Federal Energy Regulatory Commission (2006)

Tuesday,

June 6, 2006

Part II

Department of

Energy

Federal Energy Regulatory Commission

sroberts on PROD1PC70 with PROPOSALS

18 CFR Parts 35 and 37

Preventing Undue Discrimination and

Preference in Transmission Service;

Proposed Rule

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Federal Register / Vol. 71, No. 108 / Tuesday, June 6, 2006 / Proposed Rules

DEPARTMENT OF ENERGY

Federal Energy Regulatory

Commission

18 CFR Parts 35 and 37

[Docket Nos. RM05–25–000 and RM05–17–

000]

Preventing Undue Discrimination and

Preference in Transmission Service

May 19, 2006.

AGENCY: Federal Energy Regulatory

Commission, DOE.

sroberts on PROD1PC70 with PROPOSALS

ACTION: Notice of proposed rulemaking.

SUMMARY: The Federal Energy

Regulatory Commission is proposing

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.

DATES: Comments are due August 7,

2006. Reply comments are due

September 5, 2006.

ADDRESSES: You may submit comments,

identified by Docket Nos. RM05–25–000

and RM05–17–000, by one of the

following methods:

• Agency Web site: http://

www.ferc.gov. Follow the instructions

for submitting comments via the eFiling

link found in the Comment Procedures

section of the preamble.

• Mail: Commenters unable to file

comments electronically must mail or

hand deliver an original and 14 copies

of their comments to: Federal Energy

Regulatory Commission, Office of the

Secretary, 888 First Street, NE.,

Washington, DC 20426. Please refer to

the Comment Procedures section of the

preamble for additional information on

how to file paper comments.

FOR FURTHER INFORMATION CONTACT:

Daniel Hedberg (Technical Information),

Office of Energy Markets and Reliability,

Federal Energy Regulatory Commission,

888 First Street, NE., Washington, DC

20426, (202) 502–6243.

Kathleen Barrón (Legal Information),

Office of the General Counsel—Energy

Markets, Federal Energy Regulatory

Commission, 888 First Street, NE.,

Washington, DC 20426, (202) 502–6461.

David Withnell (Legal Information),

Office of the General Counsel—Energy

Markets, Federal Energy Regulatory

Commission, 888 First Street, NE.,

Washington, DC 20426. (202) 502–8421.

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Introduction

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II. Background

A. Historical Antecedent

B. Order No. 888 and Subsequent Reforms

C. EPAct 2005 and Recent Developments

III. The Need for Reform of Order No. 888

A. Opportunities for Undue Discrimination

Continue To Exist

B. A Lack Of Transparency Undermines

Confidence in Open Access and Impedes

Enforcement of Open Access

Requirements

C. Congestion and Inadequate

Infrastructure Development Impede

Customers’ Use of the Grid

D. A Consistent Method of Measuring ATC

Has Not Been Established

E. A Number of Transmission Pricing

Policies May Impede the Use of the Grid

F. EPAct 2005 Emphasized Certain Policies

and Priorities for the Commission

IV. Summary, Scope and Applicability of the

Proposed Rule

A. Summary of Proposed Reforms .

B. Core Elements of Order No. 888 That

Are Retained

1. Federal/State Jurisdiction

2. Native Load Protection

3. The Types of Transmission Services

Offered

4. Functional Unbundling

C. Applicability of the Proposed Rule

1. Public Utility Transmission Providers

2. Non-Public Utility Transmission

Providers/Reciprocity

V. Proposed Modifications of the OATT

A. Consistency and Transparency of ATC

Calculations

B. Transmission Planning—Coordinated,

Open and Transparent Planning

C. Transmission Pricing

1. Imbalances

2. Credits for Network Customers

3. Capacity Reassignment

4. ‘‘Operational’’ Penalties

a. Unauthorized Use Penalties

b. How Transmission Providers Should Pay

Operational Penalties

5. ‘‘Higher of’’ Pricing Policy

D. Non-Rate Terms and Conditions

1. Potential Modifications to Long-Term

Firm Point-to-Point Service

2. Hourly Firm Service

3. Rollover Rights

4. Modification of Receipt or Delivery

Points

5. Acquisition of Transmission Service

a. Processing of Service Requests

b. Queue Processing Business Practices

c. Reservation Priority

6. Designation of Network Resources

a. Qualification as a Network Resource

b. Documentation for Network Resources

c. Undesignation of Network Resources

7. Clarifications Related to Network

Service

8. Transmission Curtailments

9. Standardization of Rules and Practices

10. OATT Definitions

E. Enforcement

1. General Policy

a. Compliance Review Regime

b. Use of Independent Third Party Audits

2. Civil Penalties

a. Background

b. Whether Civil Penalties Should Be

Specified in the OATT

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c. Whether Transmission Providers Should

Be Subject to Revocation of Their

Market-Based Rates for OATT Violations.

d. Whether Certain OATT Violations

Should Be Considered Market

Manipulation Under the Market

Behavior Rules and Section 1283 of

EPAct 2005

VI. Information Collection Statement

VII. Environmental Analysis

VIII. Regulatory Flexibility Act Analysis

IX. Comment Procedures

X. Document Availability

Appendix A: Commenter Acronyms

Appendix B: Pro Forma Open Access

Transmission Tariff

I. Introduction

1. Ten years have passed since the

Commission issued its landmark Order

No. 888.1 Named after our new

headquarters in Washington, DC, Order

No. 888 sought to eradicate undue

discrimination in the provision of

transmission service in interstate

commerce. It did so by requiring that

each public utility that owns, operates,

or controls facilities used for

transmission in interstate commerce

offer unbundled transmission service

pursuant to a standard Open Access

Transmission Tariff (pro forma OATT)

and separate its transmission and

merchant generation functions pursuant

to a companion order issued that same

day, Order No. 889.2 These remedies

reduced barriers to entry, led to greater

competition in bulk power markets and

provided the foundation for subsequent

regulatory reforms at both the federal

and state level.

2. 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. 2000,3 that

1 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).

2 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).

3 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).

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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.4 The Commission in Order

No. 2000 thus encouraged utilities to

voluntarily join independent regional

transmission organizations (RTOs) that

would operate their transmission

facilities on a non-discriminatory basis

and administer the OATT. The

Commission based Order No. 2003 on a

similar finding, explaining that the

interconnection process includes

opportunities for undue discrimination

that may lead to delays that benefit

generation-owning transmission utilities

and undermine competition.5 While

many regions of the country now have

independent grid operators, not all do,

and changes to the pro forma OATT are

necessary to reduce the opportunity for

transmission providers to engage in

undue discrimination. In the past ten

years new investment has faltered and

many regions now experience chronic

transmission congestion and inadequate

infrastructure. Congress, through the

Energy Policy Act of 2005 (EPAct

2005),6 recognized this problem and

provided the Commission not only new

tools to encourage infrastructure but

also made clear that the Commission

should use its existing authority to

ensure an adequate infrastructure to

support a vibrant economy.

3. The reforms we propose today are

intended to address deficiencies in the

pro forma OATT that have become

apparent since 1996 and to facilitate

improved planning and operation of

transmission facilities. We summarize

these reforms in Part IV.A below, but

note the major focus of this reform effort

here. As a general matter, 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

discrimination as well as making the

undue discrimination that does occur

4 Order No. 2000 at 31,015.

5 See Order No. 2003 at P 11–12.

6 Pub. L. 109–58, 119 Stat. 594 (to be codified in

scattered itles of the U.S.C.).

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more difficult to detect. First, we

propose to improve transparency and

consistency in several critical areas,

such as the calculation of available

transfer capability (ATC).7 We propose

to direct public utilities, under the

auspices of the North American Electric

Reliability Council (NERC) and the

North American Energy Standards

Board (NAESB), to provide for greater

consistency in ATC calculation. By

reducing unnecessarily broad discretion

in this and other areas, we will reduce

the ability of transmission providers to

unduly discriminate and provide them

greater certainty to facilitate compliance

with our regulations. Second, we

propose 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 loadserving entities. The pro forma OATT

contains only minimal requirements

regarding transmission planning, which

have proven to be inadequate as the

Nation faces inadequate transmission

investment in many areas. We propose

to require public utilities to engage in an

open and transparent planning process

at both the local and regional levels.

Third, we propose to remedy certain

portions of the pro forma OATT that

may have permitted utilities to

discriminate against new merchant

generation, including intermittent

generation. For example, we propose to

modify the energy imbalance provisions

of the pro forma OATT and adopt

certain other tariff modifications.

Fourth, we 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 our ability to

detect any remaining incidents of undue

discrimination. Finally, we provide for

reform and greater clarity in areas that

have generated recurring disputes over

the past 10 years, such as rollover rights,

‘‘redirects,’’ and generation redispatch.

4. Although the reforms being

proposed in these areas are significant,

we wish to underscore that we propose

to maintain many of the core elements

of Order No. 888. For example, we are

retaining the comparability requirement

7 We note that 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

is proposing to revise the pro forma OATT to adopt

the term ‘‘Available Transfer Capability.’’

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under which each public utility must

treat third parties in a manner

comparable to its service to bundled

customers. We are retaining the basic

nature of the services being offered—

network service and point-to-point

service. We are retaining the protection

of native load customers embodied in

Order No. 888, consistent with EPAct

2005’s new requirement that loadserving entities be provided

transmission rights to meet their service

obligations.8 We are retaining our

decision to exercise jurisdiction over

unbundled transmission service, but not

transmission service provided as part of

a bundled retail service. We are

retaining the use of functional

unbundling to address undue

discrimination, rather than requiring

corporate unbundling. We are retaining

the use of an OATT to facilitate the

development of competitive wholesale

markets by reducing barriers to entry

through the control of transmission

assets, not imposing any particular

market structure on the industry.

5. In proposing to reform Order No.

888, we have relied heavily on the

comments received in response to our

notices of inquiry in the abovecaptioned dockets.9 We appreciate the

time and thoughtfulness of all sectors of

the industry in preparing comments on

these notices of inquiry. We have found

them very informative and useful and

this Notice of Proposed Rulemaking

(NOPR) incorporates many of the

commenters’ suggestions. We invite

further comments on this NOPR. We

also are scheduling technical

conferences to more fully address the

topics of ATC calculation and

transmission planning.

II. Background

A. Historical Antecedent

6. 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,

8 EPAct 2005 sec. 1233 (to be codified at section

217(b)(4) of the FPA, 16 U.S.C. 824q).

9 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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and entered into long-term contracts to

make wholesale requirements sales

(bundled sales of generation and

transmission) to municipal, cooperative,

and other 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 due

primarily to the cost and technological

limitations on the distance over which

electricity could be transmitted.

7. 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),10 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 wheeling of

electricity under limited

circumstances.11 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

10 Pub. L. 95–617, 92 Stat. 3117 (1978) (codified

in U.S.C. titles 15, 16, 26, 30, 42, and 43 (2000)).

11 Section 211 of the FPA, 16 U.S.C. 824j (2000).

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

Company, 839 F. Supp. 1563 (M.D. Fla. 1993).

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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.

9. 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).14 EPAct 1992 reduced regulatory

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 1935.15 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.

many traditional vertically integrated

utilities still did not provide open

access to third parties and favored their

own generation if and when they

provided transmission access to third

parties, access to cheaper, more efficient

generation sources remained limited.

8. The Commission encouraged the

development of independent power

producers (IPPs), as well as emerging

power marketers, by authorizing marketbased 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. Marketbased 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 longterm 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

possessed.12 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 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.13 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

B. Order No. 888 and Subsequent

Reforms

10. 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

minimum terms and conditions of nondiscriminatory 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

12 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).

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

14 Pub. L. 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 (2000)).

15 15 U.S.C. 79a (2000), 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).

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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.16 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).17 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 and

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 which

conditions the use by non-public

utilities of public utilities’ open access

services on an agreement to offer open

access services in return.

11. 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 ‘‘have

the potential to provide significant

benefits (e.g., to help provide regional

efficiencies, to facilitate economically

efficient pricing, and, especially in the

context of power pools, to remedy

undue discrimination and mitigate

market power) and will further our goal

of achieving a workably competitive

market.’’ 18 While the Commission

declined to mandate ISOs, it set forth

eleven principles for assessing ISO

proposals submitted to the

Commission.19

12. Order No. 888 also clarified the

Commission’s interpretation of the

federal/state jurisdictional boundaries

over transmission and local distribution.

While it reaffirmed that the Commission

has exclusive jurisdiction over the rates,

terms, and conditions of unbundled

16 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

retain ownership over both functions. See infra Part

IV.B.4.

17 See Order No. 888 at 31,769–70 (noting that the

pro forma OATT expressly identified certain nonrate terms and conditions, such as the time

deadlines for determining available 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).

18 Order No. 888 at 31,655.

19 Id. at 31,730–32.

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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.20

13. The same day it issued Order No.

888, the Commission issued a

companion order, Order No. 889,

addressing both 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.

14. Among the information required

to be posted by Order No. 889 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.’’ 21 Because formal methods

did not then exist to calculate ATC and

total transfer capability (TTC), the

Commission encouraged industry efforts

to develop consistent methods for

calculating ATC and TTC.22 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.23 The

Commission noted that the requirement

that transmission providers purchase

only ATC that is posted as available

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

21 Order No. 889 at 31,605.

22 Id. at 31,607.

23 Id.

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‘‘should create an adequate incentive for

them to calculate ATC and TTC as

accurately and as uniformly as

possible.’’ 24

15. 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.25 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 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.

16. In the wake of these changes, in

December 1999, the Commission

adopted Order No. 2000.26 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.27 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 energy, capacity and

ancillary services. The Commission

24 Id.

25 See Energy Information Administration, Retail

Unbundling—U.S. Summary (2005), http://

www.eia.doe.gov/oil_gas/natural_gas/restructure/

state/us.html.

