otherwise allows interruptions in generation service “to meet [the] Seller’s public utility

or statutory obligations to its customers.” Thus, the WSPP Schedule C agreement

appears to allow interruptions for reasons other than reliability and, as a result, would not

be eligible for designation as a network resource under the Dynegy

or WPPI precedent.

We find that the provision in the WSPP Schedule C agreement allowing for interruption

of generation service in order to serve native load would need to be revised to explicitly

prohibit interruptions for reasons other than reliability of service to native load in order

for that provision to meet the requirements established under Dynegy

and WPPI.

1461. Maintaining the standard for eligibility established in Dynegy

and WPPI will

further the Commission’s goals of preventing undue discrimination, promoting

comparable treatment of customers, and increasing the accuracy of ATC calculations.

However, we acknowledge that some may currently be relying on the WSPP Schedule C

agreement in designating network resources and that there may be disruption if we were

to invalidate the designations of the existing WSPP Schedule C resources. Thus, we

exercise our discretion not to invalidate existing designations of the WSPP Schedule C

agreements as a result of noncompliance with this particular requirement until the earlier

of the following: (1) the expiration of the current term of a power purchase agreement or

Docket Nos. RM05-17-000 and RM05-25-000 - 871 -

(2) redesignation of a previously designated WSPP Schedule C resource following a

period of temporary or indefinite termination pursuant to sections 30.2 and 30.3 of the

pro forma

OATT. Alternatively, parties may voluntarily reform the offending contract

terms in order to preserve their eligibility for network service.

(2) Off-System Resources

Comments

1462. Many commenters request clarification or reconsideration of the information that

is required to be specified in section 29.2(v) of the pro forma

OATT in order to designate

a seller’s choice contract or system sale as a network resource. Northwest Parties agree

with the proposal in the NOPR that system sales may be designated by providing the

control area from which the sale is made, transmission arrangements, and delivery points

to the transmission provider’s transmission system.

870

For system sales, Northwest

Parties argue that unit-specific information is not needed because such sales are, by

definition, from a variety of resources and, in any event, the resource-specific

information is typically not available to the purchaser. This is particularly true, they

argue, for sales from large hydroelectric systems, which are operated as one

interconnected unit. For purchase contracts, they argue that unit-specific information is

not needed because it is provided in the generation interconnection agreement to the

870

Northwest Parties request similar clarification for designation of purchase

contracts from one or more specified, individual resources.

Docket Nos. RM05-17-000 and RM05-25-000 - 872 -

control area where the resource is located. Northwest Parties contend that not requiring

unit-specific information for purchase of power, including purchases of system power, is

consistent with the Commission’s description in the NOPR of the requirements to

designate a network resource.

1463. Pinnacle argues that the Final Rule should recognize that the level of detail

required by section 29.2(v) may vary depending on circumstances and permit the

transmission provider to determine the level of information necessary for the evaluation

of the network resource. In some cases, a power purchase agreement may, they argue,

appropriately refer to more general information than a specific single control area or

single source of supply.

1464. In cases where a power purchase agreement is being sourced by generating units

from an external control area, Entergy contends on reply that simply identifying the

control area is sufficient for purposes of studying the deliverability of that resource.

However, in cases where the power is sourced by generating units internal to the

transmission provider’s control area, Entergy argues that identifying only the control area

does not provide sufficient information to study deliverability. In that case, Entergy

argues that the customer must provide the specific information required by section

29.2(v) of the pro forma

OATT, including the location of the specific generating units. If

such information is not available at the time of the network resource designation, Entergy

argues that the customer should still be able to designate the agreement as a network

Docket Nos. RM05-17-000 and RM05-25-000 - 873 -

resource, but that the customer would have to confirm resource deliverability prior to

actually scheduling the service.

1465. TDU Systems argue in their reply comments that specifying the control area and

the interface over which power will enter the transmission provider’s transmission system

from a designated network resource in an external control area is sufficient for purposes

of studying the deliverability of that resource. TDU Systems also argue that, for

competitive reasons, an LSE should never be required to identify the generator or the

transmission zone where the generator is located.

1466. In contrast, EEI requests that the Commission modify section 29.2(v) to clearly

state that the transmission provider has the discretion to require the network customer to

identify the location of the generator with more specificity than simply specifying the

control area in which the network resource is located, since the location will affect the

flowgate over which the energy will be transmitted. EEI argues that it is necessary to

narrow the location of the source of a power purchase to the system of a particular

transmission owner, rather than a control area. PNM-TNMP and Duke also support

requirements that network customers provide more information concerning the location

of off-system network resources and purchase agreements so that the transmission

provider can properly evaluate the impact on its system. Duke states that Duke Carolinas

are now receiving requests to designate as network resources power purchase agreements

that list the point of delivery as “the PJM control area” or “into Southern.”

Docket Nos. RM05-17-000 and RM05-25-000 - 874 -

1467. Dynegy argues in its reply comments that the Commission has never explained

how a transmission customer designating a firm LD contract as a network resource could

ever comply with section 29.2 of the pro forma

OATT, which requires specific

information about the generation resource being designated. Dynegy contends that, just

like a seller’s choice contract, a customer is not entitled to any information about

particular generating assets when entering a firm LD purchase contract such as the EEI

Firm LD Product. As a result, Dynegy states that it is unclear how a network customer

would ever be able to legitimately designate such contracts as a network resource.

1468. In order to help ensure that all network resources are in fact backed by capacity,

Dynegy argues that the Commission should require identification of more than just the

control area when designating a network resource. Dynegy argues that the Commission

should require the generation owner or trading agent for the generation to positively

verify that capacity was sold to the entity designating that particular generator as a

network resource, and that the designation is appropriate pursuant to the parties’

agreement, as is currently required in PJM.

1469. Because some regions of the country determine ATC using a flow-based

methodology and other regions use a rated path methodology, EEI argues that section

29.2(v) should be modified to permit transmission providers to require a network

customer to designate the point to which the energy is delivered and from which the

transmission provider will provide network service if it is not delivered at the generator

bus.

Docket Nos. RM05-17-000 and RM05-25-000 - 875 -

1470. Duke requests that the Commission resolve an inconsistency between the NOPR’s

statement at P 408 that “when a network customer is designating a system purchase as a

new network resource, the source information required in section 29.2(v) should identify

that the resource is a system purchase and should identify the control area from which the

power will originate,” and the statement in the very next sentence that a “power purchase

agreement that is structured so that a network customer cannot specify all of the

information required by section 29.2(v) cannot be designated as a network resource.”

Duke notes that significantly more information is required by section 29.2(v) (unit size,

VAR capability, operating restrictions, variable generating cost for redispatch

computations, etc.

) than the “control area from which the power will originate.”

1471. Morgan Stanley contends that the information required in section 29.2(v) must not

disallow designation of seller’s choice contracts as network resources. They assert that

transmission providers use security constrained economic dispatch under which the

source of supply in a contract is generally irrelevant from a planning or operational

perspective and is therefore not needed. Morgan Stanley also argues that, if the

underlying network customer’s contract permits the seller to curtail its dispatch and

substitute a source from the market, the transmission provider would never actually know

the location where a network customer’s power is coming from and, thus, it is unclear

why the specification of that source should be a requirement. Therefore, Morgan Stanley

requests that the Commission consider revising 29.2(v) to eliminate the inclusion of

Docket Nos. RM05-17-000 and RM05-25-000 - 876 -

information that is not necessary or make the provision of such information required “to

the extent practicable.”

1472. Duke replies that Morgan Stanley accurately portrays what typically happens

under seller’s choice contracts, but reaches the wrong conclusion about a remedy. Duke

argues that, if network customers are permitted to designate as network resources

contracts that may be relatively long-term, but under which the seller has no obligation to

identify the source of the power any sooner than on a day-ahead basis, then ATC may be

reserved even though there is no intent to use it. Duke also argues that allowing seller’s

choice contracts would hamper the transmission provider’s ability to plan its system. In

Duke’s view, it would be appropriate to permit a seller’s choice contract to be a

designated network resource at the time transmission service is granted for the period

such transmission service lasts, as at that point the customer will have designated a

source and sink.

1473. Fayetteville recognizes that there are problems related to modeling and reliability

in contracts for energy which do not specify particular units as sources, but argues that

these problems are exactly the same as those that exist within any vertically integrated

utility which names its generation fleet as network resources for its native load.

Commission Determination

1474. Many comments were received with respect to seller’s choice and system

purchases. Some comments refer not only to seller’s choice and system purchases, but

also to other possible off-system transactions, including sourcing from owned generation

Docket Nos. RM05-17-000 and RM05-25-000 - 877 -

located off-system. We therefore use the term “off-system resources” here to refer to all

such resources.

1475. The existing requirements in section 29.2(v) are intended to ensure that the

network customer designating resources on other transmission systems provides

sufficient information to allow the local transmission provider to determine the effect on

ATC. Conversely, network customers should not be permitted to designate off-system

resources which are so vaguely defined that the effects on ATC cannot be determined. In

light of the requests that the Commission clarify exactly what information must be

provided in order to designate network resources located off-system, and what

information required by section 29.2(v) must be posted on OASIS, we will revise section

29.2(v) of the pro forma

OATT to specify exactly what information is required.

1476. As revised by the Final Rule, section 29.2(v) of the pro forma

OATT will require

the following information to be provided with the request and posted on OASIS when

designating an off-system resource: (1) identification of the resource as an off-system

resource; (2) amount of power to which the customer has rights; (3) identification of the

control area(s) from which the power will originate; (4) delivery point(s) to the

transmission provider’s transmission system; and (5) transmission arrangements on the

external transmission system(s). Additionally, section 29.2(v) is revised to require that

the following information be provided with such designation, but such information must

be masked on OASIS to prevent the release of commercially sensitive information

including (1) any operating restrictions (periods of restricted operation, maintenance

Docket Nos. RM05-17-000 and RM05-25-000 - 878 -

schedules, minimum loading level of resource, normal operating level of resource); and,

(2) approximate variable generating cost ($/MWH) for redispatch computations.

Requests to designate off-system network resources submitted on or after the effective

date of this Final Rule must include all of the information listed above.

1477. We direct transmission providers to develop OASIS functionality to (1) allow all

of the information required for a request to designate network resources to be provided

electronically, (2) mask information about operating restrictions and generating cost on

OASIS, and (3) allow for queries of all information provided with designation requests in

accordance with section 37.6 of the Commission’s regulations.

871

As provided in

paragraph 385, we also direct transmission providers to work in conjunction with

NAESB to develop business practice standards describing procedural requirements for

submitting designations over any new OASIS functionality. Transmission providers need

not implement this new OASIS functionality and any related business practices until

NAESB develops appropriate standards. Prior to implementation of this new OASIS

functionality, any information that cannot be provided electronically may be submitted by

transmitting the information to the transmission provider by telefax or providing the

information by telephone over the transmission provider’s time recorded telephone line.

1478. Duke argues that there is an inconsistency between the following statements in P

408 of the NOPR: (1) “when a network customer is designating a system purchase as a

871

18 CFR 37.6.

Docket Nos. RM05-17-000 and RM05-25-000 - 879 -

new network resource, the source information required in section 29.2(v) should identify

that the resource is a system purchase and should identify the control area from which the

power will originate”; and (2) the statement in the very next sentence that a “power

purchase agreement that is structured so that a network customer cannot specify all of the

information required by section 29.2(v) cannot be designated as a network resource.” We

disagree. The first statement only provided guidance on what could be provided in lieu

of the source of supply

information (as required in the last bullet of section 29.2(v) of the

existing pro forma

OATT) and was not intended to excuse customers from providing all

of the relevant information for an off-system purchase other than the specific source of

supply. However, the revisions to section 29.2(v) we adopt in this Final Rule remove any

confusion.

1479. We disagree with Dynegy’s argument that no firm LD contracts would be able to

meet the requirements for designation. We note that all of the information required for

off-system resources should be available for a seller’s choice contract. Even firm LD

contracts have variable generating costs (energy cost) and may have maintenance and

other operating constraints. If no such constraints are contractually specified, or if no

such constraints are relevant to an owned generation resource being designated, then that

should be reflected in the information posted on OASIS.

1480. We reject Dynegy’s request that the Commission require additional verification by

sellers that capacity was in fact sold to an entity designating that particular generator as a

network resource and that the network resource designation is appropriate pursuant to the

Docket Nos. RM05-17-000 and RM05-25-000 - 880 -

parties’ agreement. As the Commission explained in Illinois Power

872

a firm energy

purchase need not be backed by capacity to qualify as a designated network resource.

1481. We disagree with commenters who argue that more specific information than the

control area must be provided with each request to designate system purchases or seller's

choice contracts as network resources. In particular, we disagree with EEI’s and Duke’s

argument that customers designating seller's choice contracts as network resources must

be required, on a generic basis, to identify the specific transmission system, rather than

the more general control area, in which the physical resources are located. EEI argues

that such specificity is required for transmission providers to identify the individual

flowgates over which the power will flow into their system. The existing section 29.2(v)

of the pro forma

OATT requires that customers designating network resources identify

the “delivery point(s) to the transmission provider's transmission system.” We agree with

Entergy and TDU Systems that providing both the control area in which off-system

resources are located as well as the delivery point(s) to the transmission provider's

transmission system is usually sufficiently specific to allow a transaction to be evaluated

for its effect on the ATC of the local transmission system. However, we acknowledge

Duke’s concern about receiving requests to designate as network resources purchase

agreements that list the point of delivery as only vague statements such as “the PJM

control area” or “into Southern.” If any transmission provider believes that it faces

872

102 FERC ¶ 61,257 at P 14.

Docket Nos. RM05-17-000 and RM05-25-000 - 881 -

unique circumstances that require deviations from the pro forma

OATT in order to allow

them to determine the effects of designations of network resources on ATC, it can, in a

filing pursuant to FPA section 205, propose terms and conditions that it demonstrates are

consistent with or superior to the pro forma

OATT.

1482. Because some regions of the country determine ATC using a flow-based

methodology and other regions use a rated path methodology, EEI argues that section

29.2(v) should be modified to permit transmission providers to require a network

customer to designate the point to which the energy is delivered and from which the

transmission provider will provide network service if it is not delivered at the generator

bus. It is unclear what specific changes EEI is requesting. We note that, with respect to

off-system purchases, section 29.2(v) of the pro forma

OATT already requires that the

delivery point(s) to the transmission provider’s transmission system be included in the

description of the network resource.

1483. In response to Entergy's request, we clarify that a customer may not designate as a

network resource a seller's choice power purchase agreement which is sourced by

generating units internal to the transmission provider's control area, since evaluating the

effect on ATC would be problematic. We disagree with Entergy that a customer should

be able to designate such a resource, even without specifying the location of the specific

generating units, provided that the customer's network service from those units is

contingent upon confirming resource deliverability prior to actually scheduling the

service, because such a policy would still significantly obscure the evaluation of ATC. If

Docket Nos. RM05-17-000 and RM05-25-000 - 882 -

a customer wishes to have a choice of resources that are internal to the particular

transmission provider's control area from which to dispatch power, it must designate each

of the resources as network resources.

1484. We disagree with Morgan Stanley's unsupported comments that the source of

supply in a contract is irrelevant. We find that location of resources is a critical factor to

the transmission provider’s ATC calculations and its ability to model and evaluate the

proposed network resource, regardless of whether the transmission providers use security

constrained economic dispatch.

(3) Ability to Serve Native Load

Comments

1485. Many parties contend that the Commission’s policy with regard to the

qualification of network resources affects their ability to serve native load. EEI argues

that energy purchases are an integral part of the resources many utilities use to serve their

loads, yet often such projected energy purchases are not under contract until shortly

before the power is needed. According to EEI, the requirement that a purchase contract

be executed to qualify as a network resource jeopardizes the ability of such utilities to

serve their native loads because they will not be able to reserve transmission capacity and

other users may receive all of the ATC before their contracts are executed.

1486. APPA, EEI and Nevada Companies argue that restrictions on the types of

generation and power supply arrangements that qualify for network service may violate

section 217 of the FPA. EEI notes that section 217 provides that LSEs are entitled to use

Docket Nos. RM05-17-000 and RM05-25-000 - 883 -

firm transmission rights to deliver the output of their generators or purchased energy to

meet their service obligations to their loads. In EEI’s view, section 217 requires the

Commission to exercise its authority in a manner that enables LSEs to secure firm

transmission rights on a long term basis for long term power supply arrangements made,

or ‘planned,’ to meet such needs and, therefore, a requirement that network customers

and transmission providers not reserve transmission capacity to serve their network loads

and native loads unless they either own generation or have executed contracts that specify

the source of the energy is inconsistent with section 217. APPA notes that section 217

does not distinguish among the types of power supply arrangements that an LSE must

enter into to be protected and that section 217(b)(1)(A) refers to a broad universe of

owned or contracted generation that would suffice, so long as the power supplies are for

the purpose of meeting a service obligation.

1487. Newmont Mining disagrees that the Commission’s requirements for designation of

network resources are contrary to the new FPA section 217(b)(2). Newmont Mining

argues the legislative history of section 217(b)(2) shows that it was intended essentially

to codify Order No. 888

873

and that the resource designation requirements do not deny

873

In its reply comments, Newmont Mining cites (through reference to its own

NOI reply comments) the statement in H.R. Rep No. 108-65 at 171 (2003) that “[t]his

section is intended to be consistent with the Commission’s Order No. 888,” as well as the

statement in S. Rep. No. 109-78 at 50 (2005) that section 217 “does not affect the

Commission’s authority under sections 205 and 206 [of the FPA] to ensure that rates are

just and reasonable and not unduly discriminatory or preferential.”

Docket Nos. RM05-17-000 and RM05-25-000 - 884 -

LSEs any right to use their transmission, but rather prescribe how they are to implement

that right.

1488. EEI, Nevada Companies, PNM-TNMP and South Carolina E&G

on reply also

argue that the Commission’s requirements for eligibility for designation as a network

resource may impermissibly conflict with state-mandated procurement plans. EEI and

South Carolina E&G contend that, by imposing restrictions on the ability of LSEs to

serve their native load, the Commission is indirectly asserting jurisdiction over state-

regulated procurement practices, which they further argue is prohibited under Northern

States Power Co. v. FERC.

874

1489. Nevada Companies argue that the type of contracts that the Commission has

determined to be eligible for qualification as network resources tend to be the most

expensive. They point out that state regulatory agencies might determine that other types

of contracts are more cost-effective without unnecessarily jeopardizing reliability. Even

more troubling, they argue, is the problem created when transmission providers have

peak loads that can more effectively be served by purchasing power on a short-term

period (i.e.

, less than one year). To reserve the transmission required to serve a needle

peak that can occur anytime within a four month period would require the purchase of

thousands of megawatt hours of power that Nevada Power knows it will not need,

874

176 F.3d 1090, 1096 (8th Cir. 1999), cert. denied, 528 U.S. 1182 (2000).

Docket Nos. RM05-17-000 and RM05-25-000 - 885 -

resulting in a disallowance by the Public Utility Commission of Nevada, which approves

all open positions, options and hedges for Nevada Power.

1490. Nevada Companies contend that the network designation process should not be

changed on systems where the process works reasonably well, particularly on systems

where transmission providers are required to make significant purchases of power to meet

their retail loads. Nevada Companies argue that the Commission should therefore give

transmission providers the option of instituting a reservation-based contract demand

service similar to that previously approved in Florida Power

875

1491. Newmont Mining replies that Nevada Companies proposal is not similar to the

Florida Power

proposal or other approved contract demand network service

arrangements, as those services were offered at the request of a network customer;

designed to deal with a particular circumstance of the network customer; and offered as

an option to, not as a replacement for, standard network integration services. Utah

Municipals in their reply comments agree that utilities should not be permitted to

unilaterally impose a contract demand “reservation based” methodology on its network

customers.

1492. Newmont Mining argues that Nevada Companies’ request to maintain an open

position for a portion of their resource portfolio, in accordance with their required

resource planning process, does have some basis, but that Nevada Companies’ proposal is

875

Florida Power Corp, 81 FERC ¶ 61,247 (1997) (Florida Power).

Docket Nos. RM05-17-000 and RM05-25-000 - 886 -

not the right solution. If the Commission is inclined to provide some relief to Nevada

Companies, Newmont Mining argues that such relief should come, if at all, only after an

investigation of how similar problems are handled on other systems and that such relief

should be limited. The limitations Newmont Mining suggests include, among other

things, excusing Nevada Companies from the requirement, if at all, only to the extent that

a specific open portfolio position is contained in a resource plan approved in accordance

with applicable law; requiring that the reservation be posted on OASIS; not granting a

reservation to Nevada Companies over a competing application for network service by a

potential network customer that actually has a designated network resource; and

permitting other network customers to hold similar open positions.

Commission Determination

1493. We generally disagree with arguments that the Commission's restrictions on the

designation of network resources may violate section 217 of the FPA. Congress did not

require that LSEs be able to take transmission service without limitations of any kind in

order to serve their native load, and nothing in section 217 suggests that LSEs should not

be required to comply with reasonable requirements that are necessary to prevent undue

discrimination and maintain a reliable transmission system. The conditions that have

been established for taking network transmission service are reasonable and support these

goals, and we therefore disagree that such conditions are inconsistent with the

requirements of section 217. Furthermore, as Newmont Mining points out, the legislative

history of section 217(b)(2) supports the interpretation that section 217 was intended to

Docket Nos. RM05-17-000 and RM05-25-000 - 887 -

be consistent with the Commission's authority under sections 205 and 206 of the FPA to

ensure that rates are just and reasonable and not unduly discriminatory or preferential,

under which the designation requirements in Order No. 888 were adopted.

1494. We also disagree with commenter arguments that the Commission's requirements

for eligibility for designation as a network resource impermissibly conflicts with state-

mandated procurement plans. We point out that, with the exception of some

clarifications on the types of LD provisions that are acceptable in designated firm LD

products and what information a customer designating a system purchase or a seller's

choice contract must provide, the requirements for designation of network resources are

not new. Order No. 888 has long required that contracts be executed and imposed

reasonable restrictions on the types of resources that may be designated as network

resources.

1495. To the extent that individual transmission providers have unique circumstances or

needs that justify a variation from the pro forma

OATT, those parties can request such a

variation and explain why their proposed variation is consistent with or superior to the

requirements of the pro forma

OATT in a section 205 filing. In particular, Nevada

Companies’ request for approval of a contract demand service in order to address certain

issues presented by their unique situation would properly be made in the context of a

section 205 filing requesting a deviation from the pro forma

OATT. We agree with

Newmont Mining and Utah Municipals that approved variations, if any, must be applied

Docket Nos. RM05-17-000 and RM05-25-000 - 888 -

on a comparable basis to both the transmission provider's merchant function and the other

network customers.

(4) General

Comments

1496. A number of commenters raised other general concerns regarding the designation

of network resources. TAPS requests that the Commission clarify that conditional firm

transmission service is sufficiently firm to meet the requirement that third-party

transmission arrangements to deliver a designated purchase to the network be

noninterruptible. TAPS also requests that the Commission provide for designation of

network resources within the control area on a conditional firm basis.

1497. In its reply comments, South Carolina E&G request clarification of the content

and process of making information postings in accordance with section 29.2 of the pro

forma OATT. South Carolina E&G argues that, taken literally, section 29.2 requires that

everything in an application for network service be posted. South Carolina E&G

contends, however, that the contents of an application do not fit on OASIS as currently

configured, and that making such information available on OASIS is not necessary for

the Commission’s purposes, particularly given the Commission’s representations in favor

of preserving the integrity of customer confidential information. South Carolina E&G

suggests the Commission require only the following information to be posted on OASIS:

identification of the service type as “network”; identification of the source by name of the

generator or system; identification of the sink by name of the network customer’s load;

Docket Nos. RM05-17-000 and RM05-25-000 - 889 -

identification of the point of receipt by specification of the interface at which the network

customer intends to deliver to the resource into the transmission provider's transmission

area; and identification of the point of delivery and sink.

1498. South Carolina E&G also requests clarification on how designated network

resources are to be posted. South Carolina E&G asks, for instance, whether the

Commission expects transmission providers to develop an OASIS template that network

customers can update, as necessary, for network resources to simply be posted in PDF

format, or be accomplished via the comment section of an OASIS reservation. South

Carolina E&G argues that posting via the comment section of OASIS allows for

operational ease, but provides limited transparency and includes administrative

challenges due to character limitations and formatting constraints. Alternatively, South

Carolina E&G argues, new functionality on OASIS that allows customers to post, modify

and update network resources would satisfy the Commission’s requirements, but would

involve added costs and time.

1499. TranServ seeks clarification as to the minimum term, if any, that the transmission

provider must honor for designation of new network resources. TranServ requests that

network resources be allowed to be designated for the same minimum time periods used

for firm point-to-point service, i.e.

, daily or hourly service. Conversely, South Carolina

E&G argues in its reply comments that requiring transmission providers to update their

list of designated network resources on an hourly basis is too burdensome. South

Carolina E&G requests that the Commission allow alternative methods of designating

Docket Nos. RM05-17-000 and RM05-25-000 - 890 -

network resources on a short-term basis, such as adding comments to the appropriate

comment field on either eTags or OASIS reservations.

1500. TDU Systems argue that the designation of network resources (explicit or implicit)

by some transmission providers is automatic, while network customers are required to

pay for elaborate studies of every conceivable path affected by the addition of the

resource. TDU Systems request that the Commission clarify that the process of network

resource designation should be the same for all network users.

1501. APPA, Fayetteville, NCPA, Northwest Parties, TAPS, and Wolverine request that

clarifications made to the Commission’s policy for qualification as a network resource

apply prospectively and/or that sufficient time be allowed after the adoption of the Final

Rule such that the necessary products, information systems and business practices can be

developed. Such commenters contend that the designated network resources they

currently rely upon were acquired and designated consistent with prior Commission

precedent, so that changes to the network resource criteria established in this proceeding

should not invalidate the continued use of such resources. Because there may be many

existing designated network resources that do not meet the standards that the Commission

eventually sets, Duke suggests on reply that the Commission may need to permit existing

contractual designated network resources that do not qualify under the new standard to

retain their designated status until the earlier of the expiration data of the transaction or

the expiration date of any necessary transmission service supporting that network

resource.

Docket Nos. RM05-17-000 and RM05-25-000 - 891 -

1502. In its reply comments, Dynegy disagrees with request to grandfather existing

designated network resources, and argues that the Commission’s holding in Dynegy

was

erroneous and should be remedied in its entirety, without the creation of yet another class

of grandfathered entities.

Commission Determination

1503. The Commission agrees with TAPS that firm point-to-point transmission service

provided on a conditional firm basis is sufficiently firm to be used for transmission to

import a designated network resource. Firm point-to-point transmission service provided

on a conditional firm basis meets the existing requirement that transmission arrangements

in other control areas delivering power purchases designated as network resources to the

network customer’s transmission provider must not be interruptible for economic

reasons, as explained further in section III.F of this Final Rule. With respect to TAPS’

second request for clarification to allow for designation of network resources within the

control area on a conditional-firm basis, we note that such designation of network

resources within the control area will not be allowed, as discussed further in section III.F.

1504. In response to South Carolina E&G’s request, we reiterate that not all of the

information required by section 29.2 of the pro forma

OATT for designation of a network

resource will be made publicly available on OASIS. As discussed above, information

about operating restrictions and generating cost will be masked to protect commercially

sensitive information. South Carolina E&G has also requested clarification of the

Commission’s intent with respect to how designated network resource information is

Docket Nos. RM05-17-000 and RM05-25-000 - 892 -

posted. Our existing regulations specify the view, download, and query requirements for

information posted regarding network resource designations.

876

The details of how those

informational postings are accomplished are best left to be determined as part of the

NAESB standards development process.

1505. TranServ requests that the Commission clarify the minimum term, if any, that a

transmission provider must honor for designations of new network resources. We agree

with TranServ that the minimum term should be the same as the minimum time period

used for firm point-to-point service (i.e.

, daily), unless otherwise demonstrated by the

transmission provider and approved by the Commission.

877

1506. In response to TDU Systems’ request for clarification that the process of network

resource designation should be the same for all users, we note that section 28.2 of the pro

forma OATT already provides that “[t]he Transmission Provider, on behalf of its Native

Load Customers, shall be required to designate resources and loads in the same manner

as any Network Customer under Part III of this Tariff.” We encourage parties to utilize

the Commission’s Enforcement Hotline to report suspected abused of this process.

876

See 18 CFR 37.6(a).

877

See, e.g., Entergy Services, Inc., 105 FERC ¶ 61,318 (2003), reh’g denied in

relevant part, 109 FERC ¶ 61,216 (2004).

Docket Nos. RM05-17-000 and RM05-25-000 - 893 -

b. Documentation for Network Resources

NOPR Proposal

1507. In the NOPR, the Commission noted that transmission providers are responsible

for verifying that the network customer has provided all the information required in

section 29.2, but that transmission providers are not responsible for verifying that the

generating units and power purchase agreements network customers designate as network

resources satisfy the requirements in sections 30.1 and 30.7 of the pro forma

OATT.

However, the Commission also explained that the transmission provider continues to

have the responsibility to verify that third-party transmission arrangements to deliver the

purchase to the transmission provider’s system are firm.

1508. The Commission proposed to require the transmission provider’s merchant

function as well as network customers to include a statement with each application for

network service or to designate a new network resource that attests that, for each network

resource identified in the application for service, (1) the transmission customer owns or

has committed to purchase the designated network resource, and (2) the designated

network resource comports with the requirements for designated network resources.

1509. If the network customer does not include an attestation when it confirms its

request, the Commission proposed that the transmission provider will notify the network

customer within 15 days of confirmation that its request is deficient and that, wherever

possible, the transmission provider will attempt to remedy deficiencies in the request

through informal communications with the network customer. If such efforts are

Docket Nos. RM05-17-000 and RM05-25-000 - 894 -

unsuccessful, the Commission further proposed that the status of the request on OASIS

will be changed to “retracted” and the network customer’s request will be terminated

without prejudice to the network customer submitting a new request that includes the

required attestation, after which the network customer will be assigned a new priority

consistent with the date of the new request.

1510. In the event that the transmission provider or any network customer designates a

network resource that it does not own or has not committed to purchase, or that does not

otherwise comport with the requirements for designated network resources, the

Commission proposed that it will deem the network customer to be in violation of the pro

forma OATT and will consider assessing civil penalties on a case-by-case basis

consistent with the Commission’s Policy Statement on Enforcement. The Commission

encouraged the transmission provider and other market participants to use the

Commission’s Enforcement Hotline to report instances when they believe a network

customer has designated as a network resource a resource that does not meet the criteria

for network resources.

Comments

1511. Several commenters support the overall proposed changes involving attestation

requirements, claiming the proposal should help to eliminate abuse, including the practice

of some utilities denying transmission requests in order to accommodate its merchant

Docket Nos. RM05-17-000 and RM05-25-000 - 895 -

function’s plans to engage in future short-term purchases to serve native load.

878

Entegra

explicitly supports the Commission's proposal to treat failures to comply as violations of

the pro forma

OATT subject to enforcement. Pinnacle notes that customers should make

such attestations in good faith, such that an inadvertent error or omission would not

automatically result in recourse to a legal remedy if it can be corrected without adverse

impacts.

1512. Dynegy argues in its reply comments that transmission customers who knowingly

provide false or inaccurate information in their network resource designations not only

jeopardize reliability, but are essentially engaging in theft. Dynegy argues that such

parties should be subject to the sanctions and penalties under the Market Behavior

Rule,

879

including revocation of the violator’s market-based rate authority. APPA and

TAPS argue that the new attestation requirements should be consistently applied to all

network customers, including the transmission provider’s merchant function and

affiliates.

1513. Several commenters support the Commission’s determination that transmission

providers are not required to independently verify the accuracy of an application for

878

E.g., Ameren, Entegra, Pinnacle, Public Power Council, and Southern.

879

See Investigation of Terms and Conditions of Public Utility Market-Based Rate

Authorizations, 105 FERC ¶ 61,218 (2003).

Docket Nos. RM05-17-000 and RM05-25-000 - 896 -

network service.

880

Some commenters request that the Commission clarify that

transmission providers or transmission owners can voluntarily seek information which

verifies that contractual terms meet the requirements in section 30.1 and 30.7 of the pro

forma OATT.

881

In its reply comments, Duke argues that, without the ability to request

the contracts supporting the compliance with the requirement that the designated network

resources are firm enough, the Commission may have not authority to require that the

network customer support its designation in situations where the network customer is

nonjurisdictional.

1514. Pinnacle disagrees with the NOPR proposal that transmission providers should

continue to be responsible for verifying the firmness of the network customers’

transmission arrangements on other systems. Instead, Pinnacle contends that the

transmission customer should have the obligation to ensure that their transmission

arrangements meet the requirements needed to ensure that their resources qualify as

designated network resources. In its reply comments, Detroit Edison also requests that

the Commission require proof that network customers have obtained the requisite

transmission service on external systems.

880

E.g., Ameren, EEI, Suez Energy NA, Nevada Companies, and Utah

Municipals.

881

E.g., Ameren, Duke Reply, Entergy, and Pinnacle.

Docket Nos. RM05-17-000 and RM05-25-000 - 897 -

1515. Dynegy, in its reply comments, requests that network resource information and

validity of designation be verified not only by the designating customer, but also by the

seller or owner of the generation, in order to help ensure that all network resources are in

fact backed by capacity. Entegra similarly suggests that the Commission require that

entities designating network resources make periodic OASIS postings that will permit

verification that the entity designating a generating facility as a network resource actually

has rights to power from that facility.

1516. EEI and Entergy allege that the Commission’s NOPR attestation proposal may

have unintended consequences. Some commenters contend that the gap between the

Commission’s interpretation of the qualifications of network resources and current

procurement practices creates a significant possibility that, if the Commission enforces its

policies, it could cause substantial disruptions of service to network and native loads,

reduce supply options, or expose network customers and transmission providers to

increased liability.

882

EEI asserts that this is because a significant number of network

customers and transmission providers are serving their network loads and native loads

using resources, particularly power purchase contracts, that may not meet the

Commission’s requirement for designation as network resources. Some commenters

request that the Commission engage in a comprehensive review of power purchase

882

E.g., EEI, TDU Systems, Indianapolis Power Reply, and South Carolina E&G

Reply.

Docket Nos. RM05-17-000 and RM05-25-000 - 898 -

practices before implementing its proposed attestation requirement, and apply any change

in policies only to power purchases entered into after the effective date of the Final Rule

and after the industry has had time to develop new products that meet the Commission’s

requirements.

883

1517. Entegra replies that the expressed concern about the attestation requirement by

EEI is puzzling and troubling, because the NOPR did not propose to change the current

requirements of the pro forma

OATT regarding the qualification of network resources.

Entegra argues that the widespread non-compliance alleged by EEI makes adoption of an

attestation requirement more important and that EEI’s allegations may, at most, suggest

that the Commission consider some sort of amnesty for network customers and

transmission providers willing to self-report and commit to full compliance with the

network resource rules going forward.

1518. To ensure that network customers can submit requests for new network service

without a final, executed contract, Entergy requests that an attestation to designate a new

network resource should not be required until the service request is confirmed. If the

request is pre-confirmed, Entergy suggests that the attestation should be provided at the

time the request is submitted.

1519. SPP requests that the Commission not require it to police the additional

restrictions on the designation of network resources proposed in the NOPR. SPP states

883

E.g., EEI and Indianapolis Power Reply.

Docket Nos. RM05-17-000 and RM05-25-000 - 899 -

that it has neither the data nor the personnel necessary to perform this function and that

the Commission should rely on network customer verification, subject to Commission

audits. TranServ suggests that the exact nature of how the customer would make the

newly required attestation, as well as the treatment of OASIS requests failing to provide

the required attestation, should be determined in the NAESB forum at the time when the

technical requirements for processing network service requests on OASIS are established.

1520. Several commenters request that the Commission amend section 30.2 of the

pro forma

OATT to require network customers that designate network resources in an

external control area also provide a certification from that control area’s administrator

that the resource being designated is not counted as a designated resource for another

load on or off of the system.

884

TDU Systems disagree, arguing on reply that the

Commission should not require these types of certifications. TDU Systems recommend,

in the alternative, that LSEs on multiple systems should not have to undesignate network

resources to serve off-system load, which would eliminate the need for such control area

certification for such transactions. TDU Systems also argues that, in the absence of any

evidence of abuse, the Commission should not further complicate a process that most

market participants would agree is already overly complicated and burdensome.

884

E.g., MISO, Indianapolis Power Reply, and Detroit Edison Reply.

Docket Nos. RM05-17-000 and RM05-25-000 - 900 -

Commission Determination

1521. The Commission adopts the NOPR proposal that transmission providers continue

to be responsible for verifying that third-party transmission arrangements to deliver the

purchase to the transmission provider's system are firm, but that transmission providers

are not responsible for verifying that the generating units and power purchase agreements

network customers designate as network resources satisfy the requirements in sections

30.1 and 30.7 of the pro forma

OATT. We also adopt the proposal to require both the

transmission provider’s merchant function and network customers to include a statement

with each application for network service or to designate a new network resource that

attests, for each network resource identified, that (1) the transmission customer owns or

has committed to purchase the designated network resource and (2) the designated

network resource comports with the requirements for designated network resources. The

network customer should include this attestation in the customer’s comment section of

the request when it confirms the request on OASIS.

1522. If the network customer does not include the attestation when it confirms the

request, the transmission provider must notify the network customer within 15 days of

confirmation that its request is deficient, in accordance with the procedures in section

29.2 of the pro forma

OATT. Whenever possible, the transmission provider shall attempt

to remedy deficiencies in the request through informal communications with the network

customer. If such efforts are unsuccessful, the transmission provider shall terminate the

network customer's request and change the status of the request on OASIS to “retracted.”

Docket Nos. RM05-17-000 and RM05-25-000 - 901 -

This termination shall be without prejudice to the network customer submitting a new

request that includes the required attestation. The network customer shall be assigned a

new priority consistent with the date of the new request.

1523. In the event that the transmission provider or any other network customer

designates a network resource that it does not own or has not committed to purchase or

that does not comport with the requirements for designated network resources, we will

deem the network customer to be in violation of the pro forma

OATT and will consider

assessing civil penalties on a case-by-case basis, consistent with the Commission's Policy

Statement on Enforcement.

885

We encourage the transmission provider and other market

participants to use the Commission’s Enforcement Hotline to report instances where they

believe a network resource has been designated that does not meet the Commission’s

requirements.

1524. In response to Pinnacle’s request that an inadvertent error or omission should not

automatically result in a penalty if it can be corrected without adverse impacts, we

reiterate the policy established in the Commission’s Policy Statement on Enforcement

that enforcement actions will not be imposed “automatically.” Enforcement actions are

instead considered on a case-by-case basis after consideration of a number of factors

which may result in penalties being reduced or eliminated.

886

Among the many factors to

885

See supra note 75.

886

Policy Statement on Enforcement at P 13.

Docket Nos. RM05-17-000 and RM05-25-000 - 902 -

be considered pursuant to the Policy Statement on Enforcement is whether the violation

is willful.

887

At the same time, consideration is provided for other factors that may weigh

for assessing civil penalties, even in circumstances of inadvertent violations. For

instance, the Commission considers whether the violator has a history of violations and

whether the actions were recklessly or deliberately indifferent to the results.

888

While

enforcement actions will not be automatic, and the inadvertence of a violation would be a

consideration when determining what, if any, penalty to impose, there may be some

instances where inadvertent violations would be found, after consideration as established

in the Policy Statement on Enforcement, to warrant a penalty.

1525. Dynegy also requests that transmission customers who knowingly provide false or

inaccurate information in their network resource designations be subject to the sanctions

and penalties under the Market Behavior Rules,

889

including revocation of the violator's

market-based rate authority. We reiterate that violations will be dealt with on a case-by-

case basis in accordance with the Policy Statement on Enforcement.

1526. We reject requests to allow the transmission provider to voluntarily seek

information which verifies that contractual terms meet the requirements in sections 30.1

887

Id. at P 20.

888

Id.

889

Investigation of Terms and Conditions of Public Utility Market-Based Rate

Authorizations, 105 FERC ¶ 61,218 (2003).

Docket Nos. RM05-17-000 and RM05-25-000 - 903 -

and 30.7 of the pro forma

OATT. Allowing transmission providers to verify terms and

conditions of power purchase agreements would put transmission providers in the

position of interpreting contracts and accepting or rejecting designations based on their

interpretations. We believe such authority is unnecessary in light of the new attestation

requirements and that instances of non-compliance are better handled by the

Commission’s enforcement staff in the context of audits and Enforcement Hotline

reports. This applies equally to jurisdictional and nonjurisdictional customers. Every

transmission customer must satisfy the requirements of the transmission provider’s

OATT in order to take service. The Commission thus has authority to require that all

network customers support their designations.

1527. We disagree with Pinnacle’s argument that transmission providers should not be

responsible for verifying the firmness of the network customer's transmission

arrangements on other systems. We find that having transmission providers verify

firmness of such transmission arrangements provides a significant benefit to the system

and is not unduly burdensome. The confirmation or lack thereof of service on the third-

party's system should be readily available on OASIS. If firm third-party service is not

confirmed in OASIS, the transmission provider should attempt to remedy any

information deficiency in the request through informal communications with the network

customer. If such efforts are unsuccessful, the transmission provider should find the

request to designate the network resource deficient. Because this information is available

Docket Nos. RM05-17-000 and RM05-25-000 - 904 -

on OASIS, we disagree with Detroit Edison's request that the Commission require proof

that customers have obtained requisite transmission service on external systems.

