FERC- 732 Supporting Statement 2009 PWM_11_9_09eb11_17

FERC-732 11

Supporting Statement for

FERC-732, “Electric Rate Schedules and Tariffs: Long-term Firm Transmission Rights in Organized Electricity Markets”

Request for a Three-Year Extension of a Currently Approved Collection

The Federal Energy Regulatory Commission (Commission) requests that the Office of Management and Budget (OMB) review and extend its approval of FERC-732 “Electric Rate Schedules and Tariffs: Long-term Firm Transmission Rights in Organized Electricity Markets,” (OMB Control No. 1902-0245). Current OMB approval expires on January 31, 2010.

A. Justification

1. CIRCUMSTANCES THAT MAKE THE COLLECTION OF INFORMATION NECESSARY

To encourage investment in transmission infrastructure, the Commission requires all Regional Transmission Organizations (RTOs), Independent Service Operators (ISOs), independent transmission providers, or other independent transmission organizations to make available long-term firm transmission rights to load-serving entities (LSEs). The Commission implemented this policy with Order No. 681 (Attachment C), following direction provided by Congress in EPAct 2005, Title VII section 1233 (b) (Attachment B).

To ensure that long-term firm transmission rights are made available in organized markets, the Commission requires that RTOs, ISOs, independent transmission providers, or other independent transmission organizations submit tariff sheets and rate schedules that make available long-term firm transmission rights, or alternatively, an explanation of how their current tariff and rate schedule provide for long-term firm transmission rights (18 CFR 42.1) (Attachment A). These long-term firm transmission rights made available to transmission customers must satisfy each of the guidelines for long-term firm transmission rights set forth in 18 CFR 42.1(d) in order to comply with Commission requirements.

While all existing RTOs and ISOs were required to submit the applicable tariff sheets and rate schedules by 2007, FERC-732 requirements apply to any transmission organization approved by the Commission after January 29, 2007.

2. HOW, BY WHOM AND FOR WHAT PURPOSE IS THE INFORMATION TO BE USED AND THE CONSEQUENCES OF NOT COLLECTING THE INFORMATION

The Commission will use the tariff sheets and rate schedules submitted by transmission organizations in accordance with this requirement to ensure that the transmission organizations make available long-term firm transmission rights. Failure to collect this information would prevent the Commission from monitoring the availability of long-term firm transmission rights from a transmission organization.

2. DESCRIBE ANY CONSIDERATION OF THE USE OF IMPROVED INFORMATION TECHNOLOGY TO REDUCE BURDEN AND THE TECHNICAL OR LEGAL OBSTACLES TO REDUCING BURDEN

To reduce the burden on regulated entities, the Commission is implementing the eTariff system. Following April 10, 2010, the Commission will require that all rate proposals be submitted electronically using this system.

4. DESCRIBE EFFORTS TO IDENTIFY DUPLICATION AND SHOW SPECIFICALLY WHY ANY SIMILAR INFORMATION ALREADY AVAILABLE CANNOT BE USED OR MODIFIED FOR USE FOR THE PURPOSE(S) DESCRIBED IN INSTRUCTION NO. 2.

No other existing filing requirement provides information on the availability of firm long-term transmission rights, so FERC-732 remains a necessary information collection in order for the Commission to remain in compliance with EPAct 2005 mandates.

5. METHODS USED TO MINIMIZE BURDEN IN COLLECTION OF INFORMATION INVOLVING SMALL ENTITIES

No small entities will likely be involved in this information collection. Any applicable information will be collected from transmission organizations, which are typically large entities.

6. CONSEQUENCE TO FEDERAL PROGRAM IF COLLECTION WERE CONDUCTED LESS FREQUENTLY

The requirement for transmission organizations to submit tariff sheets and rate schedules to comply with EPAct 2005 requirements to make available long-term firm transmission rights is a one-time filing requirement. Collecting the information less frequently would mean not collecting the information at all. If the information were not collected, the Commission would be unable to monitor the availability of long-term firm transmission rights in wholesale electric markets.

6. EXPLAIN ANY SPECIAL CIRCUMSTANCES RELATING TO THE INFORMATION

There are no special circumstances relating to this information.