26 See supra note 3.

27 Order No. 2000 at 31,015.

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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.’’ 28

17. Following Order No. 2000, RTOs

were approved in several regions of the

country including the Northeast (PJM

Interconnection, Inc.; 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.

sroberts on PROD1PC70 with PROPOSALS

C. EPAct 2005 and Recent

Developments

18. EPAct 2005,29 enacted on August

8, 2005, added a number of new

authorities and priorities for the

Commission and emphasized certain of

its existing obligations. Specifically,

EPAct 2005 recognized the importance

of adequate transmission infrastructure

development and its role in facilitating

the development of competitive

wholesale markets. For example,

Congress required the Commission to

adopt a rule establishing incentive

ratemaking for transmission

infrastructure to help promote reliability

and reduce congestion.30 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.’’ 31 Congress also

gave the Commission certain ‘‘backstop’’

transmission siting authority, and

authorized the creation of interstate

compacts establishing transmission

siting agencies.32 EPAct 2005 also

authorized the Commission to require

unregulated transmitting utilities

28 Id. at 30, 993.

29 See supra note 6.

30 EPAct 2005 sec. 1241 (to be codified at section

219 of the FPA, 16 U.S.C. 824s).

31 EPAct 2005 sec. 1233(a) (to be codified at

section 217(b)(4) of the FPA, 16 U.S.C. 824q).

32 EPAct 2005 sec. 1221(a) (to be codified at

section 216 of the FPA, 16 U.S.C. 824p).

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(except for certain small entities) to

provide access to their transmission

facilities on a comparable basis.33

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.34 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.35 Finally,

Congress emphasized compliance with

the Commission’s regulations,

increasing the civil and criminal

penalties for violations of Commissionadministered statutes and regulations.36

19. Recognizing the need for reform of

Order No. 888 in light of these

developments and those described in

the next section, the Commission issued

an NOI in September 2005 seeking

comments on the reforms needed to the

Order No. 888 pro forma OATT to

prevent undue discrimination and

preference in the provision of

transmission services. 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

33 EPAct 2005 sec. 1231 (to be codified at section

211A of the FPA, 16 U.S.C. 824j–1).

34 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 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. 1234 (b).

35 EPAct 2005 sec. 1281 (to be codified at section

220 of the FPA, 16 U.S.C. 824t).

36 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).

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to more readily identify violations and

facilitate compliance.

20. 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 adopted it, we conclude that

reform of the pro forma OATT is

necessary, for the reasons we discuss

next.

III. The Need for Reform of Order No.

888

A. Opportunities for Undue

Discrimination Continue To Exist

21. In Order No. 2000, the

Commission found that ‘‘opportunities

for undue discrimination continue to

exist that may not be remedied

adequately by [the] functional

unbundling [remedy of Order No.

888].’’ 37 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.38 The Commission has a

responsibility under section 206 of the

FPA to remedy undue discrimination.39

Our action today proposes to fulfill that

responsibility by proposing reforms to

the pro forma OATT that will address

remaining opportunities for undue

discrimination.

22. As the Commission noted in Order

No. 888, it is in the economic selfinterest of transmission monopolists,

particularly those with high-cost

generation assets, to deny transmission

or to offer transmission on a basis that

is inferior to that which they provide

themselves.40 Such an incentive can

lead to unduly discriminatory behavior

37 Order No. 2000 at 31,105.

38 Order No. 2003 at P 11–12.

39 In Associated Gas Distributors v. FERC, 824

F.2d 981 (D.C. Cir. 1987), (AGD), the court

concluded that, like the Natural Gas Act, the FPA

‘‘fairly bristles’’ with concern over undue

discrimination. Based on AGD, the Commission

determined in Order No. 888 that:

The Commission has a mandate under sections

205 and 206 of the FPA to ensure that, with respect

to any transmission in interstate commerce or any

sale of electric energy for resale in interstate

commerce by a public utility, no person is subject

to any undue prejudice or disadvantage. We must

determine whether any rule, regulation, practice or

contract affecting rates for such transmission or sale

for resale is unduly discriminatory or preferential,

and must prevent those contracts and practices that

do not meet this standard. * * * AGD demonstrates

that our remedial power is very broad and includes

the ability to order industry-wide nondiscriminatory open access as a remedy for undue

discrimination.

Order No. 888 at 31,669.

40 Id. at 31,682.

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against third parties, particularly if

public utilities have unnecessarily

broad discretion in the application of

their tariffs. This discretion also can

create problems for transmission

providers seeking to comply with our

regulations in good faith because so

many issues are left for their

interpretation, thereby increasing the

possibility of disputes with

transmission customers and

enforcement actions by the

Commission.41 Transmission customers

also have found ways to use the tariffs

to their own advantage, particularly in

the scheduling and queuing processes.42

Finally, tariff provisions have been

modified in numerous ways on a

company-by-company basis, leading to

uncertainties within the industry as to

the proper interpretation of those

provisions and to unnecessarily

inconsistent treatment of transmission

customers across public utilities.

23. Commenters suggest that

enhanced clarity and consistency in the

pro forma OATT would go a long way

toward eliminating the opportunities for

undue discrimination and the

perception that it is occurring.43 Calpine

notes that undue discrimination is most

likely to occur when the transmission

provider retains discretion to implement

an OATT provision in a manner that

favors its affiliated generation. APPA

asserts that the success of the OATT

regime depends on public utilities’

ability to faithfully implement the

OATT’s provisions. Large transmission

providers share this view to some

degree. Entergy notes that a lack of

clarity is at the heart of many disputes

involving the OATT, and urges the

Commission to improve the OATT in a

manner that will minimize the potential

for future violations. Duke posits that

tariff terms and conditions that are

susceptible to multiple interpretations

present opportunities for discrimination

sroberts on PROD1PC70 with PROPOSALS

41 See, e.g., Order No. 2003 at P 11–12.

42 See, e.g., Potomac Economics, Ltd., 2004 State

of the Market Report: Midwest ISO at 30–31, 34–35

(Jun. 2005) (explaining that the queuing process, by

giving customers the opportunity to submit

multiple requests for service, provides a low or nocost option that restricts other customers’ access to

congested interfaces, and the scheduling process, by

allowing customers to leave transmission requests

unconfirmed, provides a free option that may invite

hoarding or result in underutilized capacity), http://

www.midwestmarket.org/publish/Document/

2b8a32_103ef711180_-7bf20a48324a/

2004%20MISO%20SOM%20Report.

pdf?action=download&_property=Attachment.

43 E.g., Calpine, Duke, and MidAmerican. (A list

of commenter acronyms may be found in Appendix

A). As the Commission noted in Order No. 2000,

‘‘[p]erceptions of discrimination are significant

impediments to competitive markets. Efficient and

competitive markets will develop only if market

participants have confidence that the system is

administered fairly.’’ Order No. 2000 at 31,017.

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and/or the perception thereof. Progress

Energy agrees that several OATT

provisions can be interpreted

differently, leaving room for

disagreement as to their meaning.

24. Perhaps the most obvious

deficiency in this regard is ATC

calculation. In Order Nos. 888 and 889,

the Commission declined to require a

specific methodology for ATC

calculation. As a result, there are few

clear rules respecting ATC calculation,

and transmission providers, therefore,

retain unnecessarily broad discretion in

this area. On systems where

transmission capacity is congested, this

lack of consistency, coupled with a lack

of transparency, has led to recurring

disputes over whether the transmission

provider is exercising its discretion to

discriminate against its competitors.

25. There is a similar lack of clarity

in the transmission provider’s planning

obligations. Order No. 888 included a

general obligation on the part of the

transmission providers to plan on a

comparable basis (i.e., comparable to the

manner in which it would plan for its

own needs) to serve network loads and

to construct new facilities as necessary

to respond to requests for firm service

from point-to-point customers.

However, there were no clear guidelines

with respect to whether transmission

customers should be included in the

planning process, what standards and

criteria should be used in system

planning, and whether the planning

process should identify potential

economic upgrades that could benefit a

wide range of customers, as opposed to

responding only to customer-specific

requests. Here too, this lack of clarity

has led to significant disputes over

whether transmission providers are

planning on a nondiscriminatory basis

or are favoring service to their own

loads.

B. A Lack of Transparency Undermines

Confidence in Open Access and

Impedes Enforcement of Open Access

Requirements

26. A major focus of comments on the

NOI is that increased transparency

would aid transmission customers in

their participation in the wholesale

market.44 Constellation explains that the

transmission provider’s unique position

as the owner and operator of the

transmission system and often the

majority of the generation assets in its

control area gives it better information

than its transmission customers.

Moreover, the transmission provider,

Constellation argues, has financial

44 E.g., LG&E, MidAmerican, Midwest SATs, TDU

Systems, and Williams.

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32641

incentives to use the system differently,

and more efficiently, to serve its own

loads than to serve its other customers

under the pro forma OATT. TDU

Systems urges the Commission to

ensure that transmission providers make

their actions under the OATT

completely transparent on a timely basis

to all transmission customers. NARUC

posits that enhanced reporting

requirements, if sufficiently targeted,

would facilitate greater transparency in

transmission activities. Alberta

Intervenors states that the current pro

forma OATT provides transmission

customers with only a narrow glimpse

of how the system is being operated. For

example, Bonneville notes that many

terms and conditions of native load

service are not transparent to OATT

transmission customers.45 EEI also

states that greater transparency, such as

with respect to ATC calculation, can

increase confidence in open access and

potentially reduce claims of undue

discrimination.

27. Calpine argues that undue

discrimination is difficult to detect

given the lack of access to data,

analytical assumptions, and processes

used by transmission providers to

determine transmission access and

service. It recommends that the

Commission increase reporting

requirements for denials of transmission

service, for congestion management

mitigation events, including

curtailments and redispatch, and for

transmission expansion planning

decisions. Powerex notes that the

Commission already has posting

standards, and urges the Commission to

enforce them and to increase

requirements to provide more

meaningful posting of reliable ATC data,

curtailment methodology and results,

details relating to denials of service, and

congestion information. Constellation

agrees, urging the Commission to

require OASIS posting of service

metrics, such as all transmission

requests approved, rejected, confirmed

and curtailed.

28. A common theme in the

comments is that the lack of

transparency can lead to claims of

undue discrimination and can make

such claims more difficult to resolve.46

As such, National Grid asserts that

greater transparency will allow the

Commission and transmission system

users to understand when a

transmission access decision is

45 Bonneville urges the Commission to require

load-serving transmission providers to post the

same information for bundled retail load that they

must post for service to network customers.

46 E.g., Ameren, National Grid, and NRECA.

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sroberts on PROD1PC70 with PROPOSALS

motivated by a legitimate reason rather

than an intent to discriminate. If

transmission customers have more

accurate information about the

transmission service request process,

National Grid contends, they also will

have more accurate expectations and a

better understanding of how to expedite

the implementation of service. Though

NRECA agrees that increased

transparency will allow the Commission

to deter undue discrimination and

facilitate accountability, it urges the

Commission to require not just raw data

but meaningful, clear and

understandable data, in a format that

facilitates understanding.

29. Commenters urge the Commission

to improve the transparency of

transmission service in a number of

areas, particularly the evaluation of ATC

and the planning of the transmission

system.47 Another area often cited as

lacking sufficient transparency is the

processing of transmission service

requests and studies. For example,

several commenters note that system

impact studies are often not completed

within the tariff-prescribed time limits,

and that information about that process

is not available to transmission

customers.48 TDU Systems suggests that

one way to address the difficulty of

determining acceptable delays is to

require transmission providers to post

statistics on their OASIS sites providing

information as to the length of time it

might take to process requests for

transmission service. Cinergy proposes

that adopting such reporting metrics

could result in an improved quality of

service.

30. We agree that a lack of

transparency both increases the

potential for undue discrimination and

makes it more difficult to detect. We

believe this lack of sufficient

transparency is caused in part by

inadequate compliance with our

existing OASIS regulations, and in part

by inadequate transparency

requirements. Our reforms address both

elements of the problem in an effort to

increase confidence in open access

tariffs and to facilitate compliance with

our regulations and our enforcement of

them.

C. Congestion and Inadequate

Infrastructure Development Impede

Customers’ Use of the Grid

31. The ability and incentive to

discriminate increases as the

transmission system becomes more

47 We discuss these specific aspects of the pro

forma OATT below in Parts V.A. and V.B.

48 E.g., Constellation, EPSA, Powerex, and

Williams.

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congested. Vertically integrated utilities

do not have an incentive to expand the

grid to accommodate new entry or to

facilitate the dispatch of more efficient

competitors. Even with the advent of

RTOs, transmission infrastructure

development has not kept pace with the

increase in demand for electricity.

Transmission capacity is being

constructed at a much slower rate than

the rate of increase in customer demand.

Indeed, transmission capacity per MW

of peak demand declined at an average

rate of 2.1 percent per year during the

period 1992 to 2002.49 Investment for

the most recent year available, 2003,

was below 1975 levels,50 and

projections suggest that this trend will

continue through 2012.51 As a result,

there has been a significant decrease in

transmission capacity relative to load in

every NERC region.52 EEI estimates that

capital spending must increase by 25

percent, from $4 billion annually to $5

billion annually, to ensure system

reliability and to accommodate

wholesale electric markets.53 The legacy

systems constructed by vertically

integrated utilities prior to the adoption

of Order No. 888 support ‘‘only limited

amounts of inter-regional power flows

and transactions. Thus, existing systems

cannot fully support all of society’s

goals for a modern electric-power

system.’’ 54 These systems were built to

meet the vertically integrated utilities’

retail native load obligations, not to

support the development of a bulk

power market.

32. Inadequate expansion of the

transmission grid has contributed to

increasing transmission congestion in

most regions of the country.

Transmission congestion has created

fairly small local load pockets in

primarily urban areas, e.g., New York

City, Long Island, Boston, parts of

Connecticut, and the San Francisco Bay

Area. Other load pocket concerns have

49 Eric Hirst, U.S. Transmission Capacity: Present

Status and Future Prospects (Aug. 2004), available

at http://www.eei.org/industry_issues/

energy_infrastructure/transmission/

USTransCapacity10-18-04.pdf (Present Status and

Future Prospects).

50 EEI, EEI Survey of Transmission Investment:

Historical and Planned Capital Expenditures (1999–

2008) at 3 (May 2005), available at http://

www.eei.org/industry_issues/energy_infrastructure/

transmission/Trans_Survey_Web.pdf.

51 Present Status and Future Prospects at v.

52 Brendan Kirby (Oak Ridge National Laboratory,

U.S. Department of Energy, Barriers to

Transmission Investment, Technical Conference

Presentation, (Docket No. AD05–5–000) (April 22,

2005) Transmission Independence and Investment.