1528. We also disagree with SPP's argument that it should not be required to police the

additional restrictions on the designation of network resources, since it has neither the

data nor the personnel necessary to perform this function. The only “additional”

restrictions that the transmission provider is called upon to police is that network

customers submit the appropriate attestations when requesting designation of a network

resource, which places a particularly small burden on the transmission provider. We also

do not expect the requirement that transmission providers verify the firmness of the

network customer's transmission arrangements on other transmission systems to require

any additional data or personnel.

1529. We reject Dynegy's request that the validity of network resource designations be

verified not only by the designating customer, but also by the seller or owner of the

generation, in order to help ensure that all network resources are in fact backed by

capacity. Similarly, we deny Entegra's request that the customer be required to make

additional, periodic OASIS postings to demonstrate that it has rights to the power from a

designated resource. We find that such additional verifications are unnecessary in light

of the new attestation requirements.

1530. With regard to arguments that requiring an attestation may disrupt service, the

alleged confusion over the Commission's requirements for designation of network

resources seems primarily concerned with whether the EEI Firm LD Product and similar

Docket Nos. RM05-17-000 and RM05-25-000 - 905 -

products were eligible to be designated as network resources and whether certain

resources can be designated both to serve native load and other network customers. As

we have addressed both of these questions above, we believe that many of the concerns

about the attestation requirement are resolved. Commenters have not supported claims

that the attestation requirement will be either burdensome or that the requirement will

require substantial time to comply. As noted above, the minimal additional network

resource designation requirements impose in this Final Rule beyond the existing

requirements are not expected to be unduly burdensome. While exceptions may be

appropriate in cases of legitimate emergencies, we disagree with the implication that a

customer should be granted general flexibility to designate a network resource that

otherwise may not be eligible.

1531. In response to Entergy’s request, we agree that attestations will not be required to

be submitted until the service request is confirmed. However, if the request is pre-

confirmed, we agree that the attestation must be provided at the time the request is

submitted.

1532. In response to TranServ’s request that the exact nature of how the customer would

make an attestation should be determined in the NAESB forum, we note that the contents

and the specific information that is required to be provided with the attestation are

specified in the pro forma

OATT, and we are requiring that the attestation be submitted

through OASIS with each request to designate a new network resource. The appropriate

subject for transmission providers to coordinate with NAESB to resolve is limited to the

Docket Nos. RM05-17-000 and RM05-25-000 - 906 -

appropriate formatting of such information to be provided in OASIS. In response to

TranServ's request that NAESB should also determine the treatment of OASIS requests

where the customer fails to provide the necessary attestation, we point out that we have

already directed that such requests are to be found deficient by the transmission provider

and treated in accordance with the procedures in section 29.2 of the pro forma

OATT.

1533. We reject requests to require network customers designating network resources in

an external control area to provide certification from that control area's administrator that

the resource being designated is not counted as a designated resource for another load on

or off the system. We find that, in absence of any evidence that the Commission's new

attestation requirements will be insufficient, this requested verification appears

unnecessary.

c. Undesignation of Network Resources

1534. Section 28.2 of the pro forma

OATT requires the transmission provider, on behalf

of its native load customers, to designate resources and loads in the same manner as any

network customer under Part III of the pro forma

OATT (Network Integration

Transmission Service). The information provided by the transmission provider must be

consistent with the information it uses to calculate ATC. Section 30.3 of the pro forma

OATT previously allowed the network customer to terminate the designation of all or

part of a generating resource as a network resource at any time, but stated that the

network customer should provide notification to the transmission provider as soon as

reasonably practicable.

Docket Nos. RM05-17-000 and RM05-25-000 - 907 -

1535. In Order No. 888-B, the Commission clarified that the pro forma

OATT allows

network customers to designate network resources over shorter time periods. The

Commission indicated that a network customer that seeks to engage in firm sales from its

currently designated network resources may terminate the generating resource (or a

portion of it) as a network resource pursuant to section 30.3 of the pro forma

OATT and

request that, as set forth in section 29 of the pro forma

OATT, the same generation

resource be designated as a network resource effective with the end of its power sale.

890

NOPR Proposal

1536. In the NOPR the Commission proposed to continue to allow network customers to

“undesignate”

891

a portion of their network resources on a short-term basis to make off-

system sales. The Commission reiterated that a network customer may redesignate the

resource by making a request to designate a new network resource. Additionally, the

Commission reiterated that the transmission provider and all network customers must

designate their network resources and are prohibited from making firm third-party sales

from designated network resources. The Commission stated that, to the extent the

transmission provider or a network customer wants to make a firm sale from a network

resource, it must undesignate the resource pursuant to section 30.3 of the pro forma

890

Order No. 888-B at 62,093.

891

The general term “undesignation” refers to both temporary terminations and

indefinite terminations of network resource status, as discussed below.

Docket Nos. RM05-17-000 and RM05-25-000 - 908 -

OATT. The network customer, including the transmission provider itself, could request

to redesignate the resource by making a request to designate a new network resource

pursuant to section 30.2 of the pro forma

OATT.

1537. The Commission also sought comment on the amount of time prior to operation

that the transmission provider and other network customers should be required to

terminate a network resource to ensure that the appropriate set of network resources are

included in the ATC calculation.

(1) Overview

Comments

1538. Most commenters appear to support the Commission’s proposal to continue to

allow network customers to undesignate a portion of their network resources on a short-

term basis to make off-system sales. However, many commenters request clarification

that a temporary undesignation will not cause them to forfeit their rights to transmission

priority or ATC for any other time period. Several commenters also request that formal

undesignations not be required or that the process not be burdensome. A wide range of

comments were received in response to the Commission’s request for comments on the

amount of time prior to operation that the transmission provider and other network

customers should be required to terminate a network resource to ensure that the

appropriate set of network resources are included in the ATC calculation.

Docket Nos. RM05-17-000 and RM05-25-000 - 909 -

Commission Determination

1539. The Commission generally adopts the NOPR proposal to continue to require

network customers and the transmission provider’s merchant function to undesignate

network resources or portions thereof in order to make certain firm, third-party sales from

those resources. In particular, network customers and the transmission provider’s

merchant function may only enter into a third-party power sale from a designated

network resource if the third-party power purchase agreement allows the seller to

interrupt power sales to the third party in order to serve the designated network load.

Such interruption must be permitted without penalty, to avoid imposing financial

incentives that compete with the network resource’s obligation to serve its network load.

1540. We clarify that requests to undesignate network resources that are submitted

concurrently with a request to redesignate those network resources at a specific point in

time shall be considered temporary terminations. Conversely, requests to undesignate

network resources submitted without any concurrent request to redesignate those network

resources shall be considered a request for indefinite termination of those network

resources.

1541. We direct transmission providers to develop OASIS functionality and, working

through NAESB, business practice standards describing the procedural requirements for

submitting both temporary and indefinite terminations of network resources, to allow

network customers to provide all required information for such terminations. Such

OASIS functionality should allow for electronic submittal of the type of termination

Docket Nos. RM05-17-000 and RM05-25-000 - 910 -

(temporary or indefinite), the effective date and time of the termination, and identification

and capacity of resource(s) or portions thereof to be terminated. For temporary

terminations, such OASIS functionality should also allow for electronic submittal of

(1) effective date and time of redesignation, following the period of temporary

termination; (2) information and attestation for redesignating the network resource

following the temporary termination, in accordance with section 30.2 of the pro forma

OATT; and (3) identification of any related transmission service requests to be evaluated

concomitantly with the request for temporary termination. In response to TranServ’s

request, we clarify that the request for temporary termination of the resource and the

requests for the related transmission service identified in item (3), if any, should be

evaluated as a single request, and approved or disapproved as such. We specifically

direct transmission providers, working through NAESB, to develop business standards

describing the procedures for submitting and processing requests for concomitant

evaluations of transmission requests and temporary terminations. When processing such

requests, the evaluation of the transmission service requests identified in item (3) should

take into account the undesignation of the network resources identified in the request for

termination. However, the evaluation of the transmission service requests in item

(3) should be processed taking proper account of all competing transmission service

requests of higher priority.

1542. Consistent with the requirements for requests for designation of new network

resources, the new OASIS functionality should also allow for queries of requests to

Docket Nos. RM05-17-000 and RM05-25-000 - 911 -

undesignate and redesignate network resources. In accordance with section 37.6 of the

Commission’s regulations,

892

such requests must be able to be queried by the publicly

available information posted on OASIS.

1543. Transmission providers need not implement this new OASIS functionality and any

related business practices until NAESB develops appropriate standards. Prior to

implementation of this new OASIS functionality, requests for temporary or indefinite

terminations of network resources may be submitted by transmitting the required

information to the transmission provider by telefax or providing the information by

telephone over the transmission provider’s time recorded telephone line.

(2) Risk to ATC Rights

Comments

1544. Most commenters request clarification that a temporary undesignation of a

network resource does not constitute a forfeiture of priority followed by a new request to

designate the network resource, or otherwise put in jeopardy the ATC associated with the

designation of that resource for any period other than the period of undesignation.

893

Several commenters argue that virtually no network customers will ever make a firm

third-party sale if they are forced to reapply for transmission service after a period of

892

18 CFR 37.6.

893

E.g., Duke, EEI, Entergy, Exelon, MDEA Reply, Northwest Parties, Pinnacle,

Progress Energy, South Carolina E&G Reply, Southern, TDU Systems Reply, TranServ,

and WSPP Reply.

Docket Nos. RM05-17-000 and RM05-25-000 - 912 -

undesignation of their resource, since they would run the risk of losing the ATC

associated with the resource.

894

EEI and Entergy contend that the result of such a policy

would be that the industry would no longer be able to take advantage of the diversity of

peak loads to make firm sales and purchases, and an almost immediate shortage of firm

energy sources to serve network and native loads. Duke argues that the approach of not

compelling network customers to risk losing the ATC associated with their designated

resources beyond the period that the resource is designated would be the comparable

approach vis-à-vis point-to-point customers seeking to temporarily redirect their service.

1545. Southern argues that to treat a redesignation as an entirely new application for

network resource designation would appear to depart from existing tariff requirements

and unnecessarily limit the reliability of network customers’ service. It also argues that

such an approach would be in contravention with section 217(b)(4) of the FPA, which

directs the Commission to act in a manner that facilitates the planning and expansion of

facilities to meet the reasonable needs of LSEs to satisfy the service obligations of the

LSEs. Southern contends that the NOPR proposal would create administrative burdens

on transmission providers, potentially treat network service as an inferior product to long

term point-to-point transmission service, and introduce a substantial deterrent against

optimization of network resources by network customers.

894

E.g., Duke, EEI, Entergy, Progress Energy, South Carolina E&G Reply, and

TranServ.

Docket Nos. RM05-17-000 and RM05-25-000 - 913 -

1546. On the other hand, Great Northern initially requests that ATC not be set aside for a

former network resource in anticipation that it might be designated as a network resource

at some time in the future. In order to ensure comparable treatment for all transmission

service customers, Great Northern argues, the Commission should place new requests to

designate network resources at the end of the transmission queue, regardless of the prior

designation of those resources. Great Northern clarifies on reply that, while ATC should

not be set aside for former network resources in anticipation that it might be designated

as a network resource at some unspecified time in the future, it has no objection to setting

aside ATC to be used by a formerly designated network resource after a temporary,

specified period of undesignation such as one month or one season.

1547. NorthWestern, in its reply comments, disagrees with Great Northern’s initial

comments that new designations be placed at the end of transmission service queue

regardless of the prior designation of those resources. NorthWestern argues that such a

policy would unduly discriminate against the network customer who is paying for the use

of the entire transmission system and grant an undue preference to the point-to-point

customer. NorthWestern also argues that the proposal that ATC not be set aside for an

undesignated network resource appears to conflict with the Commission’s standard

interconnection procedures for large and small generators. Once all upgrades specified

through the interconnection process have been installed, NorthWestern contends that the

generator can be specified as a network resource by any customer, at the time of

commercial operation for the generator or at any time in the future.

Docket Nos. RM05-17-000 and RM05-25-000 - 914 -

1548. TAPS appears to support a requirement that transmission customers get back in

the queue when re-designating resources, so long as the rules apply to transmission

providers as well as network customers.

Commission Determination

1549. In response to the many requests and comments, we clarify that a request for

termination of a network resource that is concurrently paired with a request to redesignate

that resource at a specific point in time will not result in the network customer

permanently forfeiting rights to use that resource as a designated network resource. Any

change in ATC that is determined by the transmission provider to have resulted from the

temporary termination shall be posted on OASIS during this temporary period. We agree

that requiring network customers making temporary terminations to permanently forfeit

rights to use this ATC would significantly reduce or eliminate firm third-party power

sales. We emphasize, however, that a request to terminate a network resource that is not

accompanied with a request to redesignate that resource at a specific point in time is to be

considered an indefinite termination. After an indefinite termination of a resource, the

network customer has no continuing rights to the use of such resource and future requests

to designate that resource would be processed consistent with section 30.2 as a

designation of new network resource.

1550. We disagree with NorthWestern’s argument that, once upgrades specified through

the interconnection process have been installed, the generator can be specified as a

network resource by any customer, at the time of commercial operation of the generator

Docket Nos. RM05-17-000 and RM05-25-000 - 915 -

or at any time in the future. The Commission has long noted that the generator

interconnection process is separate and independent of the acquisition of transmission

service for the same generator.

895

The fact that system upgrades may be required to

interconnect a generator does not mean any network customer is entitled to the use of that

generator at all times, even in the event that the network customer indefinitely terminates

the designation of that resource. The integration of network resources with different

network customers presents different effects and flows on the transmission system that

must be evaluated by the transmission provider.

(3) Minimum Lead-Time

Comments

1551. EEI and Entergy argue that the Commission should not require transmission

providers or network customers to undesignate a network resource for a specific amount

of time prior to the commencement of an off-system sale. In many instances, EEI argues,

short-term firm power sales are made with relatively little lead time, particularly after

events such as forced outages or unusual weather conditions. EEI and PNM-TNMP

argue that requiring transmission providers or network customers to undesignate a

specific amount of time prior to an off-system sale would foreclose the possibility that

firm sales could be made with short lead times. That, EEI argues, would adversely affect

the sales market, without having any impact on ATC on the path used by the network

895

See, e.g., Order No. 2003 at P 118, 744.

Docket Nos. RM05-17-000 and RM05-25-000 - 916 -

resource because the network resource would not be undesignated. In EEI’s view,

imposing lead times on undesignations of network resources would also result in treating

network and native load customers less favorably than point-to-point customers. EEI

points out that the pro forma

OATT does not impose any minimum lead times on firm

redirects of point-to-point transmission service pursuant to section 22 of the pro forma

OATT or reassignment of transmission service pursuant to section 23 of the OATT,

despite the fact that advance notice of redirects might make the resultant ATC more

marketable.

1552. Most commenters, however, appear to support the establishment of a minimum

amount of time prior to operation that the transmission provider and other network

customers should be required to terminate a network resource to ensure that the

appropriate set of network resources are included in the ATC calculation, although they

express widely varying opinions on what period of time would be appropriate.

1553. Ameren and Pinnacle contend that the amount of time prior to operation that the

transmission provider and other network customers should be required to terminate a

network resource should be linked to the frequency of the calculation that gets

standardized in the ATC process. Pinnacle contends that, if the undesignation and

redesignation are performed on OASIS as they propose, ATC could be recalculated and

posted immediately following the undesignation or redesignation. Ameren contends that

it cannot comment further until the parameters of the ATC process are defined.

FirstEnergy states that the amount of time should be consistent with the time periods

Docket Nos. RM05-17-000 and RM05-25-000 - 917 -

required in markets, and that outside of markets, times should be established that coincide

with such markets. Southern argues that the current practice, under which a resource is

undesignated when it schedules point-to-point transmission service for an off-system

sale, provides adequate time to ensure that the appropriate set of network resources is

included in the ATC calculation.

1554. PJM notes that, under its system, a generator resource with excess capacity can

undesignate the excess resource on a “day ahead” basis. PJM believes that this is the

proper amount of time needed to ensure resource adequacy. PJM argues that a generator

should not, under any circumstance, change the designation of its resource “same day.”

1555. TranServ argues that, at a minimum, a request for undesignation should be

supplied no later than the firm scheduling deadline so that released capacity may be

acquired on a non-firm basis. If that data were required to be submitted earlier than the

scheduled deadline, TranServ suggests the transmission provider may be able to offer

incremental capacity for firm sales. TranServ requests that the Commission establish in

the pro forma

OATT some nominal timeframe for network customers to provide to the

transmission provider their planned use of designated resources to serve loads.

1556. Nevada Companies requests that, due to some system emergencies, force majeure

events, and hourly scheduling of tie-line changes, they be allowed to change

undesignation of network resources at any time to handle these types of events.

Docket Nos. RM05-17-000 and RM05-25-000 - 918 -

Commission Determination

1557. Commenters presented many alternative views in response to the Commission’s

request in the NOPR for comments on the appropriate minimum lead-time prior to

operation that the transmission provider and other network customers should be required

to terminate a network resource to ensure that the appropriate set of network resources

are included in the ATC calculation. In consideration of these comments, the

Commission finds that the appropriate requirement is that network customers not be

permitted to make firm third-party sales from any designated network resource without

(1) undesignating that resource for the period of the third-party sale pursuant to pro forma

OATT section 30.3 and (2) providing notice of such undesignation before the firm

scheduling deadline (10 a.m. the day before service commences). We find that this

requirement strikes the appropriate balance, allowing undesignated capacity to be

acquired on a non-firm basis but not creating an undue adverse effect on third-party sales.

1558. We find it unnecessary to incorporate into the pro forma

OATT provisions relaxed

rules for changing the undesignation of network resources at any time to handle system

emergencies, force majeure events, forced outages or unusual weather conditions, as

suggested by some commenters. Other procedures such as those in NERC’s standard for

Capacity & Energy Emergencies, EOP-002-2, or the possible use of capacity benefit

margin, are more appropriate to deal with legitimate system emergencies. Outside the

context of legitimate system emergencies, network customers should rely on appropriate

planning and operation, rather than relaxed rules for designation of network resources.

Docket Nos. RM05-17-000 and RM05-25-000 - 919 -

1559. We disagree with EEI’s argument that requiring a minimum lead-time will result

in treating network and native load customers less favorably than point-to-point

customers. In particular, EEI is incorrect in its statement that the OATT does not impose

any minimum lead times on firm redirects of point-to-point transmission service or

reassignments of transmission service. Firm point-to-point customers are also subject to

deadlines for scheduling redirects pursuant to section 22.2 of the pro forma

OATT.

Furthermore, we find that EEI has provided no compelling evidence to support its

argument that the adverse impacts on the market for firm energy with short lead times

justifies having no minimum lead time.

(4) General

Comments

1560. Several commenters argue that the Commission should not require network

customers or the transmission provider to make formal modifications to their

designations of network resources when they make firm sales to third parties from those

resources.

896

EEI and Southern argue that the practice of most network customers and

transmission providers in the ten years since the Commission issued Order No. 888 has

been that a network resource is undesignated for any period for which the customer

requests firm point-to-point transmission service from the generator or a third party. This

practice, EEI argues, has not resulted in any adverse impacts on reliability or on the

896

E.g., EEI, NRECA Reply, PNM-TNMP, and Southern.

Docket Nos. RM05-17-000 and RM05-25-000 - 920 -

availability of transmission service and that, to the contrary, selling energy from network

resources on a firm basis instead of a non-firm basis frees up firm transmission capacity

that otherwise would have to be reserved for the network customer. EEI and NRECA

contend that requiring formal undesignations is substantially more cumbersome for

network customers and transmission providers making off-system sales.

1561. Progress Energy and TranServ argue that network customers should not have to go

through the process of redesignating a network resource as new when the network

customer once again needs to use this resource to serve network load. TranServ argues

that such a transaction is exactly analogous to a redirect of firm point-to-point service on

a firm basis and requests clarification of whether the provider should evaluate a request to

undesignate a network resource concomitantly with the assessment of that same

customer’s point-to-point request, as is done with redirects on a firm basis.

1562. NRECA states that the undesignation requirement is too burdensome and,

therefore, the Commission should adopt a comparability requirement that would allow

network customers to utilize the practice that many public utility transmission providers

use today: i.e.

, use designated resources for firm off-system transactions or third party

uses without having to go through the designation, undesignation and redesignation

process. NRECA argues that existing scheduling procedures have allowed transmission

providers to deliver power from their designated network resources for off-system

merchant purposes reliably and should perform equally well for network customers,

provided they still pay a point-to-point charge for the “outbound” leg of a delivery to a

Docket Nos. RM05-17-000 and RM05-25-000 - 921 -

neighboring network to serve the customer’s network load on the neighboring network.

NRECA argues in its reply comments that, whatever the Commission decides to do,

comparability is the most important principle when considering the undesignation policy

and that “grandfathering” agreements which would allow transmission providers to

essentially get around this requirement would allow undue discrimination to continue.

EEI disagrees in its reply comments with NRECA’s assertion that transmission providers

currently have an advantage over network customers, arguing that the same standards

apply to the transmission provider’s merchant function and network customers when they

seek to make off-system sales from network resources.

1563. PNM-TNMP contends that the Commission has held that formal undesignation

and redesignation are not required, so long as the transmission provider treats its own

resources and the network resources of network customers comparably. PNM-TNMP

and Pinnacle further argue that to require formal undesignation and redesignation would

appear to do nothing more than impose an extra layer of administration to the

management of network resources, making power sales more difficult and potentially

reducing financial benefits to end use customers. Bonneville argues that the

Commission’s proposals regarding the use of network resources for surplus sales are

likely to raise the cost to consumers.

1564. Duke requests that the Commission clarify that any product that is not

“designatable” as a network resource by a buyer may be sold by a seller that happens to

be a network customer, without having to undesignate any network resources.

Docket Nos. RM05-17-000 and RM05-25-000 - 922 -

1565. Suez Energy NA requests that the Commission ensure that a utility cannot use

redesignation to hoard transmission capacity in order to deprive independent power

producers of access to the grid. It contends that a utility could consistently hold

transmission to serve generation that never runs for economic reasons and, the day before

power flows, redesignate that transmission to accommodate a third-party purchase,

effectively using its ability to redesignate network transmission capacity to hoard scarce

ATC. In order to prevent potential abuse, Suez Energy NA agrees with the NOPR

proposal to require transmission providers to use the same OASIS procedures to

designate and terminate network status for themselves that they apply to network

customers.

1566. If the Commission requires formal designations and undesignations, EEI asks the

Commission to clarify whether it is changing its policy that it is not necessary to modify

service agreements in such circumstances in order to avoid requiring transmission

providers to make numerous filings amending service agreements.

897

If formal

undesignations are required, EEI argues on reply that each transmission provider would

be required to submit a revised application for network service under section 29.2 of the

pro forma

OATT both at the time the resource was undesignated and at the time that

897

See Virginia Electric and Power Co., 81 FERC ¶ 61,125 at 61,111-12 (1997),

reh’g denied

, 82 FERC ¶ 61,034 (1998).

Docket Nos. RM05-17-000 and RM05-25-000 - 923 -

resource was redesignated. EEI also argues that formal undesignation would require the

execution and filing of revised network service agreements reflecting the changes.

1567. South Carolina E&G argues in its reply comments that off-system sales of firm

power are typically in the form of a slice-of-system sale. South Carolina E&G requests

that the Commission provide guidance for how to treat such a sale of power, suggesting

that the transmission provider be permitted to undesignate a slice of a system sufficient to

support the firm power sale and then, at the conclusion of the sale, redesignate that slice

of the system as a network resource.

1568. While generally supporting the Commission’s proposal to continue to allow

network customers and the transmission provider, with respect to its native load, to

undesignate network resources to allow them to make sales to third parties, some

commenters seek certain changes, consideration, or clarification by the Commission.

898

EEI, joined by TDU Systems on reply, argue that the Commission should modify its

statement that network customers should be permitted to undesignate network resources

“on a short-term basis to make off system sales.” They argue that nothing in Order No.

888, the Commission’s decisions, or the public interest requires that network resources be

undesignated only for short-term sales. They further argue that such sales need not be

“off-system.” Progress Energy argues that the Commission should only allow

transmission customers to undesignate network resources to make firm off-system sales

898

E.g., EEI, Pinnacle, and Progress Energy.

Docket Nos. RM05-17-000 and RM05-25-000 - 924 -

for a term which the transmission customer has adequate generation reserves to serve its

network load. In its view, the transmission provider also must have the authority to deny

the designation or undesignation of the network resources if the transmission provider

determines that it needs the network resources to preserve the reliability of its

transmission system or to ensure that there is sufficient transmission capability to support

the requested changes. NRECA disagrees on reply, arguing that granting transmission

providers the authority to deny undesignation requests would give them too much

discretion and the perfect opportunity to discriminate.

1569. Progress Energy agrees with the Commission that network service involves the

entire transmission provider’s system and does not involve a contract path like point-to-

point service. It also agrees that the delivery of a network resource once inside the

system does not need to be redirected. Progress Energy notes that peaking resources

have low capacity factors and, therefore, their transmission reservations are frequently

underutilized. They request that network customers be given the ability to optimize their

transmission purchases by bringing energy into the host transmission provider’s system

from other designated network resources in times when they are not using their peaking

designated resources.

1570. MDEA, Progress Energy, and Entergy request that, for reliability and economic

reasons, network customers be given the flexibility to substitute new designated network

resources without abandoning the original transmission queue position of an existing

Docket Nos. RM05-17-000 and RM05-25-000 - 925 -

designated network resource.

899

If the Commission does not change its proposal in order

to provide network customers with this flexibility, Progress Energy contends that point-

to-point service will be a superior service to network service.

1571. Entergy states that it is important for the Commission to recognize that the

undesignation of network resources can be used by network customers as a means of

allowing merchant generators the opportunity to displace existing resources in serving

network and native load. It argues that the Commission should be wary of limiting the

ability of a network customer to undesignate network resources, as any such restriction

will have broader implications than just the ability of network customers, including the

transmission provider’s wholesale merchant function, to sell that resource off-system

with point-to-point service.

1572. Entergy also requests that the Commission clarify that, while network customers

cannot redirect network service, nothing in this prohibition prevents transmission

providers from studying requests to designate new network resources as displacements of

existing network resources. It argues that preventing network customers from using

automated study functions would significantly hinder the ability of these customers to

substitute their existing long-term resources with short-term purchases of energy and

capacity from merchant generators when it is economical to do so.

899

In its reply comments, MDEA requests that any such flexibility afforded to

transmission providers also be available to network customers on a non-discriminatory

basis.

Docket Nos. RM05-17-000 and RM05-25-000 - 926 -

1573. TDU Systems argue that network customers (and transmission providers to the

extent they serve native load on other systems) should be able to schedule output on a

firm basis from network resources on one system to serve their network loads on

neighboring systems without having to designate and redesignate network resources

among the various transmission providers’ control areas. TDU Systems state this would

permit LSEs that serve across multiple systems to come closer to replicating the

economic dispatch of control area operators, significantly reducing the cost of

discharging their service obligations to the customers they serve.

1574. Xcel opposes requiring a transmission customer to undesignate a network resource

even in a situation where the resource is used only transiently to provide off-system sales,

arguing that such policy would have significant adverse consequences for customers

across the country. It points out that it is native load customers that frequently benefit

from purchase of economy energy and that, if an undesignation was required to deliver

economy energy, most such transactions likely would not occur. Xcel also argues the

NOPR concepts relating to designation of network resources and justification of economy

energy purchases are irrelevant in the context of an RTO where energy is procured and

dispatched throughout the RTO on a security constrained economic basis.

1575. EEI, joined by TDU Systems on reply, requests that the Commission clarify that

any changes to the procedures for designating and undesignating network resources apply

only to designations made after the Final Rule becomes effective, in order to avoid

substantial adverse impacts on the reliability of service to network and native loads.

Docket Nos. RM05-17-000 and RM05-25-000 - 927 -

Duke and Pinnacle request that the Commission require NAESB to develop standards

that address undesignation and redesignation and allow sufficient time for the NAESB

process and for OASIS tools to be developed and approved, prior to the implementation

of a new policy. TranServ asks that the undesignation of network resources be supported

on OASIS.

Commission Determination

1576. We disagree with commenters arguing that formal undesignations and/or

redesignations of resources used to make firm third-party sales should not be required.

The undesignation and redesignation requirements exists not only to promote reliability,

but also to prevent undue discrimination, promote comparable treatment of customers,

and increase the accuracy of ATC calculations. We find that the interest in advancing

these policy goals overrides the minimal burden and cost that submitting undesignations

and/or redesignations entails. We disagree with Xcel’s argument that most economy

energy purchases that benefit its native load customers likely will not take place if

undesignation of network resources is required prior to firm, third-party sales. First, the

requirement to undesignate network resources only applies to firm sales, while typical

non-firm economy energy transactions would not require undesignation. Second,

undesignating a network resource is not unduly burdensome, consisting only of

electronically submitting several items of information, as described above. Therefore, we

do not believe that a transaction prevented purely as a result of the requirement to

Docket Nos. RM05-17-000 and RM05-25-000 - 928 -

undesignate network resources would have provided any significant economic value had

it taken place.

1577. We find that requests to allow “informal undesignations” appear to be simply

requests to not require undesignations at all. Since the salient feature of requiring an

undesignation is that the proper account is taken of the effects on ATC, informal

undesignations, which do not take proper account of the fact that a resource is no longer a

designated network resource, appear to serve no purpose.

1578. With regard to PNM-TNMP’s argument that the Commission has held that formal

undesignation and redesignation are not required, so long as the transmission provider

treats its own resources and the network customer’s resources comparably, we believe

PNM-TNMP misunderstands our policies. We note that PNM-TNMP provides no

citation to Commission precedent to support its statement.

1579. Duke requests clarification as to whether a network customer must undesignate a

network resource in order to make a third-party sale from that resource if the third-party

sale would not itself qualify to be designated as a network resource. We reiterate the

existing requirement that designated network resources must not be committed for sale to

non-designated third-party load or include resources that otherwise cannot be called upon

to meet the network customer's network load on a noninterruptible basis. We find that a

resource is “committed for sale to a non-designated third party load” if a power purchase

agreement for the sale from that resource provides for penalties if service to the third

party is interrupted in order to serve the designated network load.

Docket Nos. RM05-17-000 and RM05-25-000 - 929 -

1580. In response to comments by EEI, NRECA, and Suez Energy NA, we reiterate that

all parties, including transmission providers serving their native loads, are subject to these

requirements for designation and undesignation of network resources. Section 28.2 of the

pro forma

OATT clearly provides that transmission providers are required to designate

resources and loads in the same manner as any network customer. We encourage parties

suspecting that transmission providers or other network customers are not conforming to

the requirements for designating or undesignating network resources to report their

concerns using the Commission’s Enforcement Hotline.

1581. EEI has requested clarification of whether the Commission is changing its policy

that transmission providers do not need to modify network service agreements when

network resources are undesignated and redesignated. We have not proposed and do not

intend to begin requiring that network customers file modified service agreements when

network resources are designated or undesignated. As we explained in Dayton Power

and Light Co.,

900

“changes in network resources may require the customer to file a

request under OASIS, but a change to the information recorded initially in the network

service agreement is not a requirement.” EEI also argues that, if formal undesignations

are required, then each transmission provider would be required to submit a revised

application for network service under section 29.2 of the pro forma

OATT, both at the

time the resource was undesignated and the time that resource was redesignated. We

900

93 FERC ¶ 61,331 at 62,128 (2000).

Docket Nos. RM05-17-000 and RM05-25-000 - 930 -

disagree. There is no requirement that a transmission provider submit a revised

application for network service every time a resource is designated or undesignated.

1582. In response to a request by South Carolina E&G, we clarify that firm third-party

sales may be made from an undesignated portion of a network customer’s network

resources (i.e.

, a “slice-of-system sale”), so long as all of the applicable requirements are

met. In particular, the network customer must submit undesignations for each portion of

each resource supporting the third-party sale. If the undesignation is temporary, then the

request must be accompanied by a request to redesignate the resource(s) on a specific

date. When the undesignation takes effect, the network customer must update the

capacities specified in its list of designated network resources posted on OASIS.

1583. We agree with EEI and TDU Systems’ comments that there should be no

minimum term for undesignations. We also agree with EEI and TDU Systems’

arguments that network customers should not be restricted to temporarily undesignating

network resources only for use in off-system sales, and clarify that network customers are

not so restricted.

1584. We agree with Progress Energy that network customers should only make firm

third-party sales when they have sufficient generation reserves to serve their loads.

However, the purpose of the pro forma

OATT is to provide nondiscriminatory

transmission access, not to enforce generation adequacy requirements.

1585. With regard to Progress Energy’s request for flexibility to evaluate potential

impacts to the transmission system related to the undesignation and redesignation of

Docket Nos. RM05-17-000 and RM05-25-000 - 931 -

network resources, we find that situations where undesignations cannot be

accommodated due to transmission constraints should be extremely rare, such as highly-

extraordinary counterflow situations. In such rare situations, the transmission provider

should attempt to remedy the situation without denying the undesignation. If it is

determined that the resource cannot be undesignated without jeopardizing reliability, then

the transmission provider may deny the request for undesignation.

1586. We share NRECA’s concern that allowing transmission providers to deny

undesignations for reliability reasons could give a direct market competitor a significant

opportunity to discriminate, but must weigh this concern against our significant interest

in preserving reliability. We point out that transmission providers denying requests for

service or changes to service because of reliability concerns must post a description of

such denials in accordance with section 37.6(e)(2) of the Commission’s regulations.

901

Again, we encourage any parties with concerns about denials of service or changes to

service by a transmission provider for reasons of reliability to report their concerns to the

Commission’s Enforcement Hotline.

1587. We deny requests by MDEA, Progress Energy, and Entergy that network

customers be given the flexibility to substitute new designated network resources without

abandoning the original transmission queue position of an existing designated network

resource. These parties seem to be requesting that a network customer be allowed to be

901

18 CFR 37.6(e)(2).

Docket Nos. RM05-17-000 and RM05-25-000 - 932 -

“first in line” to use the ATC freed up by an undesignation of a network resource, as long

as the network customer uses that ATC to designate an alternate resource. We disagree.

Granting this request would, without any apparent justification, put point-to-point

customers seeking ATC freed up by an undesignation at a disadvantage. We also

disagree that, if the Commission does not allow network customers this flexibility, point-

to-point service will be a superior service to network service. Progress Energy seems to

be arguing that the point-to-point customer’s ability to engage in a redirect affords that

customer more flexibility than the network customer. We point out that redirects of

point-to-point service on a firm basis are only on an “as-available” basis. Firm point-to-

point customers cannot redirect unless ATC is available to support such a redirect after

all higher-priority requests have been accommodated.

1588. Entergy has requested clarification that, while network customers cannot redirect

network service, nothing in this prohibition prevents transmission providers from

studying requests to designate new network resources as displacements of existing

network resources. Although Entergy’s request is unclear, we reiterate that redirects are

not allowed within the context of network service and that network customers are not

“first in line” to use ATC freed up by their undesignation of another network resource.

Such requests must be processed taking proper account of all competing transmission

service requests of higher priority.

1589. We disagree with TDU System’s argument that network customers should be able

to schedule output on a firm basis from network resources on one system to serve their

Docket Nos. RM05-17-000 and RM05-25-000 - 933 -

network loads on neighboring systems without having to designate and redesignate

network resources among the various transmission providers’ control areas. Allowing

network customers to not formally undesignate and redesignate network resources, even

only when using those resources to serve their network loads on neighboring systems,

will necessarily result in inaccurate evaluations of ATC. We reiterate that the burden

associated with undesignating and redesignating the resources is particularly light and

find that requiring network customers to make temporary undesignations when making

third-party firm sales is thus justified in light of the ATC-related benefits.

1590. Xcel argues that the concepts relating to designation of network resources are

irrelevant in the context of an RTO where energy is procured and dispatched throughout

the RTO on a security constrained economic basis. We agree that Day 2 RTOs do not

use the physical rights model contemplated under the pro forma

OATT and, hence, not all

the provisions discussed here are directly applicable to Day 2 markets. However, as we

explain in section IV.C.2, RTOs and ISOs must make the necessary filings to comply

with the Final Rule, or demonstrate that their existing tariff provisions are consistent with

or superior to the terms of the revised pro forma

OATT.

1591. We agree with parties arguing that network customers should not be required to

use the new NAESB processes and OASIS tools to be developed in response to this

section until such time as the NAESB standards and OASIS functionality have been

developed and implemented. However, once the new standards and functionality are in

place, network customers must use these new procedures to undesignate (whether

Docket Nos. RM05-17-000 and RM05-25-000 - 934 -

temporarily or as part of an indefinite termination) any network resources, regardless of

the date that those resources were originally designated.

7. Clarifications Related to Network Service

a. Secondary Network Service

1592. Section 28.4 of the existing pro forma

OATT allows a network customer to deliver

energy to its network load from non-designated network resources on an as-available

basis without additional charge, referred to as secondary network service. In Order No.

888, the Commission described such energy as non-firm economy energy purchases used

to displace firm network resources.

902

1593. The use of secondary network service to deliver purchased power when a network

customer is making off-system sales has been raised in several Commission

investigations and audits. In Idaho Power

, the Commission accepted a settlement with

Idaho Power related to Idaho Power’s incorrect use of the native load priority to access

its transmission system.

903

In Idaho Power, the utility’s wholesale merchant function

purchased power outside of Idaho Power's control area to facilitate an off-system sale and

used secondary network service to bring the purchases into Idaho Power’s control area.

904

In accepting the settlement, the Commission stated that “[i]t is axiomatic that the native

902

Order No. 888 at 31,751.

903

Idaho Power Co., 103 FERC ¶ 61,182 at P 2 (2003) (Idaho Power).

904

Id. at P 4.

Docket Nos. RM05-17-000 and RM05-25-000 - 935 -

load priority cannot be used to complete sales that are not necessary to serve native

load.”

905

In MidAmerican, the Commission issued an audit report that contained a

finding that MidAmerican’s wholesale merchant function used network service instead of

point-to-point service to deliver short-term energy purchases to its control area that were

not used to serve MidAmerican’s native load.

906

NOPR Proposal

1594. In the NOPR, the Commission proposed to clarify that a network customer may

not use secondary network service to import energy onto its system to support an off-

system sale if the purchased power does not displace the customer’s own higher cost

generation. The Commission therefore proposed to modify section 28.4 of the pro forma

OATT to state that a network customer may use secondary network service only to

deliver economy energy and to define “economy energy” as energy purchased by a

network customer that displaces the customer’s own higher cost generation for the

purpose of serving the customer’s designated network loads. The Commission further

explained that all participants engaging in purchases for resale must compete on a

comparable basis and use point-to-point service to complete all segments of a purchase

for resale off-system.

905

Id.

906

MidAmerican Energy Co., 112 FERC ¶ 61,346 at P 6 (2005).

Docket Nos. RM05-17-000 and RM05-25-000 - 936 -

(1) Overview

Comments

1595. Several commenters agree with the Commission and support the proposed

clarification regarding the use of secondary network service.

907

Alberta Intervenors state

that such a restriction ensures fair competition among network customers and preserves

the entitlement of native load customers.

1596. Other participants oppose the proposal, arguing that it is too broad and would

interfere with legitimate activity by network customers.

908

EEI points out that, if a

network customer is using all available network resources but is still purchasing energy

from non-designated network resources to meet its peak native load, the network

customer would need to rely on secondary service to transmit this purchase. In EEI’s

view, the Commission’s proposal would prevent this customer from using secondary

service for this non-economy energy, thereby interfering with its service obligations. To

avoid such cases, EEI, Pinnacle, and PGP recommend that secondary service not be

limited to economy energy only. NRECA states that the Commission’s proposed

limitation on the use of secondary service would prevent network customers from

meeting their native load obligations in cases of extreme weather and power outages.

907

E.g., Alberta Intervenors, Southern, Suez Energy NA, and TAPS.

908

E.g., EEI, Entergy, Northwest Parties, NRECA, Pinnacle, PGP, Southern, and

Xcel.

Docket Nos. RM05-17-000 and RM05-25-000 - 937 -

NRECA asks the Commission to state explicitly in section 28.4 of the pro forma

OATT

that secondary service may not be used to facilitate off-system third party sales, but rather

must be used to import power needed to serve network load economically and efficiently.

Entergy suggests the Commission abandon the limitation and specify simply that

secondary service cannot be used to serve loads other than the network or native load.

1597. Others argue that the restriction of secondary service to only economy energy

would have unintended consequences regarding the purchase of renewable resources.

Emerald, Flathead, and the Northwest Parties state that, for reasons of customer demand

or contractual obligation, network customers may be required to purchase renewable

power that generally is more expensive than traditional thermal or hydro electric

generation. These purchases could displace less expensive non-renewable resources,

resulting in the need for the network customer to make off-system sales of the non-

renewable resources. Emerald, Flathead, and Northwest Parties suggest that the

Commission revise the definition of “economy energy” to include an exception for

renewable energy. TAPS raises a similar issue, asking the Commission to clarify that

economy purchases as well as substitute resources qualify for use of secondary service.

1598. EEI argues that the proposed limitation on secondary service would require all

network customers to engage in a specific form of Commission-regulated economic

dispatch, while requiring transmission providers to evaluate each resource and become

“dispatch police.” Entergy, SPP, and PGP agree. They assert that calculating the “cost”

of power is problematic, inherently subjective and burdensome because transmission

Docket Nos. RM05-17-000 and RM05-25-000 - 938 -

providers lack the necessary knowledge to perform this analysis. EEI, Entergy, SPP, and

PGP instead suggest that the Commission conduct periodic audits of secondary service to

ensure compliance with the requirements of OATT section 28.4 rather than transmission

providers.