8. DESCRIBE EFFORTS TO CONSULT OUTSIDE THE AGENCY: SUMMARIZE PUBLIC COMMENTS AND THE AGENCY’S RESPONSE TO THESE COMMENTS

In accordance with 5 CFR §1320.8(d), the Commission issued a notice to renew the FERC-732 OMB approval and published it in the Federal Register on September 2, 2009 (Attachment D).¹ The Commission did not receive any comments in response to this notice.

9. EXPLAIN ANY PAYMENT OR GIFTS TO RESPONDENTS

There are no respondent payments or gifts required in this proposed information collection.

10. DESCRIBE ANY ASSURANCE OF CONFIDENTIALITY PROVIDED TO RESPONDENTS

The Commission generally does not consider the information filed in FERC-732 to be confidential. In fact, transmission organizations are required to file this information as part of their tariffs so the information can be made available to the public. However, the applicant may request privileged treatment, in accordance with 18 CFR §388.112, for a filing thought to contain information harmful to the competitive posture of the applicant if released to the general public.

11. PROVIDE ADDITIONAL JUSTIFICATION FOR ANY QUESTIONS OF A SENSITIVE NATURE

There are no questions of a sensitive nature associated with the reporting requirements in this information collection.

12. ESTIMATED BURDEN OF COLLECTION OF INFORMATION

FERC-732 Error: Reference source not found	Number of Respondents Annually (1)	Number of Responses Per Respondent (2)	Average Burden Hours Per Response2 (3)	Total Annual Burden Hours (1)x(2)x(3)
New Transmission Organizations with Organized Electricity Markets--filing requirement	1	1	1,180	1,180
Existing & New Transmission Organizations with Organized Markets--making plans & procedures available to public	6	1	2	12
TOTAL ANNUAL ESTIMATE			Error: Reference source not found	1,192

This number of filings is based on workload statistics and represents a burden adjustment of -7,080 hours per year. There are no changes to the filing requirements and, correspondingly, no program changes to the burden.

13. ESTIMATE OF TOTAL ANNUAL COST OF BURDEN TO

RESPONDENTS

Total Respondent Burden Hours		Number of Hours per Staff Year		Cost per Staff Employee		Total Annualized Cost
1,192	÷	2080	x	$128,297	=	$73,524.05

The estimated total cost to respondents is $73,524.05 [1,192 hours divided by 2,080 hours³ per year, times $128,297equals $73,524.05].

The estimated average cost for each new transmission organization is $72,783.86 [(1180/2080)X$128,297], and for existing transmission organizations $123.36 [(2/2080)X$128,297]. Error: Reference source not found

14. ESTIMATED ANNUALIZED COST TO FEDERAL GOVERNMENT:

(a) Information analysis (40 hours) $ 2,399.04

(b) Forms clearance review $ 1,480.00

Year of operation $ 3,879.04

This estimated cost to the Federal Government is based on salaries for professional and clerical support, as well as direct and indirect overhead costs. Direct costs include all costs directly attributable to providing this information, such as administrative costs and the cost for information technology. Indirect or overhead costs are costs incurred by an organization in support of its mission.

15. REASONS FOR CHANGES IN BURDEN INCLUDING THE NEED FOR ANY INCREASE

The estimated burden for this information collection has decreased, as all existing transmission organizations are in compliance with FERC-732. As this is a one-time filing requirement, the burden will only increase if the Commission approves a new transmission organization to begin operations. [One response is being used as a placeholder for an application for a new transmission organization with organized electricity market.]

16. TIME SCHEDULE FOR PUBLICATION OF DATA

Copies of the filings are made available to the public within two days of submission to FERC via the Commission's web site. There are no other publications or tabulations of the information.

17. DISPLAY OF EXPIRATION DATE

In the event that a transmission organization submits a tariff proposal to comply with Commission requirements for long-term firm transmission rights, the OMB expiration date for this requirement will not be displayed, as this proposal cannot be classified as a form. If the Commission approves a new transmission organization, then this organization would submit a rate proposal that includes provisions for long-term firm transmission rights in lieu of an actual form.

18. EXCEPTIONS TO THE CERTIFICATION STATEMENT

The Commission does not use statistical survey methodology for this information collection.

B. COLLECTION OF INFORMATION EMPLOYING STATISTICAL METHODS

Not Applicable. Statistical methods are not employed for this information collection.

ATTACHMENT A

Title 18: Conservation of Power and Water Resources
PART 42—LONG-TERM FIRM TRANSMISSION RIGHTS IN ORGANIZED ELECTRICITY MARKETS

§ 42.1   Requirement that Transmission Organizations with Organized Electricity Markets Offer Long-Term Firm Transmission Rights.