53 Energy Policy Act of 2005: Hearings before the

House Subcommittee on Energy and Commerce,

109th Congress, First Sess. (2005) (Prepared

statement of Thomas R. Kuhn, President of EEI).

54 Present Status and Future Prospects at v.

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arisen in parts of northern Virginia, and

various load centers in SPP. Still other

constraints are more regional in scope:

(1) From the Midwest to the MidAtlantic, (2) from the Midwest to the

Tennessee Valley Authority (TVA), (3)

into and within California, (4) from TVA

and Southern into Entergy, (5) from

Mid-America Interconnected Network

into Wisconsin-Upper Michigan

Systems, and (6) into Florida. The

existence of these and other constraints

affecting transmission systems can

result in an increase in the frequency of

denials of requests for transmission

service, and an increase in the

frequency of transmission service

interruptions and/or curtailments of

transmission service. While not all

congestion needs to be remedied (i.e., if

the cost of the congestion is less than

the cost to relieve it), it is also true that

undue discrimination and preferential

treatment also are much more difficult

to detect when the transmission grid is

constrained, given the lack of

transparency in ATC calculations and

transmission system planning. Increased

congestion also presents additional

opportunities for undue discrimination.

As a result, it is more difficult for the

Commission to carry out its statutory

responsibility to ensure that

transmission providers provide

nondiscriminatory open access

transmission service.

33. In recognition of the lack of

adequate infrastructure, a broad crosssection of the industry supports greater

coordination in the planning and

investment in transmission

infrastructure between transmission

providers, transmission customers and

state regulatory agencies. A major focus

of comments on our NOI was the need

to plan and build infrastructure to

facilitate regional electricity markets.

For example, AEP argues that the most

important issue faced by public utilities

and their customers is not day-to-day

OATT administration but the planning

and expansion of the transmission grid.

EEI likewise asserts that the focus

should be on the need to develop energy

infrastructure necessary to facilitate

growth in wholesale electric market

transactions. Santa Clara acknowledges

that lack of needed infrastructure causes

the grid to become constrained and less

reliable, which sometimes provides

even stronger incentives for owners to

restrict access by others. The Nevada

Companies urge the Commission to

focus on ways Order No. 888 and the

pro forma OATT can be revised to

eliminate disincentives to the

construction of additional transmission

facilities. Xcel suggests that the

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Commission focus its efforts on ways to

encourage investment in new energy

infrastructure as a way of easing

congestion and enabling growth in

market transactions. Salt River contends

that the Commission should increase

incentives to participate in long-term

regional planning processes. Midwest

SATs argue that increased access for all

transmission system users through

policies that promote investment in

transmission will do more to reduce

undue discrimination than policies that

seek to uncover and penalize such

discrimination.

34. Customers also complain that

there is often a lack of transparency in

utility transmission planning processes,

which the customers claim typically do

not include economic system upgrades

that would benefit non-affiliate users of

the system. Customers also note the lack

of clarity in the existing planning

obligations required of transmission

providers. They assert that these failures

have contributed to the inadequate

development of the transmission grid.

35. Order No. 888 contemplated that

ISOs would enhance infrastructure

development through open and regional

planning processes, but these efforts

have stalled in many regions of the

country. Even where RTOs have been

established, there have been concerns

that the planning process has not always

been sufficiently robust, inclusive or

transparent to ensure that transmission

investment occurs where it is

reasonably needed for all users of the

grid. For example, in its reply

comments, TDU Systems urges the

Commission to include RTOs in its

planning reforms, contending that many

RTO planning processes are not open to

all stakeholders, nor are they

collaborative and inclusive. Many

commenters argue that RTO

transmission planning regimes have

failed to get needed transmission

facilities built.55

36. We conclude that the inadequacy

of the existing obligation to conduct

joint and regional transmission system

planning, coupled with the lack of

transparency surrounding system

planning generally, require reform of the

pro forma OATT to ensure that

transmission infrastructure is

constructed on a nondiscriminatory

basis and is otherwise sufficient to

support reliable and economic service to

all eligible customers.

55 E.g., APPA, TDU Systems Reply Comments,

and Williams Reply Comments.

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D. A Consistent Method of Measuring

ATC Has Not Been Established

37. Under Order No. 888, each public

utility calculates the amount of transfer

capability on its system that is available

for sale to third parties.56 However,

Order No. 888 did not require that the

methodology for ATC calculation be

standardized across the industry, nor

did it impose any specific requirements

regarding the disclosure of the

methodologies used by each

transmission provider. As a result, there

are a variety of ATC calculation

methodologies in use today. Moreover,

there is often very little transparency

regarding the nature of these

calculations, given that many

transmission providers have filed only

summary explanations of their ATC

methodologies in Attachment C to the

OATT. As a result, transmission

providers retain unnecessarily broad

discretion in calculating ATC. The

resulting discretion is a significant

problem because calculation of ATC,

which varies greatly depending on the

criteria and assumptions used, may

allow the transmission provider to

discriminate in subtle ways against its

competitors. This discretion, coupled

with the lack of transparency, also

hampers the detection of undue

discrimination and, thereby,

undermines the Commission’s ability to

enforce the general requirement in

Order No. 888 that transmission service

be provided on a not unduly

discriminatory basis.57

38. The comments on the NOI and the

ATC NOI reflect these underlying

problems. Many market participants

complain that there is widespread

misinformation regarding the actual

ATC, which results in missed

opportunities for transactions. ATC

calculation errors often occur. A lack of

transparency leaves transmission

customers unaware of why some

transmission requests are granted and

others are denied.58 Several ATC inputs,

such as the capacity benefit margin

(CBM) or the transmission reliability

margin (TRM), can be calculated using

overly conservative or otherwise faulty

assumptions. Transmission customers

often complain that transmission

providers designate unreasonably high

CBM or TRM levels, which limits the

56 Order No. 888 at 31,794 n.610.

57 APPA submitted comments in Docket No.

RM05–17–000 arguing that the calculation and

posting of ATC ‘‘sits at the pivot point among

reliability, economic regulation and wholesale

electric commerce.’’ APPA at 5.

58 See, e.g., EEI at 18 (agreeing that the

Commission should require transmission providers

to make their ATC calculations more transparent).

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32643

amount of remaining transfer capability

available for other users of the system.

39. As a result of these uncertainties,

the Commission issued the ATC NOI to

address the lack of clear and consistent

methodologies for calculating ATC. In

the ATC NOI, the Commission

acknowledged that NERC has been

working on specific recommendations

for calculating and coordinating ATC

and available flowgate capability

(AFC).59 That NERC effort culminated in

a report and a number of

recommendations. The Commission

asked for comments on those

recommendations, as well as comments

on whether there should be common

transmission calculation methodologies

among regions. The Commission has

reviewed those comments as part of this

proceeding.60

40. Many commenters support the

development of a consistent, industrywide methodology for calculating

ATC.61 These commenters maintain that

a requirement that all transmission

providers use the same methodology to

determine ATC would not only remedy

the lack of clarity that surrounds these

calculations and reservations, but would

provide regulatory certainty and assist

transmission customers in predicting

the outcome of transmission service

requests.

41. We agree. Although the industry

has sought to pursue greater consistency

in ATC calculations through existing

NERC processes, those efforts to date

have been largely unsuccessful. The

lack of a consistent, industry-wide

methodology for calculating ATC gives

transmission providers the ability and

the opportunity to unduly discriminate

against third parties. We therefore

propose below a number of reforms to

the process of calculating ATC to

provide clarity and transparency to

users of the grid.

E. A Number of Transmission Pricing

Policies May Impede the Use of the Grid

42. Transmission customers often

complain about the level and scope of

imbalance charges that are levied under

the pro forma OATT and under

individual interconnection agreements.

59 See NERC, Long-Term AFC/ATC Task Force

Final Report (2005) (NERC Report) at 2, available

at ftp://www.nerc.com/pub/sys/all_updl/mc/ltatf/

LTATF_Final_Report_Revised.pdf.

60 Accordingly, we consolidate Docket No.

RM05–17–000 with this proceeding. We will

distinguish the comments received in the ATC NOI

proceeding by the designation ‘‘ATC NOI

Comments.’’ In addition, we also revise the name

of the proceeding in Docket No. RM05–17–000 to

‘‘Preventing Undue Discrimination and Preference

in Transmission Service.’’

61 E.g., Alcoa, AWEA, Constellation, Exelon,

Occidental, and Renewable Energy.

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Energy imbalance charges, including

penalties on some systems, are imposed

on a transmission customer when the

amount of energy scheduled for delivery

to the transmission grid does not equal

the amount of energy withdrawn by that

customer. Customers complain that

these charges are excessive and not

related to the actual costs incurred by

transmission providers. They also argue

that the inconsistency between these

charges in different control areas is

unnecessary, and that other means of

compensating the transmission

provider, such as return-in-kind, should

be considered. Generator imbalance

charges are levied on generators for

deviations between the amount of

energy they schedule and the amount

they actually deliver to the grid.

Generators likewise complain that these

charges are excessive, that transmission

providers refuse to credit generators

with the revenues resulting from

imbalance penalties that are collected,

and that transmission providers prevent

unaffiliated generators from purchasing

or self-supplying generator imbalance

services. In addition, owners of

intermittent resources complain that

generator imbalance penalties, which

are imposed to provide an incentive for

generators to schedule accurately, are

inappropriate given their lack of control

and ability to cure deviations.

43. Transmission providers and

customers raise a number of concerns

related to the pricing of transmission

service under Order No. 888,

contending that the Commission’s

pricing policies are in need of reform.

For example, under the pro forma

OATT, network customers can receive a

credit toward their transmission charges

for new facilities that they jointly plan

with the transmission provider.

Customers contend that this provision

actually acts as a disincentive for joint

planning because transmission

providers can avoid granting credits if

they fail to jointly plan with their

transmission customers.

44. Finally, there is also concern

about the appropriate rate for

transmission capacity that has been

resold by the original transmission

customer. Under Order No. 888, such

capacity may be priced at the higher of

the original rate, the transmission

provider’s maximum stated firm rate, or

the assignor’s opportunity costs capped

at the cost of expansion. Customers

complain that this policy does not work

when opportunity costs exceed the

embedded cost rate, because the

assignor must make a FPA section 205

filing with the Commission that

estimates its opportunity cost over the

term of the reassignment as well as the

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cost of system expansion. The time and

effort required to complete the

regulatory process appears to inhibit

such reassignments.

45. Although Order No. 888 was

primarily directed at establishing the

non-rate terms and conditions of open

access, the rule did adopt certain

pricing policies that were associated

with the form of open access being

ordered. After reviewing the comments,

we believe certain reforms are

appropriate because some of the pricing

policies associated with the pro forma

OATT are no longer just and reasonable

or are otherwise unduly discriminatory.

However, we do not intend to pursue

generic reform of other pricing policies

that are better addressed on a region-or

case-specific basis, such as the pricing

of new transmission facilities.

F. EPAct 2005 Emphasized Certain

Policies and Priorities for the

Commission

46. The reforms we propose today

also are consistent with the policies and

priorities embodied in EPAct 2005, in

which Congress emphasized many of

the principles reflected in this NOPR.

47. First, Congress in EPAct 2005

placed special emphasis on the

development of transmission

infrastructure. Congress required the

Commission to adopt a rule establishing

incentive-based rates for new

transmission infrastructure investment.

The stated purpose of new FPA section

219 is to benefit ‘‘consumers by

ensuring reliability and reducing the

cost of delivered power by reducing

transmission congestion.’’ 62 FPA

section 219 requires the Commission to

‘‘promot[e] capital investment in the

enlargement, improvement,

maintenance, and operation of all

facilities for the transmission of electric

energy in interstate commerce,

regardless of the ownership of the

facilities.’’ 63 Congress also gave the

Commission certain ‘‘backstop’’

transmission siting authority, and

authorized the creation of interstate

compacts establishing transmission

siting agencies.64 Finally, the

Commission was directed to ‘‘exercise

its authority’’ under EPAct 2005 ‘‘in a

manner that facilitates the planning and

expansion of transmission facilities to

62 EPAct 2005 sec. 1241 (to be codified at section

219 of the FPA, 16 U.S.C. 824s). The Commission

issued a NOPR implementing such an incentive rate

program in November 2005. See Promoting

Transmission Investment through Pricing Reform,

70 FR 71409 (Nov. 29, 2005), FERC Stats. & Regs.

¶ 32,593 (2005).

63 FPA Sec. 219(b)(1).

64 EPAct 2005 sec. 1221(a) (to be codified at

section 216 of the FPA, 16 U.S.C. 824p).

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meet the reasonable needs of loadserving entities to satisfy the service

obligations of the load-serving entities,

and enables load-serving entities to

secure firm transmission rights* * * on

a long-term basis for long-term power

supply arrangements made, or planned,

to meet such needs.’’ 65 Although these

provisions are, or will be, addressed

primarily in other proceedings, our

NOPR is consistent with these

provisions because it supports new

infrastructure by reforming the

transmission planning process to ensure

that it is open, transparent and

nondiscriminatory.66

48. Second, Congress emphasized the

need for greater transparency in

electricity markets, including

transmission service. EPAct 2005 added

section 220 to the FPA, which requires

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

[that market], fair competition, and the

protection of consumers.’’ 67 The

Commission was authorized to

‘‘prescribe such rules as the

Commission determines necessary and

appropriate to carry out the purposes

of’’ FPA section 220. Those rules ‘‘shall

provide for the dissemination, on a

timely basis, of information about the

availability and prices of wholesale

electric energy and transmission service

to the Commission, State commissions,

buyers and sellers of wholesale electric

energy, users of transmission services,

and the public.’’ Our NOPR similarly

seeks to promote greater transparency in

the provision of transmission service in

many important areas, including ATC

calculation and transmission planning.

49. Finally, Congress emphasized

compliance with the Commission’s

regulations, increasing the civil and

criminal penalties for violations of

Commission-administered statutes and

regulations.68 This new authority

buttresses the Commission’s efforts to

enforce public utility OATTs and the

regulations requiring transmission

information to be posted on OASIS. As

we explained in the Enforcement Policy

Statement, however, this new authority

carries with it the responsibility to

ensure that enforcement is firm but fair

and that our rules are as clear as

65 EPAct 2005 sec. 1233(a) (to be codified at

section. 217(b)(4) of the FPA, 16 U.S.C. 824q).