1599. Although Powerex supports the Commission’s restriction on the proper use of

secondary service, it also states that determining whether or not an import would qualify

as “economy energy” would be difficult. Powerex requests that the Commission

implement specific rules in advance of such transactions to resolve uncertainty. It

suggests a capacity test to prevent preferential acquisition of generation capacity, a tariff

prohibition on the use by the network customer or its energy affiliates of any export

transmission capacity made available on another intertie, and the modification of business

practices governing curtailment. In reply, Alberta Intervenors agree with Powerex’s

proposed changes to curtailment practices, but disagree with the other two elements.

Alberta Intervenors assert that the tariff prohibition causes inefficient use of ATC and

that the capacity test is not a stand-alone test and, as a result, would only be helpful as a

supplement to the “economy energy” test.

1600. Some participants raise other issues not addressed in the NOPR. South Carolina

E&G asks that the Commission clarify its policy on purchases of economy energy, as

well as provide a clear definition of the acceptable trading practices – notably parking,

hubbing, and lending – under the current pro forma

OATT. Emerald and Flathead

request the Commission to revise the definition of “network load” in section 1.24 of the

Docket Nos. RM05-17-000 and RM05-25-000 - 939 -

pro forma

OATT to allow point-to-point and network service to the same discrete point

of delivery. Morgan Stanley asks that the Commission explain why using secondary

service to make an off-system purchase while there is any off-system sale during the

same interval is improper and whether the Commission will prohibit such activity only if

the off-system purchase and sale are part of a single transaction. Finally, Xcel argues that

the concepts relating to designation of network resources are irrelevant in the context of

an RTO where energy is procured and dispatched throughout the RTO on a security

constrained economic basis.

Commission Determination

1601. In general, the Commission agrees with parties that favor an expansion of the

proper use of secondary network service. Although we affirm our finding in

MidAmerican

909

the Commission recognizes that there are instances outside the

proposed definition of economy energy that warrant the use of secondary service in order

to serve network loads reliably. The Commission therefore declines to adopt the

definition of economy energy proposed in the NOPR and, instead, will retain the existing

909

MidAmerican Energy Co., 112 FERC ¶ 61,346 at P 6 (2005) (MidAmerican).

Following an audit, the Commission found that MidAmerican’s wholesale merchant

function used network service instead of point-to-point service to deliver short-term

energy purchases to its control area that were not used to serve MidAmerican’s native

load. The Commission stressed that the use of secondary network service is not for the

purpose of serving off-system sales. Id.

at P 6. The modifications to section 28.4

adopted in this Final Rule do not alter that limitation.

Docket Nos. RM05-17-000 and RM05-25-000 - 940 -

section 28.4 that permits use of secondary network service “to deliver energy to its

Network Loads.”

1602. With respect to Powerex’s comments, we reject the requested clarifications as

Powerex has not fully supported the use of its proposed capacity test or other measures

and has not demonstrated that such test would not preclude legitimate uses of this priority

as noted in the NOPR. If parties suspect inappropriate use of secondary network service,

they may report the suspected activity to the Commission’s Enforcement Hotline or file a

compliant with the Commission pursuant to FPA section 206. Furthermore, the

Commission’s staff will continue to provide oversight of all tariff-related activities

through its enforcement program.

(2) “On an as-available basis”

1603. Section 28.4 of the existing pro forma

OATT allows a network customer to use

secondary network service to deliver energy purchases to its network load from non-

designated resources “on an as-available basis.” However, the current pro forma

OATT

does not specify how a network customer must arrange for secondary network service.

NOPR Proposal

1604. In the NOPR, the Commission proposed to modify section 28.4 of the pro forma

OATT to clarify that a network customer does not need to file an application for network

service to receive secondary service. Instead, the customer must merely request such

service on OASIS in a manner consistent with pro forma

OATT sections 18.1 and 18.2

(Procedures for Arranging Non-Firm Point-to-Point Transmission Service).

Docket Nos. RM05-17-000 and RM05-25-000 - 941 -

Comments

1605. TDU Systems request that the Commission clarify that time constraints located in

OATT section 18.3 are not applicable to secondary service. Section 18.3 provides that

requests for non-firm point-to-point service shall not be made before certain specified

periods (more than 60 days in advance for monthly service, more than 14 days in advance

for weekly service, etc

.). TDU Systems state that some of its members currently use

secondary service to access economy off-system purchases where intervening

transmission constraints preclude the designation of those resources as network resources

for long periods of time. Application of the non-firm point-to-point service request

deadlines would impair TDU Systems’ ability to rely on secondary service in those

instances since they would extend beyond the timing requirements set forth in section

18.3.

Commission Determination

1606. The Commission clarifies that secondary service must be requested in accordance

with section 18, including the timing restrictions set forth in section 18.3, of the pro

forma OATT. Secondary service is on an as-available basis, and network customers

should not be permitted to lock in such service in advance of other non-firm uses of

available transmission. Allowing lower-priority secondary service to have a scheduling

advantage over non-firm transmission would be inappropriate and would discourage the

use of non-firm transmission service, thereby minimizing the revenue credits from non-

firm transmission service that benefit all firm transmission customers.

Docket Nos. RM05-17-000 and RM05-25-000 - 942 -

(3) Redirect of Network Service

1607. The current pro forma

OATT does not include any provision to change the point

of receipt for an off-system designated network resource in a manner similar to redirect

of point-to-point service. We are aware, however, that several transmission providers

have posted business practices that allow network customers either to substitute an off-

system non-designated network resource for a designated network resource or to redirect

the point of receipt associated with an existing network resource.

NOPR Proposal

1608. The Commission proposed to clarify that network customers may not redirect

network service in a manner comparable to redirect of point-to-point service, as network

service involves no identified contract path and is, therefore, not a directable service.

Should a network customer wish to substitute one designated network resource for

another, the Commission stated that it must terminate the existing resource and designate

a new one. The Commission explained that the network customer could also request to

redesignate its original network resource by making a request to designate a new network

resource. Alternatively, a network customer could use secondary network service when it

wants to substitute a non-designated network resource for a designated network resource

on an as-available basis.

Comments

1609. MISO strongly supports the Commission’s clarification stating that network

service is not a directable service and believes that the proposal appropriately clarifies the

Docket Nos. RM05-17-000 and RM05-25-000 - 943 -

Commission’s policy on redirect service. TDU Systems and NRECA, however, believe

that the Commission should allow redirects of network service to deliver an LSE’s

resources. TDU Systems assert that redirect of network service is critical to LSEs

serving native load across multiple transmission systems because it allows the amount of

flexibility necessary to manage power supply costs. In addition, in TDU Systems’ view,

redirects have no effect on system reliability.

1610. EEI argues on reply that it is unclear why redirects of network service should be

allowed. The advantage of redirecting firm point-to-point service is that the customer

does not have to pay an additional charge for transmission service. However, both TDU

Systems and NRECA agree that network customers should pay an additional charge for

transmission service from network resources to off-system loads.

1611. Sacramento alternatively recommends that the Commission remove the ban on

off-system sales in order to maximize efficiency in allocating transmission capacity.

Occidental requests that the Commission place all transmission, including on behalf of

native load, under the OATT guidelines to ensure that service is provided in a non-

discriminatory fashion.

Commission Determination

1612. The Commission clarifies that network customers may not redirect network

service in a manner comparable to the way customers redirect point-to-point service.

Point-to-point service consists of a contract-path with a designated point of receipt and

point of delivery. Network service has no identified contract-path and is therefore not a

Docket Nos. RM05-17-000 and RM05-25-000 - 944 -

directable service. Network service instead provides for the integration of new network

resources and permits designation of another network resource, which has the same

practical effect as redirecting network service. If the customer wants to permanently

substitute one designated network resource for another, it should terminate the

designation of the existing network resource and designate a new network resource. The

customer could then simply request to redesignate its original network resource, if it so

desires, by making a request to designate a new network resource. The ability of a

network customer to also temporarily substitute one designated network resource for

another is addressed in section V.D.6.

1613. The Commission rejects Sacramento’s proposal to remove the ban on off-system

sales. Network service is not based upon making off-system sales, but rather on

integrating a network customer’s resources with its load. Transmission providers must

take point-to-point transmission service for off-system sales and network customers

should be treated comparably. The Commission also rejects Occidental’s request to place

all transmission, including on behalf of native load, under the pro forma

OATT. In Order

No. 888-A the Commission clarified that a “transmission provider is not required to ‘take

service’ under its own tariff for the transmission of power that is purchased on behalf of

bundled retail customers.”

910

However, the Commission required that transmission

providers, pursuant to section 28.2 of the pro forma

OATT, must designate network

910

Order No. 888-A at 30,216.

Docket Nos. RM05-17-000 and RM05-25-000 - 945 -

resources and network loads in the same manner as any network customer. Occidental

offers no explanation why the existing requirement of section 28.2 is not sufficient to

address its concerns.

b. Behind the Meter Generation

1614. In Order No. 888, in response to customers with load served by “behind the meter”

generation that sought to eliminate such load from their network calculation, the

Commission found that a customer may exclude a particular load at discrete points of

delivery from its load ratio share of the allocated cost of the transmission provider’s

integrated system. The Commission determined, however, that customers electing to do

so must seek alternative transmission service, such as point-to-point transmission service,

for any load that has not been designated as network load for network service.

911

Order No. 888-A, the Commission stated that it would permit a network customer to

either designate all of a discrete load as network load under the network integration

transmission service or to exclude the entirety

of a discrete load from network service and

serve such load with the customer’s behind the meter generation and/or through any

point-to-point transmission service.

912

1615. The Commission did not address the subject of behind the meter generation in the

NOPR. A few commenters nonetheless proposed revisions to the pro forma

OATT to

911

Order No. 888 at 31,736.

912

Order No. 888-A at 30,258-61.

Docket Nos. RM05-17-000 and RM05-25-000 - 946 -

require netting of a network customer’s behind the meter generation against their network

load as described in more detail below.

Comments

1616. Some commenters argue that, in order to meet the objective of eliminating

discrimination in the provision of open access transmission service, the Commission must

require comparable treatment between retail native load and network customers by

allowing network customers to net behind the meter generation against their network

load.

913

Specifically, such commenters argue that the Commission should modify the

current pricing rules for network service to allow an LSE’s load ratio share to reflect the

reduction in load caused by behind the meter generation serving retail load.

914

In support

of this position, these commenters argue that assigning transmission-related costs to

customers that do not rely on the transmission provider’s system to serve load is

inconsistent with the Commission’s cost-causation principles.

915

For example,

CAC/EPUC contends that customer generation does not cause the transmission provider

to incur costs when power is not being sold to or taken off the grid. Similarly, AMP-

913

E.g., TAPS, TDU Systems, AMP-Ohio, and CAC/EPUC.

914

TDU Systems and TAPS also cite Consumers Energy, 98 FERC ¶ 61,333 at

62,410 (2002) (requiring that a transmission provider’s retail load associated with behind

the meter generation be included in the transmission provider’s load ratio share to ensure

comparability between transmission providers and network customers in the calculation

of load ratio share).

915

E.g., AMP-Ohio, CAC/EPUC, and TAPS.

Docket Nos. RM05-17-000 and RM05-25-000 - 947 -

Ohio argues that it is inappropriate to assign a full load ratio share of transmission-related

costs to behind the meter generation customers that do not use the network to the full

extent of their load ratio shares.

916

Further, CAC/EPUC asserts that measuring the

customer’s use of the transmission system at the customer’s meter would be appropriate

as it would demonstrate that, if no power flows to the customer from the grid occur, that

customer has not used nor caused costs to be incurred by the grid for the delivery of its

energy requirements.

1617. Some commenters note that the Commission has approved PJM netting provisions

that apply to behind the meter generation used by non-retail and wholesale customers to

serve load.

917

These same commenters further observe that PJM has filed with the

Commission to expand participation in its behind the meter generation netting program to

include municipal, electric cooperatives, and electric distribution transmission customers

who take network service on the PJM system pursuant to a settlement agreement filed by

PJM on October 24, 2005 in Docket No. EL05-127-000.

918

916

Citing Occidental Chemical Corporation v. PJM Interconnection, L.L.C., and

Delmarva Power & Light Company, 102 FERC ¶ 61,275 at P 14 (2003) (“Access charges

for use of PJM’s transmission system should be allocated to network customers based on

a network customer’s actual use of PJM’s system, consistent with the principle of cost-

causation.”); PJM Interconnection, L.L.C.

, 107 FERC ¶ 61,113, at P 28 (2004).

917

E.g., AMP-Ohio, TAPS, and TDU Systems (citing PJM Interconnection,

L.L.C., 107 FERC ¶ 61,113 (2004), reh’g denied, 108 FERC ¶ 61,032 (2004) (PJM)).

918

This settlement agreement was accepted in PJM Interconnection, L.L.C.,

113 FERC ¶ 61,279 (2005).

Docket Nos. RM05-17-000 and RM05-25-000 - 948 -

1618. Further, both TAPS and AMP-Ohio argue that behind the meter generation

provides benefits to the transmission provider that should be taken into account as part of

system planning obligations. For instance, AMP-Ohio asserts that utility planning can

and should be able to take into account the ability of customers to reduce their load on the

system with behind the meter generation. TDU Systems also notes PJM’s representation

that allowing municipal and electric cooperative system participation in behind the meter

generation netting programs increased reliability and demand response opportunities on

PJM’s system.

919

Similarly, TAPS observes that PJM’s rules reserve the right to call

upon non-retail behind the meter generation under certain conditions.

Commission Determination

1619. The Commission is not persuaded to require transmission providers to allow

netting of behind the meter generation against transmission service charges to the extent

customers do not rely on the transmission system to meet their energy needs.

Commenters in this proceeding have not provided any different arguments that were not

fully considered and addressed in Order No. 888, et al

. The existing pro forma OATT

already permits transmission customers to exclude the entirety

of a discrete load from

network service and serve such load with the customer’s behind the meter generation and

through any needed point-to-point transmission service, thereby reducing the network

customer’s load ratio share. Therefore, the Commission’s existing policy already

919

PJM Interconnection, L.L.C., 113 FERC ¶ 63,024 (2005).

Docket Nos. RM05-17-000 and RM05-25-000 - 949 -

provides customers with the opportunity to reduce network service costs to the extent a

customer is not relying on the transmission system to meet its energy needs.

920

As the

Commission concluded in Order No. 888-A, transmission customers ultimately must

evaluate the financial advantages and risks and choose to use either network integration

or firm point-to-point transmission service to serve load.

921

We believe it is most

appropriate to continue to review alternative transmission provider proposals for behind

the meter generation treatment on a case-by-case basis, as the Commission did in the

PJM proceeding cited by the commenters.

8. Transmission Curtailments

1620. In the NOPR, the Commission proposed no changes to the pro forma

OATT with

respect to curtailment provisions for point-to-point service (set forth in sections 13.6 and

14.7) and network service (set forth in section 33). These provisions establish the terms

and conditions under which a transmission provider may curtail service to maintain

reliable operation of the system. Though several commenters claimed in response to the

NOI that the reasons for transmission curtailments are difficult to discern, they did not

provide sufficient detail to indicate whether that difficulty is a result of inadequate

disclosure regulations, inadequate compliance with those regulations, or some other

920

We note that EEI responds to allegations of undue discrimination in the

calculation of load ratio share costs in the OATT Definitions section of this Final Rule.

921

Order No. 888-A at 30,260-61.

Docket Nos. RM05-17-000 and RM05-25-000 - 950 -

reason. Therefore, the Commission sought further comment on whether requiring

transmission providers to post additional information would improve transparency and

the ability of customers to make use of that information. The Commission also declined

in the NOPR to propose generic penalties for improper transmission curtailments.

Comments

1621. APPA suggests that the Commission require transmission providers to produce

additional information regarding firm transmission service curtailments, including all

circumstances and events contributing to the need for such firm service curtailments,

specific services and customers curtailed (including the transmission provider’s own

retail loads), and the duration of all such curtailments. TAPS also urges the Commission

to move toward maximum transparency and require that sufficient information be

provided for a customer to evaluate whether it has been treated fairly as compared to

other users of the system including the transmission provider. TDU Systems suggests

that the Commission require investigations into the need for network upgrades when

Level 5 Transmission Loading Relief (TLR) procedures are repeatedly employed. It also

suggests that all Level 5 TLRs be posted on OASIS and filed with the Commission. EEI

agrees that providing customers with information on transmission curtailments may help

to reduce confusion and suspicion concerning curtailments and suggests the Commission

request WEQ (NAESB) to develop a more detailed template for posting information on

curtailments that will be more useful to customers.

Docket Nos. RM05-17-000 and RM05-25-000 - 951 -

1622. Southern and other commenters

922

state that sufficient information regarding

curtailments of transmission service is already available on OASIS and believe that the

existing rules requiring transmission providers to make curtailment data available on

OASIS are adequate. Nevada Companies request the Commission be very specific if it

decides to mandate additional reporting requirements in order to remove the burden of

potential confidentiality problems from the reporting entity.

1623. Powerex is concerned about inconsistent communication and curtailment

procedures. It recommends that the Commission require three additional measures

including: early notice of curtailment through the use of the “recall” function on OASIS;

a requirement to provide credits for curtailed service when non-firm point-to-point

transmission service is interrupted; and requiring pro rata

curtailments made prior to the

energy scheduling and tagging deadline (e.g.

, 20 minutes before the operating hour) to be

based on reservation rather than schedule. In its reply comments, Seattle states support of

pro rata

curtailments based on reservations. TDU Systems recommend that the

Commission require transmission providers to refund transmission charges to curtailed

customers, to discourage transmission providers from overselling their systems. On

reply, EEI and PNM-TNMP urge the Commission to reject the proposals to require

transmission providers to refund transmission service charges to curtailed customers.

They state that transmission providers are following ATC calculation procedures, but the

922

PNM-TNMP and TranServ.

Docket Nos. RM05-17-000 and RM05-25-000 - 952 -

planning process is not structured to overbuild the system to ensure that no curtailments

occur. They also argue that the rate of return permitted in existing cost of service

regulation does not account for the risk of loss of curtailment-related revenues.

Northwest IOUs request the Commission examine whether pro rata

curtailments of

transactions to relieve transmission constraints unnecessarily impose burdens on

transmission customers, because different curtailments on different paths have different

effectiveness in relieving a given transmission constraint.

1624. Manitoba Hydro notes that MISO is the only RTO in the Eastern Interconnection

that does not redispatch when constraints occur on non-market to market flows.

Manitoba Hydro therefore urges the Commission to encourage implementation of

redispatch to the fullest extent before resorting to curtailment. Seattle also supports

modifying the pro forma

OATT to require reliability redispatch. Seattle proposes that

redispatch costs should be allocated to all classes of customers, and transmission

providers’ cost recovery should be allowed through automatic adjustment clause-type

formulas to ensure all such costs are recovered. It suggests that routine maintenance

outages are resulting in curtailments, which is an indication that transmission service is

oversold. Seattle further suggests that transmission providers prepare a quarterly incident

report for redispatch events detailing circumstances resulting in the redispatch, system

status information, power transfer distribution factors, generator offers for redispatch and

other information supporting redispatch determinations, including the basis for selecting

generators called for redispatch.

Docket Nos. RM05-17-000 and RM05-25-000 - 953 -

1625. APPA, EEI and others comment that the Commission should not impose generic

penalties for improper curtailments, but treat violations on a case-by-case basis. To

ensure compliance with curtailment posting information, Southwestern Coop suggests

that the Commission adopt generic penalties for curtailment violations, claiming that

penalties for transmission provider curtailment discrimination would provide incentives

for compliance.

Commission Determination

1626. The Commission concludes that the posting of additional curtailment information

is necessary to provide transparency and allow customers to determine whether they have

been treated in the same manner as other transmission system users, including customers

of the transmission provider. A primary goal of this rulemaking is to remove

opportunities for transmission providers to unduly discriminate in favor of their own or

their affiliates’ use of the transmission system. Making transparent details concerning

transmission curtailments so that regulators and customers can verify that the

transmission provider curtailed services in accordance with its OATT is entirely

consistent with this goal. Commenters who oppose greater curtailment transparency offer

no convincing evidence to suggest that any harm or hardship of doing so outweigh the

benefits.

1627. We agree with suggestions for the posting of additional curtailment information on

OASIS and, therefore, require transmission providers, working through NAESB, to

develop a detailed template for the posting of additional information on OASIS regarding

Docket Nos. RM05-17-000 and RM05-25-000 - 954 -

firm transmission curtailments. Transmission providers need not implement this new

OASIS functionality and any related business practices until NAESB develops

appropriate standards. These postings must include all circumstances and events

contributing to the need for a firm service curtailment, specific services and customers

curtailed (including the transmission provider’s own retail loads), and the duration of the

curtailment. This information is in addition to the Commission’s existing requirements:

(1) when any transmission is curtailed or interrupted, the transmission provider must post

notice of the curtailment or interruption on OASIS, and the transmission provider must

state on OASIS the reason why the transaction could not be continued or completed; (2)

information to support any such curtailment or interruption, including the operating status

of facilities involved in the constraint or interruption, must be maintained for three years

and made available upon request to the curtailed or interrupted customer, the

Commission’s Staff, and any other person who requests it; and, (3) any offer to adjust the

operation of the transmission provider’s system to restore a curtailed or interrupted

transaction must be posted and made available to all curtailed and interrupted

transmission customers at the same time.

1628. The Commission rejects TDU Systems’ proposal to require reports filed with the

Commission regarding Level 5 TLRs or to require transmission providers to conduct

investigations into the need for network upgrades when TLR 5 procedures are repeatedly

employed. TDU Systems’ proposal is unnecessary at this time in light of our requirement

that OASIS templates for curtailment information be developed that will report

Docket Nos. RM05-17-000 and RM05-25-000 - 955 -

occurrences of all levels of TLRs. This will enable the Commission and customers to

monitor TLR patterns and frequency. Furthermore, the requirements imposed in this

Final Rule for congestion studies as part of the coordinated, open and transparent

planning requirement will allow stakeholders in the transmission provider’s planning

process to request studies of those portions of the transmission system where they have

encountered transmission problems due to frequent and recurring constraints.

1629. The Commission rejects the three proposals suggested by Powerex. First, it is not

necessary to provide early curtailment notification through the OASIS “recall” function

since the OASIS currently provides a curtailment notification function. Transmission

providers should continue to use the OASIS Schedule Details template to post

information on the scheduled uses of the transmission system and any curtailments and

interruption thereof. Second, with respect to Powerex’s request to credit customers when

their non-firm point-to-point transmission service is interrupted, we find it unnecessary to

modify the pro forma

OATT to adopt such crediting procedures, consistent with our

finding in Order No. 888-A that proper crediting would vary depending on the specific

rate design a company uses.

923

Third, we believe that pro-rating curtailments based on

923

See Order No 888-A at 30,276. In Allegheny Power System, Inc., 80 FERC

¶ 61,143 at 61,549 (1997), the Commission clarified that where a transmission provider

has not proposed an express crediting provision for the interruption of non-firm point-to-

point customers, the transmission provider must compute its bill to an interrupted non-

firm customer as if the term of service actually rendered were the term of service

reserved. In other words, if a customer with a weekly reservation was interrupted after

one day, its bill must be computed as if it had a daily reservation, and if a customer with a

(continued)

Docket Nos. RM05-17-000 and RM05-25-000 - 956 -

reservations would have the potential to impair reliability since the amount of capacity

actually curtailed using this approach would not address actual power flows and,

therefore, may be less than required to relieve the overloaded facility.

1630. The Commission also rejects TDU Systems’ recommendation to refund

transmission charges to curtailed customers as a means of disciplining instances of

improper curtailments or transmission providers’ overselling their systems. We also

reject proposals to remedy improper curtailments through refunds of transmission charges

to curtailed customers or imposing generic penalties. Rather, the Commission believes

that addressing allegations of inappropriate curtailment practices or transmission

providers overselling their transmission system are more effectively administered by the

Commission on a case-by-case basis.

1631. With respect to the proposal to require redispatch to be performed to the fullest

extent prior to curtailments, Manitoba Hydro itself notes that the proposal is intended to

address curtailment and redispatch practices unique to MISO. Therefore we conclude

that Manitoba Hydro’s concerns are best addressed on a case specific basis.

1632. Regarding Seattle’s proposal to require what it characterizes as “reliability

redispatch” to benefit and be paid by all customer classes, we note that this proposal

would require expansion of the network service “reliability redispatch” provisions to

daily reservation was interrupted after ten hours, its bill must be computed using the

hourly rate applied to ten hours of service.

Docket Nos. RM05-17-000 and RM05-25-000 - 957 -

apply to point-to-point service as well. The network service “reliability redispatch”

provisions in pro forma

OATT sections 33.2 and 33.3 were established in Order No. 888

to ensure comparable reliable service to network customers as the service that the

transmission provider provides to its bundled retail load. These redispatch procedures

further provide for redispatch of not just the transmission provider's own resources, but

all network resources, including those of network customers, when required to maintain

the reliability of the system and avoid the need for curtailments. Seattle has not

demonstrated that its proposal to extend “reliability redispatch” for point-to-point service

is required to ensure comparable, not unduly discriminatory transmission service and has

not addressed why network customer resources should be redispatched for the benefit of

point-to-point customer. Accordingly, we decline to adopt Seattle’s proposal. We

discuss redispatch issues more broadly in section V.D.1 of this Final Rule.

9. Standardization of Rules and Practices

a. Business Practices

1633. In Order No. 888, the Commission required each public utility that owns, controls,

or operates facilities used for transmitting electricity in interstate commerce to file,

pursuant to section 205 of the FPA, a pro forma

OATT under which it would provide

open access transmission services. However, certain rules, standards, and practices

governing the provision of transmission service (e.g.

, public utility business practices) are

not reflected in the pro forma

OATT. Only when a public utility adopts a rule, standard,

or practice that significantly affects its rates and services has the Commission required it

Docket Nos. RM05-17-000 and RM05-25-000 - 958 -

to make a filing pursuant to FPA section 205 to amend its OATT.

924

The Commission

has applied this policy using a “rule of reason” test.

925

NOPR Proposal

1634. In the NOPR, the Commission proposed not to modify its existing policy

regarding the inclusion of rules, standards and practices in a transmission provider’s

OATTs. The Commission expressed concern that requiring transmission providers to

include all of their rules, standards, and practices in their OATTs could decrease a

transmission provider’s flexibility to change business practices and respond to the

requests of its customers. The Commission also expressed a belief that requiring

transmission providers to file all of their rules, standards, and practices in their OATTs

would be impractical and potentially administratively burdensome.

1635. The NOPR further noted that there is broad consensus that rules, standards, and

practices not required to be included in a transmission provider’s pro forma

OATT

should be posted on the transmission provider’s OASIS. The Commission agreed and

proposed to require transmission providers to post on OASIS all of their rules, standards,

924

E.g., Cleveland v. FERC, 773 F.2d 1368, 1376 (D.C. Cir. 1985).

925

See, e.g., Public Serv. Comm’n of N.Y.v. FERC, 813 F.2d 448, 454 (D.C. Cir.

1987) (holding that the Commission properly excused utilities from filing policies or

practices that dealt with only matters of “practical insignificance” to serving customers);

Midwest Independent Transmission System Operator, Inc.

, 98 FERC ¶ 61,137 at 61,401

(“It appears that the proposed Operating protocols could significantly affect certain rates

and service and as such are required to be filed pursuant to section 205.”), order granting

clarification, 100 FERC ¶ 61,262 (2002).

Docket Nos. RM05-17-000 and RM05-25-000 - 959 -

and practices that relate to transmission services. The Commission sought comment on

how best to determine what “relates” to transmission service to facilitate a consistent

interpretation and to minimize discretion on what rules, practice and standards should be

posted on OASIS.

1636. On the particular issue of creditworthiness and security requirements, the

Commission preliminarily concluded that the mere posting of information on OASIS was

insufficient. The Commission proposed that each transmission provider’s OATT contain

sufficient information about its credit process and requirements to enable customers to

understand the information required to demonstrate creditworthiness and to determine for

themselves the general amount and type of security they may need to provide in order to

receive service. The Commission therefore proposed to amend section 11 of the pro

forma OATT on creditworthiness to require each transmission provider to include its

creditworthiness and security requirements in a new Attachment L to its OATT.

Consistent with the Creditworthiness Policy Statement,

926

the Commission proposed to

require the new Attachment L to include such qualitative and quantitative criteria

necessary to determine the level of secured and unsecured credit required, with

926

Policy Statement on Electric Creditworthiness, 109 FERC ¶ 61,186 (2004)

(Creditworthiness Policy Statement).

Docket Nos. RM05-17-000 and RM05-25-000 - 960 -

supplementation in a credit guide or manual to be posted on OASIS.

927

The Commission

sought comment on whether the proposal is unduly burdensome.

Comments

Included in Open Access Transmission Tariffs

1637. Many commenters express support for the continuation of the current Commission

policy which requires the inclusion in the transmission provider’s OATT of only those

rules, standards and practices that significantly affect transmission rates and services.

928

These commenters generally state that any rule, practice, term or condition that could

result in limiting access to transmission services, including rates and charges for service,

should be included in the OATT and should be subject to Commission scrutiny.

Examples given include all rules and practices affecting calculation of ATC,

creditworthiness criteria, and rules or practices affecting the transmission provider’s

regional planning process. Commenters argue that Commission oversight is necessary to

927

The Commission proposed to require the new Attachment L to include the

following elements: (1) a summary of the procedure for determining the level of secured

and unsecured credit; (2) a list of the acceptable types of collateral/security; (3) a

procedure for providing customers with reasonable notice of changes in credit levels and

collateral requirements; (4) a procedure for providing customers, upon request, a written

explanation for any change in credit levels or collateral requirements; (5) a reasonable

opportunity to contest determinations of credit levels or collateral requirements; and

(6) a reasonable opportunity to post additional collateral, including curing any non-

creditworthy determination.

928

E.g., ISO/RTO Council, CAISO, LDWP, MISO/PJM States, PGP, and PNM-

TNMP.

Docket Nos. RM05-17-000 and RM05-25-000 - 961 -

ensure that these rates, charges, rules, practices, terms or conditions of transmission

service are reasonable and afford comparable treatment for wholesale customers.

1638. Other commenters advocate further inclusion of rules, standards and practices in

the transmission provider’s OATT. Morgan Stanley believes that business practices

manuals should be incorporated into each OATT and filed with the Commission for

approval. Morgan Stanley states that if this is not required then, at a minimum, each

OATT should provide for a process to use when the transmission provider wishes to

amend its business practices manuals. For example, transmission providers should

provide notice to all affected parties of an intent to make a change, a mechanism to

receive stakeholder feedback on the proposed change, and a minimum period of time

between the final implementation decision and the effective date of the proposed change

(e.g.

, 30-60 days after final decision). Southwestern Coop, however, maintains that

transmission providers should not be allowed to change their rules, standards and

practices that affect the justness and reasonableness of OATTs without prior Commission

review. Southwestern Coop states that the Commission should require all rules,

standards and practices relating to transmission services to be included in the OATT filed

with the Commission, because otherwise it cannot ensure that jurisdictional rates are just

and reasonable.

Posted on OASIS

1639. Many commenters also express support for the proposed requirement that all rules,

standards and practices that are not required to be included in a transmission provider’s

Docket Nos. RM05-17-000 and RM05-25-000 - 962 -

OATT and that affect a transmission provider’s provision of transmission service be

posted on OASIS.

929

Commenters generally state that these postings will allow for

increased transparency, while affording the transmission provider flexibility to make

revisions rather than having to amend the OATT each time a change occurs.

1640. Powerex argues that the transmission provider also should be required to post data

used to calculate ATC, any metrics the Commission adopts regarding the transmission

provider’s performance of system impact and facilities studies, information concerning

both planned and unplanned transmission outages, and a transmission provider’s business

practices, tariff, organizational charts and job descriptions of its employees.

1641. Southern takes issue with the use in the NOPR of the phrase “all of their rules,

standards and practices,” stating that language suggests that a transmission provider

might be required to reduce each detail of its business practices to writing, which could

be overly burdensome. In addition, Southern believes that any rule relating to posting

requirements on OASIS should have certain mechanisms to allow the transmission

provider to deviate from posted practices when necessary. In contrast, ELCON states

that any rule, standard or practice used by the transmission provider and any of its

employees to approve or disapprove a request for service should be committed to writing

and posted. Similarly, TranServ argues that transmission providers should be required to

929

E.g., CAISO, EEI, MidAmerican, MISO/PJM States, Nevada Companies, PJM,

Powerex, Santa Clara, Suez Energy NA, TDU Systems, and TAPS.

Docket Nos. RM05-17-000 and RM05-25-000 - 963 -

post on OASIS any criteria applied by the transmission provider to any attribute of a

transmission or ancillary service request for the purpose of determining whether the

service request should be approved or denied.

1642. Northwest IOUs suggests that the Commission should adopt a "rule of reason" test

for matters required to be posted on the OASIS similar to the test applied to matters

required to be included in the OATT.

Creditworthiness

1643. Several commenters support the inclusion of a separate Attachment L to the pro

forma OATT outlining creditworthiness requirements, asserting that Attachment L will

standardize credit procedures and security requirements and increase transparency.

930

Suez Energy NA states that the proposal is not unduly burdensome, that the procedures

proposed are not different from the Creditworthiness Policy Statement or the procedures

already imposed in individual cases, and that the Commission is merely proposing to

apply an existing requirement in a non-discriminatory manner.

1644. Other commenters propose modifications to the credit-related proposals set forth

in the NOPR. TAPS urges the Commission to require the transmission provider to adopt

a two-part creditworthiness assessment in order to facilitate non-burdensome and fair

assessment of creditworthiness. TAPS recommends that a standard similar to the Florida

930

E.g., APPA, East Texas Cooperatives, Lassen, MISO/PJM States, Nevada Companies,

NRECA, PGP, Powerex, Southern, Suez Energy NA, TANC, and TAPS.

Docket Nos. RM05-17-000 and RM05-25-000 - 964 -

Power Corp. OATT be applied, which provides that customers with “satisfactory long-

term payment history” and a minimum credit rating of Baa2 (Moody’s) or BBB (S&P)

would not have to post any credit security. If a customer fails to meet the threshold test,

TAPS states that the transmission provider would perform a transparent credit assessment

that is consistent with the Commission’s Creditworthiness Policy Statement and the

credit policies developed for use in regional transmission organizations such as MISO

and SPP. According to TAPS, since quantitative measures sometimes understate public

power creditworthiness, transmission providers will need to weigh qualitative factors

more heavily than quantitative factors in assessing public power creditworthiness. For

public entities that fail the threshold test, TAPS states that transmission providers should

use outstanding bond indebtedness as a proxy for tangible net worth for those entities

whose energy and transmission service payments receive priority over bond payments.

1645. PJM generally agrees with the creditworthiness proposals, except for inclusion in

the OATT of the actual detailed algorithms used to calculate credit scores, stating that

those algorithms, as the Commission recognized,

931

may change over time. In PJM’s

view, requiring all such changes to be approved by the Commission would be

unnecessarily burdensome to both the Commission and the transmission provider. PJM

recommends that the overall framework of the credit determinations be included in the

OATT, while the detailed algorithms be posted on OASIS to meet transparency goals.

931

See NOPR at P 456.

Docket Nos. RM05-17-000 and RM05-25-000 - 965 -

PJM also recommends that the Commission accept, as an option, a regularly-updated

posting on the transmission provider’s web site of each customer’s available credit and

collateral requirement as sufficient notification for most changes in credit available and

credit requirements. PJM further recommends that only significant and sudden

reductions in credit available (for example, those greater than 25 percent within a one-

month period) be subject to an active notification requirement.

1646. TVA recommends the Commission consider two fundamental principles as it

standardizes creditworthiness terms and conditions. First, as long as qualitative factors

are part of the equation (and TVA agrees that they should be), TVA states that certain

subjective judgments by the transmission provider will be required. TVA encourages the

Commission to provide guidance on appropriate criteria to consider in making these

judgments, but not to remove entirely from the process the flexibility necessary for

individual assessments of customer creditworthiness. Second, TVA states that

transmission providers may have to impose different security requirements as a result of

differences in statutes, regulations, or other legal requirements. For example, TVA states

that its ability to incur debt is limited by section 15d(a) of the Tennessee Valley

Authority Act

932

and, therefore, it may need to impose security requirements that are

stricter than those of a public utility, as the Commission has previously recognized.

933

932

16 U.S.C. 831n-4.

933

Citing East Ky. Power Coop., Inc., 114 FERC ¶ 61,035 at P 56 (2006).

Docket Nos. RM05-17-000 and RM05-25-000 - 966 -

TVA requests that the final rule respect these differing legal obligations and provide

corresponding flexibility in credit decisions among transmission providers.

1647. A number of commenters oppose the Commission’s proposed creditworthiness

policy.

934

In general, these commenters believe that each transmission provider should

have the flexibility to make and change creditworthiness procedures without the delay of

obtaining Commission approval. They also argue that the Commission’s goal of

transparency could be better achieved by requiring the posting of a transmission

provider’s creditworthiness policy on OASIS.

935

Xcel and MidAmerican assert that the

Commission’s proposal would decrease a transmission provider’s ability to timely

respond to changing market and financial conditions and, therefore, creditworthiness and

security requirements should simply be posted on OASIS. Southern believes that the

Commission should permit but not require transmission providers to file their

creditworthiness and security procedures as part of their OATTs.

936

Southern also asks

that the Commission allow a transmission provider, in its compliance filing, to request a

determination that its current creditworthiness policies and practices are acceptable under

the new Commission policies. Similarly, ISO-New England states that this rulemaking

934

E.g., MidAmerican, Southern, PNM-TNMP, NorthWestern, and Xcel.

935

E.g., PNM-TNMP, EEI, and MidAmerican.

936

Southern states that it already includes creditworthiness and security

requirements in its OATT since the Commission issued its Creditworthiness Policy

Statement.

Docket Nos. RM05-17-000 and RM05-25-000 - 967 -

should not modify the ISO-New England Financial Assurance and Billing Policies, which

are already on file with the Commission.

1648. CAISO states that although the NOPR requirements concerning credit and security

requirements do not appear unduly burdensome, it is concerned that the Commission may

apply these requirements in a manner that will impose an undue burden on transmission

providers and effectively eliminate the ability of transmission providers to supplement

basic elements with a credit guide or manual. CAISO and MidAmerican further state that

there is no legitimate reason to treat credit policies and procedures any differently than

the other rules, practices and standards that the Commission permits to be included on

OASIS and does not require to be filed as part of the tariff. Santa Clara recommends that

if the Commission decides to require creditworthiness and security policies to be posted

on OASIS rather than included in the OATT, then it should require at least a 30-day

notice period for changes in the credit policies.

Commission Determination

1649. The Commission adopts the NOPR proposal to continue to require only those

rules, standards, and practices that significantly affect transmission service be

incorporated into a transmission provider’s OATT. The Commission further affirms the

use of a “rule of reason” to determine what rules, standards, and practices significantly

affect transmission service and, as a result, must be included in the transmission

provider’s OATT.

Docket Nos. RM05-17-000 and RM05-25-000 - 968 -

1650. The “rule of reason” test has arisen primarily with respect to protocols or

operating procedures used by RTOs and ISOs. For example, the Commission has held

that, while MISO’s business practices manuals implicate the Commission’s jurisdiction

because they generally involve “the installation, operation, or use of facilities for the

transmission or delivery of power in interstate commerce,” they do not require an FPA

section 205 filing because “they mostly involve general operating procedures.” In other

cases, the facts have required the filing of the rule, standard or practice. For example,

CAISO proposed to post certain technical, operational and business standards related to

dynamic scheduling on its website and include only the rates under its OATT. In that

instance, the Commission found that the details contained in the standards were practices

that could significantly affect the terms and conditions of service and, therefore, under

the Commission’s “rule of reason” must be filed under section 205 of the FPA.

937

1651. Comments received in response to the NOPR confirm that there is broad support

for the Commission’s existing practice, requiring only those rules, standards, and

practices that significantly affect transmission service, and the use of the “rule of reason”

937

California Independent System Operator Corp., 107 FERC ¶ 61,329 at P 21-22

(2004); see also

Southwest Power Pool, Inc., 112 FERC ¶ 61,303 at P 25 (requiring that

the SPP OATT provide sufficient information for market participants to fully understand

SPP’s implementation of an imbalance market), reh’g denied

, 113 FERC ¶ 61,115

(2005); PJM Interconnection, L.L.C.

, 104 FERC ¶ 61,124 at P 61 (requiring PJM to place

all procedures, standards and requirements for proposing that a transmission owner

construct a specific upgrade, and all procedures for charging customers, in its tariff, not

in its manuals), order on reh’g

, PJM Interconnection, L.L.C., 105 FERC ¶ 61,123 (2003).

Docket Nos. RM05-17-000 and RM05-25-000 - 969 -

test to identify those rules, standards, and practices. The Commission disagrees with

parties arguing that all of a transmission provider’s rules, standards, and practices should

be incorporated into its OATT. We believe that requiring transmission providers to file

all of their rules, standards and practices in their OATTs would be impractical and

potentially administratively burdensome.

1652. The Commission instead requires transmission providers to post on their public

websites all rules, standards, and practices that relate to transmission service and provide

a link to those rules, standards, and practices on OASIS. We conclude that it would not

be appropriate to place the rules, standards, and practices only on OASIS as some

transmission providers use certificates to restrict access to their OASIS sites. By

providing a link on OASIS to the rules, standards, and practices that are otherwise

publicly posted, the Commission ensures that all potential customers will have access to

the information necessary for them to understand the terms and conditions of service.

We amend section 4 of the pro forma

OATT to expressly establish this posting

requirement.

1653. We note that we already require certain rules and practices to be posted on

OASIS.