(a) Purpose. This section requires a transmission organization with one or more organized electricity markets (administered either by it or by another entity) to make available long-term firm transmission rights, pursuant to section 217(b)(4) of the Federal Power Act, that satisfy each of the guidelines set forth in paragraph (d) of this section. This section does not require that a specific type of long-term firm transmission right be made available, and is intended to permit transmission organizations flexibility in satisfying the guidelines set forth in paragraph (d) of this section.

(b) Definitions . As used in this section:

(1) Transmission Organization means a Regional Transmission Organization, Independent System Operator, independent transmission provider, or other independent transmission organization finally approved by the Commission for the operation of transmission facilities.

(2) Load serving entity means a distribution utility or an electric utility that has a service obligation.

(3) Service obligation means a requirement applicable to, or the exercise of authority granted to, an electric utility under Federal, State, or local law or under long-term contracts to provide electric service to end-users or to a distribution utility.

(4) Organized Electricity Market means an auction-based day ahead and real time wholesale market where a single entity receives offers to sell and bids to buy electric energy and/or ancillary services from multiple sellers and buyers and determines which sales and purchases are completed and at what prices, based on formal rules contained in Commission-approved tariffs, and where the prices are used by a transmission organization for establishing transmission usage charges.

(c) General rule. (1) Every public utility that is a transmission organization and that owns, operates or controls facilities used for the transmission of electric energy in interstate commerce and has one or more organized electricity markets (administered either by it or by another entity) must file with the Commission, no later than January 29, 2007, one of the following:

(i) Tariff sheets and rate schedules that make available long-term firm transmission rights that satisfy each of the guidelines set forth in paragraph (d) of this section; or

(ii) An explanation of how its current tariff and rate schedules already provide for long-term firm transmission rights that satisfy each of the guidelines set forth in paragraph (d) of this section.

(2) Any transmission organization approved by the Commission for operation after January 29, 2007 that has one or more organized electricity markets (administered either by it or by another entity) will be required to satisfy this general rule.

(3) Filings made in compliance with this paragraph (c) must explain how the transmission organization's transmission planning and expansion procedures will accommodate long-term firm transmission rights, including but not limited to how the transmission organization will ensure that allocated long-term firm transmission rights remain feasible over their entire term.

(4) Each transmission organization subject to this general rule must also make its transmission planning and expansion procedures and plans publicly available, including (but not limited to) both the actual plans and any underlying information used to develop the plans.

(d) Guidelines for Design and Administration of Long-term Firm Transmission Rights. Transmission organizations subject to paragraph (c) of this section must make available long-term firm transmission rights that satisfy the following guidelines:

(1) The long-term firm transmission right should specify a source (injection node or nodes) and sink (withdrawal node or nodes), and a quantity (MW).

(2) The long-term firm transmission right must provide a hedge against day-ahead locational marginal pricing congestion charges or other direct assignment of congestion costs for the period covered and quantity specified. Once allocated, the financial coverage provided by a financial long-term right should not be modified during its term (the “full funding” requirement) except in the case of extraordinary circumstances or through voluntary agreement of both the holder of the right and the transmission organization.

(3) Long-term firm transmission rights made feasible by transmission upgrades or expansions must be available upon request to any party that pays for such upgrades or expansions in accordance with the transmission organization's prevailing cost allocation methods for upgrades or expansions.

(4) Long-term firm transmission rights must be made available with term lengths (and/or rights to renewal) that are sufficient to meet the needs of load serving entities to hedge long-term power supply arrangements made or planned to satisfy a service obligation. The length of term of renewals may be different from the original term. Transmission organizations may propose rules specifying the length of terms and use of renewal rights to provide long-term coverage, but must be able to offer firm coverage for at least a 10 year period.

(5) Load serving entities must have priority over non-load serving entities in the allocation of long-term firm transmission rights that are supported by existing capacity. The transmission organization may propose reasonable limits on the amount of existing capacity used to support long-term firm transmission rights.

(6) A long-term transmission right held by a load serving entity to support a service obligation should be re-assignable to another entity that acquires that service obligation.

(7) The initial allocation of the long-term firm transmission rights shall not require recipients to participate in an auction.