66 We note that we also have proposed to

implement FPA section 217(b)(4) in a separate

rulemaking in Docket No. RM06–8–000.

67 EPAct 2005 sec. 1281 (to be codified at 16

U.S.C. 824t).

68 EPAct 2005 sec. 1284(e)(1) (to be codified at

section 316(A) of the FPA, 16 U.S.C. 825o–1 (2000).

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practicable to facilitate compliance.69

The NOPR is fully consistent with these

principles because it seeks, in many

areas, to clarify our rules to facilitate

compliance by transmission providers.

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IV. Summary, Scope and Applicability

of the Proposed Rule

50. This section provides: (1) A

summary of the major components of

the NOPR, (2) a description of the core

elements of Order No. 888 that we

propose to retain, and (3) a discussion

of the applicability of the proposed rule

to various entities.

A. Summary of Proposed Reforms

51. Consistency and transparency of

ATC calculations. The Commission

finds that the lack of a consistent,

industry-wide methodology for

calculating ATC, and the lack of

adequate transparency in ATC

calculations, increases the potential for

undue discrimination and also makes

undue discrimination more difficult to

detect. The lack of consistent standards

can facilitate undue discrimination by

giving a transmission provider the

discretion, and hence the ability and

opportunity, to favor itself and its

affiliates over third parties in how it

calculates and allocates ATC and,

therefore, may be unjust, unreasonable,

unduly discriminatory and preferential.

As a result, we propose to give the

industry specific guidance and a firm

deadline to develop certain

requirements to make the process of

calculating ATC and the process of

exchanging data between transmission

providers about ATC more consistent. In

addition, we propose to amend pro

forma OATT requirements as well as

our OASIS regulations to increase the

transparency in how ATC is calculated.

52. Requirement for coordinated,

open and transparent transmission

planning. The Commission finds that

Order No. 888 does not contain

sufficient protections to guard against

undue discrimination in transmission

system planning. This, in turn, can

affect a customer’s ability to obtain

transmission service and the price it

pays for transmission. Specifically,

Order No. 888 does not require

sufficient coordination, openness, and

transparency in transmission planning

to ensure that new infrastructure is

constructed to meet the needs of all

eligible customers on a not unduly

discriminatory basis. Without adequate

coordination and open participation,

market participants have minimal input

69 Enforcement of Statutes, Orders, Rules and

Regulations, Policy Statement on Enforcement, 113

FERC ¶ 61,068 (2005) (Enforcement Policy

Statement).

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or insight into whether a particular

transmission plan treats all loads and

generators comparably. To ensure that

truly comparable transmission service is

provided by all public utility

transmission providers, including RTOs

and ISOs, we propose to amend the pro

forma OATT to require coordinated,

open, and transparent transmission

planning on both a sub-regional and

regional level. To implement this

remedy, we propose eight planning

principles that each public utility

transmission provider will be required

to follow. We recognize that many

regions have made significant progress

in recent years in creating greater

openness and transparency in

transmission planning and believe our

proposed reforms will build upon,

strengthen, and improve this progress to

reform transmission planning.

53. Transmission Pricing Reforms.

Consistent with the focus of Order No.

888 on the non-rate terms and

conditions of open access, the

Commission does not intend to initiate

broad reform of transmission pricing

policy through this NOPR. However, we

have identified several pricing rules that

are part and parcel of OATT service that

merit reform.

• Energy and Generator Imbalance

Charges. We find that existing energy

and generator imbalance charges may be

excessive and otherwise unrelated to the

cost of providing the service and,

therefore, propose to reform energy and

generator imbalance pricing. We

propose to require that all such

imbalance charges meet the following

criteria: The charges must (1) be related

to the cost of correcting the imbalance,

(2) be tailored to encourage accurate

scheduling behavior, such as by

increasing the percentage of the adder as

the deviations become larger, and (3)

account for the special circumstances

presented by intermittent generators,

such as by waiving the higher ends of

the deviation penalties.

• Capacity Reassignment Pricing. We

find that the existing cap on the

reassignment of point-to-point service

may no longer be just and reasonable

and, therefore, propose to eliminate the

cap. We believe that removing the cap

will eliminate an unnecessary

impediment to the resale of capacity,

which in turn should increase

utilization of the grid and otherwise

ensure that point-to-point service is just,

reasonable and not unduly

discriminatory. We seek comment on

this proposal and, in particular, the

nature of the reporting obligations that

should be imposed as part of lifting the

cap on reassignment.

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• Crediting of Customer-Owned

Facilities. We propose to retain most

elements of our existing policy

respecting the crediting of customerowned facilities, including the

requirement that such facilities meet the

integration standard. However, we

propose to eliminate the requirement

that new facilities can receive credits

only if they are ‘‘jointly planned’’

because this requirement may provide a

disincentive to coordinated planning.

Rather, we propose that such new

facilities be eligible for credits if: (1)

Such facilities are integrated into the

operations of the transmission

provider’s facilities, and (2) such

facilities would be eligible for inclusion

in the transmission provider’s annual

transmission revenue requirement if

owned by the transmission provider.

54. Improvements to Point-to-Point

Service. The Commission concludes that

the existing methods for evaluating

requests for long-term firm point-topoint service may no longer be just,

reasonable and not unduly

discriminatory. When a transmission

provider considers a new resource to

serve native load, the transmission

provider does not eliminate an

otherwise economic option because the

resource may not be deliverable in a few

hours of the year. For transmission

customers, however, the transmission

provider evaluates whether service can

be granted in every hour of the year that

is modeled and, if not, it informs the

customer that service cannot be

provided out of existing transfer

capability. Only if the transmission

customer agrees to pay for timeconsuming and costly facilities studies

does the transmission provider evaluate

redispatch options, including whether

they are less expensive than the upgrade

options. The Commission proposes to

address this problem by clarifying that

a transmission provider must use all of

its available redispatch options to

satisfy a request for firm point-to-point

service and, at the transmission

customer’s option, these redispatch

options must be studied before the

customer is obligated to incur the costs

and time delays associated with a

facilities study. The Commission also

seeks comment on whether this remedy

is adequate or, alternatively, whether

the Commission should modify the

nature of point-to-point service to

require that transmission providers offer

a ‘‘conditional firm’’ service that would

be subject to curtailment prior to firm

service only a limited number of hours

of the year.

55. Reform of rollover rights. The

Commission concludes that section 2.2

of the pro forma OATT, which grants an

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ongoing right to transmission customers

to renew or ‘‘rollover’’ their contracts, is

in need of reform. The Commission

proposes to revise that provision to

apply to contracts that have a minimum

term of five years, rather than the

current minimum term of one year. We

conclude that this reform will ensure

that the rollover right is enjoyed by

transmission customers that have made

a significant commitment to (and

investment in) the transmission grid. In

addition, the Commission proposes that

a transmission customer eligible for

rollover rights must provide notice of

whether or not it will exercise its right

of first refusal to renew the contract no

less than one year prior to the expiration

date of the transmission service

agreement, rather than within the

current 60-day period.

56. Increases in transparency to

lessen the opportunities to discriminate

and reduce transaction costs. In

addition to the increased transparency

we propose to require regarding the

calculation of ATC and transmission

planning, we propose to increase the

transparency of transmission service

provided under the pro forma OATT in

several other respects. For example, we

propose to require transmission

providers and their network customers

to use the transmission provider’s

OASIS to request designation of a new

network resource and to terminate the

designation of an existing network

resource. In addition, we propose to

require the transmission provider to

modify its OASIS so that requests to

designate and terminate a network

resource can be queried. We also

propose to require the transmission

provider to post on its OASIS a list of

its current designated network resources

and all network customers’ current

designated network resources. Finally,

we propose to require transmission

providers to post on OASIS all their

business rules, practices and standards

that relate to transmission services

provided under the pro forma OATT.

57. Strengthening enforcement of the

pro forma OATT. Our proposed reforms

include several clarifications of the

terms and conditions of the pro forma

OATT that have made undue

discrimination difficult to detect and

otherwise frustrated enforcement of the

obligation to provide open access, nondiscriminatory transmission service.

Our new civil penalty authority under

EPAct 2005 gives us ample power to

remedy tariff violations, but it also

places upon us an increased

responsibility to make the rules as clear

as possible. In addition, we propose a

number of posting and reporting

requirements that will provide the

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Commission and market participants

with information about each

transmission provider’s performance of

pro forma OATT obligations. For

example, we propose to require

transmission providers to post specific

performance metrics related to their

completion of studies required under

the pro forma OATT. We note that the

Commission will continue to audit

compliance with the pro forma OATT,

and toward that end propose to require

transmission information kept on

OASIS to be retained for audit purposes

for five years. Finally, we make a

number of proposals relating to

operational penalties assessed under the

pro forma OATT, including so-called

‘‘over-use’’ penalties, and the treatment

of operational penalty revenues

collected from transmission providers

and their affiliates.

58. Miscellaneous OATT

improvements. We propose a number of

improvements to the terms and

conditions of the pro forma OATT to

incorporate the lessons learned over the

past ten years. We briefly note these

below:

Hourly Firm. We propose to require

transmission providers to offer hourly

firm service under the pro forma OATT.

Designation of network resources. We

propose to make a number of

clarifications related to the types of

agreements that may be designated as

network resources, the process for

verifying whether agreements meet the

requirements in the pro forma OATT,

and the requirement for transmission

providers to designate and undesignate

network resources. We also propose to

require customers to submit an

attestation with each application to

designate a new network resource.

Reservation priorities. We propose to

change the priority rules to give priority

to pre-confirmed transmission service

requests submitted in the same time

period. We also propose to add price as

a tie-breaker in determining reservation

queue priority when the transmission

provider is willing to discount

transmission service.

Clarifications related to network

service. We propose to clarify that a

network customer may not use

secondary network service to bring

energy onto its system to support an offsystem sale if the purchased power does

not displace the customer’s own higher

cost generation. We also propose

clarifications related to use of network

service on an ‘‘as available basis’’ and to

‘‘redirects’’ of network service.

Definitions. In addition to some minor

revisions, we propose to add a

definition of ‘‘non-firm sales’’ to the pro

forma OATT and propose to amend the

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definition of Good Utility Practice to

reference the definition of ‘‘reliable

operation’’ adopted in EPAct 2005.

B. Core Elements of Order No. 888 That

Are Retained

59. Although we are proposing many

important reforms to Order No. 888 and

the pro forma OATT, we also wish to

emphasize that we propose to retain

many of the core elements of Order No.

888. We note that many of these core

elements enjoy broad support across

many sectors of the industry. In their

comments, APPA, EEI, and NARUC urge

the Commission to proceed carefully in

reforming Order No. 888, focusing on

incremental reforms not industry

restructuring. We share the view that

Order No. 888 can be strengthened

without discarding its fundamental

structure. We discuss below the core

elements that are being retained and,

where appropriate, respond to the

comments on these points that were

received in the NOI.

1. Federal/State Jurisdiction

60. In Order No. 888, the Commission

stated that it has exclusive jurisdiction

over the rates, terms and conditions of

unbundled retail transmission in

interstate commerce.70 Though the

Commission adopted a test for

determining which facilities were used

for retail transmission, as opposed to

local distribution to end-users,71 the

Commission stated that it generally

would defer to determinations by state

regulatory authorities concerning where

to draw the jurisdictional line under

that test.72 The Commission declined to

assert jurisdiction over bundled retail

transmission, reasoning that ‘‘when

transmission is sold at retail as part and

parcel of the delivered product called

electric energy, the transaction is a sale

of electric energy at retail.’’ 73 The U.S.

Supreme Court affirmed the

Commission’s decision to assert

jurisdiction over unbundled but not

bundled retail transmission, finding that

the Commission made a statutorily

permissible choice.74

61. We propose to retain the

jurisdictional divide we established in

Order No. 888. We also are mindful of

the need for heightened cooperation

between federal and state regulators in

areas where there are overlapping

federal and state policy concerns.

Moreover, our jurisdictional

determination was sustained by the U.S.

70 Order No. 888 at 31,781.

71 Id. at 31,771 (setting forth the seven-factor test).

72 Id. at 31,781.

73 Id.

74 See New York v. FERC, 535 U.S. 1, 28 (2002).

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Supreme Court and has been accepted

by industry and state regulatory

authorities. We see no reason to disturb

that determination now.

2. Native Load Protection

62. Order No. 888 did not require

transmission providers to unbundle

transmission service to their retail

native load nor did it require that

bundled retail service be taken under

the terms of the pro forma OATT.75

Moreover, the Commission allowed a

transmission provider to reserve, in its

calculation of ATC, transmission

capacity necessary to accommodate

native load growth reasonably

forecasted in its planning horizon.76 As

noted above, Order No. 888 granted a

rollover right to existing firm service

customers,77 but allowed transmission

providers to restrict that rollover right if

the capacity was reasonably forecasted

to be needed to serve native load

customers, as long as that restriction

was specified in the customer’s service

contract.78

63. Congress in section 1233 of EPAct

2005 added section 217 to the FPA,

entitled ‘‘Native Load Service

Obligation,’’ which addresses

transmission rights held by load-serving

entities. It allows load-serving entities to

use their own and contracted-for

transmission capacity to the extent

required to meet their service

obligations, without being subject to

charges of unlawful discrimination.

Among other things, FPA section 217

states that it does not require the

abrogation of any contract or service

agreement for firm transmission service

or rights in effect as of the date of

enactment.79

64. In the NOI, the Commission stated

that it was not proposing to change the

protection of native load embodied in

Order No. 888.80 The Commission

sought comment on whether the

approach the Commission took in Order

No. 888 is the same as that set forth in

FPA section 217.

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Comments

65. Several commenters argue that the

approach the Commission took in Order

No. 888 is largely consistent with the

treatment of native load preference in

FPA section 217.81 They state that Order

No. 888 makes clear that native load has

a priority right to a transmission

75 Order No. 888 at 31,745.

76 Id. at 31,694.

77 Id.; pro forma OATT section 2.2.

providers’ capacity and that

transmission providers may reserve a

portion of their capacity for native load

growth.