938

We find that it is now necessary to also require that all rules, standards or

business practices that relate to the terms and conditions of transmission service, and how

938

See, e.g., Order No. 889 at 31,588-89; Open Access Same-Time Information

Systems, Order No. 605, 64 FR 34117 (Jun. 25, 1999), FERC Stats. and Regs. ¶ 31,075

(1999); Order No. 676 at P 79.

Docket Nos. RM05-17-000 and RM05-25-000 - 970 -

that transmission service is provided to customers, to be detailed, clearly stated on the

transmission provider’s public website, with a link to this information on OASIS.

939

emphasize that this requirement applies to all such rules, standards, and practices,

currently written or otherwise.

940

While we acknowledge this requirement will result in

some burden to transmission providers, we find that this approach is necessary to provide

greater transparency and mitigate the potential for undue discrimination against

customers taking service under the transmission provider’s OATT. Further, our holding

is not intended to eliminate all discretion under the pro forma

OATT; rather, we

recognize that certain tariff provisions require consideration of the specific facts and

939

If a particular rule, standard or practice conflicts with an OATT provision, the

OATT of course shall govern in all circumstances. Moreover, as noted in the NOPR, we

emphasize that posting rules, practices and standards – in lieu of filing such practices

with the Commission as part of the transmission provider’s pro forma

OATT – neither

insulates a transmission provider from complaints nor confers a just and reasonable

presumption. We encourage customers to call the Commission’s Enforcement Hotline

with complaints about the application of such rules, standards and practices should they

experience problems with their transmission providers. To the extent customers are not

satisfied with responses from their transmission provider, they should contact the

Commission’s Enforcement Hotline via telephone (202) 502-8390, toll-free 1-888-889-

8030, fax (202) 208-0057, or at

http://www.ferc.gov/contact-us/enforce-hot.asp

940

With respect to the business practices developed by NAESB, there may be

certain copyright restrictions that limit the transmission provider’s ability to post those

practices on its own website. In such instances, we expect that the transmission provider

will reference any NAESB practices it uses and provide a link on its public website to the

NAESB website in order to provide interested parties with a means to access the

copyrighted material.

Docket Nos. RM05-17-000 and RM05-25-000 - 971 -

circumstances related to particular service requests.

941

We merely require that, if the

transmission provider uses standards, rules or business practices to administer its OATT,

such standards, rules or business practices must be available for public inspection.

Moreover, we note that our actions here are consistent with actions we have taken in

recent proceedings. For example, the Commission has required that certain business

practices manuals be posted and made available for public view on a permanent basis.

942

As in those cases, we find that making rules, standards, and practices readily accessible

will serve as a tool to supplement each transmission provider’s OATT and facilitate fair

and open access to the transmission grid.

1654. To provide guidance to the transmission providers as to whether a particular rule,

standard, or practice “relates to” transmission service, and therefore warrants posting, the

Commission believes the MAPP Policies and Procedures for Transmission Operations

manual is a good example of the type of information that relates to the terms and

conditions of transmission service. For example, the MAPP manual sets forth

information supplementing its OATT pertaining to (1) transmission service requests on

941

The circumstances and manner in which a transmission provider exercises its

discretion under its OATT must be posted in accordance with 18 CFR 37.6(4).

942

See, e.g., Midwest Independent Transmission System Operator, Inc., 108 FERC

¶ 61,163 at P 658, order on reh’g

, 109 FERC ¶ 61,157 (2004), order on reh’g, 111 FERC

¶ 61,043, order on reh’g

, 112 FERC ¶ 61,086 (2005); see also PJM Interconnection,

L.L.C., 81 FERC ¶ 61,257 at 62,267 (1997) (finding no reason to require filing of the

PJM Manuals but requiring that such manuals be available for public inspection on a

permanent basis), order on reh’g

, 92 FERC ¶ 61,282 (2000).

Docket Nos. RM05-17-000 and RM05-25-000 - 972 -

the MAPP OASIS site, (2) the retraction of an accepted or counteroffer transmission

request, (3) timing requirements for transmission service requests, (4) methods to

accommodate a firm transmission request with redispatch, and (5) transmission service

charge implementation procedures. Other examples include detailed information

regarding tagging, scheduling, billing and other matters provided in other RTO manuals.

This is the type of information that clearly relates to transmission service and therefore

must be reduced to writing and publicly posted.

1655. We also agree with requests to require a transparent process for amending rules,

standards, and practices previously posted by a transmission provider. We therefore

require each transmission provider also post on its public website (with a corresponding

link on OASIS) a statement of the process by which the transmission provider will amend

these rules, standards, and practices that are accessible via OASIS. As part of this

process, the transmission provider must specify a mechanism to provide reasonable

notice of any proposed changes to a posted business practice and the respective effective

date of such change.

943

We amend section 4 of the pro forma OATT to formalize this

posting requirement and obligate transmission providers to follow the amendment

procedures specified by the transmission provider. As with the requirement to post the

underlying standards, rules and practices, we believe the amendment procedures required

943

As part of their business practice amendment procedures, transmission

providers may adopt such additional procedures they deem appropriate, such as

opportunities for comment to proposed changes to rules, standards, and practices.

Docket Nos. RM05-17-000 and RM05-25-000 - 973 -

here will increase transparency and help minimize opportunities for undue

discrimination.

1656. The Commission also adopts the NOPR proposal and amend the pro forma

OATT

to include a new Attachment L.

944

We find that the transmission provider’s basic credit

standards significantly affect transmission service and, therefore, must be included in the

pro forma

OATT. This will ensure that all customers have clear information as to the

credit process and standards used by a transmission provider to grant or deny

transmission service and, in turn, will serve to prevent undue discrimination and

eliminate a potentially significant barrier to entry in the provision of service. Most

importantly, by making Attachment L a part of the pro forma

OATT, customers will have

an opportunity to comment on any changes to the standards proposed by a transmission

provider in a rate filing with the Commission.

1657. To that end, each transmission provider’s Attachment L must specify the

qualitative and quantitative criteria that the transmission provider uses to determine the

level of secured and unsecured credit required. Attachment L must also contain the

following elements: (1) a summary of the procedure for determining the level of secured

and unsecured credit; (2) a list of the acceptable types of collateral/security; (3) a

944

As with new Attachment K to the pro forma OATT, regarding transmission

planning, we acknowledge that some transmission providers may already have

attachments to their OATTs labeled with the letter “L,” in which case transmission

providers are free to label their credit procedures OATT attachment with the next

available letter.

Docket Nos. RM05-17-000 and RM05-25-000 - 974 -

procedure for providing customers with reasonable notice of changes in credit levels and

collateral requirements; (4) a procedure for providing customers, upon request, a written

explanation for any change in credit levels or collateral requirements; (5) a reasonable

opportunity to contest determinations of credit levels or collateral requirements; and

(6) a reasonable opportunity to post additional collateral, including curing any non-

creditworthy determination. We will allow the transmission provider to supplement

Attachment L with a credit guide or manual to be posted on OASIS.

1658. We disagree with commenters that claim requiring this information in an

attachment to each transmission provider’s OATT will hinder the transmission provider’s

ability to timely respond to changing market and financial conditions. Because

Attachment L requires only a summary of credit requirements and other information, we

expect the need to revise Attachment L will occur infrequently. As suggested by PJM,

detailed information, such as the algorithms used by the transmission provider to

determine credit scores, can be posted on OASIS along with other information that relates

to the provision of transmission service. Thus, the requirement we are imposing should

not be overly burdensome.

1659. At the same time, we agree that transmission providers need flexibility in

determining credit requirements in light of qualitative and quantitative factors, as we

recognized in the NOPR and the Creditworthiness Policy Statement. We believe the

requirements adopted in this Final Rule allow for such flexibility. By requiring

transmission providers to consider both quantitative and qualitative factors, the particular

Docket Nos. RM05-17-000 and RM05-25-000 - 975 -

circumstances surrounding public power entities can be recognized. We agree, moreover,

with TVA that the transmission provider’s credit policies must be consistent with its legal

obligations and expect that interested parties will bring any legal conflicts to our attention

on review of the transmission provider’s compliance filing.

1660. With regard to requests to find existing credit policies consistent with the

requirements of the Final Rule, all transmission providers will be required to demonstrate

compliance with all aspects of the Final Rule either by implementing the reforms adopted

today or showing that departures are consistent with or superior to the terms and

conditions of the pro forma

OATT, as modified by this Final Rule. The procedural

mechanisms for making such a showing provided for in section IV.C above give

transmission providers the opportunity to demonstrate that retention of their existing

credit practices is appropriate.

1661. Finally, with regard to Santa Clara’s request to require the transmission provider

to provide at least a 30-day notice period for changes in creditworthiness and security

policies that are posted on OASIS, we explain above that each transmission provider

must identify and incorporate a specific process in its OATT for amending business

practices that are posted on OASIS. Such practices include those that describe and

implement its creditworthiness and security policies.

Docket Nos. RM05-17-000 and RM05-25-000 - 976 -

b. Liability and Indemnification

1662. In Order No. 888, the only liability provisions included in the pro forma

OATT

related to force majeure and indemnification.

945

Section 10.1 of the pro forma OATT

provides that neither the transmission provider nor the transmission customer will be

considered in default as to any obligation under the tariff if prevented from fulfilling the

obligation due to an event of force majeure. A party whose performance under the tariff

is hindered by an event of force majeure, however, is required to make all reasonable

efforts to perform its obligations under the tariff. With respect to indemnification, under

section 10.2 of the pro forma

OATT, the transmission customer indemnifies the

transmission provider against third party claims arising from the transmission provider’s

performance of its obligations under tariff on behalf of the transmission customer, except

in cases of negligence or intentional wrongdoing by the transmission provider.

(1) Force Majeure

Comments

1663. Santa Clara queries whether the Commission intended to make the transmission

provider’s performance of its obligations less burdensome by using the phrase “all

reasonable efforts” instead of “due diligence” in the force majeure provision in section

10.1 of the pro forma

OATT is. In either case, Santa Clara requests the Commission to

945

Order No. 888-B at 62,081.

Docket Nos. RM05-17-000 and RM05-25-000 - 977 -

consider the use of the most stringent term when addressing a transmission provider’s

obligation to perform under its tariff.

Commission Determination

1664. The Final Rule retains the current “all reasonable efforts” standard in the force

majeure provision. Santa Clara does not explain how the “all reasonable efforts”

standard may be more or less stringent than the “due diligence” standard. Further, as the

Commission explained in Order No. 888, this protection against unexpected and

unpredictable events is appropriately made available to both the transmission provider

and transmission customer. We therefore find that the clarification requested by Santa

Clara is unnecessary.

(2) Indemnification/Limitation of Liability

Comments

1665. Several commenters

946

urge the Commission to change the indemnification

provision to protect transmission providers from liability except in the case of gross

negligence or intentional misconduct, thereby exempting the transmission provider from

liability for acts of ordinary negligence. These commenters also request that the

Commission add to the pro forma

OATT a new provision clarifying that the transmission

provider would not be liable to any transmission customer or third party for direct,

incidental, consequential, indirect, or punitive damages arising from services provided

946

E.g., Southern, EEI, and Northwest IOUs

Docket Nos. RM05-17-000 and RM05-25-000 - 978 -

under the tariff, except in cases of gross negligence or intentional misconduct (in which

case, EEI, and Northwest IOUs propose, liability would be limited to direct damages).

These commenters note that the Commission has allowed transmission providers this

protection in the tariffs of MISO, PJM, ISO New England, SPP, and their member

transmission owners and generators, but it has not fully explained its basis for treating

non-RTO member transmission providers differently from RTOs and ISOs. EEI further

notes that the Commission accepted similar liability protection in the Large Generator

Interconnection Agreement (“LGIA”) and in natural gas pipeline tariffs.

947

EEI requests

that this liability limitation be added to the pro forma

transmission service agreement that

would apply to transmission customers acting in good faith to carry out the directives of a

transmission provider.

1666. With respect to third party indemnification, EEI notes that the Commission

reasoned in SPP that, even though a broader liability limitation would relieve a

transmission provider from liability for ordinary negligence, that provision only applies

to transmission customers under the tariff. EEI states that there are many other entities

that could initiate legal action against the transmission provider in connection with the

provision of transmission service, thereby making an adequate indemnification provision

947

Citing Article 18, Large Generator Interconnection Agreement; ANR Pipeline

Co., 98 FERC ¶ 61,218, order on tariff filing, 100 FERC ¶ 61,132 (2002).

Docket Nos. RM05-17-000 and RM05-25-000 - 979 -

in the pro forma

OATT necessary for the same reasons as the limited liability

provision.

948

1667. EEI contends that the addition of the Commission’s new EPAct 2005 authority to

establish mandatory reliability standards to provide open access transmission service to

all customers, regardless of their risk profile, makes it an appropriate time to revisit the

liability provisions in the OATT. According to EEI, a limitation on liability in the pro

forma OATT should be viewed as a necessary element of the implementation of the

Commission’s reliability authority. Because transmission providers cannot deny service

to particular customers based on the risk of potential damages, EEI and Southern assert

that all transmission providers should be protected from certain risks associated with this

obligation to serve. EEI argues that increased protection from liability would lower the

cost of capital for new transmission projects and promote the expansion of transmission

infrastructure. EEI further argues that the technological complexity of modern utility

systems and the potential for service interruptions unrelated to human errors justify

liability limitations. According to EEI, a limitation on liability to direct damages puts the

risk on those customers with special reliability needs, rather than spreading the risk

among all customers.

1668. EEI notes that the Commission has denied requests for exemptions from liability

for ordinary negligence in the indemnification provision on the grounds that liability and

948

Citing Southwest Power Pool, Inc., 112 FERC ¶ 61,100 at P 39 (2005).

Docket Nos. RM05-17-000 and RM05-25-000 - 980 -

indemnification were “separate issue[s]” and that transmission providers seeking liability

protections could rely on state laws.

949

EEI argues, however, that an OATT and the

accompanying service agreement constitute a contract between the transmission provider

and the customer that is established pursuant to federal law and, as a result, it is not at all

clear that a state law limitation on liability would apply. Southern asserts that adopting

liability limits would provide uniformity, certainty, and reduce risk since reliance on state

law is an issue not free from doubt.

1669. Entegra argues on reply that the NOPR did not contemplate any modification to

these provisions of the pro forma

OATT and neither EEI nor Southern has established a

nexus between such a modification and the goals set forth in the NOPR. TDU Systems

on reply similarly argue that EEI’s request is outside the scope of the rulemaking and

neither EEI nor Southern show a change in circumstance justifying a new limitation on

liability. Immunizing transmission providers from these liability risks, TDU Systems

contend, would simply transfer risk to customers that have no control over the

transmission provider’s negligence. Entegra and TDU Systems further argue that

Southern previously sought the same relief in a tariff filing rejected by the Commission

less than a year ago, stating that the Commission thus already rejected the notion that

949

Citing Order No. 888-A at 30,301.

Docket Nos. RM05-17-000 and RM05-25-000 - 981 -

Southern was similarly situated to the RTOs and ISOs that have this protection.

950

Entegra notes that Southern did not seek rehearing of that order and its comments here

are therefore an impermissible collateral attack on a final Commission order. As for the

argument regarding EPAct 2005, TDU Systems note that the Commission presumably

was aware of its new reliability authorities when it issued the Southern

order four months

after EPAct was enacted.

1670. TDU Systems also point out that the tariff language proposed by EEI would not

protect a transmission customer from being sued by a third party for the negligence or

willful misconduct of the transmission provider. In such lawsuits, TDU Systems claim, a

third party would not be limited to direct damages. According to TDU systems, any

indemnification as between the transmission provider and the transmission customer that

is limited to direct damages would leave the customer holding the bag for the indirect

damages caused by the transmission provider’s negligence or willful misconduct.

Commission Determination

1671. We will retain the current liability protections in the pro forma

OATT for the same

reasons that the Commission has rejected similar past proposals. While the Commission

explained in Order Nos. 888-A and 888-B that the pro forma

tariff was not intended to

address liability issues, as EEI notes, the Commission stated that liability was a separate

950

See Entegra Reply (citing Southern Company Services, Inc., 113 FERC

¶ 61,239 (2005)).

Docket Nos. RM05-17-000 and RM05-25-000 - 982 -

issue from indemnification.

951

The Commission further explained that transmission

providers were not precluded from relying on state laws that protected utilities or others

from claims founded in ordinary negligence.

952

The Commission declined to adopt a

uniform federal liability standard and decided that, while it was appropriate to protect the

transmission provider through force majeure and indemnification provisions from

damages or liability when service is provided by the transmission provider without

negligence, it would leave the determination of liability in other instances to other

proceedings.

953

1672. On the issue of a negligence standard for the indemnification provision, we

decline to depart from our policy set forth in Order No. 888, as affirmed in Order No.

888-A and subsequent orders.

954

In Order No. 888, the Commission stated:

We have limited the indemnification portion of the provision so that it is

now only the transmission customer who indemnifies the transmission

provider from the claims of third parties. The customer is taking service

from the transmission provider and may appropriately be asked to bear the

risks of third-party suits arising from the provision of service to the

customer under the tariff. We find that this new indemnification provision

would be too strict if it required customers to indemnify transmission

providers even in cases where the transmission provider is negligent.

951

See Order No. 888-A at 30,301 and Order No. 888-B at 62,081 (section 10.2 of

the pro forma

OATT).

952

Order No. 888-A at 30,301.

953

Order No. 888-B at 62,081.

954

See, e.g., Northeast Utilities Services Co., 111 FERC ¶ 61,333 (2005)

(Northeast Utilities

Docket Nos. RM05-17-000 and RM05-25-000 - 983 -

Accordingly, the revised provision provides that the customer will not be

required to indemnify the transmission provider in the case of negligence or

intentional wrongdoing by the transmission provider.

955

1673. The Commission subsequently addressed this issue in Northeast Utilities

. There,

the Commission found that a broader customer indemnification obligation that would

include ordinary negligence would not give any incentive to the transmission provider to

avoid negligent actions. In Northeast Utilities

, the Commission explained again why it

permitted a gross negligence exception in the pro forma

LGIA section 18.1 in order to

further limit the transmission provider’s liability. As the Commission explained in Order

No. 2003, interconnection warrants a different standard because it presents a greater risk

of liability than exists for the provision of transmission service. The Commission further

found that because risk exposure can increase interconnection costs, a broader indemnity

standard is appropriate in the interconnection context.

956

1674. Further, unlike Order No. 888 in which the transmission customer indemnifies the

transmission provider, in Order No. 2003 the indemnity provision is expressly bilateral.

In Order No. 2003 the interconnecting generator and the transmission provider each

indemnifies the other from all damages to third parties arising under the LGIA from

conduct on behalf of the indemnifying party, except in cases of gross negligence. Given

that the indemnification provision in the pro forma

LGIA is bilateral, in contrast to the

955

Order No. 888 at 31,765.

956

Order No. 2003 at P 636; Order No. 2003-A at 31,162.

Docket Nos. RM05-17-000 and RM05-25-000 - 984 -

pro forma

OATT, it is reasonable to permit a gross negligence standard in the case of an

interconnection.

1675. We also reject commenters’ assertions that the liability standard the Commission

has approved for RTOs/ISOs and gas pipelines is appropriate for other transmission

providers. In the Reliability Policy Statement,

957

the Commission stated that it would

consider, on a case-by-case basis, proposals by public utilities to amend their OATTs to

include limitations on liability. The Commission further noted that while this issue has

not been resolved on a standardized basis, the Commission has entertained RTO

transmission providers’ specific proposals to amend their OATTs to include provisions

addressing limitations on liability.

958

1676. In subsequent orders, the Commission found that the gross negligence and

intentional wrongdoing indemnification and liability standard is appropriate for RTOs

and ISOs. However, the Commission has declined to extend this protection to all

transmission providers. In Southwest Power Pool, Inc.

, the Commission explicitly stated

“that our acceptance here of the gross negligence and intentional wrongdoing indemnity

standard is limited to SPP, in its role as an RTO, and its TOs; we do not intend to extend

957

Policy Statement on Matters Related to Bulk Power System Reliability, 107

FERC ¶ 61,052 (2004) (Reliability Policy Statement).

958

Reliability Policy Statement at P 40 (citations omitted).

Docket Nos. RM05-17-000 and RM05-25-000 - 985 -

such protection to all transmission providers.”

959

In Southern Company Services, Inc.,

the Commission stated that:

Having considered Southern Companies’ proposed limitation on liability

and indemnification provisions pursuant to our Reliability Policy Statement

cited above, we find that Southern Companies have not shown that they are

similarly situated to the RTOs/ISOs they cite in support. While Southern

Companies claim that they ‘may not be protected by any State-regulated

limitations on liability,’ Southern Companies offer no evidence to support

this concern. The Commission has provided such liability protection to

RTOs/ISOs because they were created by and solely regulated by the

Commission, and otherwise would be without limitations on liability.

Southern Companies have proffered no evidence of any change in

circumstances vis-à-vis their liability exposure post-Order No. 888.

960

1677. Commenters offer no new arguments that demonstrate that they are unable to rely

on state laws, i.e.

, the state laws provide inadequate protection. While EEI and Southern

assert that there is uncertainty in whether state law on liability would apply to a service

agreement between a transmission provider and a transmission customer, we note that

neither provide any evidence that transmission providers are actually precluded from

relying on state law for liability protection. EEI and Southern thus fail to show that the

potential for a legal and regulatory gap is so great as to warrant inclusion of liability

protections in the pro forma

OATT for all transmission providers. In this regard, the

Commission also finds without merit assertions that increased liability protections in the

pro forma

OATT should be viewed as a necessary element of the implementation of the

959

112 FERC ¶ 61,100 at P 39 (2005).

960

113 FERC ¶ 61,239 at P 7 (2005).

Docket Nos. RM05-17-000 and RM05-25-000 - 986 -

Commission’s reliability authority. As none of the arguments proffered by commenters

persuade us to change our policy regarding liability protections applicable to non-RTO

and non-ISO transmission providers, we decline to modify the liability protections in the

pro forma

OATT.

10. OATT Definitions

1678. In order to support the reforms adopted in this Final Rule and otherwise clarify the

requirements of the pro forma

OATT, the Commission adds and amends various

definitions in the pro forma

OATT, as set forth below.

a. Affiliate

NOPR Proposal

1679. In the NOPR, the Commission proposed a new definition of Affiliate incident to

the proposed change to the pricing of reassigned capacity.

Comments

1680. Some commenters request clarification that the proposed definition of Affiliate

would not apply to transmission-only cooperatives or independent entities such as RTOs.

NRECA asserts that in Order No. 2004-A, the Commission concluded that “[g]eneration

and transmission cooperatives (G&T) are not subject to the Standards of Conduct

consistent with the policies established under Order No. 888.” NRECA asks for

confirmation that distribution and generation and transmission cooperatives will not to be

considered affiliates of each other for OATT and Standards of Conduct purposes because

recent pleadings reveal that there continues to be confusion about this definition.

Docket Nos. RM05-17-000 and RM05-25-000 - 987 -

TranServ asks for clarification of the application of the definition of “affiliate” with

respect to a merchant affiliate of a transmission provider that has turned over tariff

administration functions to an ISO, RTO, or other independent entity. PNM-TNMP

suggests that the definition of Affiliate be expanded or clarified to encompass divisions

of an entity that operate as a functional unit. PNM-TNMP asserts that such a change

would make clear that an Affiliate includes not only separate legal entities, but also may

apply to divisions and functional units within the entity.

Commission Determination

1681. As discussed in section V.C.4, the Commission lifts the price cap on reassigned

transmission capacity for all transmission customers, regardless of affiliation with the

transmission provider. It is therefore no longer necessary to define an affiliate for

purposes of that provision. The Commission nonetheless adopts the proposed definition

of Affiliate to implement the reforms associated with distribution of operational penalties

discussed in section V.C.5.b.

1682. With regard to the request that we clarify that an Affiliate does not apply to

transmission-only cooperatives, we agree with NRECA that the Commission made clear

in Order No. 888-A that there was no corporate affiliation between G&T cooperatives

and their member distribution cooperatives..

961

Order No. 888-A at 30,286 and 30,366.

Docket Nos. RM05-17-000 and RM05-25-000 - 988 -

1683. TranServ requests clarification regarding the use of the term “affiliate” in the

context of a transmission owner that has turned over operational control of its

transmission facilities to an RTO, ISO, or to an independent entity. We clarify that, for

purposes of the distribution of penalties, if such transmission owner is not required to be

a transmission provider under a Commission-approved tariff, the merchant affiliate of

such transmission owner would not be considered to be an “affiliate” of the RTO, ISO, or

independent entity under the definition adopted in this Final Rule. The affiliation of a

merchant to a transmission owner does not establish an affiliation between such merchant

and the RTO, ISO, or independent entity transmission provider.

1684. As to PNM-TNMP’s request that the definition of “affiliate” be expanded or

clarified to encompass divisions of an entity that operate as a functional unit, we note that

PNM-TNMP’s concern appears to have been raised in the context of lifting the price cap

for capacity reassignment, initially proposed only for non-affiliated transmission

customers. We believe we have addressed PNM-TNMP’s concerns by lifting the price

cap for capacity reassignment for all customers, including affiliates of the transmission

provider and the transmission provider’s merchant function.

b. Good Utility Practice

NOPR Proposal

1685. In the NOPR, the Commission proposed to incorporate the definition of reliable

operation from FPA section 215 in the definition of Good Utility Practice in the pro

forma OATT.

Docket Nos. RM05-17-000 and RM05-25-000 - 989 -

Comments

1686. No commenters oppose the Commission’s proposal to modify the definition of

Good Utility Practice to reference the reliable operation standard of FPA section 215.

Commission Determination

1687. The Commission adopts the NOPR proposal to incorporate the definition of

reliable operation from FPA section 215 in the definition of Good Utility Practice in the

pro forma OATT

. FPA section 215(b) obligates all users, owners and operators of the

bulk power system to comply with reliability standards that will take effect under that

section. Referencing section 215 in the definition of Good Utility Practice is appropriate

to ensure that the reliability standards ultimately developed by the ERO and approved by

the Commission are reflected in the pro forma

OATT.

c. Non-Firm Sales

NOPR Proposal

1688. The Commission proposed to add a definition for Non-Firm Sales to clarify the

treatment of such sales under section 30.4 of the pro forma

OATT.

962

The Commission

proposed defining a Non-Firm Sale as “an energy sale for which delivery or receipt of the

energy may be interrupted for any reason or for no reason, without liability on the part of

962

Section 30.4 as proposed in the NOPR provides, in relevant part, that “[t]he

Network Customer shall not operate its designated Network Resources located in the

Network Customer’s or the Transmission Customer’s Control Area such that the output

of those facilities exceeds its designated Network Load, plus Non-Firm Sales delivered

pursuant to Part II of the Tariff, plus losses.”

Docket Nos. RM05-17-000 and RM05-25-000 - 990 -

either the buyer or seller.” The Commission also proposed to clarify that, for the

purposes of applying section 30.4, energy sales that can only be interrupted to maintain

system reliability would be considered firm sales.

Comments

1689. Several commenters argue that the proposed definition of Non-Firm Sales could

impede a network customer’s ability to obtain transmission service for certain types of

energy products. In particular, Duke, EEI, and Southern question the treatment of power

purchase agreements with LD provisions under the proposed definition. Duke contends

that a contract with an LD provision might be interruptible for any reason, but it would

still provide for liability in the form of LD payments. As a result, the LD contract might

not fall within the definition of a Non-Firm Sale. At the same time, network customers

can only designate resources from system purchases not linked to a specific generating

unit if the purchase power agreement is not interruptible for economic reasons, does not

excuse seller performance for economic reasons, and requires the network customer to

pay for the purchase.

1690. Commenters are thus concerned that some contracts with LD provisions may be

too firm to be a Non-Firm Sale, but not firm enough to be designated as a network

resource. Duke argues that network customers should be allowed to operate their

Network Resources to both serve load and sell a firm LD product. EEI is concerned that

the proposed definition of Non-Firm Sales would prohibit a network customer from

making an off-system sale of a firm LD product or any other product that does not result

Docket Nos. RM05-17-000 and RM05-25-000 - 991 -

in undesignation of a Network Resource, given the restrictions set forth in section 30.4.

Duke and EEI therefore propose that a Non-Firm Sale should be defined as any sale that

is not sufficiently firm to be designated a Network Resource of the purchasing entity.

Raising concerns similar to those raised by Duke and EEI, Southern proposes to define

Non-Firm Sales as any sale that does not commit the associated resource to a third party

and otherwise keeps the resource available for network service on a non-interruptible

basis.

1691. NRECA, however, argues that contracts with LD provisions are typically

considered firm products, so long as they cannot be curtailed for economic reasons alone.

NRECA requests that the Commission confirm its understanding that the mere inclusion

of an LD provision in a contract does not make the sale non-firm, provided that the sale

cannot be curtailed only for economic reasons.

Commission Determination

1692. The Commission adopts the proposed definition of a Non-Firm Sale and

incorporates that defined term in section 30.4 of the pro forma

OATT. Network

customers may use network resources for third party sales only if the sale is on a non-

firm basis. This ensures that the network resource is available to serve the network load

on an uninterruptible basis. We conclude that it would be inappropriate, as some

commenters suggest, to relax the definition of a Non-Firm Sale to include any sale that is

not otherwise firm enough to be designated as a network resource. We address the

requirements for designation of network resources in section V.D.6, concluding that not

Docket Nos. RM05-17-000 and RM05-25-000 - 992 -

all contracts with LD provisions are sufficiently firm to be eligible for designation. There

we explain that only LD provisions that provide for “make whole” remedies are

sufficiently firm to be designated as network resources. It does not follow, however, that

all remaining contracts with LD provisions are non-firm. The very existence of an LD

provision indicates that interruption of service will result in liability and, thus, such

contracts cannot automatically be considered Non-Firm Sales for purposes of section

30.4. To allow otherwise would create conflicting incentives for the network customer.

d. Pre-Confirmed Application

NOPR Proposal

1693. Incident to the proposal to give priority to requests that are pre-confirmed, the

NOPR proposed a new definition of Pre-Confirmed Application.

Comments

1694. No commenters oppose the Commission’s proposed definition of a Pre-Confirmed

Application.

Commission Determination

1695. The Commission adopts the proposed definition of Pre-Confirmed Application in

order to implement the reforms adopted above regarding the priority of transmission

service requests under the pro forma

OATT.

Docket Nos. RM05-17-000 and RM05-25-000 - 993 -

e. NOPR Proposals Not Adopted

Economy Energy

1696. The Commission also proposed in the NOPR to adopt a definition of “economy

energy” incident to its proposed changes to section 28.4 regarding the use of secondary

network service. As discussed in section V.D.7, the Commission retains the existing

requirement in section 28.4 that permits use of secondary network service “to deliver

energy to its Network Loads.” The proposed definition of “economy energy” is therefore

unnecessary.

f. Commenter Proposals

1697. Several commenters request that the Commission amend or add other definitions

in the pro forma

OATT.

(1) Network Transmission Service

Comments

1698. TDU Systems and Northwest Parties contend that, to help eliminate undue

discrimination, the Commission should modify the definitions of “network load” and

“network operating committee” in the pro forma

OATT. Although the pro forma OATT

already defines “network load” to include wholesale native load, TDU Systems contend

that transmission providers frequently either give preference to their own retail native

load or ignore wholesale customer native load in planning and expansion of the system

and in ATC calculations for processing transmission service requests. TDU Systems

argue that comparable treatment of wholesale native load and retail native load is

Docket Nos. RM05-17-000 and RM05-25-000 - 994 -

required in all respects in light of the definition of “network load.” At the same time,

TDU Systems argue that the definition of “network load” unreasonably restricts a

transmission customer from serving a part of its load at a given delivery point with non-

network resources since it provides that a customer “may not designate only part of the

load at a discrete Point of Delivery.”

1699. Northwest Parties also assert that the Commission should revise the definition of

“network load” to permit point-to-point service and network service to the same network

load if the point-to-point service is ignored in calculating load ratio share. Northwest

Parties also argue that the Commission should allow point-to-point and network service

to the same network load if the point-to-point service is purchased as non-firm.

1700. EEI replies in opposition to TDU Systems’ proposal to eliminate the requirement

that a network customer may designate only part of its load delivery as a network load.

EEI argues that TDU Systems are incorrect in asserting that the definition of “network

load” prohibits a network customer from serving part of its load with non-network

resources and secondary network service to serve part, or even all, of its network load.

EEI contends that adoption of TDU Systems’ proposal would eliminate one of the

fundamental principles on which network service is founded: that the network customer

must pay for network service based on its entire load, including load served by behind the

meter generation, since the transmission provider must plan its transmission system to

serve the customer’s entire load.

Docket Nos. RM05-17-000 and RM05-25-000 - 995 -

1701. PNM-TNMP agree on reply that Commission should reject a change to the

definition in the pro forma

OATT regarding network load. PNM-TNMP state that the

proposal presupposes that transmission providers discriminate against transmission

customers and provides preferential treatment to their own retail native load in terms of

planning and expansion of the system and in ATC calculations for processing

transmission service requests. PNM-TNMP contend that they treat retail native load

comparably with other network customers in all aspects and believe that any problems

encountered by a transmission customer regarding undue discrimination should be

addressed through the enforcement or complaint process, and that a change to the pro

forma OATT is not warranted.

Commission Determination

1702. The Commission declines to modify the definitions of “network load” and

“network operating committee.” The reforms related to ATC calculation and

transmission planning adopted in this Final Rule adequately address the concerns

regarding undue preference of native load in those areas. With regard to the request to

allow network customers to serve part of their load with non-firm point-point service and

part with network service, the Commission already determined in Order Nos. 888 and

888-A that a transmission customer is not allowed to take a combination of both network

Docket Nos. RM05-17-000 and RM05-25-000 - 996 -

and point-to-point transmission service to serve the same discrete load.

963

We are not

persuaded to modify that policy here.

(2) Firm and Non-Firm Transmission Service

Comments

1703. Powerex contends that “firm transmission service” is not adequately defined or

sufficiently described in the pro forma

OATT to ensure that a transmission customer is

not being required to pay for firm service that is curtailed on a regular basis. For

example, Powerex states the Commission could require that firm transmission service be

available at least 95 percent of the time (excluding force majeure curtailments) in order

for transmission to be defined as “firm.”

1704. Powerex also contends that “non-firm transmission service” is interpreted

differently in different regions. In the Pacific Northwest, Powerex asserts that non-firm

service implies a lower curtailment priority but only as a result of actual transmission

system constraints (i.e.

, once the operating hour has begun, higher priority firm

reservations cannot implement schedules over lower priority non-firm reservation). In

contrast, Powerex argues that, for some transmission providers located in the Desert

Southwest, transmission capacity associated with firm service reservations that have

capacity schedules attached to them (e.g.

, to deliver operating reserves) can also be sold

as non-firm service that could be interrupted in the operating hour by the firm

963

See Order No. 888 at 31,736; Order No. 888-A at 30,259.

Docket Nos. RM05-17-000 and RM05-25-000 - 997 -

reservation. Powerex believes that these two types of service could be described as non-

firm, non-interruptible (for the Pacific Northwest) and non-firm, interruptible (for the

Desert Southwest).

Commission Determination

1705. The Commission finds that the clarifications proposed by Powerex are

unnecessary to remedy undue discrimination in the provision of open access transmission

service. In section V.D.8 of this Final Rule, the Commission requires transmission

providers to post additional information regarding curtailments in order to provide

transparency and allow customers to determine whether they have been treated in the

same manner as other transmission system users. We conclude that existing compliance

and enforcement procedures, coupled with these new posting requirements, are sufficient

to address improper curtailments of service.

(3) System Impact Study

Comments

1706. Powerex urges the Commission to modify sections 1.47 and 17.5 of the pro forma

OATT to clarify that transmission providers are not required to perform system impact

studies for short-term service requests. Specifically, Powerex requests that the

Commission amend the definition of a “system impact study” to refer only to requests for

long-term firm point-to-point service or network service. Powerex argues that short-term

firm point-to-point service requests do not require transmission providers to upgrade their

systems and, as a result, requiring system impact studies for short-term requests often

Docket Nos. RM05-17-000 and RM05-25-000 - 998 -

creates unnecessary burdens for transmission providers by mandating them to use limited

resources to perform studies that do not offer significant benefits to customers. Powerex

contends that the 60-day study period is particularly ill-suited for short-term transmission

requests, most of which are for service that must commence within the study period.

Commission Determination

1707. The Commission declines to modify the definition of “system impact study” or

otherwise modify section 17.5 to restrict system impact studies only to exclude reference

to short-term point-to-point service. Regardless of the length of a service request, a

transmission provider must assess whether a system impact study is required to evaluate

the request for transmission service. Only upon the completion of such an assessment

will the transmission provider be able to identify the impact a particular request will have

on the grid. We conclude that eliminating or shortening the system impact study period

could jeopardize system reliability and therefore reject the modifications proposed by

Powerex.

(4) Definitions for RTOs, ISOs and ITCs

Comments

1708. Wisconsin Electric and International Transmission argue that the terms used in

the pro forma

OATT are inadequate when applied to RTO regions, especially in MISO.

International Transmission and Wisconsin Electric assert that, in an RTO, the

transmission provider and transmission owner are separate entities with separate

functions, thus creating a need for separate definitions. They also contend that additional

Docket Nos. RM05-17-000 and RM05-25-000 - 999 -

definitions may be needed when the transmission owner is an independent stand-alone

transmission company operating within the RTO.

1709. Wisconsin Electric requests that the Commission define the term “transmission

owner” in the pro forma

OATT and specify which of its provisions are applicable to the

transmission provider and which apply to the “transmission owner.” Additionally,

Wisconsin Electric states that the pro forma

OATT includes a definition for “control

area” and the NOPR refers to the geographic area served by transmission providers as its

control area, which in Wisconsin Electric’s view is inaccurate in the case of MISO.

Wisconsin Electric explains MISO has shifted to the use of the NERC functional model

and uses terms such as “balancing authorities,” “generator operators,” “reliability

authorities,” and the like. Wisconsin Electric therefore requests that the Commission

supplant the term “control area” in the pro forma

OATT with a term that is predicated on

the performance of a particular function, not the type of entity performing the function.

1710. International Transmission does not object to the Commission’s proposal to

largely retain the existing definitions set forth in the pro forma

OATT, but asserts that the

Commission should explicitly recognize in the Final Rule that such definitions may be

inadequate when applied to RTOs. International Transmission also asks the Commission

not to require RTOs with additional definitions in their tariffs to remove those definitions

when complying with the Final Rule and, instead, expressly allow RTOs to propose

additional definitions that may be necessary.

Docket Nos. RM05-17-000 and RM05-25-000 - 1000 -

Commission Determination

1711. As explained in section IV.C, all transmission providers – including ISOs and

RTOs – will have an opportunity to demonstrate that departures from the pro forma

OATT, as modified by this Final Rule, are consistent with or superior to the terms and

conditions of the pro forma

OATT. Proposals to amend terms such as “control area” or

“transmission owner” based on a particular set of facts are best left for case-by-case

review.

(5) Other Definitions

Comments

1712. Ameren advocates the modification of a number of other pro forma

OATT

definitions. Ameren proposes definitions for “source” and “sink,” as well as additional

provisions in section 22.2 governing source and sink of transmission. Ameren also

requests clarification of the word “use” in section 30.8, arguing that some entities have

assumed that “use” means scheduled amounts. Ameren argues for an improved

definition of “transmission peak” because the data necessary no longer resides with the

transmission owner in an RTO or ISO. Finally, Ameren suggests a revised definition of

“long-term firm,” which would include only contracts that are longer than one year, not

just one year or longer, arguing it would reduce the number of contracts that are only

one-year in length that are used in the denominator for purposes of calculating the load

ratio share and for ratemaking purposes. On this latter point, Ameren asserts that such

contracts should be reflected as a revenue credit instead. In addition, Ameren believes

Docket Nos. RM05-17-000 and RM05-25-000 - 1001 -

that the current definition of long-term firm point-to-point service in section 1.18 of the

pro forma

OATT makes calculation of load ratio share very difficult in the modern

RTO/Seams Elimination Cost Allocation (SECA) environment.

Commission Determination

1713. The Commission is not persuaded to adopt the revisions proposed by Ameren. We

believe that what constitutes source and sink is sufficiently addressed in Order No. 888

and OASIS related proceedings and we will not expand the discussion here.

964

Order No.

888 also made clear that there are no “load ratio” limitations on the use of interfaces

under section 30.8 of the pro forma

OATT.

965

Otherwise, requests for interface capacity

are subject to the pro forma

OATT procedures. Moreover, Ameren has failed to justify

revising the definition of “transmission peak.” While peak load data ultimately resides

with the RTO or ISO, each transmission provider coordinates this type of data with RTO

or ISO. Finally, we reaffirm that long-term firm service is service with a term of one

year or more. Modifying the term of long-term service to reduce the number of contracts

used in the denominator for purposes of calculating the load ratio share and for

ratemaking purposes may affect how the transmission provider plans its system to service

customers and has not been justified.

964

Redirect-related issues are addressed in section V.D.4.

965

See Order No. 888 at 31,753-54; Order No. 888-A at 30,304-5; see also Sierra

Pacific Power Co., 81 FERC ¶ 61,136 at 61,139-40 (1997); New England Power Pool,

83 FERC ¶ 61,045 at 61,248 (1998).

Docket Nos. RM05-17-000 and RM05-25-000 - 1002 -

E. Enforcement

1714. The Commission attaches substantial importance to strengthening compliance with

the OATT, on monitoring and auditing OATT compliance, including its staff’s efforts to

resolve disputes about compliance through the Enforcement Hotline and other dispute

resolution mechanisms, and on investigating potential and alleged OATT violations. The

expansion of the Commission’s enforcement powers pursuant to EPAct 2005 directly

augmented its ability to enforce the OATT by, among other things, providing authority to

assess civil penalties of up to $1 million for each day that an OATT violation continues.