ATTACHMENT B

EPAct Title VII, Section 1233 (b)

FERC RULEMAKING ON LONG-TERM TRANSMISSION RIGHTS IN ORGANIZED MARKETS.—Within 1 year after the date of enactment of this section and after notice and an opportunity for comment, the Commission shall by rule or order, implement section 217(b)(4) of the Federal Power Act in Transmission Organizations, as defined by that Act with organized electricity markets.

ATTACHMENT C

116 FERC ¶ 61,077

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Part 42

(Docket No. RM06-8-000; Order No. 681)

Long-Term Firm Transmission Rights in Organized Electricity Markets

(Issued July 20, 2006)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Final Rule

SUMMARY: The Federal Energy Regulatory Commission is amending its regulations under the Federal Power Act to require transmission organizations that are public utilities with organized electricity markets to make available long-term firm transmission rights that satisfy certain guidelines adopted by the Commission in this Final Rule. The Commission is taking this action pursuant to section 1233(b) of the Energy Policy Act of 2005, Pub. L. No. 109-58, § 1233(b), 119 Stat. 594, 960 (2005).

EFFECTIVE DATE: This Final Rule will become effective [insert date 30 days after publication in the Federal Register].

FOR FURTHER INFORMATION CONTACT:

Udi E. Helman (Technical Information)

Office of Energy Markets and Reliability

Federal Energy Regulatory Commission

888 First Street, N.E.

Washington, DC 20426

(202) 502-8080

Roland Wentworth (Technical Information)

Office of Energy Markets and Reliability

Federal Energy Regulatory Commission

888 First Street, N.E.

Washington, DC 20426

(202) 502-8262

Wilbur C. Earley (Technical Information)

Office of Energy Markets and Reliability

Federal Energy Regulatory Commission

888 First Street, N.E.

Washington, DC 20426

(202) 502-8087

Harry Singh (Technical Information)

Office of Enforcement, Division of Energy Market Oversight

Federal Energy Regulatory Commission

888 First Street, N.E.

Washington, DC 20426

(202) 502-6341

Jeffery S. Dennis (Legal Information)

Office of the General Counsel

Federal Energy Regulatory Commission

888 First Street, N.E.

Washington, DC 20426

(202) 502-6027

SUPPLEMENTARY INFORMATION:

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Long-Term Firm Transmission Rights in Organized Electricity Markets

Docket No.

RM06-8-000

TABLE OF CONTENTS

Paragraph Numbers

I. Background 3.

A. The Development of ISOs and RTOs 3.

B. Interest in Long-Term Firm Transmission Rights 6.

C. Staff Paper on Long-Term Transmission Rights 11.

D. Energy Policy Act of 2005 14.

E. Notice of Proposed Rulemaking 15.

II. Discussion 16.

A. Overview 16.

B. Definitions 24.

1. Organized Electricity Market 24.

2. Load Serving Entity and Service Obligation 34.

3. Long-Term Power Supply Arrangement 55.

4. Transmission Organization 63.

C. Commission Interpretation of EPAct 2005 Requirements 70.

D. Commission’s Approach, Regional Flexibility, and Regional Seams Issues 84.

E. Guidelines for the Design and Administration of Long-Term Firm Transmission Rights in Organized Electricity Markets 108.

Guideline (1) – Specify Source, Sink and Quantity 108.

Guideline (2) - Long-Term Hedge That Cannot Be Modified 122.

Guideline (3) – Rights Made Available by Expansions Go to Parties That Pay for the Upgrade 185.

Guideline (4) – Term of Rights Must be Sufficient to Hedge Long-Term Power Supply Arrangements 217.

Guideline (5) – Load Serving Entities with Long-Term Power Supply Arrangements Have Priority to the Existing System 273.

Guideline (6) – Rights are Reassignable to Follow Load 331.

Guideline (7) – Auction Not Required 361.

Guideline (8) – Balance Adverse Economic Impacts 394.

F. Transmission Planning and Expansion 429.

G. Alternative Designs for Long-Term Firm Transmission Rights 458.

H. Miscellaneous Comments 477.

I. Implementation of the Final Rule and Compliance Issues 479.

III. Information Collection Statement 496.

IV. Environmental Analysis 500.

V. Regulatory Flexibility Act Certification 501.

VI. Document Availability 502.

VII. Effective Date and Congressional Notification 505.

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Joseph T. Kelliher, Chairman;

Nora Mead Brownell, and Suedeen G. Kelly.