66. Other commenters perceive

varying degrees of difference between

Order No. 888 and FPA section 217.82

EEI states that FPA section 217 extends

native load protection to all load-serving

entities that have direct or indirect

service obligations to end-users for

terms of one year or more, while Order

No. 888 does not. Nevada Companies

and TAPS argue that the FPA section

217 requirement that the Commission

exercise its authority to facilitate the

planning and expansion of transmission

facilities to satisfy the service

obligations of load-serving entities

necessitates changes to Order No. 888.

67. Several commenters argue that

FPA section 217 requires the

Commission to revisit its rollover rights

policy.83 Duke maintains that the

current Commission approach is not the

same as set forth in either Order No. 888

or FPA section 217 because the

Commission’s current approach to

rollover rights does not meaningfully

recognize the native load preference.

Commission decisions since Order No.

888, according to Duke, have weakened

the native load preference envisioned in

Order No. 888 to the point where the

Commission’s treatment of the native

load preference is not what Congress

provides in FPA section 217. LPPC

argues that FPA section 217 reverses

Commission precedent that makes it

impossible to recall capacity for native

load once it is subject to a rollover right.

68. EEI states that in order to

harmonize Order No. 888 rollover rights

with the native load protections

contained in FPA section 217, the

Commission should revise the pro

forma OATT to require a notice period

for rollover rights that is consistent with

the time needed to plan for and

construct transmission facilities to serve

native load customers and the rollover

customer. EEI and Salt River argue that

FPA section 217 requires that the

Commission permit load-serving entities

to implement curtailment procedures

that recognize native load service

priorities.

69. Metropolitan Water District argues

that the mandate to preserve native load

preference is complicated further when

a transmission owner has transferred

operational control to an ISO or RTO. In

such a scenario, to honor the native load

preference in FPA section 217,

78 Order No. 888–A at 30,198.

79 16 U.S.C. 217(f).

80 NOI at P 9.

81 E.g., Memphis Light, Newmont Mining Reply

Comments, Progress Energy, and TDU Systems.

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82 E.g., Duke, EEI, Metropolitan Water District,

and Southern.

83 E.g., Duke, Energy, LPPC, Progress Energy, Salt

River, Santee Cooper, and Southern.

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Metropolitan Water District contends

that the Commission either should

reconsider its prior rulings rejecting the

allocation of physical rights to serve

native load or should require ISOs and

RTOs to issue financial rights options,

in addition to financial right obligations,

so that load-serving entities have a

greater ability to avoid congestion costs

in serving their native load.

Discussion

70. The Commission concludes that

the protection of native load embodied

in Order No. 888 is consistent with FPA

section 217, and we reaffirm our

commitment to the protection of native

load. Order No. 888 gave public utilities

the right to reserve existing transmission

capacity needed for native load growth

reasonably forecasted within the

utility’s current planning horizon. It

also allowed transmission providers to

restrict rollover rights based on a

reasonably forecasted need at the time

the contract is executed. This approach

is consistent with FPA section 217,

which protects the transmission rights

of entities with service obligations to

end-users or a distribution utility, to the

extent required to meet their service

obligations. Though commenters appear

to believe FPA section 217 would

support the cancellation of contracts

that include rollover rights, FPA section

217 by its terms does not contemplate

abrogation of existing transmission

service contracts.84 However, to the

extent commenters argue that the terms

of service and notice periods associated

with the OATT rollover rights are too

short to protect native load adequately,

we note that we are proposing to extend

them in this NOPR.

71. In response to Metropolitan Water

District, the Commission finds that the

issue of firm transmission rights in

organized markets is best addressed as

part of the long-term firm transmission

rights rulemaking in Docket Nos. RM06–

8–000 and AD05–7–000. We further

note, in response to the comments of

Nevada Companies and TAPS, that we

are proposing a coordinated and

regional planning process to facilitate

the planning and expansion of

transmission facilities pursuant to FPA

section 217.

3. The Types of Transmission Services

Offered

72. In Order No. 888, the Commission

required all public utilities to offer on

a non-discriminatory, open-access basis

firm network service and firm and non84 See FPA section 217(f) (explaining that section

217 does not abrogate any firm service agreements

or rights in effect as of the date of enactment).

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firm point-to-point service. In the NOI,

the Commission sought comments on

whether the Commission should require

transmission providers to offer

transmission services in addition to, or

in place of, the point-to-point and

network services prescribed in the

OATT.

73. Among other questions, the

Commission asked whether network

service alone or both network and pointto-point services should be converted

into a single contract demand service.85

Generally speaking, contract demand

service is a hybrid of point-to-point and

network services that is reservationbased and allows transmission

customers to receive a firm entitlement

to integrate multiple resources and

deliver energy to multiple points,

without paying a separate charge for

each point of receipt or delivery.

Contract demand service would allow

current point-to-point customers to

avoid having to arrange and pay for

separate reservations for each point of

receipt. And current network customers

would be allowed to pay for

transmission based on the amount of

their reservation rather than customer

loads at a delivery point.

sroberts on PROD1PC70 with PROPOSALS

Comments

74. Most commenters argue against

requiring that network service alone or

in combination with point-to-point

service be converted into contract

demand service.86 Some warn that the

imposition of this service would

interfere with efficient transmission

system planning and operation due to

increased capacity reservations that

would go unused.87 They also argue that

it would result in significant cost shifts

among transmission customers if not

priced correctly. FP&L argues that the

current services are a better match for

the actual use of the transmission

system and thereby permit more ATC to

be available.

75. Some commenters ask that the

Commission require transmission

providers to offer contract demand

service as an additional transmission

service option in the pro forma OATT.88

85 For examples of contract demand service, the

Commission cited Florida Power Corp., FERC

¶ 61,248 (1995); Wisconsin Electric Power Co., 72

FERC ¶ 61,033 (1995); and Florida Power Corp., 81

FERC ¶ 61,247 (1997).

86 E.g., Ameren, APPA, Bonneville, Calpine, EEI,

EPSA, Fallon Reply Comments, FP&L, NRECA,

PacifiCorp, Southern, Suez Energy NA, TVA, TAPS,

and TDU Systems.

87 E.g., EEI, FP&L, KCP&L, and TVA.

88 E.g., AMP-Ohio, APPA, Cogeneration

Association of California Reply Comments,

Constellation, EPSA, FMPA Reply Comments,

Midwest Municipals, PacifiCorp, and Public Power

Council.

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AMP-Ohio argues that, as long as

Commission policy requires network

customers to pay load-ratio network

transmission charges for load served

with behind-the-meter generation,

contract demand network service is

essential to avoid unduly discriminatory

transmission charges. Midwest

Municipals and FMPA argue that the

Commission should order contract

demand service where the transmission

provider does not plan and operate its

system to meet total customer load

because, as the Commission stated in

Order No. 888, full network service is

essential for achieving comparability

and efficient integration of power

supply and load. FMPA contends that

where a customer needs network service

from another system for only part of its

load, it would benefit from being able to

buy system power from multiple

designated resources for part of its load.

In this way, FMPA continues, the

transmission provider would not have

the planning obligation for the

customer’s entire load, perhaps avoiding

or delaying expensive transmission

additions. FMPA claims that such

service would tend to benefit all

transmission users because it would

allow a more efficient use of the grid

and provide additional transmission

revenues.

76. Other commenters state that

transmission providers should have the

option whether to offer contract demand

or other customized transmission

services.89 LPPC argues that the

Commission should allow a

transmission provider to voluntarily

provide alternative forms of

transmission service where

circumstances support their

implementation, with the caveat that

such service must not place any market

participant at a disadvantage or increase

transmission rates for network or pointto-point customers. Southern proposes

that the pro forma OATT be modified to

include a process through which a

transmission provider may propose to

adopt new services that customers

specifically request.

77. Commenters also raise general

concerns regarding the use and potential

abuse of network contract demand

service. For example, MidAmerican

argues that contract demand service

should not be used as a means for

transmission customers with behindthe-meter generation to avoid paying for

a load-ratio share of a system that was

built to support their entire load and on

which they rely for service. Rather,

MidAmerican continues, network

contract demand service should be

89 E.g., LPPC, NRECA, and Southern.

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limited to situations in which

deliverability is physically limited, such

as where the integrated transmission

system does not have the capacity to

serve all the load at a designated point

of delivery. EEI argues that the

Commission should not convert

network service to network contract

demand service because conversion

would result in a substantial reduction

in ATC as it would provide contract

rights on the transmission system on an

around-the-clock basis that are equal to

network load’s monthly or annual peak

loads.

Discussion

78. We propose to retain the services

we ordered in Order No. 888: firm and

non-firm point-to-point service and firm

network service. We do not propose

requiring transmission providers to

adopt a network contract demand

service, either as a replacement for

network or point-to-point service or as

a third category of service under the

OATT. The Commission continues to

believe that network and point-to-point

services are the appropriate base-line

service offerings in the OATT. Although

forms of contract demand service have

been approved by the Commission, and

the service may provide benefits to

certain customers, sufficient potential

drawbacks exist that prevent us from

concluding that it is a necessary

transmission service that should be

included in the pro forma OATT. For

example, the service would require a

departure from full load-ratio pricing for

network customers, which may not be

warranted to the extent the transmission

provider plans its system to serve all

native load. While the Commission

concludes that it will not require all

transmission providers to offer this

service, we acknowledge that the

introduction of this service on a

voluntary basis may be appropriate in

certain circumstances.

79. Although we are not proposing to

require that transmission providers

adopt contract demand service, we note

that the commenters who support this

service appear concerned principally

with inequities in the pricing of network

integration service. The Commission is

addressing certain of these concerns

elsewhere in the NOPR. For example, in

this NOPR, we propose to modify our

treatment of transmission credits for

new transmission facilities and clarify

that the transmission provider must

satisfy the comparability requirement

when including transmission facilities

in its rate base for pro forma OATT

purposes. We also address concerns

regarding the linkage between how the

transmission provider plans and

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operates its system through proposed

revisions to planning and ATC.

4. Functional Unbundling

80. When the Commission proposed

the open access policy that culminated

in Order No. 888, there was

considerable debate about whether

corporate unbundling (in which a

public utility’s transmission and

generation assets would be placed in

separate corporate entities) was

necessary to ensure non-discriminatory

open access transmission service. The

Commission decided to mandate

functional, rather than corporate,

unbundling of transmission and

generation services. In Order No. 888,

the Commission explained that

functional unbundling has three

components:

1. A public utility must take transmission

services (including ancillary services) for all

of its new wholesale sales and purchases of

energy under the same tariff of general

applicability as do others;

2. A public utility must state separate rates

for wholesale generation, transmission, and

ancillary services;

3. A public utility must rely on the same

electronic information network that its

transmission customers rely on to obtain

information about its transmission system

when buying or selling power.90

81. In the years following Order No.

888, a number of public utilities

nonetheless underwent corporate

unbundling. Many of these entities did

so as a result of state-mandated

restructuring laws. Others did so for

corporate or tax reasons. Some entities

divested all of their generation assets to

a non-affiliate, while others simply

restructured internally to place the

generation assets in a different corporate

subsidiary than the transmission assets.

There remain, however, a significant

number of vertically-integrated public

utilities that have operated under the

functional unbundling approach.

sroberts on PROD1PC70 with PROPOSALS

Comments

82. Retention of Order No. 888’s

functional unbundling approach is

supported by a number of commenters.

For example, the LPPC states that

vertical integration remains a viable

business model for serving customers

reliably and at economic rates. LG&E

posits that, absent a proven and real

level of abuse, major structural changes

are unwarranted. NARUC argues that

the issue of whether there should be

structural separation of generation from

transmission is best left to the states.

NPPD alleges that mandatory vertical

unbundling would do more harm than

90 Order No. 888 at 31,654.

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good by threatening the continued

economic operation of those utilities

that continue to provide bundled

service to their retail native load

customers. The North Carolina

Commission does not believe the

evidence in that state supports the

imposition of structural remedies.

83. Some commenters, however,

continue to urge the Commission to

impose structural separation. National

Grid contends that the best way to

eliminate the possibility of undue

discrimination is to separate the

ownership and operation of the

transmission system from interests in

the market. Calpine urges the

Commission to structurally separate the

merchant function that is engaged in

selling power for resale from those who

control access to transfer capability and

service, not just those who operate the

transmission system. TAPS argues that

structural solutions are preferable to

behavioral rules.

84. Many commenters favoring

structural separation urge the

Commission to impose an independent

transmission coordinator requirement.

These commenters would have

transmission providers employ an

independent entity to administer their

OATTs, performing such functions as

maintaining the utility’s OASIS,

granting or denying service requests,

reviewing system impact and facilities

study results, and overseeing decisions

with respect to line ratings,

transmission outages and generation

dispatch.91 Other commenters oppose

the imposition of a potentially costly

new layer of bureaucracy, at least on a

generic basis.92

Discussion

85. We propose to preserve the

functional unbundling approach

adopted by Order No. 888. For public

utilities that kept transmission and

generation assets in the same corporate

entity, the Commission imposed strict

Standards of Conduct that required

separation of the utilities’ transmission

system operations and wholesale

marketing functions.93 These Standards

of Conduct were replaced by a broader

set of rules adopted in Order No. 2004.94

91 E.g., Arkansas Commission, Calpine,

Constellation, EPSA, and PPL.

92 E.g., APPA, NRECA, and TAPS.

93 Order No. 889 at 31,595.

94 See Standards of Conduct for Transmission

Providers, Order No. 2004, 68 FR 69134 (Dec. 11,

2003), FERC Stats. & Regs. ¶ 31,155 (2003), order

on reh’g, Order No. 2004–A, 69 FR 23562 (Apr. 29,

2004), FERC Stats. & Regs. ¶ 31,161 (2004), order

on reh’g, Order No. 2004–B, 69 FR 28371 (Aug. 10,

2004), FERC Stats. & Regs. ¶31,166 (2004), order on

reh’g, Order No. 2004–C, 70 FR 284 (Jan. 4, 2005),

FERC Stats. & Regs. ¶ 31,172 (2005), order on reh’g,

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32649

These rules require that employees

engaged in transmission functions

operate separately from employees of

energy affiliates and marketing affiliates.

A number of information sharing

restrictions also apply, which prohibit

transmission providers from allowing

employees of their energy and

marketing affiliates to obtain access to

transmission or customer information,

except via OASIS.