The Commission intends to use its enforcement powers with respect to the OATT in a

fair and even-handed manner, pursuant to the principles set forth in the Policy Statement

on Enforcement.

1. General Policy

a. Compliance Review Regime

NOPR Proposal

1715. The Commission proposed to maintain a strong program to audit compliance with

the new pro forma

OATT. The audit program would include operational audits similar to

past OATT compliance audits, during which staff may collect information on

implementation of a transmission provider’s OATT. The Commission stated that it

would issue public reports of audit results and noted that contested audits would be

Docket Nos. RM05-17-000 and RM05-25-000 - 1003 -

subject to the Commission’s Final Rule on contested operational audits.

966

Comments

1716. Most initial commenters support a strong staff audit program.

967

Other

commenters counter that staff audits will not be needed if the Commission issues a

corrected pro forma

OATT, especially with respect to RTOs and ISOs.

968

These

commenters argue that formal complaints, Enforcement Hotline calls and random audits

sufficiently inform staff of OATT compliance issues as to make additional staff audits

unnecessary. Southern asserts that, under the separation of function policy, Commission

audit staff should be separated from investigative and enforcement staff. Particular

commenters contend that the Commission should focus compliance efforts on specific

OATT provisions, such as those concerning network service (Arkansas Cities), or on

structural issues such as independent planning and operation of transmission facilities

(Reliant). Nevada Companies suggests that the Commission set up regional audit teams

to foster strong working relationships with transmission providers. EPSA asks the

966

See Procedures for Disposition of Contested Audit Matters, Order No. 675,

71 FR 9698 (Feb. 27, 2006), FERC Stats. & Regs. ¶ 31,209 (2006) (Contested Audit

Matters), order on rehearing and clarification

, Order No. 675-A, 71 FR 29779 (May 24,

2006), FERC Stats. & Regs. ¶ 31,217 (2006).

967

E.g., APPA, AWEA, EEI, Morgan Stanley, NRG, Southern, TAPS, and

Williams.

968

E.g., Ameren, PNM-TNMP, and South Carolina E&G. In reply comments,

TDU Systems urge the Commission to reject this contention.

Docket Nos. RM05-17-000 and RM05-25-000 - 1004 -

Commission to adopt stronger measures than a staff audit program to monitor

compliance. EPSA’s proposed measures include requiring transmission providers to:

designate compliance officers to report OATT violations to company boards; undergo

compliance audits by an independent auditor in response to material violations; and hire

an independent administrator to oversee OATT compliance and regional planning efforts

if a transmission provider has not complied with its new OATT within a specified period

of time. In reply comments, MISO opposes EPSA’s proposal for a third-party

compliance administrator for RTOs and ISOs if they do not timely comply with new

OATT provisions, arguing that these entities already are independent administrators of

transmission grids and planning processes. MISO asserts that inserting an “independent”

authority over OATT compliance by RTOs and ISO would create a superfluous

bureaucratic layer. NRECA opposes EPSA’s proposal because a third-party compliance

administrator or auditor would be too expensive and the Commission cannot delegate its

compliance authority.

1717. Noting that the Commission required RTOs to undertake extensive market

monitoring in Order No. 2000, PJM states that the Commission should require in the pro

forma OATT a similar degree of market monitoring in non-RTO areas to make available

to Commission staff information needed to ascertain market abuses in these areas. PJM

asserts that any such market monitoring should be performed by entities independent of

the non-RTO utilities, with Commission oversight. Indicated Parties reply that RTOs’

market monitors should examine market power in transmission planning because RTOs

Docket Nos. RM05-17-000 and RM05-25-000 - 1005 -

delegate transmission operations and planning duties to constituent transmission owners

that retain incentives to benefit affiliates or vertically-integrated divisions.

Commission Determination

1718. The Commission adopts the NOPR proposal to emphasize a strong staff audit

program for compliance with OATT requirements, including operational audits. Staff

audits of OATT compliance may be random or targeted with respect to the entities being

audited or particular provisions of the OATT that are scrutinized. Because its

responsibility is to assess and ensure compliance with the OATT, staff will maintain

discretion as to the entities it audits and the subject matter of these audits. The

Commission encourages transmission providers to designate employees as compliance

officers for the OATT or to conduct third-party audits relating to OATT compliance

when appropriate. However, we do not believe that staff should forego an audit of an

entity’s OATT compliance solely because a transmission provider has designated an

OATT compliance officer, engaged a third-party auditor, or transferred transmission

functions to an independent transmission coordinator. We decline EPSA’s proposal to

require such actions, except on a case-by-case basis when warranted.

1719. We disagree with PJM’s request that the Commission require third-party market

monitoring to ascertain market abuses occurring with respect to transmission providers

outside RTOs and ISOs, subject to Commission oversight. In a number of instances since

2000, the Commission has established third-party monitoring of a transmission provider

Docket Nos. RM05-17-000 and RM05-25-000 - 1006 -

located outside an RTO or ISO.

969

These monitors were established on a case-specific

basis to address concerns related to the transmission provider at issue. We have no

evidence to support requiring monitors for every transmission provider in the Nation.

Further, the Commission has access to substantial information on OATT compliance by

transmission providers that are not RTOs or ISOs through their postings on OASIS,

informal and formal complaints by customers, and reports by market monitors for such

transmission providers. Indeed, the revised pro forma

OATT will greatly enhance our

oversight and enforcement capabilities by increasing the transparency of many critical

functions under the pro forma

OATT, such as ATC calculation and transmission

planning. PJM has not provided any evidence that the enhanced transparency under the

OATT, coupled with the Commission’s own monitoring and audits of OATT compliance

and its enhanced enforcement authority, will be insufficient to ascertain and deter OATT

violations. We do not object to the suggestion of Indicated Parties that RTO and ISO

market monitors examine market power in transmission planning, so long as the market

monitors’ activities in this respect are consistent with these roles as set forth in the

applicable RTO and ISO tariffs.

1720. We do not agree with Southern’s assertion that the Commission’s audit staff

should be separated from its investigative and enforcement staff. The Commission’s

969

See, e.g., Duke Power, 113 FERC ¶ 61,288 (2005); MidAmerican Energy

Holdings Co., 113 FERC ¶ 61,298 (2005).

Docket Nos. RM05-17-000 and RM05-25-000 - 1007 -

separation of functions regulation

970

generally permits Commission auditors,

investigators and enforcement staff to speak freely to persons inside the Commission as

to the subject matter of their inquiries.

971

Southern has not cited any justification for

restricting communications among these staff members or from them to the Commission.

To the contrary, a free flow of communications among auditors and investigators,

consistent with the Commission’s rule on staff separation of functions, should increase

the efficiency of the Commission staff’s compliance program and enforcement efforts.

972

b. Use of Independent Third Party Audits

NOPR Proposal

1721. The Commission proposed not to mandate the use of third party auditors and,

instead, proposed that Commission staff conduct audits of compliance with the pro forma

OATT. The Commission stated that it may require third party compliance audits as part

of a compliance plan following a Commission staff audit report. In response to situations

such as systematic OATT violations, a pattern of repeated violations, or violations that

970

18 CFR 385.2202.

971

Statement of Administrative Policy on Separation of Functions, 101 FERC

¶ 61,340 at P 24-26 (2002).

972

See also Order No. 675-A at P 25-29 (the Commission’s regulation and policy

statement on separation of functions remain applicable following EPAct 2005, and

efficiency and sound administrative practice continue to favor the sharing of information

between the Commission’s audit staff and investigative staff).

Docket Nos. RM05-17-000 and RM05-25-000 - 1008 -

require ongoing monitoring, the Commission could require an audited party to hire a third

party to continue compliance audits.

Comments

1722. Most initial commenters agree with the Commission’s proposal to require third-

party audits only as part of an individual post-audit compliance plan.

973

EEI and

Southwestern Coop submit that selection of third-party auditors should be subject to

Commission review and approval, while South Carolina E&G cautions that the

Commission should carefully weigh the costs and benefits of independent auditors before

requiring their use. Southern suggests that third-party audits be required only for

systematic, egregious OATT violations. Entegra doubts that third-party auditors can

remedy patterns of discrimination by transmission providers against independent

merchant generators.

Commission Determination

1723. The Commission adopts the NOPR proposal not to require generally the use of

third party auditors to assess compliance with the OATT. We believe that a requirement

for the use of third-party audits in compliance plans should depend on particular facts,

including the egregiousness and extent of violations found during a staff audit or

investigation and the appropriate scope or cost of a third-party audit. As stated above, we

973

E.g., Alberta Intervenors, Arkansas Commission, Constellation, EEI, EPSA,

MISO/PJM States, Nevada Companies, PNM-TNMP, South Carolina E&G,

Southwestern Coop, and Suez Energy NA.

Docket Nos. RM05-17-000 and RM05-25-000 - 1009 -

encourage transmission providers to use third-party compliance audits when appropriate

to supplement our staff’s audit efforts.

2. Civil Penalties

1724. In the NOI, the Commission asked for comment as to whether it should address

imposing remedies or penalties against transmission providers as part of OATT reform.

After the NOI, the Commission issued its Policy Statement on Enforcement and, in

response to specific authority granted it in EPAct 2005, issued Order No. 670, the Anti-

manipulation Rule.

974

a. Whether Civil Penalties Should Be Specified in the OATT

NOPR Proposal

1725. Aside from operational penalties proposed in the NOPR,

975

the Commission

proposed not to establish a schedule of enforcement remedies and sanctions in the pro

forma OATT. Rather, the Commission stated that it would address OATT violations and

appropriate responses on a case-by-case basis, consistent with the Policy Statement on

Enforcement. The Commission explained that it may impose civil penalties when

warranted, after consideration of applicable factors listed in the Policy Statement on

974

Prohibition of Energy Market Manipulation, III FERC Stats. & Regs. ¶ 31,202

(2006), order denying rehearing

, 114 FERC ¶ 61,300 (2006).

975

NOPR at P 384.

Docket Nos. RM05-17-000 and RM05-25-000 - 1010 -

Enforcement; OATT violators also will be expected to disgorge unjust profits when they

can be determined or reasonably estimated.

Comments

1726. The majority of parties filing comments on this issue agree that the Commission

should assess civil penalties on a case-by-case basis under the guidance of the Policy

Statement on Enforcement.

976

Other commenters instead support incorporation in the pro

forma OATT of a schedule of significant remedies and sanctions for specific violations to

assure transparency and certainty as to situations in which penalties would be assessed

and to deter anticompetitive behavior.

977

EPSA advises that the Commission refrain from

setting pre-determined limits on penalty amounts because each violation of a specific pro

forma OATT provision may present different facts that may warrant different outcomes.

Nevada Companies suggest that the Commission provide incentives to construct new

transmission infrastructure rather than implement an overbearing penalty regime because

additional transmission capacity itself will resolve many complaints.

1727. Wisconsin Electric concludes that OATT violations by non-profit RTOs and ISOs

should not be subject to civil penalties because they would be passed through to

976

E.g., APPA, EEI, EPSA, Nevada Companies, PNM-TNMP, Southern, and

Southwestern Coop. Southwestern Coop also urges speedy review of violations and swift

assessment of penalties. In reply comments, Sacramento adds that the Commission may

assess civil penalties against a transmission provider that engages in unduly

discriminatory behavior in its transmission planning process.

977

E.g., Arkansas Commission and ELCON.

Docket Nos. RM05-17-000 and RM05-25-000 - 1011 -

customers and not act as an effective deterrent.

978

Rather than assess a penalty in

response to an RTO’s or ISO’s OATT violation, Wisconsin Electric suggests that the

Commission could intensify oversight of an RTO’s or ISO’s OATT compliance.

NorthWestern comments, in contrast, that RTOs and ISOs should not be exempted from

civil penalty assessments for their OATT violations, because these violations could have

as much or more adverse effects on transmission access or system reliability as would

OATT violations by other transmission providers.

1728. Several commenters support the Commission’s proposal to consider mitigating

factors listed in the Policy Statement on Enforcement in assessing civil penalties for

OATT violations.

979

In this regard, EEI states that the Commission should clarify that

when a party engages in self-reporting, compliance programs or cooperation with

Commission staff, the Commission will recognize the party’s attorney-client privilege.

980

1729. EEI suggests that the Commission establish “safe harbors” against civil penalties

for OATT violations involving reasonable interpretations of tariff provisions or for

978

Wisconsin Electric asserts that the Commission has recognized this principle in

other contexts, citing

Financial Reporting and Cost Accounting, Oversight and Recovery

Practices for Regional Transmission Organizations and Independent System Operators,

FERC Stats. & Regs. ¶ 35,546 at P 9 (2004).

979

E.g., Nevada Companies and PNM-TNMP.

980

EEI observes that the Commission held in its final rule on contested audit

procedures that “an audited person who appropriately interposes the attorney-client

privilege will not be considered non-cooperative.” Contested Audit Matters at P 35.

Docket Nos. RM05-17-000 and RM05-25-000 - 1012 -

actions taken for reliability purposes that are consistent with good utility practice. PNM-

TNMP and Southern ask the Commission to clarify that LSEs will not be penalized for

OATT violations for taking actions necessary to meet their native load obligations since,

pursuant to new FPA section 217,

981

LSEs should not be considered to have engaged in

“undue discrimination or preference” for certain actions required to serve native load

customers. TDU Systems argue in reply comments that a “safe harbor” approach could

permit unduly discriminatory or preferential behavior that would be penalized under a

case-by-case approach. Entegra replies that safe harbors for “reasonable” tariff

interpretations would give vertically-integrated utilities license to discriminate against

competitors, and suggests that the Commission ensure that the OATT operates as a sword

for attacking undue discrimination, not as a shield for defending it. Occidental replies

that transmission providers with a Commission-approved independent transmission

coordinator should not be insulated from tariff-based civil penalties and other sanctions.

Commission Determination

1730. Following enactment in EPAct 2005 of enhanced authority for the Commission to

assess civil penalties for violations of statutes it administers and of regulations and orders

under these statutes, the Commission issued the Policy Statement on Enforcement to set

forth how it intends to use this authority consistent with the statute.

982

Underlying this

981

16 U.S.C. 824q(k).

982

Policy Statement on Enforcement at P 1.

Docket Nos. RM05-17-000 and RM05-25-000 - 1013 -

policy is the recognition that the appropriate basis for assessment of a civil penalty for a

violation is an examination of the facts and circumstances relating to that violation, and

the use of discretion and flexibility to address it on its merits. This examination includes

a review of all applicable mitigating factors set forth in the Policy Statement on

Enforcement. While we understand that establishing a schedule of civil penalties for

violations of particular provisions of the pro forma

OATT would establish greater

specificity with respect to civil penalties, the Commission already concluded in the

Policy Statement on Enforcement that it would “not prescribe specific penalties or

develop formulas for different violations.”

983

We see no justification to depart from that

decision with respect to violations of OATT provisions.

1731. Several commenters ask that we establish specific “safe harbors” or exemptions

from assessment of civil penalties for OATT violations in specific circumstances or with

respect to specific types of entities that may engage in OATT violations. We decline to

create automatic safe harbors for specific circumstances or specific types of OATT

violations. The creation of such exemptions would require us to forego the examination

of the specific circumstances of particular violations that we described in the Policy

Statement on Enforcement as the touchstone of our policy in assessing civil penalties.

Instead, we will decide requests for leniency in particular cases by using the principles set

983

Id. at P 13.

Docket Nos. RM05-17-000 and RM05-25-000 - 1014 -

forth in the Policy Statement on Enforcement and considering all applicable mitigating

factors listed therein.

984

1732. Likewise, we will not establish an automatic exemption from civil penalty

assessments for OATT violations committed by particular types of entities such as non-

profit RTOs and ISOs. The Commission decided last year that it would not automatically

exempt RTOs and ISOs from penalties assessed by the Electric Reliability Organization

or Regional Entities for reliability violations pursuant to new FPA section 215. In Order

No. 672, the Commission stated, “[w]hile we recognize that RTOs and ISOs have some

unique characteristics, we do not believe that a generic exemption from any type of

penalty is appropriate for any entity, including an RTO or ISO.”

985

We believe the same

principle applies to civil penalties for OATT violations. However, in assessing civil

penalties for OATT violations, we will consider all applicable facts relating to the

984

We have also provided clarification on the procedures that would apply to the

assessment in formal proceedings of civil penalties relating to OATT violations in our

recent Statement of Administrative Policy Regarding the Process for Assessing Civil

Penalties, 117 FERC ¶ 61,317 (2006).

985

Rules Concerning Certification of the Electric Reliability Organization; and

Procedures for the Establishment, Approval, and Enforcement of Electric Reliability

Standards, Order No. 672, 71 FR 8662 (Feb. 17, 2006), FERC Stats. & Regs. ¶ 31,204 at

P 634 (2006), order on reh’g

, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).

Docket Nos. RM05-17-000 and RM05-25-000 - 1015 -

violator, including the effect of potential penalties on the financial viability of the

violator.

986

1733. We agree with commenters who state that the Commission and its staff should

recognize the valid assertion of the attorney-client privilege in the context of

investigations, audits and other fact-finding activities. As EEI points out, we recently

stated with respect to audits that we would not consider an entity to be uncooperative

with audit staff if the entity appropriately asserts that a communication or document is

covered by that privilege.

987

We take the same position with respect to investigations or

other fact-finding undertakings with respect to possible OATT violations.

1734. In the Policy Statement on Enforcement, however, the Commission drew a

distinction between cooperation, which we expect from entities subject to the

Commission’s jurisdiction given their statutory obligation to provide information to us,

and “exemplary” cooperation, which “quickly ends wrongful conduct, determines the

facts, and corrects a problem.”

988

The Commission explained that we will give some

consideration to exemplary cooperation and indicated that one example of such

986

Policy Statement on Enforcement at P 20. Cf. Order No. 672-A at P 56-57

(holding that for determining a penalty pursuant to the FPA section 215 reliability

program, circumstances such as organization structure or non-for-profit status will be

considered, but that there should not be an automatic exemption from monetary penalties

for RTOs and ISOs).

987

Citing Contested Audit Matters at P 35.

988

Policy Statement on Enforcement at P 26.

Docket Nos. RM05-17-000 and RM05-25-000 - 1016 -

cooperation is a situation in which an entity being investigated provides to staff internal

investigations or audit reports relating to misconduct. These investigations and reports

may include information that an entity could properly shield from disclosure pursuant to

the attorney-client privilege. We observe that an entity that is in a position to assert this

privilege validly also has the option to waive it. If a waiver of attorney-client privilege,

whether related to an internal investigation or audit or not, assists staff in ascertaining the

facts relating to alleged or apparent misconduct, ends misconduct quickly or otherwise

substantially advances an investigation or inquiry, that waiver may be an element in

finding “exemplary cooperation” as described in the Policy Statement on Enforcement.

989

b. Whether Transmission Providers Should Be Subject to

Revocation of Market-Based Rates for OATT Violations

NOPR Proposal

1735. The Commission observed in the NOPR that some OATT violations, after

applying the factors in the Policy Statement on Enforcement to all facts and

circumstances, may merit revocation of market-based rate authority. Before considering

revoking an entity’s market-based rate authority for an OATT violation, the Commission

proposed that it must find a nexus between the specific facts relating to the OATT

989

See In re PacifiCorp, 118 FERC ¶ 61,026 at P 3, 8 and attached stipulation and

consent agreement at P 24 (2007) (referring to transmission provider’s waivers of

attorney-client privilege as an element in making finding of exemplary cooperation with

investigation when approving settlement assessing civil penalty that resolved a

transmission provider’s violations of its OATT, among other matters); In re Entergy

Services, Inc., 118 FERC ¶ 61,027 at P 15, 18 (2007) (same).

Docket Nos. RM05-17-000 and RM05-25-000 - 1017 -

violation and the entity’s market-based rate authority. The Commission also proposed

that if it determines, as a result of a significant OATT violation, to revoke the market-

based rate authority of a transmission provider within a particular market, each affiliate of

the transmission provider that possesses market-based rate authority would have that

authority revoked in that market, effective on the date of revocation of the transmission

provider’s market-based rate authority.

Comments

1736. Most parties that submitted initial comments on this issue support the

Commission’s conclusion that, in certain circumstances, it may be appropriate to revoke

the market-based rate authority of an entity that engages in an OATT violation.

990

The

majority of these commenters support the Commission’s proposal to do so only if it finds

a nexus between the OATT violation and the entity’s market-based rate authority.

991

1737. Some commenters oppose the requirement for a nexus between the OATT

violation and the entity’s market-based rate authority because the Commission has not

stated what facts would be sufficient to show such a nexus.

992

EPSA and NRECA (in

reply comments) contend that if the Commission does not remove the “nexus” condition,

990

E.g., EEI, ELCON, Morgan Stanley, Nevada Companies, Northwest IOUs,

Progress Energy, PNM-TNMP, Sempra Global, Southern, and TDU Systems.

991

E.g., EEI, Nevada Companies, Northwest IOUs, Progress Energy, PNM-

TNMP, Sempra Global, and Southern.

992

E.g., APPA.

Docket Nos. RM05-17-000 and RM05-25-000 - 1018 -

it should clarify what constitutes a “nexus” between an OATT violation and an entity’s

market-based rate authority. Similarly, PNM-TNMP argues that such a nexus must be

clear and fact-specific, consistent with the Policy Statement on Enforcement. TDU

Systems contend in reply comments that, at a minimum, a transmission provider or its

affiliate that has market-based rate authority must overcome a rebuttable presumption

that its OATT violation has the requisite “nexus” to support revocation of such authority.

1738. Other commenters argue that a serious OATT violation removes the mitigation of

transmission market power provided by adherence to an OATT, thereby eviscerating one

of the essential requirements for market-based rate authority.

993

EEI and PNM-TNMP

reply that not every OATT violation diminishes the availability of transmission service so

as to establish vertical market power.

1739. APPA and TDU Systems suggest in reply comments that the proposed nexus

condition would unduly limit any sanctions, because the shareholders of the violator

could still reap the benefits of such a violation if an affiliate that did not have any

knowledge of the OATT violation could continue to engage in transactions under market-

based rate authority. According to APPA, this possibility could lessen the incentive for

senior management over a transmission provider and affiliates to make OATT

compliance a high priority. As such, APPA and TAPS suggest that the Commission

consider revoking a transmission provider’s market-based rate authority for a “material”

993

E.g., APPA, EPSA, and TAPS.

Docket Nos. RM05-17-000 and RM05-25-000 - 1019 -

OATT violation that effectively denies, delays, or diminishes a customer’s access to

transmission service essential to mitigating transmission market power.

1740. TDU Systems caution that revocation of market-based rate authority may not be

sufficient to deter OATT violations if reversion to cost-based rates may provide a

transmission provider with the ability to recover all costs and receive higher revenues

than competitive markets might otherwise produce. Therefore, TDU Systems ask that the

Commission consider assessment of civil penalties in addition to revocation of market-

based rate authority.

1741. The majority of commenters disagree, however, with the Commission’s proposal

to revoke the market-based rate authority of all affiliates of a transmission provider to the

same extent that we revoke that transmission provider’s market-based rate authority.

994

These commenters assert that affiliates that have no knowledge of, or involvement in,

their affiliated transmission provider’s unlawful activities should not lose their market-

based rate authority as a result of the transmission provider’s OATT violation. NRECA

replies that market-based rate authority is a privilege, not a right, and asserts that the

Commission should revoke market-based rate authority in response to an OATT violation

that indicates that a public utility possesses market power.

994

E.g., EEI, Nevada Companies, Northwest IOUs, Progress Energy, PNM-

TNMP, Sempra Global, and Southern.

Docket Nos. RM05-17-000 and RM05-25-000 - 1020 -

1742. APPA also suggests that, short of revocation of a transmission provider’s market-

based rate authority in response to an OATT violation, the Commission could condition

that authority, or the market-based rate authority of the transmission provider’s affiliates.

APPA provides the following examples of such conditions: a requirement to participate

in joint planning of transmission facilities with the transmission provider’s network

customers and offer these customers appropriate credits under OATT section 30.9; an

offer of joint transmission ownership opportunities to LSEs for new transmission

facilities on reasonable terms and conditions; and an offer to network service customers

to participate in the ownership of the transmission provider’s existing transmission

system on a load ratio share basis.

Commission Determination

1743. We adopt the NOPR proposal to revoke an entity’s market-based rate authority in

response to an OATT violation only upon a finding of a specific factual nexus between

the violation and the entity’s market-based rate authority. We believe that the “nexus

condition” is required in order to ensure that our actions are not arbitrary or capricious or

based on an inadequate factual record. We note that in this context the Commission has

the burden to show a factual nexus. We do not assign a burden on the violator to show

the lack of this nexus.

1744. Determining what would be a sufficient factual nexus between an OATT violation

and revocation of the violator’s market-based rate authority is best left to a case-by-case

consideration. The wide range of positions among commenters on how to define a

Docket Nos. RM05-17-000 and RM05-25-000 - 1021 -

sufficient factual nexus itself suggests that this finding is best made after review of a

specific factual situation. Some commenters assert that a finding of a “serious” or

“material” violation of the OATT would be sufficient. We disagree. While an entity’s

inconsequential OATT violation would not serve as a basis for revoking that entity’s

market-based rate authority, our view is that the nexus condition requires us to find both

that a substantial OATT violation has occurred and that the violation either related to the

exercise of the violator’s market-based rate authority or violated a specific condition of

that authority.

1745. The Commission emphasizes that we have discretion to fashion remedies for

OATT violations that relate to the violator’s market-based rate authority in instances in

which we do not find a factual nexus justifying revocation of that authority. For

example, in appropriate circumstances, we may modify or add additional conditions to

the violator’s market-based rate authority or impose other requirements to help ensure

that the violator does not commit future, similar misconduct. Nor is revocation of

market-based rate authority the only action we may take to respond to an OATT violation

that meets the nexus condition. We will consider whether to impose sanctions such as

assessment of civil penalties for particularly serious OATT violations in addition to

revocation of the violator’s market-based rate authority.

1746. We do not adopt our proposal from the NOPR to revoke the market-based rate

authority of each affiliate of a transmission provider that loses its market-based rate

authority within a particular market as a result of an OATT violation. Rather, we will

Docket Nos. RM05-17-000 and RM05-25-000 - 1022 -

create a rebuttable presumption that all affiliates of a transmission provider should lose

their market-based rate authority in each market in which their affiliated transmission

provider loses its market-based rate authority as a result of an OATT violation. We will

allow an affiliate of a transmission provider to retain its market-based rate authority in a

market area if the affiliate overcomes the rebuttable presumption with respect to that

market area.

1747. We expect that the issue of potential revocation of market-based rate authority will

arise as a result of an OATT violation in a market in which the transmission provider

possesses transmission market power through the ownership of transmission facilities in

that market. For these markets, we have evaluated whether a transmission provider

should receive authority to make sales of electric power for resale at market-based rates

using a four-prong analysis. In this analysis we consider whether the transmission

provider and its affiliates have adequately mitigated market power in generation and

transmission, whether the transmission provider or its affiliates can erect other barriers to

entry, and whether there is evidence that the transmission provider and its affiliates have

engaged in affiliate abuse or reciprocal dealing.

995

In particular, we have long held that

995

In our recent NOPR on market-based rates for wholesale sales of electricity, the

Commission proposed to discontinue referring to affiliate abuse among a transmission

provider and its affiliates as a separate “prong” of our analysis of whether to grant

market-base rate authority. The Commission instead proposed to address affiliate abuse

by requiring that transmission providers and their affiliates comply with restrictions and

conditions set forth in the regulations we propose in that proceeding. Market-Based

(continued)

Docket Nos. RM05-17-000 and RM05-25-000 - 1023 -

the existence of an OATT is deemed to mitigate vertical market power and transmission

market power held by a transmission provider and its affiliates in a particular market. An

OATT violation by a transmission provider in a market in which it possesses

transmission market power that merits revocation of the transmission provider’s market-

based rate authority may call into question whether the transmission provider’s affiliates

continue to qualify for market-based rates in that market under the standards that we have

established.

996

As a result, we believe that it is appropriate to establish a presumption in

Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public

Utilities, 71 FR 33102 (Jun. 7, 2006), FERC Stats. & Regs. ¶ 32,602 at P 13 (2006).

996

We observe that specific situations in which transmission providers have

agreed to resolve staff allegations that they engaged in OATT violations have involved

transactions with affiliates. See

Idaho Power (settlement of, among other issues, an

Enforcement staff allegation that a transmission provider permitted its merchant function

to request non-firm transmission to enable the merchant function to make off-system

sales that by definition were not used to serve native load, so that the transmission did not

qualify for the “native load” priority specified in section 28.4 of the transmission

provider’s OATT); Cleco Corp.

, 104 FERC ¶ 61,125 (2003) (settlement between

Enforcement staff and a utility holding company and its subsidiaries relating, in part, to

the provision by a transmission provider of a unique type of transmission service that was

neither made available to non-affiliates nor included in its FERC tariff); Tucson Electric

Power Co., 109 FERC ¶ 61,272 (2004) (operational audit in which staff found that,

among other matters, a transmission provider permitted its wholesale merchant function

to purchase hourly non-firm and monthly firm point-to-point transmission service using

an off-OASIS scheduling procedure while the transmission provider did not post on its

OASIS the availability of capacity on these paths); South Carolina Electric & Gas Co.

111 FERC ¶ 61,217 (2005) (settlement of Enforcement staff allegation that a

transmission provider made available firm point-to-point transmission service to its

affiliated merchant function that did not submit transmission schedules with specific

receipt points for the service as required by section 13.8 of the transmission provider’s

OATT); and MidAmerican Energy Co.

, 112 FERC ¶ 61,346 (2005) (operational audit in

which staff found, among other things, that a transmission provider permitted its

(continued)

Docket Nos. RM05-17-000 and RM05-25-000 - 1024 -

this circumstance that if we find that a transmission provider should lose its market-based

rate authority in a market in which it possesses transmission market power, we will

revoke the market-based rate authority in that market of all affiliates of the transmission

provider.

1748. We are mindful, however, that the circumstances of a particular affiliate may not

always justify the imposition of a remedy so severe as revocation of market-based rate

authority in a particular market when its affiliated transmission provider loses its market-

based rate authority in that market as a result of an OATT violation. To afford due

process to a transmission provider’s affiliates in that situation, and to ensure that a

determination to revoke market-based rate authority in a particular market for a

transmission provider and all of its affiliates that possess such authority is adequately

based upon record evidence and not arbitrary or capricious, we will allow an opportunity

for each such affiliate to make a showing that it should retain its market-based rate

authority or that enforcement action against it should be less severe than revocation. The

determination whether an affiliate has overcome the rebuttable presumption depends on

wholesale merchant function to (a) use network transmission service to bring short-term

energy purchases onto its system while it simultaneously made off-system sales,

inconsistently with the preamble to Part III of the transmission provider’s OATT and

section 28.6 of its OATT; and (b) confirm firm network transmission service requests

without identifying a designated network resource or acquiring an associated network

resource, in some instances using this service to deliver short-term energy purchases used

to facilitate off-system sales, inconsistent with section 29.2 or section 30.6 of the

transmission provider’s OATT). See also

Commission orders cited in note 989 supra.

Docket Nos. RM05-17-000 and RM05-25-000 - 1025 -

an analysis of specific facts in the record. Relevant facts would include, but are not

limited to, whether: (1) the transmission provider and the affiliate were under the same

control; (2) the affiliate knew of, participated in or was an accomplice to the OATT

violation; (3) the affiliate assisted the transmission provider in exercising market power;

or (4) the affiliate benefited from the violation.

c. Whether Certain OATT Violations Should Be Considered

Market Manipulation under Section 222 of the FPA

NOPR Proposal

1749. The Commission proposed in the NOPR to decline to identify in the pro forma

OATT specific conduct that constitutes per se

market manipulation. The Commission

proposed to consider on a case-by-case basis, if and when they arise, whether specific

circumstances relating to OATT violations constitute market manipulation under the

standards set forth in Order No. 670.

Comments

1750. All commenters on this issue concur with a case-by-case approach to it.

997

Southwestern Coop suggests that, as the Commission gains sufficient experience to

describe particular misconduct as market manipulation per se

, it should identify such

misconduct in the OATT. While contending that the Commission should act with caution

in listing behaviors that constitute per se

market manipulation in view of the dynamic

997

APPA, Nevada Companies, PNM-TNMP, Southwestern Coop, and TDU

Systems.

Docket Nos. RM05-17-000 and RM05-25-000 - 1026 -

nature of markets, TDU Systems urge the Commission to specify in the OATT that

transmission planning misconduct could constitute a form of market manipulation or

abuse.

Commission Determination

1751. We adopt the NOPR proposal for a case-by case approach to considering whether

OATT violations may constitute market manipulation. Without reference to a specific

factual pattern developed in an investigation or on-the-record proceeding, the

Commission is not in a position to identify market manipulation relating to OATT

violations.

998

VI. Information Collection Statement

1752. The Office of Management and Budget (OMB) regulations require that OMB

approve certain reporting, record keeping, and public disclosure (collections of

information) imposed by an agency.

999

Pursuant to OMB regulations, the Commission is

providing notice of its proposed information collections to OMB for review under section

3507(d) of the Paperwork Reduction Act of 1995.

1000

998

Similarly, in issuing the Anti-manipulation Rule, we declined to provide

specific examples of what would constitute market manipulation. Order No. 670 at P 64-

67.

999

5 CFR 1320.11.

1000

44 U.S.C. 3507(d).

Docket Nos. RM05-17-000 and RM05-25-000 - 1027 -

1753. The Commission identifies the information provided under Part 35 subpart C as

contained in FERC-516 and Part 37 as contained in FERC-717. The Commission

solicited comments on the need for this information, whether the information will have

practical utility, ways to enhance the quality, utility, and clarity of the information to be

collected, and any suggested methods for minimizing respondents’ burden, including the

use of automated information exchanges. The Commission did not receive any specific

comments regarding its burden estimates. Where commenters raised concerns that

specific information collection requirements would be burdensome to implement, the

Commission has address those concerns elsewhere in the rule.

1754. The Commission estimates the burden for complying with the Final Rule is as

follows:

1001

Data

Collection

Number of

Respondents

Number of

Responses

Hours per

Response

Total Annual

Hours

Part 35

(FERC-516)

Conforming

tariff changes

116 1 25 2,900

Revision of

Imbalance

Charges

116 1 5 580

ATC revisions 116 1 40 4,640

Planning

(Attachment K)

116 1 200 23,200

Congestion

studies

116 1 300 34,800

1001

These burden estimates applied only to the Final Rule and do not reflect upon

all of FERC-516 or FERC-717.

Docket Nos. RM05-17-000 and RM05-25-000 - 1028 -

Attestation of

network

resource

commitment

116 1

1 116

Capacity

reassignment

116 1 100 11,600

Operational

Penalty annual

filing

116 1 10 1,160

Creditworthines

s – include

criteria in the

tariff

116 1 40 4,640

Sub Total Part

--- 83,636

Part 37

(FERC-717)

ATC-related

standards:

NERC/NAESB

Team to

develop

Review and

comment by

utility

Implementation

by each utility

116

1,920

2,320

4,640

Mandatory data

exchanges

116 1 80 9,280

Explanation of

change of ATC

values

116 1 100 11,600

Reevaluate

CBM and post

quarterly

116 1 20 2,320

Docket Nos. RM05-17-000 and RM05-25-000 - 1029 -

Post OASIS

metrics;

requests

accepted/denied

116 1 90 10,440

Post planning

redispatch

offers and

reliability

redispatch data

116 1 20 2,320

Post curtailment

data

116 1 10 11,160

Post Planning

and System

Impact Studies

116 1 5 580

Posting of

metrics for

System Impact

Studies

116 1 100 11,600

Post all rules to

OASIS

116 1 5 580

Sub Total

(Part 37)

--- 68,760

Total (Part 35 +

Part 37)

- - - 140,476

Recordkeeping 116 1 40 4,640

1755. Information Collection Costs

: No comments were received regarding the

Commission’s estimate of costs to comply with these requirements. The Commission has

projected costs of compliance as follows:

Total Annual Hours for Collection:

Reporting + recordkeeping hours = 152,396 + 4,640 = 157,036 hours.

Cost to Comply

Reporting = $17,373,144

152,396 hours @ $114 an hour (average cost of attorney ($200 per hour),

consultant ($150), technical ($80), and administrative support ($25))

Docket Nos. RM05-17-000 and RM05-25-000 - 1030 -

Recordkeeping = $7,478,888

Labor (file/record clerk @ $17 an hour) 4,640 hours @$17/hour = $78,880

Storage 8,000 sq. ft. x $925 (off site storage) = $7,400,000

Total costs = $24,852,024

Labor $ ($17,373,144 + $78,880) + Recordkeeping Storage Costs ($7,400,000)

Title

: FERC-516, Electric Rate Schedules and Tariff Filings;

FERC-717 Standards for Business Practices and Communication Protocols for Public

Utilities.

Action

: Proposed Collections

OMB Control Nos

. 1902-0096 and 1902-0173

Respondents

: Business or other for profit

Frequency of responses

: On occasion.

Necessity of the Information

: The Federal Energy Regulatory Commission adopts

these amendments to its regulations adopted in Order Nos. 888 and 889, and to the pro

forma open access transmission tariff, to ensure that transmission services are provided

on a basis that is just, reasonable and not unduly discriminatory or preferential. The

purpose of this rulemaking is to strengthen the pro forma

OATT to ensure that it achieves

its original purpose – remedying undue discrimination – not to create new market

structures. We propose to achieve this goal by increasing the clarity and transparency of

the rules applicable to the planning and use of the transmission system and by addressing

ambiguities and the lack of sufficient detail in several important areas of the pro forma

OATT. The lack of specificity in the pro forma

OATT creates opportunities for undue

Docket Nos. RM05-17-000 and RM05-25-000 - 1031 -

discrimination as well as making the undue discrimination that does occur more difficult

to detect. To accomplish this we are proposing five objectives: (1) to improve

transparency and consistency in several critical areas, by providing for greater

consistency in the calculation of ATC, (2) to reform the transmission planning

requirements of the pro forma

OATT to eliminate potential undue discrimination and

support the construction of adequate transmission facilities to meet the needs of all LSEs,

(3) to remedy certain portions of the pro forma

OATT that may have permitted utilities to

discriminate against new merchant generation, including intermittent generation, (4) to

provide for greater transparency in the provision of transmission service to allow

transmission customers better access to information to make their resource procurement

and investment decisions, as well as to increase the Commission’s ability to detect any

remaining incidents of undue discrimination; and (5) to reform and provide greater clarity

in areas that have generated recurring disputes over the past 10 years, such as rollover

rights, “redirects,” and generation redispatch. The reforms proposed in this Final Rule

are intended to address deficiencies in the pro forma

OATT that have become apparent

since the implementation of Order No. 888 in 1996 and to facilitate improved planning

and operation of transmission facilities.

1756. Interested persons may obtain information on the reporting requirements by

contacting the following: Federal Energy Regulatory Commission, 888 First Street, N.E.,

Washington, D.C. 20426, Attention: Michael Miller, Office of the Executive Director,

Phone: (202) 502-8415, fax: (202) 273-0873, e-mail: [email protected]

Docket Nos. RM05-17-000 and RM05-25-000 - 1032 -

1757. For submitting comments concerning the collections of information and the

associated burden estimate(s), please send your comments to the contact listed above and

to the Office of Information and Regulatory Affairs, Office of Management and Budget,

725 17th Street, N.W., Washington, D.C. 20503 Attention: Desk Officer for the Federal

Energy Regulatory Commission, phone (202) 395-3122, fax: (202) 395-7285. Due to

security concerns, comments should be sent electronically to the following e-mail

address: [email protected]. Please reference the docket number of this

rulemaking in your submission.

VII. Environmental Analysis

1758. The Commission is required to prepare an Environmental Assessment or an

Environmental Impact Statement for any action that may have a significant adverse effect

on the human environment.

1002

The Commission concludes that neither an

Environmental Assessment nor an Environmental Impact Statement is required for this

Final Rule under section 380.4(a)(15) of the Commission’s regulations, which provides a

categorical exemption for approval of actions under sections 205 and 206 of the FPA

relating to the filing of schedules containing all rates and charges for the transmission or

1002

Regulations Implementing the National Environmental Policy Act, Order No.

486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783 (1987).

Docket Nos. RM05-17-000 and RM05-25-000 - 1033 -

sale subject to the Commission’s jurisdiction, plus the classification, practices, contracts

and regulations that affect rates, charges, classifications and services.

1003

VIII. Regulatory Flexibility Act Analysis

1759. The Regulatory Flexibility Act of 1980 (RFA)

1004

generally requires a description

and analysis of final rules that will have significant economic impact on a substantial

number of small entities. This rule applies to public utilities that own, control or operate

interstate transmission facilities other than those that have received waiver of the

obligation to comply with Order Nos. 888 and 889. The total number of public utilities

that, absent waiver, would have to modify their current OATTs by filing the revised pro

forma OATT is 116.

1005

Of these only six public utilities, or less than two percent, have

output of four million MWh or less per year.

1006

The Commission does not consider this

a substantial number and, in any event, each of these entities retains its rights to waiver of

these requirements.

1007

The criteria for waiver that would be applied under this

1003

18 CFR 380.4(a)(15).

1004

5 U.S.C. 601-612.

1005

The Commission has identified 116 transmission providers with tariffs on file.

We note that this figure is lower than our initial estimate in the NOPR, based on FERC

Form No. 1 and FERC Form No. 1-F data.