Long-Term Firm Transmission Rights in Organized Electricity Markets

Docket No.

RM06-8-000

ORDER NO. 681

FINAL RULE

(Issued July 20, 2006)

1. In this Final Rule, the Commission is amending its regulations to require each transmission organization that is a public utility with one or more organized electricity markets to make available long-term firm transmission rights that satisfy each of the guidelines established by the Commission in this Final Rule. We take this action pursuant to section 1233 of the Energy Policy Act of 2005 (EPAct 2005), which added new section 217 to the Federal Power Act (FPA).⁴ This Final Rule will require each transmission organization subject to its requirements to file with the Commission, no later than [INSERT DATE 180 DAYS AFTER PUBLICATION OF FINAL RULE IN THE FEDERAL REGISTER], either (1) tariff sheets and rate schedules that make available long-term firm transmission rights that satisfy each of the guidelines set forth in the final regulations, or (2) an explanation of how its current tariff and rate schedules

already provide for long-term firm transmission rights that satisfy each of the guidelines. A transmission organization approved by the Commission for operation after [INSERT DATE 180 DAYS AFTER PUBLICATION OF FINAL RULE IN THE FEDERAL REGISTER] will be required to satisfy the requirements of this Final Rule.

2. The guidelines adopted in this Final Rule will give transmission organizations the flexibility to propose designs for long-term firm transmission rights that reflect regional preferences and accommodate their regional market designs, while also ensuring that the objectives of Congress expressed in new section 217(b)(4) of the FPA are met. As described in more detail below, the Commission will allow regional flexibility in setting the terms of the rights, but long-term firm transmission rights must be made available with terms (and/or rights to renewal) that are sufficient to meet the reasonable needs of load serving entities to support long-term power supply arrangements used to satisfy their service obligations.

I. Background

A. The Development of ISOs and RTOs

3. In Order No. 888, the Commission found that undue discrimination and anticompetitive practices existed in the provision of electric transmission service in interstate commerce.⁵ Accordingly, the Commission required all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce to file open access transmission tariffs (OATTs) containing certain non-price terms and conditions and to “functionally unbundle” wholesale power services from transmission services.⁶ In addition, the Commission found in Order No. 888 that Independent System Operators (ISOs) had the potential to aid in remedying undue discrimination and accomplishing comparable access⁷ and set out 11 principles for assessing ISO proposals submitted to the Commission.⁸ Following Order No. 888, several voluntary ISOs were established and approved by the Commission.

4. In light of the creation of these ISOs and other changes in the electric industry, the Commission issued Order No. 2000.⁹ In that order, the Commission concluded that traditional management of the transmission grid by vertically integrated electric utilities was inadequate to support the efficient and reliable operation of transmission facilities necessary for continued development of competitive electricity markets¹⁰ and that opportunities for undue discrimination continued to exist.¹¹ As a result, the Commission adopted rules to facilitate the voluntary development of Regional Transmission Organizations (RTOs). The Commission concluded that RTOs would provide several benefits, including regional transmission pricing, improved congestion management, and more effective management of parallel path flows.¹² In Order No. 2000, the Commission established the minimum characteristics and functions that an RTO must satisfy to gain Commission approval.¹³ Under Order No. 2000, the Commission has approved the voluntary formation of a number of RTOs.

5. Most of the RTOs and ISOs operate organized markets for energy and/or ancillary services in addition to providing transmission service under a single transmission tariff. Most of these markets utilize a congestion management system based on Locational Marginal Pricing (LMP). Congestion is defined as the inability to inject and withdraw additional energy at particular locations in the network due to the fact that the injections and withdrawals would cause power flows over a specific transmission facility to violate the reliability limits for that facility. The market operator manages congestion by scheduling and dispatching generators that can meet load in the presence of congestion. Financially, in LMP markets the price of congestion is measured as the difference in the cost of energy in the spot market at two different locations in the network. When such price differences occur, a congestion charge is assessed to transmission users based on their nodal injections and withdrawals. These price differences can be variable and difficult to predict. In order to manage the risk associated with the variability in prices due to transmission congestion, these markets use various forms of financial transmission rights (FTRs)¹⁴ to allow market participants who hold the rights to protect against such price risks. In most cases, these FTRs have terms of one year or less. In general, load serving entities receive FTRs through either direct allocation or through a two-step process in which the load serving entity is first allocated auction revenue rights (ARRs) and then either uses those rights to purchase FTRs, or has the ability under the transmission organization tariff to convert them to FTRs.¹⁵

B. Interest in Long-Term Firm Transmission Rights

6. In recent years, interest in long-term firm transmission rights in organized electricity markets has increased, stemming in large part from a desire of some market participants to obtain rights that replicate the transmission service that was available to them prior to the formation of the organized electricity markets and remains available today in regions without organized electricity markets. The principal concern of these market participants is the inability to obtain a fixed, long-term level of service under pricing arrangements that hedge the congestion cost risk that they face in the organized electricity markets.