86. The Commission aggressively

enforces the Standards of Conduct. The

Commission’s Office of Enforcement is

well-suited to investigate potential

violations of the Standards of Conduct

and to propose remedies, including

structural remedies if necessary, to

ensure that the separation of function

and information restrictions in Order

No. 2004 are implemented.

87. The Commission has resolved a

number of complaints related to the

Standards of Conduct and the

accompanying OASIS posting

requirements.95 In Order No. 888, the

Commission noted that the possibility of

filing a complaint under FPA section

206 is an additional safeguard if a

public utility seeks to circumvent the

functional unbundling requirement. The

Commission’s Enforcement Hotline

likewise is available to customers that

do not wish to file a formal complaint.

88. In addition, one of the criticisms

of the functional unbundling

requirement is that Order No. 888 leaves

vertically integrated utilities with too

much discretion in applying the OATT

and gives them an incentive to use this

discretion to their advantage. We agree

that the existing pro forma OATT

provides too much discretion in certain

important areas. It is for this reason—as

explained elsewhere in the NOPR—that

we are proposing to require greater

clarity and transparency in several areas

of OATT administration. We believe

these reforms will limit the discretion of

transmission providers and make any

remaining attempts to discriminate

much easier to detect.

89. We believe that this increased

clarity and transparency, when coupled

with the Standards of Conduct and a

rigorous enforcement program, will

ensure that the functional unbundling

requirement will serve its original

purpose. As a result, just as the

Commission concluded in Order No.

Order No. 2004–D, 110 FERC ¶ 61,320 (2005),

appeal docketed sub nom. National Gas Fuel

Supply Corporation v. FERC, No. 04–1183 (D.C. Cir.

June 9, 2004), codified at 18 CFR Part 358 (2005).

95 See Aquila Energy Marketing Corp. v. Niagara

Mohawk Power Corp., 87 FERC ¶ 61,328

(1999)(finding that off-OASIS communicagtion

between utilty and its marketing affiliate led to

preferential treatment of the affiliate).

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888 that more intrusive and costly

corporate unbundling was not

necessary, the Commission again

concludes that there is no need to

impose a corporate or structural

unbundling requirement at this time.

We believe that the pro forma OATT, if

properly clarified and enforced, will

enable us to eliminate the opportunity

for undue discrimination in the

provision of transmission service.

90. For the same reasons, we also

decline to mandate an independent

transmission coordinator for all

transmission providers. We have

concluded that such entities may be

appropriate in certain circumstances

and we support voluntary efforts to rely

on them.96 We do not agree, however,

that there is sufficient basis for requiring

them as a generic remedy for undue

discrimination.

91. Our proposal to retain the

functional unbundling approach of

Order No. 888 does not suggest,

however, a lack of support for structural

changes that may be undertaken on a

voluntary basis by each region, such as

transmission-only companies, RTOs, or

other reforms. We continue to support

such efforts as potentially providing

significant benefits in several areas,

including, but not limited to, increased

infrastructure investment and

addressing regional issues such as cost

recovery, pancaked rates, loop flow, and

congestion management. At this time,

we believe such efforts are best

developed on a voluntary basis.

C. Applicability of the Proposed Rule

1. Public Utility Transmission Providers

sroberts on PROD1PC70 with PROPOSALS

92. Pursuant to its authority under

FPA sections 205 and 206, the

Commission in Order No. 888 required

all public utilities that owned,

controlled, or operated facilities used

for transmitting electric energy in

interstate commerce to file open access

transmission tariffs that contained

minimum terms and conditions of nondiscriminatory service. The Commission

recognized, however, that there may be

circumstances in which a public utility

believes that the pro forma OATT does

not provide sufficient flexibility.97 In

addition, the Commission

acknowledged that a public utility

might be willing to offer superior nonrate terms and conditions. As a result,

the Commission allowed a transmission

96 See Duke Power, 113 FERC ¶ 61,288 (2005);

MidAmerican Energy Co., 113 FERC ¶ 61,274

(2005); see also Entergy Services, Inc., 110 FERC

¶ 61,295 (2005), order clarificaiton, 111 FERC

¶ 61,222 (2005), order conditionally approving

filing, 115 FERC ¶ 61,095 (2006).

97 Order No. 888 at 31,770.

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provider to justify variations from the

non-price terms and conditions of the

pro forma OATT under two

circumstances. First, certain provisions

of Order No. 888 specifically allowed

public utilities to use alternatives that

were justified by ‘‘regional differences.’’

When submitting those provisions,

public utilities were permitted to follow

regional practices when doing so was

‘‘reasonable, generally accepted in the

region, and consistently adhered to by

the transmission provider,’’98 as long as

the utilities identified the regional

practices in their compliance filings.

Second, in subsequent FPA section 205

proceedings, public utilities were

permitted to propose changes to any pro

forma OATT provision that were

‘‘consistent with or superior to’’ the

terms of the pro forma OATT.

93. In the NOI, the Commission

expressed the preliminary view that

reforms to the pro forma OATT and

public utilities’ OATTs appear

necessary and sought comment on how

best to accomplish that. In particular,

the Commission sought comment on

whether reforms to Order No. 888

should be applied to all public utility

transmission providers, including those

that are approved ISOs, RTOs, or

independent transmission coordinators.

Comments

94. Independent system operators

such as MISO, CAISO, and ISO New

England submit that many of the

concerns raised by the Commission in

the NOI already have successfully been

addressed by the operation of ISOs and

RTOs. Similarly, EEI argues that many

of the issues addressed in the NOI are

not applicable to RTOs and ISOs

because RTOs and ISOs are independent

of all market participants and therefore

are presumed to not engage in undue

discrimination or preferential treatment.

PJM argues that, because of its

independence, the transparency of its

procedures, and the progress achieved

in developing effective financial and

non-financial congestion management

tools, PJM structurally addresses the

continuing concerns of the Commission

regarding persistent undue

discrimination and preference in the

industry.

95. EPSA states that it may not be

necessary to apply all aspects of the new

OATT to ISOs or RTOs. However, rather

than delineating either each term that

would not apply to an RTO or how such

terms might be modified in an RTO

tariff, EPSA recommends that the

Commission require RTOs, ISOs, and

independent transmission coordinators

98 Id.

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Frm 00016

to submit compliance filings upon

issuance of the new pro forma OATT

but allow them to propose waivers of

the new requirements based upon

appropriate justification.

96. EEI argues that, to the extent that

the Commission requires RTOs and

ISOs to amend their open access

transmission tariffs, the Commission

should establish flexible procedures that

provide the RTOs and ISOs the right to

customize their OATTs consistent with

their independent status.

97. Other commenters argue that

reforms to existing OATTs should be

applied to all market entities, including

ISOs, RTOs and independent

transmission coordinators.99 LPPC

states that there is little reason for the

Commission to be more deferential in

considering deviations from the pro

forma OATT proposed by RTOs or ISOs

than it is with respect to investor-owned

utilities.

Discussion

98. The Commission proposes to

apply the final rule to all public utility

transmission providers. The

Commission proposes to require all

such transmission providers to submit

FPA section 206 compliance filings,

within 60 days following publication of

the final rule in the Federal Register,

that contain the non-rate terms and

conditions set forth in the final rule. We

note that certain non-rate terms and

conditions, such as Attachment C

relating to the transmission provider’s

ATC calculation methodology and

Attachment K relating to the

transmission provider’s transmission

planning process, may require more

than 60 days to prepare. We seek

comment on an appropriate time period

in which to require the submission of

these attachments.

99. As we did in Order No. 888, after

making their FPA section 206

compliance filings, we propose to allow

transmission providers to submit filings

under FPA section 205 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.

100. With respect to an RTO or ISO,

we recognize that such an entity may

already have tariff terms and conditions

that are superior to the pro forma

OATT. Thus, we propose to require

RTO and ISO transmission providers to

submit FPA section 206 compliance

filings, within 90 days following

publication of the final rule in the

99E.g., Calpine, LPPC, NRECA, and Santa Clara.

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sroberts on PROD1PC70 with PROPOSALS

Federal Register, that contain the nonrate terms and conditions set forth in

the final rule or that demonstrate that

their existing tariff provisions are

consistent with or superior to the

revised provisions to the pro forma

OATT. Similarly, after making their

FPA section 206 compliance filings, we

propose to allow RTOs and ISOs to

submit filings under FPA section 205

proposing rates for the services

provided for in their tariffs as well as

non-rate terms and conditions that differ

from their existing tariffs and those set

forth in the final rule if those provisions

are ‘‘consistent with or superior to’’ the

pro forma OATT.

101. We generally note that the

purpose of this NOPR is not to redesign

approved, fully-functional RTO or ISO

markets. We do not expect that

substantial changes to those markets

would be required as a result of this

NOPR. For example, some RTOs or ISOs

have eliminated point-to-point service

for internal transactions in favor of a

form of more flexible network service.

Thus, we would not expect our reforms

to ATC to require changes to the way in

which such RTOs or ISOs assess

whether capacity for traditional network

or point-to-point service is available

within their footprints. However, there

may be elements of the proposed

reforms that are superior to what

currently exists in some RTOs or ISOs,

e.g., transparency, data exchange or

planning, which would require the RTO

or ISO to conform to the pro forma

OATT.

2. Non-Public Utility Transmission

Providers/Reciprocity

102. In Order No. 888, the

Commission conditioned non-public

utilities’ use of public utility open

access services on an agreement to offer

comparable transmission services in

return.100 The Commission found that

while it did not have the authority to

require non-public utilities to make

their systems generally available, it did

have the ability and the obligation to

ensure that open access transmission is

as widely available as possible and that

Order No. 888 did not result in a

competitive disadvantage to public

utilities.

103. Under the reciprocity provision

in section 6 of the pro forma OATT, if

a public utility seeks transmission

service from a non-public utility to

which it provides open access

transmission service, the non-public

utility that owns, controls, or operates

100 These entities are not FPA public utilities and

therefore are not subject to the Commission’s

jurisdiction under sections 205 and 206 of the FPA.

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transmission facilities must provide

comparable transmission service that it

is capable of providing on its own

system. Under the OATT, a public

utility may refuse to provide open

access transmission service to a nonpublic utility if the non-public utility

refuses to reciprocate. A non-public

utility may satisfy the reciprocity

condition in one of three ways: first, it

may provide service under a tariff that

has been approved by the Commission

under the voluntary ‘‘safe harbor’’

provision. A non-public utility using

this alternative submits a reciprocity

tariff to the Commission seeking a

declaratory order that the proposed

reciprocity tariff substantially conforms

to, or is superior to, the pro forma

OATT. The non-public utility then must

offer service under its reciprocity tariff

to any public utility whose transmission

service the non-public utility seeks to

use. Second, the non-public utility may

provide service to a public utility under

a bilateral agreement that satisfies its

reciprocity obligation. Finally, the nonpublic utility may seek a waiver of the

reciprocity condition from the public

utility.101

104. In EPAct 2005, Congress

authorized, but did not require, the

Commission to order non-public

utilities (or ‘‘unregulated transmitting

utilities’’) to provide transmission

services. Section 1231 of EPAct 2005

establishes a new section 211A in Part

II of the FPA, which states in part that

the Commission ‘‘may, by rule or order,

require an unregulated transmitting

utility to provide transmission services’’

at rates that are comparable to those it

charges itself and under terms and

conditions (unrelated to rates) that are

comparable to those it applies to itself

and that are not unduly discriminatory

or preferential. The language does not

limit the Commission to ordering

transmission services only to the public

utility from whom the non-public utility

takes transmission services, but rather it

can reasonably be read to permit the

Commission to order the non-public

utility to provide ‘‘open access’’

transmission service, i.e., service to all

eligible customers.

105. In the NOI, we sought comment

on whether the Commission should

exercise the authority granted to it by

Congress in FPA section 211A. If so, we

asked whether the Commission should

impose this requirement on all

unregulated transmitting utilities

through a rulemaking proceeding, or

whether the Commission should instead

apply this new law on a case-by-case

basis, through complaints, motions

101 See Order No. 888–A at 30,285–86.

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32651

seeking enforcement, or sua sponte

action by the Commission.

Comments

106. Several non-public utility

commenters suggest that the

Commission should not use the

authority granted by FPA section 211A

in a generic fashion.102 They argue that

there is no need to require unregulated

transmitting utilities either to file open

access tariffs with the Commission or to

require that they adhere to a pro forma

OATT. APPA asserts that while the

Commission may act under FPA section

211A to remedy particular issues that

are brought to its attention with respect

to lack of access, there is simply no

basis for concluding that there currently

exists a general problem regarding the

provision of transmission service by

non-public utility transmission

providers which calls for a generic

solution. LPPC proposes a regime of

voluntary compliance with a set of

proposed comparability guidelines.

107. Many commenters argue that the

Commission should exercise its

authority granted by FPA section 211A

by establishing a rule to require

unregulated transmitting utilities to

provide service under the pro forma

OATT.103 EEI believes a rulemaking is

essential to ensure that all utilities

required to provide open access under

FPA section 211A do so and that the

Commission should, at a minimum,

require unregulated transmitting

utilities to file and provide service

under the pro forma OATT. EPSA and

Sempra Global suggest an approach that

would not require an unregulated

transmitting utility to file an OATT with

the Commission until it receives a

request for service.

108. EEI argues that the Commission

should use FPA section 211A to require

unregulated transmitting utilities to

provide all services they are capable of

providing, not just those that they

provide to themselves. In contrast,

APPA states that FPA section 211A

establishes a ‘‘comparability’’ standard

applicable to non-public utility

transmission owner rates, and a

‘‘comparable and not unduly

discriminatory or preferential’’ standard

for terms and conditions. APPA further

states that FPA section 211A requires

that unregulated transmitting utilities

provide transmission service to others at

102 E.g., Chelan, Douglas, LDWP, LPPC, Northwest

Unregulated TUs, Public Power Council, Rural

Utilities Service, Sacramento, Santee Cooper,

Snohomish, Tacoma, TAPS, and TVA.

103 E.g., Ameren, California Commission, Calpine,

Cinergy, EEI, First Energy, Memphis Light, Nevada

Companies, Northwest IPPs, PNM–TNMP, PPL,

Progress Energy, and Suez Energy NA.