1006

Id.

1007

The Regulatory Flexibility Act defines a “small entity” as “one which is

independently owned and operated and which is not dominant in its field of operation.”

See

5 U.S.C. 601(3) and 601(6); 15 U.S.C. 632(a)(1). In Mid-Tex Elec. Coop. v. FERC,

773 F.2d 327, 340-43 (D.C. Cir. 1985), the court accepted the Commission's conclusion

(continued)

Docket Nos. RM05-17-000 and RM05-25-000 - 1034 -

rulemaking for small entities is unchanged from that used to evaluate requests for waiver

under Order Nos. 888 and 889. Accordingly, the Commission certifies that the Final

Rule will not have a significant economic impact on a substantial number of small

entities.

IX. Document Availability

1760. In addition to publishing the full text of this document in the Federal Register

, the

Commission provides all interested persons an opportunity to view and/or print the

contents of this document via the Internet through the Commission’s Home Page

(http://www.ferc.gov

) and in the Commission’s Public Reference Room during normal

business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, N.E., Room 2A,

Washington D.C. 20426.

1761. From the Commission’s Home Page on the Internet, this information is available

in the Commission’s document management system, eLibrary. The full text of this

document is available on eLibrary in PDF and Microsoft Word format for viewing,

that, since virtually all of the public utilities that it regulates do not fall within the

meaning of the term “small entities” as defined in the Regulatory Flexibility Act, the

Commission did not need to prepare a regulatory flexibility analysis in connection with

its proposed rule governing the allocation of costs for construction work in progress

(CWIP). The CWIP rules applied to all public utilities. The revised pro forma

OATT

will apply only to those public utilities that own, control or operate interstate transmission

facilities. These entities are a subset of the group of public utilities found not to require

preparation of a regulatory flexibility analysis for the CWIP rule.

Docket Nos. RM05-17-000 and RM05-25-000 - 1035 -

printing, and/or downloading. To access this document in eLibrary, type “RM05-25” or

“RM05-17” in the docket number field.

1762. User assistance is available for eLibrary and the Commission’s website during

normal business hours. For assistance, please contact the Commission’s Online Support

at 1-866-208-3676 (toll free) or 202-502-6652 (e-mail at

[email protected]), or the Public Reference Room at 202-502-8371, TTY

202-502-8659 (e-mail at [email protected]

X. EFFECTIVE DATE AND CONGRESSIONAL NOTIFICATION

1763. These regulations are effective [insert date 60 days after publication in the

FEDERAL REGISTER]. The Commission has determined, with the concurrence of the

Administrator of the Office of Information and Regulatory Affairs of OMB, that this rule

is not a “major rule” as defined in section 351 of the Small Business Regulatory

Enforcement Fairness Act of 1996. The Commission will submit the Final Rule to both

houses of Congress and to the General Accounting Office.

List of Subjects

18 CFR Part 35

Electric power rates, Electric utilities, Reporting and recordkeeping requirements

Docket Nos. RM05-17-000 and RM05-25-000 - 1036 -

18 CFR Part 37

Conflict of interests, Electric power plants, Electric utilities, Reporting and

recordkeeping requirements

By the Commission.

(S E A L )

Magalie R. Salas,

Secretary.

Docket Nos. RM05-17-000 and RM05-25-000 - 1037 -

In consideration of the foregoing, the Commission amends parts 35 and 37,

Chapter I, Title 18 of the Code of Federal Regulations

, as follows:

PART 35—FILING OF RATE SCHEDULES AND TARIFFS

1. The authority citation for part 35 continues to read as follows:

Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 71-7352.

2. Amend § 35.28 as follows:

a. Paragraph (c) is revised.

b. Paragraphs (d)(i) and (d)(ii) are redesignated as paragraphs (d)(1) and

(d)(2).

c. Newly redesignated paragraph (d)(1) is revised.

d. Paragraph (e)(1) introductory text is revised.

e. Paragraph (e)(1)(ii) is revised.

§ 35.28 Non-discriminatory open access transmission tariff

* * * * *

(1) Every public

utility that owns, controls, or operates facilities used for the transmission of electric

energy in interstate commerce must have on file with the Commission a tariff of general

applicability for transmission services, including ancillary services, over such facilities.

Such tariff must be the open access pro forma tariff contained in Order No. 888, FERC

Stats. & Regs. ¶ 31,036 (Final Rule on Open Access and Stranded Costs), as revised by

the open access pro forma tariff contained in Order No. 890, FERC Stats. & Regs. ¶ ___

Docket Nos. RM05-17-000 and RM05-25-000 - 1038 -

(Final Rule on Open Access Reforms), or such other open access tariff as may be

approved by the Commission consistent with Order No. 888, FERC Stats. & Regs

¶ 31,306 and Order No. 890, FERC Stats. & Regs. ¶ _____.

(i) Subject to the exceptions in paragraphs (c)(1)(ii), (c)(1)(iii), (c)(1)(iv) and

(c)(1)(v) of this section, the pro forma tariff contained in Order No. 888, FERC Stats. &

Regs. ¶ 31,036, as revised by the open access pro forma tariff contained in Order No.

890, FERC Stats. & Regs. ¶ ___, and accompanying rates, must be filed no later than 60

days prior to the date on which a public utility would engage in a sale of electric energy

at wholesale in interstate commerce or in the transmission of electric energy in interstate

commerce.

(ii) If a public utility owns, controls, or operates facilities used for the

transmission of electric energy in interstate commerce as of [insert 60 days after date of

publication of the Final Rule in the FEDERAL REGISTER

], it must file the revisions to

the pro forma tariff contained in Order No. 890, FERC Stats. & Regs. ¶ ____, pursuant to

section 206 of the FPA and accompanying rates pursuant to section 205 of the FPA in

accordance with the procedures set forth in Order No. 890, FERC Stats. & Regs ¶ ____.

(iii) If a public utility owns, controls, or operates transmission facilities used for

the transmission of electric energy in interstate commerce as of [insert 60 days after date

of publication of the Final Rule in the FEDERAL REGISTER

], such facilities are jointly

owned with a non-public utility, and the joint ownership contract prohibits transmission

service over the facilities to third parties, the public utility with respect to access over the

Docket Nos. RM05-17-000 and RM05-25-000 - 1039 -

public utility's share of the jointly owned facilities must file no later than [insert 60 days

after date of publication of the Final Rule in the FEDERAL REGISTER

] the revisions to

the pro forma tariff contained in Order No. 890, FERC Stats. & Regs. ¶ ____, pursuant to

section 206 of the FPA and accompanying rates pursuant to section 205 of the FPA.

(iv) Any public utility whose transmission facilities are under the independent

control of a Commission-approved ISO or RTO may satisfy its obligation under

paragraph (c)(1) of this section, with respect to such facilities, through the open access

transmission tariff filed by the ISO or RTO.

(v) If a public utility obtains a waiver of the tariff requirement pursuant to

paragraph (d) of this section, it does not need to file the pro forma tariff required by this

section.

(vi) Any public utility that seeks a deviation from the pro forma tariff contained

in Order No. 888, FERC Stats. & Regs. ¶ 31,036, as revised in Order No. 890, FERC

Stats. & Regs. ¶ _____, must demonstrate that the deviation is consistent with the

principles of Order No. 888, FERC Stats. & Regs ¶ 31,036 and Order No. 890, FERC

Stats. & Regs. ¶ _____.

(vii) Each public utility’s open access transmission tariff must include the

standards incorporated by reference in part 38 of this chapter.

(2) Subject to the exceptions in paragraphs (c)(2)(i) and (c)(3)(iii) of this

section, every public utility that owns, controls, or operates facilities used for the

transmission of electric energy in interstate commerce, and that uses those facilities to

Docket Nos. RM05-17-000 and RM05-25-000 - 1040 -

engage in wholesale sales and/or purchases of electric energy, or unbundled retail sales of

electric energy, must take transmission service for such sales and/or purchases under the

open access transmission tariff filed pursuant to this section.

(i) For sales of electric energy pursuant to a requirements service agreement

executed on or before July 9, 1996, this requirement will not apply unless separately

ordered by the Commission. For sales of electric energy pursuant to a bilateral economy

energy coordination agreement executed on or before July 9, 1996, this requirement is

effective on December 31, 1996. For sales of electric energy pursuant to a bilateral non-

economy energy coordination agreement executed on or before July 9, 1996, this

requirement will not apply unless separately ordered by the Commission.

(ii) [Reserved.]

(3) Every public utility that owns, controls, or operates facilities used for the

transmission of electric energy in interstate commerce, and that is a member of a power

pool, public utility holding company, or other multi-lateral trading arrangement or

agreement that contains transmission rates, terms or conditions, must have on file a joint

pool-wide or system-wide open access transmission tariff, which tariff must be the pro

forma tariff contained in Order No. 888, FERC Stats. & Regs. ¶ 31,036, as revised by the

pro forma tariff contained in Order No. 890, FERC Stats. & Regs. ¶ ___, or such other

open access tariff as may be approved by the Commission consistent with Order No. 888,

FERC Stats. & Regs. ¶ 31,036 and Order No. 890, FERC Stats. & Regs. ¶ _____.

(i) For any power pool, public utility holding company or other multi-lateral

Docket Nos. RM05-17-000 and RM05-25-000 - 1041 -

arrangement or agreement that contains transmission rates, terms or conditions and that is

executed after [insert 60 days after date of publication of the Final Rule in the FEDERAL

arrangement or agreement.

(ii) For any power pool, public utility holding company or other multi-lateral

arrangement or agreement that contains transmission rates, terms or conditions and that is

executed on or before [insert 60 days after date of publication of the Final Rule in the

FEDERAL REGISTER

], a public utility member of such power pool, public utility

holding company or other multi-lateral arrangement or agreement that owns, controls, or

operates facilities used for the transmission of electric energy in interstate commerce

must file the revisions to its joint pool-wide or system-wide contained in Order No. 890,

FERC Stats. & Regs. ¶ ____, pursuant to section 206 of the FPA and accompanying rates

pursuant to section 205 of the FPA in accordance with the procedures set forth in Order

No. 890, FERC Stats. & Regs ¶ ____.

(iii) A public utility member of a power pool, public utility holding company or

other multi-lateral arrangement or agreement that contains transmission rates, terms or

conditions and that is executed on or before July 9, 1996 must take transmission service

under a joint pool-wide or system-wide open access transmission tariff filed pursuant to

this section for wholesale trades among the pool or system members.

(4) Consistent with paragraph (c)(1) of this section, every Commission-

approved ISO or RTO must have on file with the Commission a tariff of general

Docket Nos. RM05-17-000 and RM05-25-000 - 1042 -

applicability for transmission services, including ancillary services, over such facilities.

Such tariff must be the pro forma tariff contained in Order No. 888, FERC Stats. & Regs.

¶ 31,036, as revised by the pro forma tariff contained in Order No. 890, FERC Stats. &

Regs. ¶ ___, or such other open access tariff as may be approved by the Commission

consistent with Order No. 888, FERC Stats. & Reg. ¶ 31,036 and Order No. 890, FERC

Stats. & Regs. ¶ _____.

(i) Subject to paragraph (c)(4)(ii) of this section, a Commission-approved ISO

or RTO must file the revisions to the pro forma tariff contained in Order No. 890, FERC

Stats. & Regs. ¶ ____, pursuant to section 206 of the FPA and accompanying rates

pursuant to section 205 of the FPA in accordance with the procedures set forth in Order

No. 890, FERC Stats. & Regs ¶ ____.

(ii) If a Commission-approved ISO or RTO can demonstrate that its existing

open access tariff is consistent with or superior to the revisions to the pro forma tariff

contained in Order No. 888, FERC Stats. & Regs. ¶ 31,036, as revised by the pro forma

tariff in Order No. 890, FERC Stats. & Regs. ¶ ____, or any portions thereof, the

Commission-approved ISO or RTO may instead set forth such demonstration in its filing

pursuant to section 206 in accordance with the procedures set forth in Order No. 890,

FERC Stats. & Regs ¶ ____.

(d) Waivers

. * * *

Docket Nos. RM05-17-000 and RM05-25-000 - 1043 -

(1) No later than [insert 60 days after date of publication of the Final Rule in the

FEDERAL REGISTER

], or

* * * * *

(e) Non-public utility procedures for tariff reciprocity compliance.

(1) A

non-public utility may submit a transmission tariff and a request for declaratory order that

its voluntary transmission tariff meets the requirements of Order No. 888, FERC Stats. &

Regs. ¶ 31,036 and Order No. 890, FERC Stats. & Regs. ¶ _____.

* * * * *

(ii) If the submittal is found to be an acceptable transmission tariff, an

applicant in a Federal Power Act (FPA) section 211 or 211A proceeding against the non-

public utility shall have the burden of proof to show why service under the open access

tariff is not sufficient and why a section 211 or 211A order should be granted.

* * * * *

PART 37—OPEN ACCESS SAME-TIME INFORMATION SYSTEMS

3. The authority citation for part 37 continues to read as follows:

Authority: 16 U.S.C. 791-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-

7352.

4. Amend § 37.6 as follows:

a. Paragraph (a)(1) is revised.

b. Paragraph (b) introductory text is revised.

c. Paragraphs (b)(1)(v) through (b)(1)(viii) are added.

Docket Nos. RM05-17-000 and RM05-25-000 - 1044 -

d. Paragraphs (b)(2)(i) through (b)(2)(iii) are revised.

e. Paragraph (b)(3) is revised.

f. Paragraphs (c)(2) and (c)(5) are revised.

g. Paragraphs (e)(1) and (e)(2)(ii) are revised.

h. Paragraph (e)(3)(ii) is revised.

i. Paragraphs (h), (i) and (j) are added.

§ 37.6 Information to be posted on the OASIS

(a) * * *

(1) Make requests for transmission services offered by Transmission Providers,

Resellers and other providers of ancillary services, request the designation of a network

resource, and request the termination of the designation of a network resource;

* * * * *

(b) Posting transfer capability

. The available transfer capability on the

Transmission Provider’s system (ATC) and the total transfer capability (TTC) of that

system shall be calculated and posted for each Posted Path as set out in this section.

(1) * * *

(v) Available transfer capability

or ATC means the transfer capability

remaining in the physical transmission network for further commercial activity over and

above already committed uses, or such definition as contained in Commission-approved

Reliability Standards.

(vi) Total transfer capability

or TTC means the amount of electric power that

Docket Nos. RM05-17-000 and RM05-25-000 - 1045 -

can be moved or transferred reliably from one area to another area of the interconnected

transmission systems by way of all transmission lines (or paths) between those areas

under specified system conditions, or such definition as contained in Commission-

approved Reliability Standards.

(vii) Capacity Benefit Margin

or CBM means the amount of TTC preserved by

the Transmission Provider for load-serving entities, whose loads are located on that

Transmission Provider’s system, to enable access by the load-serving entities to

generation from interconnected systems to meet generation reliability requirements, or

such definition as contained in Commission-approved Reliability Standards.

(viii) Transmission Reliability Margin

or TRM means the amount of TTC

necessary to provide reasonable assurance that the interconnected transmission network

will be secure, or such definition as contained in Commission-approved Reliability

Standards.

(2) * * *

(i) Information used to calculate any posting of ATC and TTC must be dated

and time-stamped and all calculations shall be performed according to consistently

applied methodologies referenced in the Transmission Provider's transmission tariff and

shall be based on Commission-approved Reliability Standards as well as current industry

practices, standards and criteria.

(ii) On request, the Responsible Party must make all data used to calculate

ATC, TTC, CBM, and TRM for any constrained posted paths publicly available

Docket Nos. RM05-17-000 and RM05-25-000 - 1046 -

(including the limiting element(s) and the cause of the limit (e.g.

, thermal, voltage,

stability), as well as load forecast assumptions) in electronic form within one week of the

posting. The information is required to be provided only in the electronic format in

which it was created, along with any necessary decoding instructions, at a cost limited to

the cost of reproducing the material. This information is to be retained for six months

after the applicable posting period.

(iii) System planning studies, facilities studies, and specific network impact

studies performed for customers or the Transmission Provider’s own network resources

are to be made publicly available in electronic form on request and a list of such studies

shall be posted on the OASIS. A study is required to be provided only in the electronic

format in which it was created, along with any necessary decoding instructions, at a cost

limited to the cost of reproducing the material. These studies are to be retained for five

years.

(3) Posting

. The ATC, TTC, CBM, and TRM for all Posted Paths must be

posted in megawatts by specific direction and in the manner prescribed in this subsection.

(i) Constrained posted paths

.—(A) For firm ATC and TTC.

) The posting shall show ATC, TTC, CBM, and TRM for a 30-day period. For

this period postings shall be: by the hour, for the current hour and the 168 hours next

following; and thereafter, by the day. If the Transmission Provider charges separately for

on-peak and off-peak periods in its tariff, ATC, TTC, CBM, and TRM will be posted

daily for each period.

Docket Nos. RM05-17-000 and RM05-25-000 - 1047 -

) Postings shall also be made by the month, showing for the current month

and the 12 months next following.

) If planning and specific requested transmission studies have been done,

seasonal capability shall be posted for the year following the current year and for each

year following to the end of the planning horizon but not to exceed 10 years.

(B) For non-firm ATC and TTC

. The posting shall show ATC, TTC, CBM and

TRM for a 30-day period by the hour and days prescribed under paragraph (b)(3)(i)(A)(1

)

of this section and, if so requested, by the month and year as prescribed under paragraph

(b)(3)(i)(A) (2

) and (3) of this section. The posting of non-firm ATC and TTC shall

show CBM as zero.

) The capability posted under paragraphs (b)(3)(i)(A) and (B) of this section

must be updated when transactions are reserved or service ends or whenever the estimate

for the path changes by more than 10 percent.

) All updating of hourly information shall be made on the hour.

) When the monthly and yearly capability posted under paragraphs

(b)(3)(i)(A) and (B) of this section are updated because of a change in TTC by more than

10 percent, the Transmission Provider shall post a brief, but specific, narrative

explanation of the reason for the update. This narrative should include, the specific

events which gave rise to the update (e.g.

, scheduling of planned outages and occurrence

of forced transmission outages, de-ratings of transmission facilities, scheduling of

Docket Nos. RM05-17-000 and RM05-25-000 - 1048 -

planned generation outages and occurrence of forced generation outages, changes in load

forecast, changes in new facilities’ in-service dates, or other events or assumption

changes) and new values for ATC on the path (as opposed to all points on the network).

) When the monthly and yearly capability posted under paragraphs

(b)(3)(i)(A) and (B) remain unchanged at a value of zero for a period of six months, the

Transmission Provider shall post a brief, but specific, narrative explanation of the reason

for the unavailability of ATC.

(ii) Unconstrained posted paths

(A) Postings of firm and nonfirm ATC, TTC, CBM, and TRM shall be posted

separately by the day, showing for the current day and the next six days following and

thereafter, by the month for the 12 months next following. If the Transmission Provider

charges separately for on-peak and off-peak periods in its tariff, ATC, TTC, CBM, and

TRM will be posted separately for the current day and the next six days following for

each period. These postings are to be updated whenever the ATC changes by more than

20 percent of the Path's TTC.

(B) If planning and specific requested transmission studies have been done,

seasonal capability shall be posted for the year following the current year and for each

year following until the end of the planning horizon but not to exceed 10 years.

(iii) Calculation of CBM

(A) The Transmission Provider must reevaluate its CBM needs at least every

year.

Docket Nos. RM05-17-000 and RM05-25-000 - 1049 -

(B) The Transmission Provider must post its practices for reevaluating its CBM

needs.

(iv) Daily load. The Transmission Provider must post on a daily basis, its

actual daily peak load for the prior day.

(2) Transmission Providers must provide a downloadable file of their complete

tariffs in the same electronic format as the tariff that is filed with the Commission.

Transmission Providers also must provide a link to all of the rules, standards and

practices that relate to transmission services posted on the Transmission Providers’ public

websites.

* * * * *

(5) Customers choosing to use the OASIS to offer for resale transmission

capacity they have purchased must post relevant information to the same OASIS as used

by the Transmission Provider from whom the Reseller purchased the transmission

capacity. This information must be posted on the same display page, using the same

tables, as similar capability being sold by the Transmission Provider, and the information

must be contained in the same downloadable files as the Transmission Provider’s own

available capability.

* * * * *

Docket Nos. RM05-17-000 and RM05-25-000 - 1050 -

(e) Posting specific transmission and ancillary service requests and responses

(1) General rules

(i) All requests for transmission and ancillary service offered by Transmission

Providers under the pro forma

tariff, including requests for discounts, and all requests to

designate or terminate a network resource, must be made on the OASIS and posted prior

to the Transmission Provider responding to the request, except as discussed in paragraphs

(e)(1) (ii) and (iii) of this section. The Transmission Provider must post all requests for

transmission service, for ancillary service, and for the designation or termination of a

network resource comparably. Requests for transmission service, ancillary service, and

to designate and terminate a network resource, as well as the responses to such requests,

must be conducted in accordance with the Transmission Provider's tariff, the Federal

Power Act, and Commission regulations.

(ii) The requirement in paragraph (e)(1)(i) of this section, to post requests for

transmission and ancillary service offered by Transmission Providers under the pro forma

tariff, including requests for discounts, prior to the Transmission Provider responding to

the request, does not apply to requests for next-hour service made during Phase I.

(iii) In the event that a discount is being requested for ancillary services that are

not in support of basic transmission service provided by the Transmission Provider, such

request need not be posted on the OASIS.

(iv) In processing a request for transmission or ancillary service, the

Responsible Party shall post the same information as required in paragraphs (c)(4) and

Docket Nos. RM05-17-000 and RM05-25-000 - 1051 -

(d)(3) of this section, and the following information: the date and time when the request

is made, its place in any queue, the status of that request, and the result (accepted, denied,

withdrawn). In processing a request to designate or terminate the designation of a

network resource, the Responsible Party shall post the date and time when the request is

made.

(v) For any request to designate or terminate a network resource, the

Transmission Provider (at the time when the request is received), must post on the

OASIS (and make available for download) information describing the request (including:

name of requestor, identification of the resource, effective time for the designation or

termination, identification of whether the transaction involves the Transmission

Provider’s wholesale merchant function or any affiliate; and any other relevant terms and

conditions) and shall keep such information posted on the OASIS for at least 30 days. A

record of the transaction must be retained and kept available as part of the audit log

required in § 37.7.

(vi) The Transmission Provider shall post a list of its current designated

network resources and all network customers’ current designated network resources on

OASIS. The list of network resources should include the name of the resource, its

geographic and electrical location, its total installed capacity, and the amount of capacity

to be designated as a network resource.

Docket Nos. RM05-17-000 and RM05-25-000 - 1052 -

(2) * * *

(ii) Information to support the reason for the denial, including the operating

status of relevant facilities, must be maintained for five years and provided, upon request,

to the potential Transmission Customer and the Commission’s Staff.

* * * * *

(3) * * *

(ii) Information to support any such curtailment or interruption, including the

operating status of the facilities involved in the constraint or interruption, must be

maintained and made available upon request, to the curtailed or interrupted customer, the

Commission’s Staff, and any other person who requests it, for five years.

* * * * *

(h) Posting information summarizing the time to complete transmission service

request studies. (1) For each calendar quarter, the Responsible Party must post the set of

measures detailed in paragraph (h)(1)(i) through paragraph (h)(1)(vi) of this section

related to the Responsible Party’s processing of transmission service request system

impact studies and facilities studies. The Responsible Party must calculate and post the

measures in paragraph (h)(1)(i) through paragraph (h)(1)(vi) of this section separately for

requests for short-term firm point-to-point transmission service, long-term firm point-to-

point transmission service, and requests to designate a new network resource and must be

calculated and posted separately for transmission service requests from Affiliates and

transmission service requests from Transmission Customers who are not Affiliates. The

Docket Nos. RM05-17-000 and RM05-25-000 - 1053 -

Responsible Party is required to include in the calculations of the measures in paragraph

(h)(1)(i) through paragraph (h)(1)(vi) of this section all studies the Responsible Party

conducts of transmission service requests on another Transmission Provider’s OASIS.

(i) Process time from initial service request to offer of system impact study

agreement.

(A) Number of new system impact study agreements delivered during the

reporting quarter to entities that request transmission service,

(B) Number of new system impact study agreements delivered during the

reporting quarter to entities that request transmission service more than thirty (30) days

after the Responsible Party received the request for transmission service,

during the reporting quarter, from the date when the Responsible Party received the

request for transmission service to when the Responsible Party changed the transmission

service request status to indicate that the Responsible Party could offer transmission

service or needed to perform a system impact study,

(D) Mean time (in days), for all system impact study agreements delivered by

the Responsible Party during the reporting quarter, from the date when the Responsible

Party received the request for transmission service to the date when the Responsible Party

delivered a system impact study agreement, and

(E) Number of new system impact study agreements executed during the

reporting quarter.

Docket Nos. RM05-17-000 and RM05-25-000 - 1054 -

(ii) System impact study processing time

(A) Number of system impact studies completed by the Responsible Party

during the reporting quarter,

(B) Number of system impact studies completed by the Responsible Party

during the reporting quarter more than 60 days after the Responsible Party received an

executed system impact study agreement,

of an executed system impact study agreement, average number of days study was

delayed due to transmission customer’s actions (e.g.

, delays in providing needed data),

(D) Mean time (in days), for all system impact studies completed by the

Responsible Party during the reporting quarter, from the date when the Responsible Party

received the executed system impact study agreement to the date when the Responsible

Party provided the system impact study to the entity who executed the system impact

study agreement, and

(E) Mean cost of system impact studies completed by the Responsible Party

during the reporting quarter.

(iii) Transmission service requests withdrawn from the system impact study

queue.

(A) Number of transmission service requests withdrawn from the Responsible

Party’s system impact study queue during the reporting quarter,

Docket Nos. RM05-17-000 and RM05-25-000 - 1055 -

(B) Number of transmission service requests withdrawn from the Responsible

Party’s system impact study queue during the reporting quarter more than 60 days after

the Responsible Party received the executed system impact study agreement, and

from the Responsible Party’s system impact study queue during the reporting quarter,

from the date the Responsible Party received the executed system impact study

agreement to date when request was withdrawn from the Responsible Party’s system

impact study queue.

(iv) Process time from completed system impact study to offer of facilities

study.

(A) Number of new facilities study agreements delivered during the reporting

quarter to entities that request transmission service,

(B) Number of new facilities study agreements delivered during the reporting

quarter to entities that request transmission service more than thirty (30) days after the

Responsible Party completed the system impact study,

Responsible Party during the reporting quarter, from the date when the Responsible Party

completed the system impact study to the date when the Responsible Party delivered a

facilities study agreement, and

(D) Number of new facilities study agreements executed during the reporting

quarter.

Docket Nos. RM05-17-000 and RM05-25-000 - 1056 -

(v) Facilities study processing time

(A) Number of facilities studies completed by the Responsible Party during

the reporting quarter,

(B) Number of facilities studies completed by the Responsible Party during

the reporting quarter more than 60 days after the Responsible Party received an executed

facilities study agreement,

executed facilities study agreement, average number of days study was delayed due to

transmission customer’s actions (e.g.

, delays in providing needed data),

(D) Mean time (in days), for all facilities studies completed by the

Responsible Party during the reporting quarter, from the date when the Responsible Party

received the executed facilities study agreement to the date when the Responsible Party

provided the facilities study to the entity who executed the facilities study agreement,

(E) Mean cost of facilities studies completed by the Responsible Party during

the reporting quarter, and

(F) Mean cost of upgrades recommended in facilities studies completed

during the reporting quarter.

(vi) Service requests withdrawn from facilities study queue

(A) Number of transmission service requests withdrawn from the Responsible

Party’s facilities study queue during the reporting quarter,

Docket Nos. RM05-17-000 and RM05-25-000 - 1057 -

(B) Number of transmission service requests withdrawn from the Responsible

Party’s facilities study queue during the reporting quarter more than 60 days after the

Responsible Party received the executed facilities study agreement, and

from the Responsible Party’s facilities study queue during the reporting quarter, from the

date the Responsible Party received the executed facilities study agreement to date when

request was withdrawn from the Responsible Party’s facilities study queue

(2) The Responsible Party is required to post the measures in paragraph

(h)(1)(i) through paragraph (h)(1)(vi) of this section for each calendar quarter within 15

days of the end of the calendar quarter. The Responsible Party will keep the quarterly

measures posted on OASIS for three calendar years.

(3) The Responsible Party will be required to post on OASIS the measures in

paragraph (h)(3)(i) through paragraph (h)(3)(iv) of this section in the event the

Responsible Party, for two consecutive calendar quarters, completes more than twenty

(20) percent of the studies associated with requests for transmission service from entities

that are not Affiliates of the Responsible Party more than sixty (60) days after the

Responsible Party delivers the appropriate study agreement. The Responsible Party will

have to post the measures in paragraph (h)(3)(i) through paragraph (h)(3)(iv) of this

section until it processes at least ninety (90) percent of all studies within 60 days after it

has received the appropriate executed study agreement. For the purposes of calculating

the percent of studies completed more than sixty (60) days after the Responsible Party

Docket Nos. RM05-17-000 and RM05-25-000 - 1058 -

delivers the appropriate study agreement, the Responsible Party should aggregate all

system impact studies and facilities studies that it completes during the reporting quarter.

The Responsible Party must calculate and post the measures in paragraph (h)(3)(i)

through paragraph (h)(3)(iv) of this section separately for requests for short-term firm

point-to-point transmission service, long-term firm point-to-point transmission service,

and requests to designate a new network resource and must be calculated and posted

separately for transmission service requests from Affiliates and transmission service

requests from Transmission Customers who are not Affiliates.

(i) Mean, across all system impact studies the Responsible Party completes

during the reporting quarter, of the employee-hours expended per system impact study

the Responsible Party completes during reporting period;

(ii) Mean, across all facilities studies the Responsible Party completes during

the reporting quarter, of the employee-hours expended per facilities study the

Responsible Party completes during reporting period;

(iii) The number of employees the Responsible Party has assigned to process

system impact studies;

(iv) The number of employees the Responsible Party has assigned to process

facilities studies.

(4) The Responsible Party is required to post the measures in paragraph

(h)(3)(i) through paragraph (h)(3)(iv) of this section for each calendar quarter within 15

Docket Nos. RM05-17-000 and RM05-25-000 - 1059 -

days of the end of the calendar quarter. The Responsible Party will keep the quarterly

measures posted on OASIS for five calendar years.

(i) Posting data related to grants and denials of service

. The Responsible Party

is required to post data each month listing, by path or flowgate, the number of

transmission service requests that have been accepted and the number of transmission

service requests that have been denied during the prior month. This posting must

distinguish between the length of the service request (e.g.

, short-term or long-term

requests) and between the type of service requested (e.g.

, firm point-to-point, non-firm

point-to-point or network service). The posted data must show:

(1) The number of non-Affiliate requests for transmission service that have

been rejected,

(2) The total number of non-Affiliate requests for transmission service that

have been made,

(3) The number of Affiliate requests for transmission service that have been

rejected, and

(4) The total number of Affiliate requests for transmission service that have

been made.

(j) Posting redispatch data.

(1) The Transmission Provider must allow the posting on OASIS of any third

party offer to relieve a specified congested transmission facility.

Docket Nos. RM05-17-000 and RM05-25-000 - 1060 -

(2) The Transmission Provider must post on OASIS (i) its monthly average

cost of planning and reliability redispatch, for which it invoices customers, at each

internal transmission facility or interface over which it provides redispatch service and

(ii) a high and low redispatch cost for the month for each of these same transmission

facilities. The transmission provider must post this data on OASIS as soon as practical

after the end of each month, but no later than when it sends invoices to transmission

customers for redispatch-related services.

5. In §37.7, paragraph (b) is revised to read as follows:

§ 37.7 Auditing Transmission Service Information

* * * * *

(b) Audit data must remain available for download on the OASIS for 90 days,

except ATC/TTC postings that must remain available for download on the OASIS for 20

days. The audit data are to be retained and made available upon request for download for

five years from the date when they are first posted in the same electronic form as used

when they originally were posted on the OASIS.

Docket Nos. RM05-17-000 and RM05-25-000 - 1061 -

NOTE: The following appendices will not be published in the Code of Federal

Regulations.

Appendix A: Summary of Compliance Filing Requirements

For a more detailed description of compliance obligations please refer to the Final Rule

paragraph number. For further information related to the Final Rule, such as electronic

versions of the pro forma

OATT showing tariff changes adopted in the Final Rule in

redline/strikeout format, and further information regarding docketing of compliance

filings and specific filing instructions, please visit our website at the following location

http://www.ferc.gov/industries/electric/indus-act/oatt-reform.asp

Deadline

(days after

publication

in Fed. Reg.) Compliance Action

Final Rule

Paragraph

30 Optional Implementation FPA section 205 filings allowing

transmission providers to propose previously approved variations

from the pro forma OATT that have been affected by pro forma

OATT Final Rule reforms to remain in effect subject to a

demonstration that such variations continue to be consistent with

or superior to the revised Final Rule pro forma OATT (non

RTO/ISO transmission providers). Such optional filings must

request a 90 day effective date to facilitate Commission review

under section 205.

P 139

60 Non-ISO/RTO transmission providers submit FPA section 206

filings that contain the non-rate terms and conditions set forth in

Final Rule. These filings need only contain the revised

provisions adopted in the Final Rule. Transmission providers

utilizing the optional Implementation FPA section 205 filing

described above, need only submit tariff sheets necessary to

implement the remaining modifications required under the Final

Rule, i.e.

, modifications related to tariff provisions that did not

implicate previously-approved variations.

P 135

75 Transmission Providers must post a “strawman” proposal for

compliance with each of the nine planning principles adopted in

the Final Rule. This may be posted on the Transmission

Providers website or its OASIS site.

P 443

90 NERC/NAESB status report and work plan for completion of

ATC related business practices and standards.

P 223

Docket Nos. RM05-17-000 and RM05-25-000 - 1062 -

Deadline

(days after

publication

in Fed. Reg.) Compliance Action

Final Rule

Paragraph

NAESB status report and work plan for completion of OASIS

functionality or uniform business practices (other than those

related to ATC).

P 141

120 Transmission Providers must submit redesigned transmission

charges that reflect the Capacity Benefit Margin set-aside

through a limited issue section 205 rate filing as part of their

initial ATC related compliance filings

P 263

180 Submit compliance filings with Attachment C (ATC) of the pro

forma OATT

P 140

210 ISOs and RTOs, and transmission providers located within an

ISO/RTO footprint, submit FPA section 206 filings that contain

the non-rate terms and conditions set forth in the Final Rule.

These filings need only contain the revised provisions adopted in

the Final Rule or a demonstration that previously approved

variations continue to be consistent with or superior to the

revised pro forma OATT.

P 157

P 161

210 Submit compliance filings with Attachment K (Planning) of the

pro forma OATT or RTOs and ISOs file a demonstration that

their planning processes are consistent with or superior to the

planning principles in the Final Rule

P 140

P 442

N/A Transmission Providers must file a revised Attachment C to

incorporate any changes to NERC’s and NAESB’s reliability and

business practice standards to achieve consistency in ATC within

60 days of completion of the NERC and NAESB processes.

P 325

N/A After the submission of FPA section 206 compliance filings,

transmission providers may submit FPA section 205 filings

proposing rates for the services provided for in the tariff, as well

as non-rate terms and conditions that differ from those set forth

in the Final Rule if those provisions are “consistent with or

superior to” the pro forma OATT.

P 135

Docket Nos. RM05-17-000 and RM05-25-000 - 1063 -

Appendix B: Commenting Party Acronyms

Initial Commenters

Abbreviation Initial Commenters

Alberta Intervenors

Alberta Intervenors (TransCanada Energy Ltd.,

ENMAX Energy Marketing, Inc.; EPCOR Merchant

and Capital, LP; and TransAlta Corporation)

Alcoa Alcoa Inc. and Alcoa Power Generating Inc.

Allegheny

Allegheny Power and Allegheny Energy Supply

Company, LLC

Ameren Ameren Services Company

American Transmission American Transmission Company LLC

AMP- Ohio American Municipal Power-Ohio, Inc.

Anaheim

Cities of Anaheim, Azusa, Banning, Colton,

Pasadena, and Riverside, California

APPA American Public Power Association

ARC Allliance for Retail Choice

Arkansas Commission Arkansas Public Service Commission

Arkansas Municipal Arkansas Municipal Power Association

AWEA American Wind Energy Association

Barrick Barrick Goldstrike Mines Inc.

Docket Nos. RM05-17-000 and RM05-25-000 - 1064 -

Abbreviation Initial Commenters

BART San Francisco Bay Area Rapid Transit District

Bonneville Bonneville Power Administration

BP Energy BP Energy Company

Bureau of Reclamation US Bureau of Reclamation

CAC/EPUC

Cogeneration Association of California (Coalinga

Cogeneration Co., Mid-Set Cogeneration Co., Kern

River Cogeneration Co., Sycamore Cogeneration Co.,

Sargent Canyon Cogeneration Co., Salinas River

Cogeneration Co., Midwest Sunset Cogeneration Co.

and Watson Cogeneration Co.) and Energy Producers

and Users Coalition (Aera Energy LLC, BP

American, Inc., Chevron USA, Inc., ConocoPhilips

Co., ExxonMobil Power and Gas Services, Inc., Shell

Oil Products, US, THUMS Long Beach Co.,

Occidental Elk Hills, Inc., and Valero Refining Co. -

California)

CAISO California Independent System Operator Corporation

California Commission Public Utilities Commission of the State of California

Calpine Calpine Corporation

Chandley-Hogan John D. Chandley and William W. Hogan

ColumbiaGrid

ColumbiaGrid Members (Bonneville Power

Administration; Avista Corp.; Public Utility District

No. 1 of Chelan County, Washington; Publicy Utility

District No. 2 of Grant County, Washington; Puget

Sound Energy, Inc.; Seattle City Light; and Tacoma

Power

Docket Nos. RM05-17-000 and RM05-25-000 - 1065 -

Abbreviation Initial Commenters

Community Power

Alliance

Community Power Alliance Members (Entergy,

Progress Energy, Salt River Project Agricultural

Improvement and Power District, and Southern Co.)

Constellation Constellation Energy Group, Inc.

CREPC Committee on Regional Electric Power Corp.

Dominion

Dominion Resources Services, Inc. (Armstrong

Energy Limited Partnership, LLLP; Dominion

Energy Marketing, Inc.; Elwood Energy, LLC;

Fairless Energy, LLC; Pleasants Energy, LLC and

Virginia Electric and Power Co. d/b/a Dominion

Virginia Power)

Dow Dow Chemical Corp.

Duke Duke Energy Corp.

E.ON E.ON U.S. LLC

East Texas Cooperatives

East Texas Electric Cooperative, Inc.; Northeast

Texas Electric Cooperative, Inc.; Sam Rayburn

Generation and Electric Cooperative, Inc. and Tex-La

Electric Cooperative of Texas, Inc.

Eastern North Carolina

Eastern NC Towns (Towns of Black Creek, NC;

Lucama, NC; Stantonsburg, NC)

EEI Edison Electric Institute

ELCON

Electricity Consumers Resource Council, American

Iron and Steel Institute, and American Forest & Paper

Institute

Emerald Emerald People's Utility District

Docket Nos. RM05-17-000 and RM05-25-000 - 1066 -

Abbreviation Initial Commenters

Entegra

Entegra Power Group LLC and LS Power Associates,

L.P.

Entergy Entergy Services, Inc.

EPSA Electric Power Supply Association

Exelon Exelon Corporation

Fayetteville

Public Works Commission of the City of Fayetteville,

North Carolina

Fertilizer Institute Fertilizer Institute

FirstEnergy

FirstEnergy Service Company (First Energy

Solutions; American Transmission Systems, Inc.;

Jersey Central Power and Light Co.; Metropolitan

Edison Co.; and Pennsylvania Electric Co.)

Flathead Flathead Electric Cooperative

Florida Commission Florida Public Service Commission

Florida Industrial

Cogeneration Association

Florida Industrial Cogeneration Association

FMPA

Florida Municipal Power Agency and Midwest

Municipal Transmission Group

Geothermal Producers

CE Generation, LLC; Ormat Technologies, Inc.;

Caithness Energy, LLC; and Geothermal Energy

Association

Grant

Grant County PUD, Chelan County PUD and Pend

Oreille County PUD

Great Northern Great Northern Power Development, L.P.

Docket Nos. RM05-17-000 and RM05-25-000 - 1067 -

Abbreviation Initial Commenters

Imperial Imperial Irrigation District

Indianapolis Power Indianapolis Power & Light Co.

Indicated New York

Transmission Owners

Central Hudson Gas & Electric Corp.; Consolidated

Edison Co. of New York, Inc.; LIPA; New York

Power Authority; New York State Electric & Gas

Corp.; Orange and Rockland Utilities, Inc.; and

Rochester Gas and Electric Corp.

International

Transmission

International Transmission Co. d/b/a

ITCTransmission

and Michigan Electric

Transmission Co., LLC

IRH Management

IRH Management Committee and the Schedule 20A

Service Providers

ISO New England ISO New England, Inc. and New England Power Pool

ISO/RTO Council ISO/RTO Council

Lassen Lassen Municipal Utility District

LDWP City of Los Angeles Department of Water and Power

LPPC Large Public Power Council

Manitoba Hydro Manitoba Hydro

MDEA

Mississippi Delta Energy Agency, Clarksdale Public

Utilities Commission, and Public Service

Commission of Yazoo City

MidAmerican MidAmerican Energy Company and PacifiCorp

Docket Nos. RM05-17-000 and RM05-25-000 - 1068 -

Abbreviation Initial Commenters

MISO

Midwest Independent Transmission System Operator,

Inc.