7. There are several important differences between transmission service under the Order No. 888 pro forma Open Access Transmission Tariff (OATT) and transmission rights in organized electricity markets that use LMP and FTRs.¹⁶ However, the differences that are most relevant for purposes of this Final Rule concern the management of congestion, the recovery of congestion costs and the availability of long-term service arrangements.

8. Under the OATT, the transmission provider in the first instance manages congestion by redispatching its own or its customers’ network resources as needed to accommodate a transmission constraint; the OATT provides no mechanism by which firm point-to-point transmission customers can participate directly in congestion management.¹⁷ However, in the organized electricity markets that use LMP, the transmission organization manages congestion through the use of locational prices that are determined by bids and offers by markets participants at given locations. This means that all available resources under an LMP system can participate in redispatch for congestion management because they all receive the congestion price signal. As a result, a transmission organization in a region with an organized electricity market is less likely to have to invoke transmission loading relief procedures and service curtailments than a transmission provider under the OATT.

9. The recovery of congestion costs also differs greatly between regions with and without organized electricity markets. In regions where transmission service is provided under the OATT, a transmission customer that takes network service or firm point-to-point transmission service is not charged directly for the costs of the redispatch that may be required to accommodate its use of the transmission system. For example, a firm point-to-point transmission customer is allowed to take service up to its contractual entitlement while paying only a fixed demand charge. Also, although a network customer must pay a share of any redispatch costs that the transmission provider and other network customers incur, its cost responsibility is determined after the fact as a load ratio share of the total redispatch costs that are incurred on behalf of all users of the system over a given time period. While this type of pricing may not present the customer with a price signal that accurately reflects all of the costs occasioned by the customer’s use of the system, it does provide price certainty. In addition, both network service and firm point-to-point transmission service can be obtained under long-term contracts. These attributes of OATT transmission service result in a less volatile price for transmission service over the long-term, which in turn can help facilitate the planning and financing of large generation facilities and other long-term power supply arrangements.

10. In contrast, a transmission organization in a region with an organized electricity market recovers congestion costs measured as differences in the locational price of energy. Because locational prices include a congestion cost component (which can be positive, negative or zero), a participant in an organized electricity market faces the prospect of paying a congestion charge for many of its transactions. Locational pricing and price-based congestion management provide the market participant with much of the information it needs to make cost effective decisions regarding energy consumption and use of the transmission system (as well as investment in new generation and transmission upgrades). However, the FTRs that transmission organizations currently provide to hedge congestion charges for using existing transmission capacity (as opposed to incremental transmission expansions) are generally available for terms of only one year or less. This can create uncertainty for the market participant who wants to procure supplies on a long-term basis because it will not know from year to year with any degree of certainty whether its award of FTRs will be sufficient to meet its needs. Some market participants have expressed concern that this uncertainty makes it more difficult to finance long-term power supply arrangements.

C. Staff Paper on Long-Term Transmission Rights

11. In May 2005, the Commission released a Staff Paper that provided background and solicited comments on whether long-term transmission rights were needed in the ISO and RTO markets, and if so, how to implement them.¹⁸ A number of commenters on the Staff Paper argued that the failure of transmission organizations to offer transmission rights with terms greater than one year is a key deficiency in the markets that produces increased financial risk due to congestion price uncertainty, the failure of forward energy markets to form, and barriers to investment in new generation capacity. Most of the parties in this group stressed that not all transmission capacity should be given over to long-term rights, but that there should be an amount sufficient to cover at least base-load generation resources and perhaps renewable energy generators.

12. A second group of commenters on the Staff Paper largely agreed with the first that long-term rights should be introduced, but argued that this should take place within the framework of existing FTR market designs and follow a cautious, incremental approach. They also supported limiting the quantity of system capability given over to long-term FTRs for at least an initial period.