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rates, terms and conditions ‘‘comparable

to those under which the unregulated

transmitting utility provides

transmission services to itself,’’ rather

than transmission services that they are

‘‘reasonably capable of providing.’’

109. The Canadian Electricity

Association believes that the adoption

of FPA section 211A requires the

Commission to revisit the reciprocity

requirement of Order No. 888.

According to the Canadian Electricity

Association, EPAct 2005 lowered the

bar for domestic unregulated

transmitting utilities, requiring them

only to provide service under terms and

conditions that are comparable to those

they apply to themselves, rather than

terms and conditions that substantially

conform or are superior to those in the

pro forma OATT. If the Commission

does not make corresponding changes to

the manner in which the reciprocity

requirement currently applies to

Canadian entities, it argues, the result

will be domestic unregulated

transmitting utilities being treated better

than Canadian entities, which would

violate the national treatment

obligations under the North American

Free Trade Agreement. The Canadian

Electricity Association argues that the

reciprocity requirement under Order

No. 888 must be modified to require that

a Canadian entity that seeks open access

in the U.S. must provide access to its

own transmission system under terms

and conditions that are comparable to

those the Canadian entity is subject to

itself.

sroberts on PROD1PC70 with PROPOSALS

Discussion

110. The Commission proposes to

retain the current reciprocity language

in the pro forma OATT, as well as Order

No. 888’s three alternative provisions

for satisfying the reciprocity condition,

which are described above: a non-public

utility that owns, controls, or operates

transmission and seeks transmission

service from a public utility must either

satisfy its reciprocity obligation under a

bilateral agreement, seek a waiver of the

OATT reciprocity condition from the

public utility, or file a safe harbor tariff

with the Commission.104

104 For non-public utilities that choose to use the

safe harbor tariff, we note that its provisions must

be substantially conforming or superior to the new

pro forma OATT. A non-public utility that already

has a safe harbor tariff may amend its tariff so that

its provisions substantially conform or are superior

to the new pro forma OATT if it wishes to continue

to qualify for safe harbor treatment. As the

Commission stated in Order No. 888–A, a nonpublic utility may limit the use of its voluntarily

offered safe harbor reciprocity tariff only to those

transmission providers from whom the non-public

utility obtains open access service, as long as the

tariff otherwise substantially conforms to the pro

forma OATT. See Order No. 888–A at 30,289.

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111. We do not propose a generic rule

to implement the new FPA section

211A.105 Rather, we will apply its

provisions on a case-by-case basis, such

as when a public utility seeks service

from an unregulated transmitting utility

that has not requested service under the

public utility’s OATT and the

reciprocity obligation therefore does not

apply.106 A customer may file an

application with the Commission

seeking an order compelling the

unregulated transmitting utility to

provide transmission service that meets

the standards of FPA section 211A.

Further, as we indicate below, we

expect unregulated transmission

providers to participate in the open and

transparent regional planning processes

that we propose to order and note that,

if there are complaints about such

participation, we will address them on

a case-by-case basis.

112. We disagree with the position of

the Canadian Electricity Association.

EPAct 2005 did not repeal the

reciprocity obligation in Order No. 888.

Rather, it granted a new avenue of

authority to the Commission to order

comparable transmission service from

non-public utilities. We are proposing

not to exercise this new authority at this

time. Rather, we are proposing to retain

our reciprocity policy, which was

adopted pursuant to sections 205 and

206 of the FPA. By maintaining the

same reciprocity requirement for

domestic, non-public utilities as for

foreign utilities doing business in the

United States, the Commission will

ensure that foreign entities will

continue to be treated no less favorably

than domestic, non-public utilities.

consistent, industry-wide method for

calculating it.108 Instead of prescribing a

specific methodology for calculating

ATC in Order Nos. 888 and 889, the

Commission encouraged the industry

efforts and required that transmission

providers base their ATC calculation

methodologies on current industry

practices, standards and criteria.109 In

addition, the Commission directed

transmission providers to include a

description of their ATC calculation

methodologies in Attachment C of their

tariffs.

114. Ten years later, however,

although some progress has been made,

the industry still has not developed a

consistent, industry-wide methodology

for evaluating ATC. In the intervening

years, the industry, working through the

North American Electric Reliability

Council (NERC), has adopted a general

definition of ATC, which establishes a

basic methodology for evaluating ATC.

NERC also has developed a set of

guiding principles for calculating ATC

and has encouraged further consistency

of ATC calculation methodologies on a

regional level. NERC defines ATC as the

transfer capability remaining on the

system for further commercial activity

over and above already committed uses.

This value is determined by deducting

existing transmission commitments

(ETC) 110 (including transmission

reservations, network and retail

customer service), capacity benefit

margin (CBM),111 and transmission

reliability margin (TRM) 112 from total

V. Proposed Modifications of the OATT

110 NERC does not have a formal definition or

standard methodology for ETC.

111 NERC defines CBM as the amount of firm

transmission transfer capability preserved by the

transmission provider for load-serving entities,

whose loads are located on that transmission

service provider’s system, to enable access by the

load-serving entities to generation from

interconnected systems to meet generation

reliability requirements. Preservation of CBM for a

load-serving entity allows that entity to reduce its

installed generating capacity below that which may

otherwise have been necessary without

interconnections to meet its generation reliability

requirements. The transmission transfer capability

preserved as CBM is intended to be used by the

load-serving entities only in times of emergency

generation deficiencies. See North American

Electric Reliability Council, Glossary of Terms Used

in Reliability Standards, (Effective April 1, 2005),

(NERC Glossary) available at

ftp://www.nerc.com/pub/sys/all_updl/standards/

sar/Glossary_07Feb06.pdf.

112 NERC defines TRM as the amount of

transmission transfer capability necessary to

provide reasonable assurance that the

interconnected transmission network will be

secure. TRM accounts for the inherent uncertainty

in system conditions and the need for operating

flexibility to ensure reliable system operation as

system conditions change. See NERC Glossary.

A. Consistency and Transparency of

ATC Calculations

113. In Order Nos. 888 and 889, the

Commission directed transmission

providers to offer their unused transfer

capability to the market and to post the

amount of ATC 107 on OASIS. At the

time those orders were issued, the

Commission noted that formal methods

did not exist for calculating ATC, but

recognized that there were industry

efforts underway to develop a

105 We note that LPPC has committed to voluntary

compliance with a set of guidelines for the

provision of comparable service under FPA section

211A.

106 We do, however, propose to amend our

regulations to make clear that an applicant in a FPA

section 211A proceeding against a non-public

utility that has submitted an acceptable safe harbor

tariff shall have the burden of proof to show why

service under the safe harbor tariff is not sufficient

and why a FPA section 211A order should be

granted. See revised 18 CFR 35.28(e)(1)(ii).

107 See supra note 7.

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108 Order No. 889 at 31,607.

109 Id.

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sroberts on PROD1PC70 with PROPOSALS

transfer capability (TTC).113 However,

NERC’s calculation methodology is not

prescriptive; it establishes a framework

for evaluating ATC, which leaves open

to each transmission provider’s

interpretation and discretion the

specific algorithm, data inputs and

assumptions needed to assess ATC.114

Consequently, transmission providers

have developed numerous ways to

evaluate ATC using their own

algorithms, data and modeling

assumptions.115

115. Although transmission providers

across the Nation have developed

various methodologies, in general, there

are two main approaches to calculating

ATC used in the industry. The first is

the contract path approach, which is

more commonly used by transmission

providers in the Western Electricity

Coordinating Council (WECC) region.116

The contract path methodology derives

ATC directly from predetermined TTC,

ETC, CBM, and TRM values derived

consistent with contract path

transmission rights. The second method

is the flowgate 117 approach, which is

used more widely in the Eastern

Interconnection.118 The flowgate

methodology is based on physical

power flow models. The flowgate

calculation first determines AFC and

then converts AFC into ATC and derives

TTC for the OASIS posting. The

differences between the two approaches

may not result in significantly different

ATC values if consistent data inputs and

industry acceptable modeling

113 NERC defines TTC as the amount of electric

power that 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. See NERC Glossary.

114 See NERC, Available Transfer Capability

Definitions and Determination: A Framework for

Determining Available Transfer Capabilities of the

Interconnected Transmission Networks for a

Commercially Viable Electricity Market (1996)

available at

ftp://www.nerc.com/pub/sys/all_updl/docs/pubs/

atcfinal.pdf.

115 See supra note 59.

116 See, e.g., Determination of Available Transfer

Capability within the Western Interconnection

(June 2001), available at

http://www.wecc.biz/documents/library/

procedures/ATC-apprdec01.pdf.

117 A flowgate is a designated point on the

transmission system used in the modeling of power

flows. While NERC currently does not have a formal

definition for AFC, the power industry commonly

defines AFC as a measure of the capability

remaining on a flowgate for future uses, after

considering the effect of prior sales.

Mathematically, the industry measures AFC as AFC

= Flowgate rating—[(base case flow)—(impacts of

existing reservations)]—FlowgateCBM—

FlowgateTRM.

118 See, e.g., PJM Manual 2: Transmission Service

Request (April 14, 2005), available at:

http://www.pjm.com/contributions/pjm-manuals/

pdf/m02v08.pdf

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assumptions are used. Without a

consistent and transparent approach to

evaluating ATC, transmission customers

will remain wary when service is

denied and transmission providers will

be the subject of suspicion and

heightened scrutiny, especially given

the increasingly congested state of the

Nation’s electric grid.

Consistency

116. Generally, transmission

providers calculate ATC by creating a

base model of their system using a set

of data inputs and assumptions, which

are determined by the transmission

provider. The transmission provider

uses the model to perform various

computer simulations of the operations

of its system to determine the levels of

transfer capability available on the

system. The types of data and

assumptions used in the models

include, for example, facility ratings, the

operating status of facilities, and

generation dispatch, which might be

supported by history, transmission

plans, or the judgment of the

transmission provider. For example, a

transmission provider could use its

judgment to reduce a facility rating or

model certain facilities as out of service,

which would have the effect of

calculating a lower TTC value. A

transmission provider also may use

generation dispatch assumptions to

limit transfer capability that otherwise

would have been available to

independent generators, thereby

favoring the transmission provider’s

own generation. A transmission

provider usually assumes that

designated network resources are

dispatched in economic merit order.

However, a transmission provider has

the discretion to decide which of the

generators that are not designated

network resources will be modeled inservice. Assumptions like these

influence the loading on transmission

lines in the model and heavily influence

the resulting ATC. Having standards in

place that address the calculation of

ATC components, data inputs, and

modeling assumptions would help

ensure non-discriminatory treatment by

limiting a transmission provider’s

ability to use discretion to the

disadvantage of competitors and the

market.

117. As noted above, NERC does not

have a formal definition of ETC.

Without clear criteria for what should

be included in a transmission provider’s

ETC, a transmission customer might not

know whether ETC is being over- or

underestimated. For example, a

transmission provider could set aside

more capacity for native load than is

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32653

realistically expected to occur. This

could happen if a transmission provider

includes in ETC excess capacity for a

load-serving entity (such as capacity to

meet generation reserve requirements)

but then also has a CBM component in

its calculation of ATC that includes the

same capacity. A transmission provider

also could overestimate its ETC by

double-counting the same transmission

reservations in its ATC calculation. For

example, this could happen if a

transmission provider fails to replace a

transmission reservation with the

associated real-time schedule, and as a

result does not release non-firm ATC. A

consistent process for calculating ETC

will limit the subjectivity of the

transmission provider’s decisions and

provide a more uniform method for

estimating ETC.

118. With respect to the modeling of

a particular transaction, when

information concerning the source is

unknown, a transmission provider has

the discretion to select which

generator(s) will be used as a source.119

There are no standards for how that

modeling should be done and,

consequently, a transmission provider

could model a source using single or

multiple generators by increasing

(scaling up) their output. In general,

modeling a transaction using multiple

generators as a source is less

conservative for the transmission system

than modeling a transaction using a

single generator as a source. Modeling a

transaction using multiple generators as

a source typically results in a higher

ATC value. Conversely, when a

transmission provider models a

transaction using a single generator as a

source, this can result in a lower ATC

value depending on the location of the

generator. Modeling of contingency

outages used for calculating ATC is

another area within the discretion of the

transmission provider. Although the

type of contingency, such as single

contingency (n–1), is determined by

governing reliability criteria,120 the

transmission provider determines which

specific contingencies will be used for

the ATC calculation. The common

industry practice is to consider the loss

119 Transmission providers do not always know

the generator used as a source of energy provided

under contracts that qualify as designated

resources; the only requirement is that the network

customer have an executed contract that commits

it to purchase noninterruptible power. See

Wisconsin Public Power Inc. v. Wisconsin Public

Service Corp., 84 FERC ¶ 61,120 at 61,650–51

(1998).

120 Standard TPL–001–0, Table I. Transmission

System Standards—Normal and Emergency

Conditions, NERC Reliability Standards for the Bulk

Electric Systems of North America (effective April

1, 2005).

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sroberts on PROD1PC70 with PROPOSALS

of each transmission facility at voltage

100 kV and above. However, the lack of

standards governing transfer analysis

allows the transmission provider to use

its discretion to monitor outages only of

facilities at 230 kV and above, ignoring

the limitations that may exist for the

loss of the facilities at lower voltages,

such as 115 kV or 138 kV.

Consequently, ATC values may vary

substantially, with ATC being much

higher when monitoring contingencies

of facilities at 230 kV and above, and

much lower while monitoring the loss

of all facilities (voltage 100 kV and

above).

119. Furthermore, in calculating ATC,

transmission providers set aside a

portion of transfer capability in the form

of CBM and/or TRM to provide for

adequate generation reserves and

account for uncertainties or

contingencies, respectively. Generally,

CBM is the amount of firm transmission

transfer capability held back by the

transmission provider so that loadserving entities, whose loads are located

on the transmission provider’s system,

can access remote generation reserve

from interconnected systems in times of

emergency generation deficiencies.

Some believe it is necessary for

transmission providers to set aside a

portion of their TTC to ensure that their

ties with other systems remain available

for this purpose. There are no consistent

industry-wide standards, however, for

determining how much transfer

capability should be set aside as CBM.