MISO Transmission

Owners

Midwest ISO Transmission Owners

MISO/PJM States

Organization of MISO States and Organization of

PJM States, Inc.

Morgan Stanley Morgan Stanley Capital Group Inc.

NAESB North American Energy Standards Board

NARUC

National Association of Regulatory Utility

Commissioners

National Grid National Grid USA

NCEMC North Carolina Electric Membership Corporation

NCPA Northern California Power Agency

NERC North American Electric Reliability Corporation

Nevada Commission Public Utilities Commission of Nevada

Nevada Companies

Nevada Power Company and Sierra Pacific Power

Company

New Jersey Board New Jersey Board of Public Utilities

New Mexico Attorney

General

New Mexico Attorney General

New York Commission New York State Public Service Commission

Docket Nos. RM05-17-000 and RM05-25-000 - 1069 -

Abbreviation Initial Commenters

Newfoundland Newfoundland and Labrador Hydro

Newmont Mining Newmont USA Limited, dba Newmont Mining Corp.

Northeast Utilities

Northeast Utilities Service Company (Connecticut

Light and Power Co.; Western Massachusetts Electric

Co.; Public Service Co. of New Hampshire; Holyoke

Water Power Co.; and Holyoke Power and Electric

Co.)

Northwest IOUs

Northwest Investor-Owned Utilities (Avista Corp.,

Portland General Electric Co., and Puget Sound

Energy, Inc.)

Northwest Parties

Northwest Parties (Avista Corp., Bonneville Power

Administration, PacifiCorp, PNGC Power, Portland

General Electric Co., Public Power Council, Public

Utility Commission of Oregon and Puget Sound

Energy, Inc.)

NorthWestern NorthWestern Corporation

NPPD Nebraska Public Power District

NRECA National Rural Electric Cooperative Association

NRG NRG Energy, Inc.

NYAPP New York Association of Public Power

Occidental Occidental Chemical Corporation

Oklahoma Commission Oklahoma Corporation Commission

Old Dominion Old Dominion Electric Cooperative

Docket Nos. RM05-17-000 and RM05-25-000 - 1070 -

Abbreviation Initial Commenters

Oversight Resources Oversight Resources, LLC

PGP Public Generating Pool and Chelan County PUD

Pinnacle

Pinnacle West Capital Corporation; Arizona Public

Service Company; and APS Energy Services

Company, Inc.

PJM PJM Interconnection, LLC

PNM-TNMP

Public Service Company of New Mexico and Texas-

New Mexico Power Company

Powerex Powerex Corp.

PPL PPL Companies

PPM PPM Energy, Inc.

Progress Energy

Progress Energy, Inc. (Carolina Power & Light Co.

d/b/a Progress Energy Carolinas and Florida Power

Corp., d/b/a Progress Energy Florida; and Progress

Ventures, Inc.)

Project for Sustainable

FERC Energy Policy

Project for Sustainable FERC Energy Policy

(American Wind Energy Association, Delaware

Division of the Public Advocate, Environmental Law

& Policy Center, Illinois Citizens Utility Board,

Natural Resources Defense Council, Northwest

Energy Coalition, Office of the Ohio Consumers'

Counsel, Pace Energy Project, Project for Sustainable

FERC Energy Policy, Renewable Northwest Project,

West Wind Wires, and Wind on the Wires)

PSEG

Public Service Electric and Gas Company; PSEG

Power LLC; and PSEC Energy Resources & Trade

LLC (PSEG Companies)

Docket Nos. RM05-17-000 and RM05-25-000 - 1071 -

Abbreviation Initial Commenters

Public Power Council Public Power Council

Reliant Reliant Energy, Inc.

Sacramento Sacramento Municipal Utility District

Salt River

Salt River Project Agricultural Improvement and

Power District

San Diego G&E San Diego Gas & Electric Company

Santa Clara

City of Santa Clara, California d/b/a Silicon Valley

Power

Santee Cooper South Carolina Public Service Authority

SCE Southern California Edison

Seattle City of Seattle - City Light Department

Sempra Global Sempra Global

South Carolina E&G South Carolina Electric & Gas Company

South Carolina

Regulatory Staff

South Carolina Office of Regulatory Staff

Southern Southern Company Services, Inc.

Southwest Transmission

Southwest Area Transmission Sub-Regional Planning

Group

Southwestern Coop Southwestern Electric Cooperative, Inc.

Docket Nos. RM05-17-000 and RM05-25-000 - 1072 -

Abbreviation Initial Commenters

SPP Southwest Power Pool, Inc.

Steel Manufacturers

Association

Steel Manufacturers Association

Suez Energy NA Suez Energy North America, Inc.

Tacoma Tacoma Power

TANC Transmission Agency of Northern California

TAPS Transmission Access Policy Study Group

TDU Systems Transmission Dependent Utilities Systems

TransAlta TransAlta Energy Marketing (US) Inc.

TranServ TranServ International, Inc.

Tucson Tucson Electric Power Company

TVA Tennessee Valley Authority

Utah Municipals Utah Associated Municipal Power Systems

WAPA Western Area Power Administration

WECC Western Electricity Coordinating Council

WestConnect WestConnect Companies

Docket Nos. RM05-17-000 and RM05-25-000 - 1073 -

Abbreviation Initial Commenters

Western Governors Western Governors’ Association

Williams Williams Power Company, Inc.

Wisconsin Electric Wisconsin Electric Power Company

WSPP Western Systems Power Pool, Inc.

Xcel Xcel Energy Services, Inc.

Docket Nos. RM05-17-000 and RM05-25-000 - 1074 -

Reply Commenters

Abbreviation Reply Commenters

Alberta Intervenors

Alberta Intervenors (TransCanada Energy Ltd.,

ENMAX Energy Marketing, Inc.; EPCOR Merchant

and Capital, LP; and TransAlta Corporation)

Anaheim

Cities of Anaheim, Azusa, Banning, Colton, Pasadena,

and Riverside, California

APPA American Public Power Association

Barrick Barrick Goldstrike Mines Inc.

Bonneville Bonneville Power Administration

CAISO California Independent System Operator Corporation

California Commission Public Utilities Commission of the State of California

Canadian Electricity

Association

Canadian Electricity Association

Chandley-Hogan John D. Chandley and William W. Hogan

CMUA California Municipal Utilities Association

ColumbiaGrid

ColumbiaGrid Members (Bonneville Power

Administration; Avista Corp.; Public Utility District

No. 1 of Chelan County, Washington; Publicy Utility

District No. 2 of Grant County, Washington; Puget

Sound Energy, Inc.; Seattle City Light; and Tacoma

Power

Community Power

Alliance

Community Power Alliance Members (Entergy,

Progress Energy, Salt River Project Agricultural

Improvement and Power District, and Southern Co.)

Detroit Edison Detroit Edison Co.

Duke Duke Energy Corp.

Dynegy Dynegy Power Marketing, Inc.

Docket Nos. RM05-17-000 and RM05-25-000 - 1075 -

Abbreviation Reply Commenters

East Texas Cooperatives

East Texas Electric Cooperative, Inc.; Northeast Texas

Electric Cooperative, Inc.; Sam Rayburn Generation

and Electric Cooperative, Inc. and Tex-La Electric

Cooperative of Texas, Inc.

EEI Edison Electric Institute

ElectriCities ElectriCities of North Carolina, Inc.

Entegra

Entegra Power Group LLC and LS Power Associates,

L.P.

Entergy Entergy Services, Inc.

EPSA Electric Power Supply Association

Exelon Exelon Corporation

Fayetteville

Public Works Commission of the City of Fayetteville,

North Carolina

Fertilizer Institute Fertilizer Institute

FMPA

Florida Municipal Power Agency and Midwest

Municipal Transmission Group

Great Northern Great Northern Power Development, L.P.

Hoosier Hoosier Energy Rural Electric Cooperative, Inc.

H.Q. Energy H.Q. Energy Services (U.S.), Inc.

Indianapolis Power Indianapolis Power & Light Co.

Docket Nos. RM05-17-000 and RM05-25-000 - 1076 -

Abbreviation Reply Commenters

Industrial Customers of

Northwest Utilities

Industrial Customers of Northwest Utilities (Air

Liquide; Air Products; BPB Gypsum, Inc.; Blue Heron

Paper Company; Boeing; Boise Cascade; CNC

Containers, Northwest; Chemi-Con Materials

Corporation; Dyno Nobel, Inc.; ConAgra Foods; Eka

Chemicals, Inc.; Evanite Fiber; Georgia-Pacific; Grays

Harbor Paper, L.P.; Hewlett-Packard; Inland Empire

Paper Co.; Intel; J.R. Simplot; Kimberly-Clark

Corporation; Longview Fibre; Microsoft Corporation;

Norpac Foods; Noveon Kalama, Inc.; Oregon Steel

Mills; PCC Structurals, Inc.; Ponderay Newsprint Co;

Shell Oil Products US; Simpson Paper; Simpson

Timber; Solar Grade Silicon LLC; SP Newsprint Co.;

Tesoro Refining and Marketing Co.; Wah Chang; West

Linn Paper Company; Weyerhaeuser)

International

Transmission

International Transmission Co. d/b/a ITCTransmission

and Michigan Electric Transmission Co., LLC

ISO/RTO Council ISO/RTO Council

Lassen Lassen Municipal Utility District

LPPC Large Public Power Council

MAPP Mid-Continent Area Power Pool

Mark Lively Mark B. Lively

MDEA

Mississippi Delta Energy Agency, Clarksdale Public

Utilities Commission, Public Service Commission of

Yazoo City, Arkansas Electric Cooperative

Corporation, Municipal Energy Agency of Mississippi,

and Lafayette Utilities System

1008

A “*” indicates that the composition of this group has altered in the reply

comment filing.

Docket Nos. RM05-17-000 and RM05-25-000 - 1077 -

Abbreviation Reply Commenters

MidAmerican MidAmerican Energy Company and PacifiCorp

MISO

Midwest Independent Transmission System Operator,

Inc.

Morgan Stanley Morgan Stanley Capital Group Inc.

NARUC

National Association of Regulatory Utility

Commissioners

NC Transmission

Planning Participants

North Carolina Transmission Planning Collaborative

Participants

NCPA Northern California Power Agency

Newmont Mining Newmont USA Limited, dba Newmont Mining Corp.

North Carolina

Commission

North Carolina Utilities Commission; Public Staff of

the North Carolina Utilities Commission; and the

Attorney General of the State of North Carolina

Northwest IOUs

Northwest Investor-Owned Utilities (Avista Corp.,

Portland General Electric Co., and Puget Sound

Energy, Inc.)

NorthWestern NorthWestern Corporation

NRECA National Rural Electric Cooperative Association

Occidental Occidental Chemical Corporation

OG&E Oklahoma Gas and Electric Company

Ohio Power Siting Board

Ohio Power Siting Board, American Municipal Power-

Ohio, Inc. and Buckeye Power, Inc.

Old Dominion

Old Dominion Electric Cooperative; Southern

Maryland Electric Cooperative, Inc.; Allegheny

Electric Cooperative, Inc.; and North Carolina Electric

Membership Corporation

Omaha Public Power Omaha Public Power District

Pennsylvania

Commission

Pennsylvania Public Utility Commission

Docket Nos. RM05-17-000 and RM05-25-000 - 1078 -

Abbreviation Reply Commenters

PJM PJM Interconnection, LLC

PNM-TNMP

Public Service Company of New Mexico and Texas-

New Mexico Power Company

Powerex Powerex Corp.

PPM PPM Energy, Inc.

Progress Energy

Progress Energy, Inc. (Carolina Power & Light Co.

d/b/a Progress Energy Carolinas and Florida Power

Corp., d/b/a Progress Energy Florida; and Progress

Ventures, Inc.)

Project for Sustainable

FERC Energy Policy

Project for Sustainable FERC Energy Policy

(Delaware Division of the Public Advocate,

Environmental Law & Policy Center, Fresh Energy,

Natural Resources Defense Council, Northwest Energy

Coalition, Pace Energy Project, Project for Sustainable

FERC Energy Policy, Renewable Northwest Project,

West Wind Wires, and Wind on the Wires)

Public Power Council Public Power Council

Sacramento Sacramento Municipal Utility District

Salt River

Salt River Project Agricultural Improvement and

Power District

Santa Clara

City of Santa Clara, California d/b/a Silicon Valley

Power

Seattle City of Seattle - City Light Department

Seminole Seminole Electric Cooperative, Inc.

South Carolina E&G South Carolina Electric & Gas Company

Southern Southern Company Services, Inc.

SPP Southwest Power Pool, Inc.

Steel Manufacturers

Association

Steel Manufacturers Association

Docket Nos. RM05-17-000 and RM05-25-000 - 1079 -

Abbreviation Reply Commenters

Strategic Energy Strategic Energy, L.L.C.

TANC Transmission Agency of Northern California

TAPS Transmission Access Policy Study Group

TDU Systems Transmission Dependent Utilities Systems

Transparent Dispatch

Advocates

PJM Interconnection, LLC; Electric Consumers

Resource Council; Electric Power Supply Association;

Natural Resources Defense Council; Renewable

Northwest Project; Project for Sustainable FERC

Energy Policy; Center for Energy Efficiency &

Renewable Technologies; Shell Trading Gas and

Power Company; American Wind Energy Association;

and Exelon

Utah Municipals Utah Associated Municipal Power Systems

WestConnect WestConnect Companies

Williams Williams Power Company, Inc.

Wolverine Wolverine Power Supply Cooperative, Inc.

WPS Companies

WPS Companies (Wisconsin Public Service

Corporation and Upper Peninsula Power Company)

WSPP Western Systems Power Pool, Inc.

Xcel Xcel Energy Services, Inc.

Docket Nos. RM05-17-000 and RM05-25-000 - 1080 -

Technical Conference Commenters

Abbreviation Technical Conference Commenters

APPA

◊

American Public Power Association

APS

◊

Arizona Public Service Company

Bonneville

◊

Bonneville Power Administration

Constellation

◊

Constellation Energy Group, Inc.

EEI

◊

Exelon Corporation on behalf of Edison Electric

Institute (EEI)

EPSA

◊1009

Electric Power Supply Association

Exelon

◊

Exelon

NAESB

◊

North American Energy Standards Board

NARUC

◊

National Association of Regulatory Utility

Commissioners

National Grid

◊

National Grid USA

National Grid/Central

Hudson

National Grid USA, Central Hudson Gas & Electric

Corporation, and American Wind Energy

NERC

◊

Prague Power, LLC, on behalf of the North American

Electric Reliability Corporation

New York Parties

Consolidated Edison Co. of New York, Inc., Orange

and Rockland Utilities, Inc., New York Power

Authority, and Independent Power Producers of New

York, Inc.

NRECA

◊

Great River Energy on behalf of National Rural

Electric Cooperative Association (NRECA)

1009

A “

◊”

indicates that this party submitted speaker materials at the October 12

Technical Conference.

Docket Nos. RM05-17-000 and RM05-25-000 - 1081 -

Abbreviation Technical Conference Commenters

NRG on behalf of

EPSA

◊

NRG Energy, Inc. on behalf of Electric Power Supply

Association (EPSA)

PacifiCorp PacifiCorp

PJM

◊

PJM Interconnection, LLC

AWEA

◊

PPM Energy, Inc. .on behalf of American Wind

Energy Association

Progress Energy

◊

Progress Energy, Inc. (Carolina Power & Light

Company, d/b/a. Progress Energy Carolinas, Inc. and

Florida Power Corporation, d/b/a Progress Energy

Florida, Inc.)

Renewable Northwest

Project

◊

Renewable Northwest Project

San Diego G&E San Diego Gas & Electric Company

TAPS

◊

Southern Minnesota Municipal Power Agency and

Transmission Access Policy Study Group

TDU Systems Transmission Dependent Utilities Systems

South Carolina

Regulatory Staff

South Carolina Office of Regulatory Staff

Southern

◊

Southern Company Services, Inc.

WECC

◊

Western Electricity Coordinating Council

Williams

◊

Williams Power

Williams

◊

Williams Power Company, Inc.

Xcel

◊

Xcel Energy Services, Inc.

Docket Nos. RM05-17-000 and RM05-25-000 - 1082 -

Supplemental Commenters

Abbreviation Supplemental Commenters

Alabama Commission Alabama Public Service Commission

Ameren Ameren Services Company

APPA American Public Power Association

Barrick Barrick Goldstrike Mines Inc.

Bonneville Bonneville Power Administration

BP Energy BP Energy Company

California Commission Public Utilities Commission of the State of California

Community Power

Alliance

Community Power Alliance Members (Entergy,

Progress Energy, Salt River Project Agricultural

Improvement and Power District, and Southern Co.)

Constellation Constellation Energy Group, Inc.

Duke Duke Energy Corp.

E.ON E.ON U.S. LLC

EEI Edison Electric Institute

Entergy Entergy Services, Inc.

EPSA and AWEA

Electric Power Supply Association and American

Wind Energy Association

Florida Commission Florida Public Service Commission

Georgia Commission Georgia Public Service Commission

LPPC Large Public Power Council

Mark Lively Mark B. Lively

MISO

Midwest Independent Transmission System Operator,

Inc.

Docket Nos. RM05-17-000 and RM05-25-000 - 1083 -

Abbreviation Supplemental Commenters

Nevada Companies

Nevada Power Company and Sierra Pacific Power

Company

North Carolina

Commission

North Carolina Utilities Commission; Public Staff of

the North Carolina Utilities Commission; and the

Attorney General of the State of North Carolina

NRECA National Rural Electric Cooperative Association

OG&E Oklahoma Gas and Electric Company

Pacific Coast Parties

Pacific Coast Parties (Avista Corporation, Bonneville

Power Administration, PacifiCorp, Portland General

Electric Company, Puget Sound Energy, Inc., the

Sacramento Municipal Utility District and the

Transmission Agency of Northern California)

PGP Public Generating Pool

Southwest Utilities

Pinnacle West Companies, Public Service Company of

New Mexico, Texas-New Mexico Power Company,

and UniSource Energy Corporation

PNM-TNMP

Public Service Company of New Mexico and Texas-

New Mexico Power Company

Powerex Powerex Corp.

PPL PPL Companies

PPM PPM Energy, Inc.

Progress Energy

Progress Energy, Inc. (Carolina Power & Light

Company, d/b/a. Progress Energy Carolinas, Inc. and

Florida Power Corporation, d/b/a Progress Energy

Florida, Inc.)

Progress Energy and

MidAmerican

Progress Energy, Inc. and MidAmerican Energy

Company

Public Power Council Public Power Council

SEARUC

Southeastern Association of Regulatory Utility

Commissioners

Docket Nos. RM05-17-000 and RM05-25-000 - 1084 -

Abbreviation Supplemental Commenters

South Carolina E&G South Carolina Electric & Gas Company

South Carolina

Regulatory Staff

South Carolina Office of Regulatory Staff

Southern Southern Company Services, Inc.

Tacoma Tacoma Power

TAPS Transmission Access Policy Study Group

TDU Systems Transmission Dependent Utilities Systems

Transparent Dispatch

Advocates

Transparent Dispatch Advocates (American Wind

Energy Association; Center for Energy Efficiency &

Renewable Technologies; Electric Consumers

Resource Council; Electric Power Supply Association;

Exelon Corporation; Natural Resources Defense

Council; PJM Interconnection, LLC; PPM Energy;

Project for Sustainable FERC Energy Policy;

Renewable Northwest Project; and Shell Trading Gas

and Power Company)*

1010

Western Governors Western Governors’ Association

Williams Williams Power Company, Inc.

WIRES WIRES

Xcel Xcel Energy Services, Inc.

1010

A “*” indicates that the composition of this group has altered in this filing.

Appendix C

RM05-17-000 & RM05-25-000

(Issued)

PRO FORMA OPEN ACCESS

TRANSMISSION TARIFF

(Name of Transmission Provider) Open Access Transmission Tariff

Original Sheet No. 2

TABLE OF CONTENTS

COMMON SERVICE PROVISIONS...................................................................10

1 DEFINITIONS...........................................................................................................10

1.1 Affiliate:.........................................................................................................10

1.2 Ancillary Services: ........................................................................................10

1.3 Annual Transmission Costs:..........................................................................10

1.4 Application: ...................................................................................................10

1.5 Commission:..................................................................................................11

1.6 Completed Application:................................................................................. 11

1.7 Control Area: .................................................................................................11

1.8 Curtailment:...................................................................................................11

1.9 Delivering Party:............................................................................................12

1.10 Designated Agent: .........................................................................................12

1.11 Direct Assignment Facilities: ........................................................................12

1.12 Eligible Customer:......................................................................................... 12

1.13 Facilities Study: ............................................................................................. 13

1.14 Firm Point-To-Point Transmission Service:..................................................13

1.15 Good Utility Practice:....................................................................................14

1.16 Interruption: ...................................................................................................14

1.17 Load Ratio Share: .......................................................................................... 14

1.18 Load Shedding:..............................................................................................15

1.19 Long-Term Firm Point-To-Point Transmission Service: ..............................15

1.20 Native Load Customers: ................................................................................15

1.21 Network Customer:........................................................................................ 15

1.22 Network Integration Transmission Service:..................................................15

1.23 Network Load:...............................................................................................16

1.24 Network Operating Agreement: ....................................................................16

1.25 Network Operating Committee: ....................................................................16

1.26 Network Resource: ........................................................................................17

1.27 Network Upgrades:........................................................................................17

1.28 Non-Firm Point-To-Point Transmission Service: .........................................17

1.29 Non-Firm Sale: ..............................................................................................17

1.30 Open Access Same-Time Information System (OASIS): .............................18

1.31 Part I: .............................................................................................................18

1.32 Part II: ............................................................................................................18

1.33 Part III:........................................................................................................... 18

1.34 Parties: ...........................................................................................................18

1.35 Point(s) of Delivery: ......................................................................................19

(Name of Transmission Provider) Open Access Transmission Tariff

Original Sheet No. 3

1.36

Point(s) of Receipt:........................................................................................19

1.37 Point-To-Point Transmission Service: ..........................................................19

1.38 Power Purchaser: ...........................................................................................19

1.39 Pre-Confirmed Application: ..........................................................................20

1.40 Receiving Party: ............................................................................................20

1.41 Regional Transmission Group (RTG): ..........................................................20

1.42 Reserved Capacity: ........................................................................................20

1.43 Service Agreement: .......................................................................................21

1.44 Service Commencement Date: ......................................................................21

1.45 Short-Term Firm Point-To-Point Transmission Service:..............................21

1.46 System Condition ..........................................................................................21

1.47 System Impact Study:....................................................................................22

1.48 Third-Party Sale:............................................................................................22

1.49 Transmission Customer: ................................................................................22

1.50 Transmission Provider:..................................................................................22

1.51 Transmission Provider's Monthly Transmission System Peak: ....................23

1.52 Transmission Service:.................................................................................... 23

1.53 Transmission System:....................................................................................23

2 INITIAL ALLOCATION AND RENEWAL PROCEDURES..............................................23

2.1 Initial Allocation of Available Transfer Capability: .....................................23

2.2 Reservation Priority For Existing Firm Service Customers:.........................24

3 ANCILLARY SERVICES ...........................................................................................25

3.1 Scheduling, System Control and Dispatch Service:......................................27

3.2 Reactive Supply and Voltage Control from Generation or Other Sources

Service: ......................................................................................................................28

3.3 Regulation and Frequency Response Service: .............................................. 28

3.4 Energy Imbalance Service:............................................................................28

3.5 Operating Reserve - Spinning Reserve Service: ...........................................28

3.6 Operating Reserve - Supplemental Reserve Service:....................................28

3.7 Generator Imbalance Service: .......................................................................28

4 OPEN ACCESS SAME-TIME INFORMATION SYSTEM (OASIS)................................28

5 LOCAL FURNISHING BONDS ...................................................................................29

5.1 Transmission Providers That Own Facilities Financed by Local Furnishing

Bonds: 30

5.2 Alternative Procedures for Requesting Transmission Service:.....................30

6 RECIPROCITY..........................................................................................................31

7 BILLING AND PAYMENT .........................................................................................33

(Name of Transmission Provider) Open Access Transmission Tariff

Original Sheet No. 4

7.1

Billing Procedure:..........................................................................................33

7.2 Interest on Unpaid Balances:.........................................................................33

7.3 Customer Default:..........................................................................................34

8 ACCOUNTING FOR THE TRANSMISSION PROVIDER'S USE OF THE TARIFF ..............34

8.1 Transmission Revenues:................................................................................35

8.2 Study Costs and Revenues: ...........................................................................35

9 REGULATORY FILINGS ...........................................................................................35

10 FORCE MAJEURE AND INDEMNIFICATION .............................................................. 36

10.1 Force Majeure:...............................................................................................36

10.2 Indemnification:.............................................................................................37

11 CREDITWORTHINESS ..............................................................................................37

12 DISPUTE RESOLUTION PROCEDURES .....................................................................37

12.1 Internal Dispute Resolution Procedures: .......................................................37

12.2 External Arbitration Procedures:...................................................................38

12.3 Arbitration Decisions:....................................................................................39

12.4 Costs: ............................................................................................................. 39

12.5 Rights Under The Federal Power Act: .......................................................... 40

II. POINT-TO-POINT TRANSMISSION SERVICE...............................................40

13 NATURE OF FIRM POINT-TO-POINT TRANSMISSION SERVICE ...............................40

13.1 Term: .............................................................................................................40

13.2 Reservation Priority:......................................................................................40

13.3 Use of Firm Transmission Service by the Transmission Provider:............... 43

13.4 Service Agreements:...................................................................................... 43

13.5 Transmission Customer Obligations for Facility Additions or Redispatch

Costs: 44

13.6 Curtailment of Firm Transmission Service: ..................................................46

13.7 Classification of Firm Transmission Service: ...............................................47

13.8 Scheduling of Firm Point-To-Point Transmission Service: ..........................49

14 NATURE OF NON-FIRM POINT-TO-POINT TRANSMISSION SERVICE ......................51

14.1 Term: .............................................................................................................51

14.2 Reservation Priority:......................................................................................51

14.3 Use of Non-Firm Point-To-Point Transmission Service by the Transmission

Provider: ....................................................................................................................52

14.4 Service Agreements:...................................................................................... 53

14.5 Classification of Non-Firm Point-To-Point Transmission Service: ..............53

14.6 Scheduling of Non-Firm Point-To-Point Transmission Service: ..................54

14.7 Curtailment or Interruption of Service: .........................................................55

(Name of Transmission Provider) Open Access Transmission Tariff

Original Sheet No. 5

SERVICE AVAILABILITY .........................................................................................57

15.1 General Conditions:.......................................................................................57

15.2 Determination of Available Transfer Capability:..........................................57

15.3 Initiating Service in the Absence of an Executed Service Agreement:.........58

15.4 Obligation to Provide Transmission Service that Requires Expansion or

Modification of the Transmission System, Redispatch or Conditional Curtailment:58

15.5 Deferral of Service: .......................................................................................61

15.6 Other Transmission Service Schedules: ........................................................61

15.7 Real Power Losses:........................................................................................61

16 TRANSMISSION CUSTOMER RESPONSIBILITIES ......................................................62

16.1 Conditions Required of Transmission Customers:........................................62

16.2 Transmission Customer Responsibility for Third-Party Arrangements:.......63

17 PROCEDURES FOR ARRANGING FIRM POINT-TO-POINT TRANSMISSION SERVICE 63

17.1 Application: ...................................................................................................63

17.2 Completed Application:.................................................................................64

17.3 Deposit:..........................................................................................................66

17.4 Notice of Deficient Application: ...................................................................68

17.5 Response to a Completed Application: .........................................................68

17.6 Execution of Service Agreement:..................................................................69

17.7 Extensions for Commencement of Service: ..................................................69

18 PROCEDURES FOR ARRANGING NON-FIRM POINT-TO-POINT TRANSMISSION

SERVICE .........................................................................................................................70

18.1 Application: ...................................................................................................70

18.2 Completed Application:.................................................................................71

18.3 Reservation of Non-Firm Point-To-Point Transmission Service:.................72

18.4 Determination of Available Transfer Capability:..........................................73

19 ADDITIONAL STUDY PROCEDURES FOR FIRM POINT-TO-POINT TRANSMISSION

SERVICE REQUESTS........................................................................................................73

19.1 Notice of Need for System Impact Study:.....................................................74

19.2 System Impact Study Agreement and Cost Reimbursement: .......................75

19.3 System Impact Study Procedures: .................................................................76

19.4 Facilities Study Procedures: ..........................................................................78

19.5 Facilities Study Modifications:......................................................................79

19.6 Due Diligence in Completing New Facilities:...............................................80

19.7 Partial Interim Service:..................................................................................80

19.8 Expedited Procedures for New Facilities: .....................................................81

19.9 Penalties for Failure to Meet Study Deadlines:.............................................82

20 PROCEDURES IF THE TRANSMISSION PROVIDER IS UNABLE TO COMPLETE NEW

(Name of Transmission Provider) Open Access Transmission Tariff

Original Sheet No. 6

RANSMISSION FACILITIES FOR FIRM POINT-TO-POINT TRANSMISSION SERVICE ........84

20.1 Delays in Construction of New Facilities:.....................................................84

20.2 Alternatives to the Original Facility Additions: ............................................84

20.3 Refund Obligation for Unfinished Facility Additions:.................................. 85

21 PROVISIONS RELATING TO TRANSMISSION CONSTRUCTION AND SERVICES ON THE

SYSTEMS OF OTHER UTILITIES ......................................................................................86

21.1 Responsibility for Third-Party System Additions:........................................86

21.2 Coordination of Third-Party System Additions: ........................................... 86

22 CHANGES IN SERVICE SPECIFICATIONS..................................................................87

22.1 Modifications On a Non-Firm Basis: ............................................................87

22.2 Modification On a Firm Basis: ......................................................................88

23 SALE OR ASSIGNMENT OF TRANSMISSION SERVICE ..............................................89

23.1 Procedures for Assignment or Transfer of Service: ......................................89

23.2 Limitations on Assignment or Transfer of Service: ......................................90

23.3 Information on Assignment or Transfer of Service: .....................................90

24 METERING AND POWER FACTOR CORRECTION AT RECEIPT AND DELIVERY

POINTS(S) ....................................................................................................................... 91

24.1 Transmission Customer Obligations: ............................................................91

24.2 Transmission Provider Access to Metering Data:.........................................91

24.3 Power Factor:.................................................................................................91

25 COMPENSATION FOR TRANSMISSION SERVICE ......................................................92

26 STRANDED COST RECOVERY .................................................................................92

27 COMPENSATION FOR NEW FACILITIES AND REDISPATCH COSTS ..........................92

III. NETWORK INTEGRATION TRANSMISSION SERVICE.............................93

28 NATURE OF NETWORK INTEGRATION TRANSMISSION SERVICE ............................93

28.1 Scope of Service: ...........................................................................................93

28.2 Transmission Provider Responsibilities: .......................................................94

28.3 Network Integration Transmission Service:..................................................95

28.4 Secondary Service: ........................................................................................95

28.5 Real Power Losses:........................................................................................96

28.6 Restrictions on Use of Service: .....................................................................96

29 INITIATING SERVICE...............................................................................................96

29.1 Condition Precedent for Receiving Service: .................................................97

29.2 Application Procedures: ................................................................................97

29.3 Technical Arrangements to be Completed Prior to Commencement of

Service: ....................................................................................................................104

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29.4

Network Customer Facilities:......................................................................104

29.5 Filing of Service Agreement: ......................................................................105

30 NETWORK RESOURCES ........................................................................................105

30.1 Designation of Network Resources:............................................................105

30.2 Designation of New Network Resources: ...................................................105

30.3 Termination of Network Resources: ...........................................................106

30.4 Operation of Network Resources: ............................................................... 108

30.5 Network Customer Redispatch Obligation:.................................................109

30.6 Transmission Arrangements for Network Resources Not Physically

Interconnected With The Transmission Provider:...................................................110

30.7 Limitation on Designation of Network Resources:.....................................110

30.8 Use of Interface Capacity by the Network Customer: ................................110

30.9 Network Customer Owned Transmission Facilities:...................................111

31 DESIGNATION OF NETWORK LOAD ......................................................................112

31.1 Network Load:............................................................................................. 112

31.2 New Network Loads Connected With the Transmission Provider: ............112

31.3 Network Load Not Physically Interconnected with the Transmission

Provider: ..................................................................................................................112

31.4 New Interconnection Points: .......................................................................113

31.5 Changes in Service Requests:......................................................................113

31.6 Annual Load and Resource Information Updates: ......................................114

32 ADDITIONAL STUDY PROCEDURES FOR NETWORK INTEGRATION TRANSMISSION

SERVICE REQUESTS......................................................................................................114

32.1 Notice of Need for System Impact Study:...................................................114

32.2 System Impact Study Agreement and Cost Reimbursement: .....................115

32.3 System Impact Study Procedures: ...............................................................116

32.4 Facilities Study Procedures: ........................................................................118

32.5 Penalties for Failure to Meet Study Deadlines:...........................................119

33 LOAD SHEDDING AND CURTAILMENTS................................................................119

33.1 Procedures: .................................................................................................. 120

33.2 Transmission Constraints: ...........................................................................120

33.3 Cost Responsibility for Relieving Transmission Constraints: ....................121

33.4 Curtailments of Scheduled Deliveries:........................................................121

33.5 Allocation of Curtailments: .........................................................................121

33.6 Load Shedding:............................................................................................122

33.7 System Reliability: ......................................................................................122

34 RATES AND CHARGES ..........................................................................................123

34.1 Monthly Demand Charge: ...........................................................................124

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34.2

Determination of Network Customer's Monthly Network Load:................124

34.3 Determination of Transmission Provider's Monthly Transmission System

Load: 124

34.4 Redispatch Charge:......................................................................................124

34.5 Stranded Cost Recovery: .............................................................................125

35 OPERATING ARRANGEMENTS ..............................................................................125

35.1 Operation under The Network Operating Agreement:................................125

35.2 Network Operating Agreement: ..................................................................125

35.3 Network Operating Committee: ..................................................................127

SCHEDULE 1................................................................................................................128

SCHEDULING, SYSTEM CONTROL AND DISPATCH SERVICE ....................................128

SCHEDULE 2................................................................................................................129

REACTIVE SUPPLY AND VOLTAGE CONTROL FROM GENERATION SOURCES

SERVICE ......................................................................................................................129

SCHEDULE 3................................................................................................................131

REGULATION AND FREQUENCY RESPONSE SERVICE...............................................131

SCHEDULE 4................................................................................................................132

ENERGY IMBALANCE SERVICE.................................................................................. 132

SCHEDULE 5................................................................................................................134

OPERATING RESERVE - SPINNING RESERVE SERVICE.............................................134

SCHEDULE 6................................................................................................................135

OPERATING RESERVE - SUPPLEMENTAL RESERVE SERVICE ..................................135

SCHEDULE 7................................................................................................................136

LONG-TERM FIRM AND SHORT-TERM FIRM POINT-TO-POINT..............................136

SCHEDULE 8................................................................................................................138

NON-FIRM POINT-TO-POINT TRANSMISSION SERVICE........................................... 138

SCHEDULE 9................................................................................................................140

GENERATOR IMBALANCE SERVICE........................................................................... 140

ATTACHMENT A........................................................................................................143

FORM OF SERVICE AGREEMENT FOR FIRM POINT-TO-POINT TRANSMISSION

SERVICE ......................................................................................................................143

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ATTACHMENT A-1.....................................................................................................147

FORM OF SERVICE AGREEMENT FOR THE RESALE, REASSIGNMENT OR TRANSFER

OF LONG-TERM FIRM POINT-TO-POINT TRANSMISSION SERVICE........................147

ATTACHMENT B ........................................................................................................151

FORM OF SERVICE AGREEMENT FOR NON-FIRM POINT-TO-POINT TRANSMISSION

SERVICE ......................................................................................................................151

ATTACHMENT C........................................................................................................153

METHODOLOGY TO ASSESS AVAILABLE TRANSFER CAPABILITY.......................... 153

ATTACHMENT D........................................................................................................155

METHODOLOGY FOR COMPLETING A SYSTEM IMPACT STUDY..............................155

ATTACHMENT E ........................................................................................................156

INDEX OF POINT-TO-POINT TRANSMISSION SERVICE CUSTOMERS.......................156

ATTACHMENT F.........................................................................................................157

SERVICE AGREEMENT FOR NETWORK INTEGRATION TRANSMISSION SERVICE... 157

ATTACHMENT G........................................................................................................158

NETWORK OPERATING AGREEMENT........................................................................158

ATTACHMENT H........................................................................................................159

ANNUAL TRANSMISSION REVENUE REQUIREMENT FOR NETWORK INTEGRATION

TRANSMISSION SERVICE ............................................................................................159

ATTACHMENT I..........................................................................................................160

INDEX OF NETWORK INTEGRATION TRANSMISSION SERVICE CUSTOMERS.......... 160

ATTACHMENT J.........................................................................................................161

PROCEDURES FOR ADDRESSING PARALLEL FLOWS ................................................161

ATTACHMENT K........................................................................................................162

TRANSMISSION PLANNING PROCESS.........................................................................162

ATTACHMENT L ........................................................................................................164

CREDITWORTHINESS PROCEDURES ..........................................................................164

(Name of Transmission Provider) Open Access Transmission Tariff

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I. COMMON SERVICE PROVISIONS

1 Definitions

1.1 Affiliate:

With respect to a corporation, partnership or other entity, each such other

corporation, partnership or other entity that directly or indirectly, through one

or more intermediaries, controls, is controlled by, or is under common control

with, such corporation, partnership or other entity.

1.2 Ancillary Services:

Those services that are necessary to support the transmission of capacity and

energy from resources to loads while maintaining reliable operation of the

Transmission Provider's Transmission System in accordance with Good

Utility Practice.

1.3 Annual Transmission Costs:

The total annual cost of the Transmission System for purposes of Network

Integration Transmission Service shall be the amount specified in Attachment

H until amended by the Transmission Provider or modified by the

Commission.

1.4 Application:

A request by an Eligible Customer for transmission service pursuant to the

provisions of the Tariff.

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1.5 Commission:

The Federal Energy Regulatory Commission.

1.6 Completed Application:

An Application that satisfies all of the information and other requirements of

the Tariff, including any required deposit.

1.7 Control Area:

An electric power system or combination of electric power systems to which a

common automatic generation control scheme is applied in order to:

1. match, at all times, the power output of the generators within the

electric power system(s) and capacity and energy purchased from

entities outside the electric power system(s), with the load within the

electric power system(s);

2. maintain scheduled interchange with other Control Areas, within the

limits of Good Utility Practice;

3. maintain the frequency of the electric power system(s) within

reasonable limits in accordance with Good Utility Practice; and

4. provide sufficient generating capacity to maintain operating reserves in

accordance with Good Utility Practice.

1.8 Curtailment:

A reduction in firm or non-firm transmission service in response to a transfer

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capability shortage as a result of system reliability conditions.

1.9 Delivering Party:

The entity supplying capacity and energy to be transmitted at Point(s) of

Receipt.

1.10 Designated Agent:

Any entity that performs actions or functions on behalf of the Transmission

Provider, an Eligible Customer, or the Transmission Customer required under

the Tariff.

1.11 Direct Assignment Facilities:

Facilities or portions of facilities that are constructed by the Transmission

Provider for the sole use/benefit of a particular Transmission Customer

requesting service under the Tariff. Direct Assignment Facilities shall be

specified in the Service Agreement that governs service to the Transmission

Customer and shall be subject to Commission approval.

1.12 Eligible Customer:

i. Any electric utility (including the Transmission Provider and any

power marketer), Federal power marketing agency, or any person

generating electric energy for sale for resale is an Eligible Customer

under the Tariff. Electric energy sold or produced by such entity may

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be electric energy produced in the United States, Canada or Mexico.

However, with respect to transmission service that the Commission is

prohibited from ordering by Section 212(h) of the Federal Power Act,

such entity is eligible only if the service is provided pursuant to a state

requirement that the Transmission Provider offer the unbundled

transmission service, or pursuant to a voluntary offer of such service by

the Transmission Provider.

ii. Any retail customer taking unbundled transmission service pursuant to

a state requirement that the Transmission Provider offer the

transmission service, or pursuant to a voluntary offer of such service by

the Transmission Provider, is an Eligible Customer under the Tariff.

1.13 Facilities Study:

An engineering study conducted by the Transmission Provider to determine

the required modifications to the Transmission Provider's Transmission

System, including the cost and scheduled completion date for such

modifications, that will be required to provide the requested transmission

service.

1.14 Firm Point-To-Point Transmission Service:

Transmission Service under this Tariff that is reserved and/or scheduled

between specified Points of Receipt and Delivery pursuant to Part II of this

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Tariff.

1.15 Good Utility Practice:

Any of the practices, methods and acts engaged in or approved by a significant

portion of the electric utility industry during the relevant time period, or any of

the practices, methods and acts which, in the exercise of reasonable judgment

in light of the facts known at the time the decision was made, could have been

expected to accomplish the desired result at a reasonable cost consistent with

good business practices, reliability, safety and expedition. Good Utility

Practice is not intended to be limited to the optimum practice, method, or act

to the exclusion of all others, but rather to be acceptable practices, methods, or

acts generally accepted in the region, including those practices required by

Federal Power Act section 215(a)(4).

1.16 Interruption:

A reduction in non-firm transmission service due to economic reasons

pursuant to Section 14.7.

1.17 Load Ratio Share:

Ratio of a Transmission Customer's Network Load to the Transmission

Provider's total load computed in accordance with Sections 34.2 and 34.3 of

the Network Integration Transmission Service under Part III of the Tariff and

calculated on a rolling twelve month basis.