There is also no common approach to

whether the capacity is set aside for

Native Load Customers, as defined in

section 1.19 of the pro forma OATT, for

retail load, or for all load-serving

entities. The lack of consistent criteria

and clarity with regard to the entity on

whose behalf CBM has been set aside

has the potential to result in the

transmission provider setting aside

capacity that it might not otherwise

need to, thus increasing costs for native

load customers and blocking other firm

uses of the transmission system.121

120. Similarly, TRM is the amount of

transmission transfer capability reserved

by the transmission provider to ensure

121 The Commission has explained that the pro

forma OATT requires both transmission customers

and transmission providers using the transmission

system to serve network load (including bundled

retail native load) to designate their resources and

loads so that the transmission customers and

transmission providers would have no incentive to

designate network resources above their needs and,

in so doing, tie up valuable transmission capacity.

Aquila Power Corp. v. Entergy Services, Inc., 90

FERC ¶ 61,260, reh’g denied, 92 FERC ¶ 61,064

(2000), reh’g denied, 101 FERC ¶ 61,328 (2002),

aff’d sub nom. Entergy Services, Inc. v. FERC, 375

F.3d 1204 (D.C. Cir. 2004) (Aquila).

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that the transmission network will be

secure under a reasonable range of

uncertainties in system conditions.

Because TRM and CBM are both

maintained in part for the loss of

generators, there exists the possibility of

double-counting reliability margins for

the loss of the same generation.

121. Moreover, a transmission

provider also can use more conservative

inputs and assumptions for calculating

ATC and performing system impact

studies (that tend to minimize ATC)

when it is assessing a long-term

transmission service request, but use

less conservative inputs and

assumptions (that tend to maximize

ATC) when it is performing system

planning for retail native load. This

creates the potential for undue

discrimination where a transmission

provider uses one set of data and

assumptions to evaluate third party

requests and another set of data and

assumptions to plan its system to serve

its own load.

Data Exchange Among Transmission

Providers

122. The lack of a consistent ATC

calculation methodology combined with

limited coordination between

transmission providers can result not

only in inefficiencies but unjust and

unreasonable terms and conditions of

service, especially for a customer

seeking contiguous transmission service

from multiple transmission providers.

The ATC values posted by a

transmission provider are often

inaccurate for reasons beyond the

control of the transmission provider. A

transmission provider may post ATC

values in good faith and attempt to

provide transmission service based on

these values only to discover later that

the transfer capability that it thought

was available no longer exists due to

decisions made by other transmission

providers that it did not know about at

the time it made its calculations.

Accurate ATC calculation requires

reliable and timely information about

such things as load, generation dispatch,

facility outages, and transactions on

neighboring systems. Transmission

providers also may apply differing

assumptions and criteria to ATC

calculations, which may produce wide

variations in posted ATC values for the

same transmission paths. All of these

considerations make it difficult for an

individual transmission provider that

operates one part of an interconnected

grid to calculate ATC accurately.

123. This lack of communication and

coordination between transmission

providers of ATC data can also affect

reliability. As discussed above, a

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transmission provider could grant

transmission service without being

aware of the real impact that service

may have on an adjacent transmission

provider’s system, thus degrading the

reliability of the interconnected system.

Inaccurate ATC values can cause

overselling of transfer capability, which

can lead to curtailments or transmission

loading relief (TLR) actions to avoid

exceeding thermal, voltage, and/or

stability limits.

Transparency

124. As discussed, the lack of a

consistent, industry-wide methodology

for assessing ATC makes undue

discrimination difficult to detect. This

problem is further exacerbated by a lack

of transparency surrounding the

calculation methodology used by

transmission providers. Although the

Commission requires transmission

providers to file their methodologies for

calculating ATC in their tariffs,

transmission providers often have

responded by filing very general

narrative descriptions of their

calculation methodologies (often simply

referring to the general NERC

definition) 122 without further

specification of the mathematical

algorithm, data inputs, and modeling

assumptions used to perform the

calculation.

125. Other than the description of the

ATC methodology provided in

transmission providers’ tariffs, third

parties often have limited access to

information concerning the specific

algorithms, data and assumptions used

by transmission providers to evaluate

their ATC, which makes it difficult to

verify or challenge a transmission

provider’s ATC calculations. The

Commission requires each transmission

provider to calculate and post ATC and

TTC values for each posted path.123

Transmission providers also are

required to make publicly available, on

request, all data used to calculate ATC

and TTC for any constrained path.124

Additionally, transmission providers are

required to make publicly available, on

request, system planning studies or

122 See, e.g., the OATTs of Aquila, Inc., Southern,

and Tucson Electric Power Company.

123 See 18 CFR 37.6 (b) (2005). A posted path is

defined as any control area to control area

interconnection; any path for which service is

denied, curtailed or interrupted for more than 24

hours in the past 12 months; and any path for

which a customer requests to have ATC or TTC

posted. Id. 37.6 (b)(1)(i).

124 Id. 37.6 (b)(2)(ii). A constrained posted path is

defined as any posted path having an ATC value

less than or equal to 25 percent of TTC at any time

during the preceding 168 hours or for which ATC

has been calculated to be less than or equal to 25

percent of TTC for any period during the current

hour or the next 168 hours. Id. 37.6 (b)(1)(ii).

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network impact studies performed for

customers to determine network

impacts. Furthermore, subsequent to

Order Nos. 888 and 889, the

Commission required each transmission

provider to post (and update) the CBM

value for each path for which it already

posts ATC and TTC, as well as a

narrative explanation of its CBM

practices.125

126. Yet, despite these requirements,

third parties often are unable to gain

access to sufficient information

surrounding a transmission provider’s

ATC calculation methodology. As a

preliminary matter, we note that while

the OASIS requirements regarding the

availability of information related to

ATC and TTC calculations are still in

effect, they have been affected by

restrictions that have been placed upon

the availability of critical energy

infrastructure information (CEII) in the

interest of national security.126

Therefore, system planning and network

impact studies and models typically are

no longer available on a transmission

provider’s OASIS. Furthermore,

transmission customers are often unable

to access other information such as load

flow base cases and associated files. In

sum, although existing Commission

regulations are intended to provide a

certain level of transparency, this

transparency is undermined by a

number of factors, including the absence

of detailed descriptions of the data

inputs, assumptions, and criteria used

to determine the data included in ATC

calculations, as well as the inability of

customers to access certain of this data

because of, among other reasons,

security concerns.

sroberts on PROD1PC70 with PROPOSALS

Recent Industry Efforts To Improve the

Consistency and Transparency of ATC

Calculations

127. The industry recently has taken

some steps to address the lack of

consistency and transparency in the

way ATC is calculated. NERC formed a

Long-Term AFC/ATC Task Force to

review NERC’s standards on ATC,

which issued a final report in 2005

(NERC Report) 127 that made

recommendations for greater

consistency and greater clarity in the

calculation of ATC. The task force also

125 Capacity Benefit Margin in Computing

Available Transmission Capacity, 88 FERC ¶ 61,099

(1999) (CBM Order).

126 See Critical Energy Infrastructure Information,

Order No. 630, 68 FR 9857 (Mar. 3, 2003), FERC

Stats. & Regs. ¶ 31,140 (2003), order on reh’g, Order

No. 630–A, 68 FR 46456 (Aug. 6, 2003), FERC Stats.

& Regs. ¶ 31,147 (2003), order on clarification,

Order No. 662, 70 FR 37031 (Jun. 28, 2005), FERC

Stats. & Regs. ¶ 31,189 (2005); see also 18 CFR

388.113 (2005).

127 See supra note 115.

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recommended greater communication

and coordination of ATC information to

ensure that neighboring entities

exchange relevant information. Based

on the recommendations in the NERC

Report, NERC has two Standards

Authorization Request (SAR)

proceedings underway to revise the

standards on ATC. The first SAR

proceeding proposes changes to the

existing standards on ATC to, among

other things, further establish

consistency (on a regional basis) in the

calculation of ATC and to increase the

clarity of each transmission provider’s

ATC calculation methodology. The

second SAR proceeding proposes

certain changes to NERC’s existing

standards on the ATC components of

CBM and TRM. This proceeding also

calls for greater regional consistency

and transparency in how CBM and TRM

are treated in transmission providers’

ATC calculations. Also, based on the

recommendations in the NERC Report,

the North American Energy Standards

Board (NAESB) has a proceeding

underway to develop business practice

standards to enhance the processing of

transmission service requests, which

use TTC, ATC and/or AFC.

128. Following the release of the

NERC Report, the Commission issued

the ATC NOI 128 seeking comments on

the contents of the NERC Report. More

specifically, the Commission sought

comments on the NERC Report’s

recommendations on areas in which

CBM and TRM could be more specific

and whether these recommendations go

far enough in promoting a common

CBM and TRM methodology within

each region. The Commission also

sought comments on the definitions of

ATC, AFC, CBM and TRM. The

Commission also solicited comments on

the advisability of revising and

standardizing ATC, AFC, TRM and CBM

values. In addition, the Commission

sought comments on the advisability of

developing interconnection-wide

standards for the Eastern

Interconnection and WECC. Finally, the

Commission asked for comments on the

most expeditious way to obtain

industry-wide standards for ATC

calculations.

129. Furthermore, in the NOI, the

Commission sought comments on

whether undue discrimination is most

likely to occur in areas such as ATC

calculation where the transmission

provider retains discretion as to how to

implement a particular tariff provision.

128 Supra note 9.

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32655

Comments

Comments on Consistency

130. Many commenters express

general support for some level of

increased consistency in ATC

calculations.129 Some commenters urge

the Commission to develop a consistent,

industry-wide methodology for

calculating ATC.130 Constellation

asserts that although transmission

providers need to be innovative and

flexible in many respects, a requirement

that all transmission providers use the

same methodology to determine ATC

would not only remedy the lack of

clarity that surrounds these calculations

and reservations, but would provide

regulatory certainty and assist

transmission customers in predicting

the outcome of transmission service

requests. This, in turn, Constellation

suggests, would expand the commercial

opportunities for transmission

customers. According to Alcoa, AWEA

and Renewable Energy, the industrywide methodology should be a flowbased methodology, rather than a

contract path methodology because they

believe that a flow-based analysis

provides a more realistic view of actual

system usage and results in a more

accurate assessment of ATC. Exelon

further suggests that this uniform

methodology should also apply to all

transmission providers, including RTOs.

131. Other commenters argue against

a one-size-fits-all approach, but rather

express a preference for greater

uniformity at a regional level to

recognize regional differences.131 These

commenters suggest that due to

differences in transmission systems or

regions, it may not be practical or

possible to standardize the ATC

calculation methodology on an

industry-wide basis. For example,

Powerex cautions that nationwide

standardization may not take into

account the unique characteristics of

particular systems or regions, such as

the differences attributable to the West’s

contract-path model and the East’s flowbased model, as well as differences

attributable to the primarily hydro129 E.g., Alcoa, Ameren, AWEA, Calpine,

Constellation, Cottonwood ATC NOI Comment,

ELCON, Exelon, FTC ATC NOI Comment, Midwest

ISO ATC NOI Comment, Midwest SATS, New York

Commission ATC NOI Comment, North Carolina

Commission, Occidental, South Carolina E&G,

TAPS, and TransAlta.

130 E.g., Alcoa, AWEA, Constellation, Exelon,

Occidental, and Renewable Energy.

131 E.g., Alberta Intervenors, APPA, Bonneville,

International Transmission, ISO/RTO Council,

LDWP, MidAmerican, Nevada Companies,

Powerex, Progress Energy, Public Generating Pool,

Public Power Council, Salt River, Santa Clara,

Snohomish, Tacoma Power, TANC, and TDU

Systems.

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based systems in the Pacific

Northwest.132 Similarly, TANC argues

that flowgate terminology and

application in ATC calculation should

not be required in the West because it

does not adequately represent the nature

of the many transmission constraints in

the West. Other commenters caution

that too much uniformity of the ATC

calculation methodology could have an

adverse effect on grid reliability.133 In

addition, some commenters urge the

Commission not to adopt an ATC

methodology that is so prescriptive that

it inhibits new or better practices or

imposes a wholesale revision of

accepted market designs and processes

that are working within established

markets.134

132. Several commenters argue

against any efforts to further standardize

ATC calculations.135 In its comments

filed in the ATC NOI proceeding, LDWP

asserts that the alleged problems with

ATC are overstated. Moreover, it argues,

the benefits of squeezing additional

ATC from existing systems have not

been established given that transmission

customers can already request any

capacity they need regardless of the

posted ATC and transmission providers

are required to make a good-faith effort

to evaluate each request. Several

commenters argue that the

circumstances of individual

transmission customers vary and often

ATC calculations rely on the individual

transmission provider’s knowledge of its

facilities and system conditions.136 For

example, Southern contends that too

many factors go into the calculation of

ATC to make the adoption of a static set

of standards feasible. In fact, Southern

and EEI maintain, standardization of

ATC calculations is inconsistent with

maintaining reliability because the

circumstances of transmission providers

vary significantly, and they must

operate their systems based on their

specific circumstances. In addition,

LG&E maintains that standardizing ATC

will not necessarily eliminate the need

for TLR procedures to deal with load

forecast errors and unplanned

generation and transmission outages.

Furthermore, some commenters argue

that increased uniformity could impose

significant costs upon utilities.137

133. Some commenters urge the

Commission to increase the consistency

of the elements of the ATC calculation,

such as the kind of data inputs that

transmission providers consider when

evaluating ATC—including load levels,

generator outage information,

transmission outage information and

generation dispatch information.138

Exelon also urges the Commission to

establish the assumptions that

transmission providers use in their ATC

methodologies—such as how

transmission reservations are accounted

for and which reservations to model.

Exelon also cites an example of

modeling transaction counterflows,

noting that uniform rules for data inputs

are needed to ensure that transaction

counterflows are modeled identically in

both the planning and ATC/AFC

calculation processes. In addition,

commenters urge the Commission to

establish the procedures for determining

ATC (and its components) and to

require a transmission provider to show

that it has properly followed all

required procedures.139 Among other

things, commenters suggest that the

Commission should establish how

frequently ATC is calculated, how

frequently inputs are updated, require

transmission providers to determine

AFC instead of ATC, and require

transmission providers to recognize all

third-party flowgates that are requested

to be monitored. In addition, several

commenters state that the Commission

should require that the methodology

and inputs for ATC calculations be

consistent

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