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1.18 Load Shedding:

The systematic reduction of system demand by temporarily decreasing load in

response to transmission system or area capacity shortages, system instability,

or voltage control considerations under Part III of the Tariff.

1.19 Long-Term Firm Point-To-Point Transmission Service:

Firm Point-To-Point Transmission Service under Part II of the Tariff with a

term of one year or more.

1.20 Native Load Customers:

The wholesale and retail power customers of the Transmission Provider on

whose behalf the Transmission Provider, by statute, franchise, regulatory

requirement, or contract, has undertaken an obligation to construct and operate

the Transmission Provider's system to meet the reliable electric needs of such

customers.

1.21 Network Customer:

An entity receiving transmission service pursuant to the terms of the

Transmission Provider's Network Integration Transmission Service under Part

III of the Tariff.

1.22 Network Integration Transmission Service:

The transmission service provided under Part III of the Tariff.

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1.23 Network Load:

The load that a Network Customer designates for Network Integration

Transmission Service under Part III of the Tariff. The Network Customer's

Network Load shall include all load served by the output of any Network

Resources designated by the Network Customer. A Network Customer may

elect to designate less than its total load as Network Load but may not

designate only part of the load at a discrete Point of Delivery. Where a

Eligible Customer has elected not to designate a particular load at discrete

points of delivery as Network Load, the Eligible Customer is responsible for

making separate arrangements under Part II of the Tariff for any Point-To-

Point Transmission Service that may be necessary for such non-designated

load.

1.24 Network Operating Agreement:

An executed agreement that contains the terms and conditions under which the

Network Customer shall operate its facilities and the technical and operational

matters associated with the implementation of Network Integration

Transmission Service under Part III of the Tariff.

1.25 Network Operating Committee:

A group made up of representatives from the Network Customer(s) and the

Transmission Provider established to coordinate operating criteria and other

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technical considerations required for implementation of Network Integration

Transmission Service under Part III of this Tariff.

1.26 Network Resource:

Any designated generating resource owned, purchased or leased by a Network

Customer under the Network Integration Transmission Service Tariff.

Network Resources do not include any resource, or any portion thereof, that is

committed for sale to third parties or otherwise cannot be called upon to meet

the Network Customer's Network Load on a non-interruptible basis.

1.27 Network Upgrades:

Modifications or additions to transmission-related facilities that are integrated

with and support the Transmission Provider's overall Transmission System for

the general benefit of all users of such Transmission System.

1.28 Non-Firm Point-To-Point Transmission Service:

Point-To-Point Transmission Service under the Tariff that is reserved and

scheduled on an as-available basis and is subject to Curtailment or

Interruption as set forth in Section 14.7 under Part II of this Tariff. Non-Firm

Point-To-Point Transmission Service is available on a stand-alone basis for

periods ranging from one hour to one month.

1.29 Non-Firm Sale:

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An energy sale for which receipt or delivery may be interrupted for any reason

or no reason, without liability on the part of either the buyer or seller.

1.30 Open Access Same-Time Information System (OASIS):

The information system and standards of conduct contained in Part 37 of the

Commission's regulations and all additional requirements implemented by

subsequent Commission orders dealing with OASIS.

1.31 Part I:

Tariff Definitions and Common Service Provisions contained in Sections 2

through 12.

1.32 Part II:

Tariff Sections 13 through 27 pertaining to Point-To-Point Transmission

Service in conjunction with the applicable Common Service Provisions of Part

I and appropriate Schedules and Attachments.

1.33 Part III:

Tariff Sections 28 through 35 pertaining to Network Integration Transmission

Service in conjunction with the applicable Common Service Provisions of Part

I and appropriate Schedules and Attachments.

1.34 Parties:

The Transmission Provider and the Transmission Customer receiving service

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under the Tariff.

1.35 Point(s) of Delivery:

Point(s) on the Transmission Provider's Transmission System where capacity

and energy transmitted by the Transmission Provider will be made available to

the Receiving Party under Part II of the Tariff. The Point(s) of Delivery shall

be specified in the Service Agreement for Long-Term Firm Point-To-Point

Transmission Service.

1.36 Point(s) of Receipt:

Point(s) of interconnection on the Transmission Provider's Transmission

System where capacity and energy will be made available to the Transmission

Provider by the Delivering Party under Part II of the Tariff. The Point(s) of

Receipt shall be specified in the Service Agreement for Long-Term Firm

Point-To-Point Transmission Service.

1.37 Point-To-Point Transmission Service:

The reservation and transmission of capacity and energy on either a firm or

non-firm basis from the Point(s) of Receipt to the Point(s) of Delivery under

Part II of the Tariff.

1.38 Power Purchaser:

The entity that is purchasing the capacity and energy to be transmitted under

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the Tariff.

1.39 Pre-Confirmed Application:

An Application that commits the Transmission Customer to execute a Service

Agreement upon receipt of notification that the Transmission Provider can

provide the requested Transmission Service.

1.40 Receiving Party:

The entity receiving the capacity and energy transmitted by the Transmission

Provider to Point(s) of Delivery.

1.41 Regional Transmission Group (RTG):

A voluntary organization of transmission owners, transmission users and other

entities approved by the Commission to efficiently coordinate transmission

planning (and expansion), operation and use on a regional (and interregional)

basis.

1.42 Reserved Capacity:

The maximum amount of capacity and energy that the Transmission Provider

agrees to transmit for the Transmission Customer over the Transmission

Provider's Transmission System between the Point(s) of Receipt and the

Point(s) of Delivery under Part II of the Tariff. Reserved Capacity shall be

expressed in terms of whole megawatts on a sixty (60) minute interval

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(commencing on the clock hour) basis.

1.43 Service Agreement:

The initial agreement and any amendments or supplements thereto entered

into by the Transmission Customer and the Transmission Provider for service

under the Tariff.

1.44 Service Commencement Date:

The date the Transmission Provider begins to provide service pursuant to the

terms of an executed Service Agreement, or the date the Transmission

Provider begins to provide service in accordance with Section 15.3 or Section

29.1 under the Tariff.

1.45 Short-Term Firm Point-To-Point Transmission Service:

Firm Point-To-Point Transmission Service under Part II of the Tariff with a

term of less than one year.

1.46 System Condition

A specified condition on the Transmission Provider’s system or on a

neighboring system, such as a constrained transmission element or flowgate,

that may trigger Curtailment of Long-Term Firm Point-to-Point Transmission

Service using the curtailment priority pursuant to Section 13.6. Such

conditions must be identified in the Transmission Customer’s Service

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Agreement.

1.47 System Impact Study:

An assessment by the Transmission Provider of (i) the adequacy of the

Transmission System to accommodate a request for either Firm Point-To-

Point Transmission Service or Network Integration Transmission Service and

(ii) whether any additional costs may be incurred in order to provide

transmission service.

1.48 Third-Party Sale:

Any sale for resale in interstate commerce to a Power Purchaser that is not

designated as part of Network Load under the Network Integration

Transmission Service.

1.49 Transmission Customer:

Any Eligible Customer (or its Designated Agent) that (i) executes a Service

Agreement, or (ii) requests in writing that the Transmission Provider file with

the Commission, a proposed unexecuted Service Agreement to receive

transmission service under Part II of the Tariff. This term is used in the Part I

Common Service Provisions to include customers receiving transmission

service under Part II and Part III of this Tariff.

1.50 Transmission Provider:

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The public utility (or its Designated Agent) that owns, controls, or operates

facilities used for the transmission of electric energy in interstate commerce

and provides transmission service under the Tariff.

1.51 Transmission Provider's Monthly Transmission System Peak:

The maximum firm usage of the Transmission Provider's Transmission

System in a calendar month.

1.52 Transmission Service:

Point-To-Point Transmission Service provided under Part II of the Tariff on a

firm and non-firm basis.

1.53 Transmission System:

The facilities owned, controlled or operated by the Transmission Provider that

are used to provide transmission service under Part II and Part III of the Tariff.

2 Initial Allocation and Renewal Procedures

2.1 Initial Allocation of Available Transfer Capability:

For purposes of determining whether existing capability on the Transmission

Provider's Transmission System is adequate to accommodate a request for

firm service under this Tariff, all Completed Applications for new firm

transmission service received during the initial sixty (60) day period

commencing with the effective date of the Tariff will be deemed to have been

filed simultaneously. A lottery system conducted by an independent party

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shall be used to assign priorities for Completed Applications filed

simultaneously. All Completed Applications for firm transmission service

received after the initial sixty (60) day period shall be assigned a priority

pursuant to Section 13.2.

2.2 Reservation Priority For Existing Firm Service Customers:

Existing firm service customers (wholesale requirements and transmission-

only, with a contract term of five years or more), have the right to continue to

take transmission service from the Transmission Provider when the contract

expires, rolls over or is renewed. This transmission reservation priority is

independent of whether the existing customer continues to purchase capacity

and energy from the Transmission Provider or elects to purchase capacity and

energy from another supplier. If at the end of the contract term, the

Transmission Provider's Transmission System cannot accommodate all of the

requests for transmission service, the existing firm service customer must

agree to accept a contract term at least equal to the longer of a competing

request by any new Eligible Customer or five years and to pay the current just

and reasonable rate, as approved by the Commission, for such service. The

existing firm service customer must provide notice to the Transmission

Provider whether it will exercise its right of first refusal no less than one year

prior to the expiration date of its transmission service agreement. This

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Original Sheet No. 25

transmission reservation priority for existing firm service customers is an

ongoing right that may be exercised at the end of all firm contract terms of

five years or longer. Service agreements subject to a right of first refusal

entered into prior to [the acceptance by the Commission of the Transmission

Provider’s Attachment K], unless terminated, will become subject to the five

year/one year requirement on the first rollover date after [the acceptance by

the Commission of the Transmission Provider’s Attachment K].

3 Ancillary Services

Ancillary Services are needed with transmission service to maintain

reliability within and among the Control Areas affected by the transmission

service. The Transmission Provider is required to provide (or offer to arrange with

the local Control Area operator as discussed below), and the Transmission

Customer is required to purchase, the following Ancillary Services (i) Scheduling,

System Control and Dispatch, and (ii) Reactive Supply and Voltage Control from

Generation or Other Sources.

The Transmission Provider is required to offer to provide (or offer to

arrange with the local Control Area operator as discussed below) the following

Ancillary Services only to the Transmission Customer serving load within the

Transmission Provider's Control Area (i) Regulation and Frequency Response, (ii)

Energy Imbalance, (iii) Operating Reserve - Spinning, (iv) Operating Reserve -

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Supplemental, and (v) Generator Imbalance. The Transmission Customer serving

load within the Transmission Provider's Control Area is required to acquire these

Ancillary Services, whether from the Transmission Provider, from a third party, or

by self-supply. The Transmission Customer may not decline the Transmission

Provider's offer of Ancillary Services unless it demonstrates that it has acquired

the Ancillary Services from another source. The Transmission Customer must list

in its Application which Ancillary Services it will purchase from the Transmission

Provider. A Transmission Customer that exceeds its firm reserved capacity at any

Point of Receipt or Point of Delivery or an Eligible Customer that uses

Transmission Service at a Point of Receipt or Point of Delivery that it has not

reserved is required to pay for all of the Ancillary Services identified in this

section that were provided by the Transmission Provider associated with the

unreserved service. The Transmission Customer or Eligible Customer will pay for

Ancillary Services based on the amount of transmission service it used but did not

reserve.

If the Transmission Provider is a public utility providing transmission

service but is not a Control Area operator, it may be unable to provide some or all

of the Ancillary Services. In this case, the Transmission Provider can fulfill its

obligation to provide Ancillary Services by acting as the Transmission Customer's

agent to secure these Ancillary Services from the Control Area operator. The

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Transmission Customer may elect to (i) have the Transmission Provider act as its

agent, (ii) secure the Ancillary Services directly from the Control Area operator, or

(iii) secure the Ancillary Services (discussed in Schedules 3, 4, 5, 6 and 9) from a

third party or by self-supply when technically feasible.

The Transmission Provider shall specify the rate treatment and all related

terms and conditions in the event of an unauthorized use of Ancillary Services by

the Transmission Customer.

The specific Ancillary Services, prices and/or compensation methods are

described on the Schedules that are attached to and made a part of the Tariff.

Three principal requirements apply to discounts for Ancillary Services provided

by the Transmission Provider in conjunction with its provision of transmission

service as follows: (1) any offer of a discount made by the Transmission Provider

must be announced to all Eligible Customers solely by posting on the OASIS, (2)

any customer-initiated requests for discounts (including requests for use by one's

wholesale merchant or an affiliate's use) must occur solely by posting on the

OASIS, and (3) once a discount is negotiated, details must be immediately posted

on the OASIS. A discount agreed upon for an Ancillary Service must be offered

for the same period to all Eligible Customers on the Transmission Provider's

system. Sections 3.1 through 3.7 below list the seven Ancillary Services.

3.1 Scheduling, System Control and Dispatch Service:

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Original Sheet No. 28

The rates and/or methodology are described in Schedule 1.

3.2 Reactive Supply and Voltage Control from Generation or Other

Sources Service:

The rates and/or methodology are described in Schedule 2.

3.3 Regulation and Frequency Response Service:

Where applicable the rates and/or methodology are described in Schedule 3.

3.4 Energy Imbalance Service:

Where applicable the rates and/or methodology are described in Schedule 4.

3.5 Operating Reserve - Spinning Reserve Service:

Where applicable the rates and/or methodology are described in Schedule 5.

3.6 Operating Reserve - Supplemental Reserve Service:

Where applicable the rates and/or methodology are described in Schedule 6.

3.7 Generator Imbalance Service:

Where applicable the rates and/or methodology are described in Schedule 9.

4 Open Access Same-Time Information System (OASIS)

Terms and conditions regarding Open Access Same-Time Information

System and standards of conduct are set forth in 18 CFR § 37 of the Commission's

regulations (Open Access Same-Time Information System and Standards of

Conduct for Public Utilities) and 18 C.F.R. § 38 of the Commission’s regulations

(Name of Transmission Provider) Open Access Transmission Tariff

Original Sheet No. 29

(Business Practice Standards and Communication Protocols for Public Utilities).

In the event available transfer capability as posted on the OASIS is insufficient to

accommodate a request for firm transmission service, additional studies may be

required as provided by this Tariff pursuant to Sections 19 and 32.

The Transmission Provider shall post on its public website all rules,

standards and practices that (i) relate to the terms and conditions of transmission

service, (ii) are not subject to a North American Energy Standards Board

(NAESB) copyright restriction, and (iii) are not otherwise included in this Tariff.

The Transmission Provider shall post on OASIS an electronic link to these rules,

standards and practices, and shall post on its public website an electronic link to

the NAESB website where any rules, standards and practices that are protected by

on its public website a statement of the process by which the Transmission

Provider shall add, delete or otherwise modify the rules, standards and practices

that are posted on its website. Such process shall set forth the means by which the

Transmission Provider shall provide reasonable advance notice to Transmission

Customers and Eligible Customers of any such additions, deletions or

modifications, the associated effective date, and any additional implementation

procedures that the Transmission Provider deems appropriate.

5 Local Furnishing Bonds

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Original Sheet No. 30

5.1 Transmission Providers That Own Facilities Financed by Local

Furnishing Bonds:

This provision is applicable only to Transmission Providers that have financed

facilities for the local furnishing of electric energy with tax-exempt bonds, as

described in Section 142(f) of the Internal Revenue Code ("local furnishing

bonds"). Notwithstanding any other provision of this Tariff, the Transmission

Provider shall not be required to provide transmission service to any Eligible

Customer pursuant to this Tariff if the provision of such transmission service

would jeopardize the tax-exempt status of any local furnishing bond(s) used to

finance the Transmission Provider's facilities that would be used in providing

such transmission service.

5.2 Alternative Procedures for Requesting Transmission Service:

(i) If the Transmission Provider determines that the provision of

transmission service requested by an Eligible Customer would

jeopardize the tax-exempt status of any local furnishing bond(s)

used to finance its facilities that would be used in providing such

transmission service, it shall advise the Eligible Customer within

thirty (30) days of receipt of the Completed Application.

(ii) If the Eligible Customer thereafter renews its request for the same

transmission service referred to in (i) by tendering an application

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under Section 211 of the Federal Power Act, the Transmission

Provider, within ten (10) days of receiving a copy of the Section

211 application, will waive its rights to a request for service under

Section 213(a) of the Federal Power Act and to the issuance of a

proposed order under Section 212(c) of the Federal Power Act.

The Commission, upon receipt of the Transmission Provider's

waiver of its rights to a request for service under Section 213(a)

of the Federal Power Act and to the issuance of a proposed order

under Section 212(c) of the Federal Power Act, shall issue an

order under Section 211 of the Federal Power Act. Upon issuance

of the order under Section 211 of the Federal Power Act, the

Transmission Provider shall be required to provide the requested

transmission service in accordance with the terms and conditions

of this Tariff.

6 Reciprocity

A Transmission Customer receiving transmission service under this Tariff

agrees to provide comparable transmission service that it is capable of providing to

the Transmission Provider on similar terms and conditions over facilities used for

the transmission of electric energy owned, controlled or operated by the

Transmission Customer and over facilities used for the transmission of electric

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energy owned, controlled or operated by the Transmission Customer's corporate

affiliates. A Transmission Customer that is a member of, or takes transmission

service from, a power pool, Regional Transmission Group, Regional Transmission

Organization (RTO), Independent System Operator (ISO) or other transmission

organization approved by the Commission for the operation of transmission

facilities also agrees to provide comparable transmission service to the members

of such power pool and Regional Transmission Group, RTO, ISO or other

transmission organization on similar terms and conditions over facilities used for

the transmission of electric energy owned, controlled or operated by the

Transmission Customer and over facilities used for the transmission of electric

energy owned, controlled or operated by the Transmission Customer's corporate

affiliates.

This reciprocity requirement applies not only to the Transmission Customer

that obtains transmission service under the Tariff, but also to all parties to a

transaction that involves the use of transmission service under the Tariff, including

the power seller, buyer and any intermediary, such as a power marketer. This

reciprocity requirement also applies to any Eligible Customer that owns, controls

or operates transmission facilities that uses an intermediary, such as a power

marketer, to request transmission service under the Tariff. If the Transmission

Customer does not own, control or operate transmission facilities, it must include

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in its Application a sworn statement of one of its duly authorized officers or other

representatives that the purpose of its Application is not to assist an Eligible

Customer to avoid the requirements of this provision.

7 Billing and Payment

7.1 Billing Procedure:

Within a reasonable time after the first day of each month, the Transmission

Provider shall submit an invoice to the Transmission Customer for the charges

for all services furnished under the Tariff during the preceding month. The

invoice shall be paid by the Transmission Customer within twenty (20) days

of receipt. All payments shall be made in immediately available funds

payable to the Transmission Provider, or by wire transfer to a bank named by

the Transmission Provider.

7.2 Interest on Unpaid Balances:

Interest on any unpaid amounts (including amounts placed in escrow) shall be

calculated in accordance with the methodology specified for interest on

refunds in the Commission's regulations at 18 C.F.R.  35.19a(a)(2)(iii).

Interest on delinquent amounts shall be calculated from the due date of the bill

to the date of payment. When payments are made by mail, bills shall be

considered as having been paid on the date of receipt by the Transmission

Provider.

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7.3 Customer Default:

In the event the Transmission Customer fails, for any reason other than a

billing dispute as described below, to make payment to the Transmission

Provider on or before the due date as described above, and such failure of

payment is not corrected within thirty (30) calendar days after the

Transmission Provider notifies the Transmission Customer to cure such

failure, a default by the Transmission Customer shall be deemed to exist.

Upon the occurrence of a default, the Transmission Provider may initiate a

proceeding with the Commission to terminate service but shall not terminate

service until the Commission so approves any such request. In the event of a

billing dispute between the Transmission Provider and the Transmission

Customer, the Transmission Provider will continue to provide service under

the Service Agreement as long as the Transmission Customer (i) continues to

make all payments not in dispute, and (ii) pays into an independent escrow

account the portion of the invoice in dispute, pending resolution of such

dispute. If the Transmission Customer fails to meet these two requirements

for continuation of service, then the Transmission Provider may provide

notice to the Transmission Customer of its intention to suspend service in

sixty (60) days, in accordance with Commission policy.

8 Accounting for the Transmission Provider's Use of the Tariff

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The Transmission Provider shall record the following amounts, as outlined

below.

8.1 Transmission Revenues:

Include in a separate operating revenue account or subaccount the revenues it

receives from Transmission Service when making Third-Party Sales under

Part II of the Tariff.

8.2 Study Costs and Revenues:

Include in a separate transmission operating expense account or subaccount,

costs properly chargeable to expense that are incurred to perform any System

Impact Studies or Facilities Studies which the Transmission Provider conducts

to determine if it must construct new transmission facilities or upgrades

necessary for its own uses, including making Third-Party Sales under the

Tariff; and include in a separate operating revenue account or subaccount the

revenues received for System Impact Studies or Facilities Studies performed

when such amounts are separately stated and identified in the Transmission

Customer's billing under the Tariff.

9 Regulatory Filings

Nothing contained in the Tariff or any Service Agreement shall be

construed as affecting in any way the right of the Transmission Provider to

unilaterally make application to the Commission for a change in rates, terms and

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conditions, charges, classification of service, Service Agreement, rule or

regulation under Section 205 of the Federal Power Act and pursuant to the

Commission's rules and regulations promulgated thereunder.

Nothing contained in the Tariff or any Service Agreement shall be

construed as affecting in any way the ability of any Party receiving service under

the Tariff to exercise its rights under the Federal Power Act and pursuant to the

Commission's rules and regulations promulgated thereunder.

10 Force Majeure and Indemnification

10.1 Force Majeure:

An event of Force Majeure means any act of God, labor disturbance, act of the

public enemy, war, insurrection, riot, fire, storm or flood, explosion, breakage

or accident to machinery or equipment, any Curtailment, order, regulation or

restriction imposed by governmental military or lawfully established civilian

authorities, or any other cause beyond a Party’s control. A Force Majeure

event does not include an act of negligence or intentional wrongdoing.

Neither the Transmission Provider nor the Transmission Customer will be

considered in default as to any obligation under this Tariff if prevented from

fulfilling the obligation due to an event of Force Majeure. However, a Party

whose performance under this Tariff is hindered by an event of Force Majeure

shall make all reasonable efforts to perform its obligations under this Tariff.

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10.2 Indemnification:

The Transmission Customer shall at all times indemnify, defend, and save the

Transmission Provider harmless from, any and all damages, losses, claims,

including claims and actions relating to injury to or death of any person or

damage to property, demands, suits, recoveries, costs and expenses, court

costs, attorney fees, and all other obligations by or to third parties, arising out

of or resulting from the Transmission Provider’s performance of its

obligations under this Tariff on behalf of the Transmission Customer, except

in cases of negligence or intentional wrongdoing by the Transmission

Provider.

11 Creditworthiness

The Transmission Provider will specify its Creditworthiness procedures in

Attachment L.

12 Dispute Resolution Procedures

12.1 Internal Dispute Resolution Procedures:

Any dispute between a Transmission Customer and the Transmission Provider

involving transmission service under the Tariff (excluding applications for

rate changes or other changes to the Tariff, or to any Service Agreement

entered into under the Tariff, which shall be presented directly to the

Commission for resolution) shall be referred to a designated senior

representative of the Transmission Provider and a senior representative of the

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Transmission Customer for resolution on an informal basis as promptly as

practicable. In the event the designated representatives are unable to resolve

the dispute within thirty (30) days [or such other period as the Parties may

agree upon] by mutual agreement, such dispute may be submitted to

arbitration and resolved in accordance with the arbitration procedures set forth

below.

12.2 External Arbitration Procedures:

Any arbitration initiated under the Tariff shall be conducted before a single

neutral arbitrator appointed by the Parties. If the Parties fail to agree upon a

single arbitrator within ten (10) days of the referral of the dispute to

arbitration, each Party shall choose one arbitrator who shall sit on a three-

member arbitration panel. The two arbitrators so chosen shall within twenty

(20) days select a third arbitrator to chair the arbitration panel. In either case,

the arbitrators shall be knowledgeable in electric utility matters, including

electric transmission and bulk power issues, and shall not have any current or

past substantial business or financial relationships with any party to the

arbitration (except prior arbitration). The arbitrator(s) shall provide each of

the Parties an opportunity to be heard and, except as otherwise provided

herein, shall generally conduct the arbitration in accordance with the

Commercial Arbitration Rules of the American Arbitration Association and

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any applicable Commission regulations or Regional Transmission Group

rules.

12.3 Arbitration Decisions:

Unless otherwise agreed, the arbitrator(s) shall render a decision within ninety

(90) days of appointment and shall notify the Parties in writing of such

decision and the reasons therefor. The arbitrator(s) shall be authorized only to

interpret and apply the provisions of the Tariff and any Service Agreement

entered into under the Tariff and shall have no power to modify or change any

of the above in any manner. The decision of the arbitrator(s) shall be final and

binding upon the Parties, and judgment on the award may be entered in any

court having jurisdiction. The decision of the arbitrator(s) may be appealed

solely on the grounds that the conduct of the arbitrator(s), or the decision

itself, violated the standards set forth in the Federal Arbitration Act and/or the

Administrative Dispute Resolution Act. The final decision of the arbitrator

must also be filed with the Commission if it affects jurisdictional rates, terms

and conditions of service or facilities.

12.4 Costs:

Each Party shall be responsible for its own costs incurred during the

arbitration process and for the following costs, if applicable:

1. the cost of the arbitrator chosen by the Party to sit on the three member

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panel and one half of the cost of the third arbitrator chosen; or

2. one half the cost of the single arbitrator jointly chosen by the Parties.

12.5 Rights Under The Federal Power Act:

Nothing in this section shall restrict the rights of any party to file a Complaint

with the Commission under relevant provisions of the Federal Power Act.

II. POINT-TO-POINT TRANSMISSION SERVICE

Preamble

The Transmission Provider will provide Firm and Non-Firm Point-To-Point

Transmission Service pursuant to the applicable terms and conditions of this Tariff.

Point-To-Point Transmission Service is for the receipt of capacity and energy at

designated Point(s) of Receipt and the transfer of such capacity and energy to designated

Point(s) of Delivery.

13 Nature of Firm Point-To-Point Transmission Service

13.1 Term:

The minimum term of Firm Point-To-Point Transmission Service shall be one

day and the maximum term shall be specified in the Service Agreement.

13.2 Reservation Priority:

(i) Long-Term Firm Point-To-Point Transmission Service shall be

available on a first-come, first-served basis, i.e.

, in the

chronological sequence in which each Transmission Customer has

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requested service.

(ii) Reservations for Short-Term Firm Point-To-Point Transmission

Service will be conditional based upon the length of the requested

transaction. However, Pre-Confirmed Applications for Short-

Term Point-to-Point Transmission Service will receive priority

over earlier-submitted requests that are not Pre-Confirmed and

that have equal or shorter duration. Among requests with the

same duration and pre-confirmation status (Pre-Confirmed or not

confirmed), priority will be given to an Eligible Customer’s

request that offers the highest price, followed by the date and time

of the request.

(iii) If the Transmission System becomes oversubscribed, requests for

longer term service may preempt requests for shorter term service

up to the following deadlines: one day before the commencement

of daily service, one week before the commencement of weekly

service, and one month before the commencement of monthly

service. Before the conditional reservation deadline, if available

transfer capability is insufficient to satisfy all Applications, an

Eligible Customer with a reservation for shorter term service or

equal duration service and lower price has the right of first refusal

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to match any longer term request or equal duration service with a

higher price before losing its reservation priority. A longer term

competing request for Short-Term Firm Point-To-Point

Transmission Service will be granted if the Eligible Customer

with the right of first refusal does not agree to match the

competing request within 24 hours (or earlier if necessary to

comply with the scheduling deadlines provided in section 13.8)

from being notified by the Transmission Provider of a longer-term

competing request for Short-Term Firm Point-To-Point

Transmission Service. When a longer duration request preempts

multiple shorter duration requests, the shorter duration requests

shall have simultaneous opportunities to exercise the right of first

refusal. Duration, pre-confirmation status, price and time of

response will be used to determine the order by which the

multiple shorter duration requests will be able to exercise the right

of first refusal. After the conditional reservation deadline, service

will commence pursuant to the terms of Part II of the Tariff.

(iv) Firm Point-To-Point Transmission Service will always have a

reservation priority over Non-Firm Point-To-Point Transmission

Service under the Tariff. All Long-Term Firm Point-To-Point

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Transmission Service will have equal reservation priority with

Native Load Customers and Network Customers. Reservation

priorities for existing firm service customers are provided in

Section 2.2.

13.3 Use of Firm Transmission Service by the Transmission Provider:

The Transmission Provider will be subject to the rates, terms and conditions of

Part II of the Tariff when making Third-Party Sales under (i) agreements

executed on or after [insert date sixty (60) days after publication in Federal

Commission requires to be unbundled, by the date specified by the

Commission. The Transmission Provider will maintain separate accounting,

pursuant to Section 8, for any use of the Point-To-Point Transmission Service

to make Third-Party Sales.

13.4 Service Agreements:

The Transmission Provider shall offer a standard form Firm Point-To-Point

Transmission Service Agreement (Attachment A) to an Eligible Customer

when it submits a Completed Application for Long-Term Firm Point-To-Point

Transmission Service. The Transmission Provider shall offer a standard form

Firm Point-To-Point Transmission Service Agreement (Attachment A) to an

Eligible Customer when it first submits a Completed Application for Short-

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Term Firm Point-To-Point Transmission Service pursuant to the Tariff.

Executed Service Agreements that contain the information required under the

Tariff shall be filed with the Commission in compliance with applicable

Commission regulations. An Eligible Customer that uses Transmission

Service at a Point of Receipt or Point of Delivery that it has not reserved and

that has not executed a Service Agreement will be deemed, for purposes of

assessing any appropriate charges and penalties, to have executed the

appropriate Service Agreement. The Service Agreement shall, when

applicable, specify any conditional curtailment options selected by the

Transmission Customer. Where the Service Agreement contains conditional

curtailment options and is subject to a biennial reassessment as described in

Section 15.4, the Transmission Provider shall provide the Transmission

Customer notice of any changes to the curtailment conditions no less than 90

days prior to the date for imposition of new curtailment conditions.

Concurrent with such notice, the Transmission Provider shall provide the

Transmission Customer with the reassessment study and a narrative

description of the study, including the reasons for changes to the number of

hours per year or System Conditions under which conditional curtailment may

occur.

13.5 Transmission Customer Obligations for Facility Additions or

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Redispatch Costs:

In cases where the Transmission Provider determines that the Transmission

System is not capable of providing Firm Point-To-Point Transmission Service

without (1) degrading or impairing the reliability of service to Native Load

Customers, Network Customers and other Transmission Customers taking

Firm Point-To-Point Transmission Service, or (2) interfering with the

Transmission Provider's ability to meet prior firm contractual commitments to

others, the Transmission Provider will be obligated to expand or upgrade its

Transmission System pursuant to the terms of Section 15.4. The Transmission

Customer must agree to compensate the Transmission Provider for any

necessary transmission facility additions pursuant to the terms of Section 27.

To the extent the Transmission Provider can relieve any system constraint by

redispatching the Transmission Provider's resources, it shall do so, provided

that the Eligible Customer agrees to compensate the Transmission Provider

pursuant to the terms of Section 27 and agrees to either (i) compensate the

Transmission Provider for any necessary transmission facility additions or (ii)

accept the service subject to a biennial reassessment by the Transmission

Provider of redispatch requirements as described in Section 15.4. Any

redispatch, Network Upgrade or Direct Assignment Facilities costs to be

charged to the Transmission Customer on an incremental basis under the

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Tariff will be specified in the Service Agreement prior to initiating service.

13.6 Curtailment of Firm Transmission Service:

In the event that a Curtailment on the Transmission Provider's Transmission

System, or a portion thereof, is required to maintain reliable operation of such

system and the system directly and indirectly interconnected with

Transmission Provider’s Transmission System, Curtailments will be made on

a non-discriminatory basis to the transaction(s) that effectively relieve the

constraint. Transmission Provider may elect to implement such Curtailments

pursuant to the Transmission Loading Relief procedures specified in

Attachment J. If multiple transactions require Curtailment, to the extent

practicable and consistent with Good Utility Practice, the Transmission

Provider will curtail service to Network Customers and Transmission

Customers taking Firm Point-To-Point Transmission Service on a basis

comparable to the curtailment of service to the Transmission Provider's Native

Load Customers. All Curtailments will be made on a non-discriminatory

basis, however, Non-Firm Point-To-Point Transmission Service shall be

subordinate to Firm Transmission Service. Long-Term Firm Point-to-Point

Service subject to conditions described in Section 15.4 shall be curtailed with

secondary service in cases where the conditions apply, but otherwise will be

curtailed on a pro rata basis with other Firm Transmission Service. When the

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Transmission Provider determines that an electrical emergency exists on its

Transmission System and implements emergency procedures to Curtail Firm

Transmission Service, the Transmission Customer shall make the required

reductions upon request of the Transmission Provider. However, the

Transmission Provider reserves the right to Curtail, in whole or in part, any

Firm Transmission Service provided under the Tariff when, in the

Transmission Provider's sole discretion, an emergency or other unforeseen

condition impairs or degrades the reliability of its Transmission System. The

Transmission Provider will notify all affected Transmission Customers in a

timely manner of any scheduled Curtailments.

13.7 Classification of Firm Transmission Service:

(a) The Transmission Customer taking Firm Point-To-Point

Transmission Service may (1) change its Receipt and Delivery

Points to obtain service on a non-firm basis consistent with the

terms of Section 22.1 or (2) request a modification of the Points

of Receipt or Delivery on a firm basis pursuant to the terms of

Section 22.2.

(b) The Transmission Customer may purchase transmission service to

make sales of capacity and energy from multiple generating units

that are on the Transmission Provider's Transmission System. For

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such a purchase of transmission service, the resources will be

designated as multiple Points of Receipt, unless the multiple

generating units are at the same generating plant in which case the

units would be treated as a single Point of Receipt.

capacity and energy from the Point(s) of Receipt to the Point(s) of

Delivery. Each Point of Receipt at which firm transmission

capacity is reserved by the Transmission Customer shall be set

forth in the Firm Point-To-Point Service Agreement for Long-

Term Firm Transmission Service along with a corresponding

capacity reservation associated with each Point of Receipt. Points

of Receipt and corresponding capacity reservations shall be as

mutually agreed upon by the Parties for Short-Term Firm

Transmission. Each Point of Delivery at which firm transfer

capability is reserved by the Transmission Customer shall be set

forth in the Firm Point-To-Point Service Agreement for Long-

Term Firm Transmission Service along with a corresponding

capacity reservation associated with each Point of Delivery.

Points of Delivery and corresponding capacity reservations shall

be as mutually agreed upon by the Parties for Short-Term Firm

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Transmission. The greater of either (1) the sum of the capacity

reservations at the Point(s) of Receipt, or (2) the sum of the

capacity reservations at the Point(s) of Delivery shall be the

Transmission Customer's Reserved Capacity. The Transmission

Customer will be billed for its Reserved Capacity under the terms

of Schedule 7. The Transmission Customer may not exceed its

firm capacity reserved at each Point of Receipt and each Point of

Delivery except as otherwise specified in Section 22. The

Transmission Provider shall specify the rate treatment and all

related terms and conditions applicable in the event that a

Transmission Customer (including Third-Party Sales by the

Transmission Provider) exceeds its firm reserved capacity at any

Point of Receipt or Point of Delivery or uses Transmission

Service at a Point of Receipt or Point of Delivery that it has not

reserved.

13.8 Scheduling of Firm Point-To-Point Transmission Service:

Schedules for the Transmission Customer's Firm Point-To-Point Transmission

Service must be submitted to the Transmission Provider no later than 10:00

a.m. [or a reasonable time that is generally accepted in the region and is

consistently adhered to by the Transmission Provider] of the day prior to

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commencement of such service. Schedules submitted after 10:00 a.m. will be

accommodated, if practicable. Hour-to-hour schedules of any capacity and

energy that is to be delivered must be stated in increments of 1,000 kW per

hour [or a reasonable increment that is generally accepted in the region and is

consistently adhered to by the Transmission Provider]. Transmission

Customers within the Transmission Provider's service area with multiple

requests for Transmission Service at a Point of Receipt, each of which is under

1,000 kW per hour, may consolidate their service requests at a common point

of receipt into units of 1,000 kW per hour for scheduling and billing purposes.

Scheduling changes will be permitted up to twenty (20) minutes

[or a

reasonable time that is generally accepted in the region and is consistently

adhered to by the Transmission Provider] before the start of the next clock

hour provided that the Delivering Party and Receiving Party also agree to the

schedule modification. The Transmission Provider will furnish to the

Delivering Party's system operator, hour-to-hour schedules equal to those

furnished by the Receiving Party (unless reduced for losses) and shall deliver

the capacity and energy provided by such schedules. Should the Transmission

Customer, Delivering Party or Receiving Party revise or terminate any

schedule, such party shall immediately notify the Transmission Provider, and

the Transmission Provider shall have the right to adjust accordingly the

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schedule for capacity and energy to be received and to be delivered.

14 Nature of Non-Firm Point-To-Point Transmission Service

14.1 Term:

Non-Firm Point-To-Point Transmission Service will be available for periods

ranging from one (1) hour to one (1) month. However, a Purchaser of Non-

Firm Point-To-Point Transmission Service will be entitled to reserve a

sequential term of service (such as a sequential monthly term without having

to wait for the initial term to expire before requesting another monthly term)

so that the total time period for which the reservation applies is greater than

one month, subject to the requirements of Section 18.3.

14.2 Reservation Priority:

Non-Firm Point-To-Point Transmission Service shall be available from

transfer capability in excess of that needed for reliable service to Native Load

Customers, Network Customers and other Transmission Customers taking

Long-Term and Short-Term Firm Point-To-Point Transmission Service. A

higher priority will be assigned first to reservations with a longer duration of

service and second to Pre-Confirmed Applications. In the event the

Transmission System is constrained, competing requests of the same Pre-

Confirmation status and equal duration will be prioritized based on the highest

price offered by the Eligible Customer for the Transmission Service. Eligible

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Customers that have already reserved shorter term service have the right of

first refusal to match any longer term reservation before being preempted. A

longer term competing request for Non-Firm Point-To-Point Transmission

Service will be granted if the Eligible Customer with the right of first refusal

does not agree to match the competing request: (a) immediately for hourly

Non-Firm Point-To-Point Transmission Service after notification by the

Transmission Provider; and, (b) within 24 hours (or earlier if necessary to

comply with the scheduling deadlines provided in section 14.6) for Non-Firm

Point-To-Point Transmission Service other than hourly transactions after

notification by the Transmission Provider. Transmission service for Network

Customers from resources other than designated Network Resources will have

a higher priority than any Non-Firm Point-To-Point Transmission Service.

Non-Firm Point-To-Point Transmission Service over secondary Point(s) of

Receipt and Point(s) of Delivery will have the lowest reservation priority

under the Tariff.

14.3 Use of Non-Firm Point-To-Point Transmission Service by the

Transmission Provider:

The Transmission Provider will be subject to the rates, terms and conditions of

Part II of the Tariff when making Third-Party Sales under (i) agreements

executed on or after [insert date sixty (60) days after publication in Federal

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Commission requires to be unbundled, by the date specified by the

Commission. The Transmission Provider will maintain separate accounting,

pursuant to Section 8, for any use of Non-Firm Point-To-Point Transmission

Service to make Third-Party Sales.

14.4 Service Agreements:

The Transmission Provider shall offer a standard form Non-Firm Point-To-

Point Transmission Service Agreement (Attachment B) to an Eligible

Customer when it first submits a Completed Application for Non-Firm Point-

To-Point Transmission Service pursuant to the Tariff. Executed Service

Agreements that contain the information required under the Tariff shall be

filed with the Commission in compliance with applicable Commission

regulations.

14.5 Classification of Non-Firm Point-To-Point Transmission Service:

Non-Firm Point-To-Point Transmission Service shall be offered under terms

and conditions contained in Part II of the Tariff. The Transmission Provider

undertakes no obligation under the Tariff to plan its Transmission System in

order to have sufficient capacity for Non-Firm Point-To-Point Transmission

Service. Parties requesting Non-Firm Point-To-Point Transmission Service

for the transmission of firm power do so with the full realization that such

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service is subject to availability and to Curtailment or Interruption under the

terms of the Tariff. The Transmission Provider shall specify the rate treatment

and all related terms and conditions applicable in the event that a

Transmission Customer (including Third-Party Sales by the Transmission

Provider) exceeds its non-firm capacity reservation. Non-Firm Point-To-Point

Transmission Service shall include transmission of energy on an hourly basis

and transmission of scheduled short-term capacity and energy on a daily,

weekly or monthly basis, but not to exceed one month's reservation for any

one Application, under Schedule 8.

14.6 Scheduling of Non-Firm Point-To-Point Transmission Service:

Schedules for Non-Firm Point-To-Point Transmission Service must be

submitted to the Transmission Provider no later than 2:00 p.m.

[or a

reasonable time that is generally accepted in the region and is consistently

adhered to by the Transmission Provider] of the day prior to commencement

of such service. Schedules submitted after 2:00 p.m. will be accommodated, if

practicable. Hour-to-hour schedules of energy that is to be delivered must be

stated in increments of 1,000 kW per hour [or a reasonable increment that is

generally accepted in the region and is consistently adhered to by the

Transmission Provider]. Transmission Customers within the Transmission

Provider's service area with multiple requests for Transmission Service at a

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Point of Receipt, each of which is under 1,000 kW per hour, may consolidate

their schedules at a common Point of Receipt into units of 1,000 kW per hour.