13. Finally, some respondents felt that long-term rights should not be introduced at this time. These parties were concerned that the introduction of multi-year rights could introduce inequity and inefficiency into the organized electricity markets because such rights will reduce the availability of FTRs with terms of one year or less that can be used to hedge shorter-term transactions. They also assert that introducing long-term rights could cause cost shifts if holders of long-term rights are given congestion risk coverage greater than that accorded to other parties.

D. Energy Policy Act of 2005

14. On August 8, 2005, EPAct 2005¹⁹ became law. As noted above, section 1233 of EPAct 2005 added a new section 217 to the FPA, which provides:

The Commission shall exercise the authority of the Commission under this Act in a manner that facilitates the planning and expansion of transmission facilities to meet the reasonable needs of load-serving entities to satisfy the service obligations of the load-serving entities, and enables load-serving entities to secure firm transmission rights (or equivalent tradable or financial rights) on a long-term basis for long-term power supply arrangements made, or planned, to meet such needs.²⁰

Section 1233(b) of EPAct 2005 requires:

Within 1 year after the date of enactment of this section and after notice and an opportunity for comment, the Commission shall by rule or order, implement section 217(b)(4) of the Federal Power Act in Transmission Organizations, as defined by that Act with organized electricity markets.²¹

E. Notice of Proposed Rulemaking

15. On February 2, 2006, the Commission issued a NOPR that proposed to amend its regulations to require each transmission organization that is a public utility with one or more organized electricity markets to make available long-term firm transmission rights that satisfy guidelines established by the Commission.²² As discussed in more detail below, the NOPR proposed eight guidelines, and sought comments on various issues raised by the introduction of long-term firm transmission rights in the organized electricity markets.

II. Discussion

A. Overview

16. In adopting this Final Rule, the Commission seeks to provide increased certainty regarding the congestion cost risks of long-term transmission service in organized electricity markets that will help load serving entities and other market participants make new investments and other long-term power supply arrangements. The guidelines we adopt in this Final Rule are designed and intended primarily to ensure that the long-term firm transmission rights that are made available by transmission organizations that are subject to the rule have characteristics that will support a long-term power supply arrangement. These guidelines provide a framework within which transmission organizations and their market participants can design and implement long-term firm transmission rights in the organized electricity markets that are compatible with the design of those markets, in particular retaining the advantages of price-based congestion management, and meet the reasonable needs of market participants.

17. Many of the comments received by the Commission express concern that the provision of long-term firm transmission rights will result in a drastic redistribution of transmission rights, with transmission organizations required to provide long-term rights to load serving entities regardless of feasibility or impact on other market participants. This concern is unfounded. While this Final Rule unequivocally requires transmission organizations to offer long-term firm transmission rights with characteristics that will support long-term power supply arrangements, in most cases, offering such rights should not require major changes in allocations or allocation procedures.²³ Our intent with regard to the existing transmission system is that load serving entities be able to request and obtain transmission rights up to a reasonable amount on a long-term firm basis, instead of being limited to obtaining exclusively annual rights.²⁴ Offering such rights should not force transmission organizations to provide rights to the existing system to one party that are infeasible. We expect that transmission organizations will be able to integrate long-term firm transmission rights into their existing procedures for assessing the feasibility of requests for transmission service.

18. While it is difficult to generalize, given the flexibility afforded in this Final Rule, we expect that in most transmission organizations with organized electricity markets the process for obtaining a long-term firm transmission right will not be substantially different from the current procedures. Most transmission organizations will be able to use their current allocation/auction systems to allow load serving entities to nominate source-to-sink transmission rights on a longer-term basis than is currently available. Transmission organizations will then assess those requests for feasibility and award a feasible set of transmission rights, as they do today. This Final Rule also allows the transmission organization to place reasonable limits on the total amount of capacity it will offer as long-term rights. Thus, this Final Rule does not necessarily guarantee that a load serving entity will be able to obtain long-term firm transmission rights to hedge its entire resource portfolio or be able to obtain all the long-term firm transmission rights it requests. Once long-term rights are awarded to a load serving entity, however, this Final Rule requires that they be fully funded over their entire term, as discussed in guideline (2) below.

19. As we noted in the NOPR and reaffirm in this Final Rule, transmission organizations must provide the opportunity for market participants to obtain long-term firm transmission rights that are not currently available by supporting an expansion or upgrade of grid transfer capability. The Commission’s policy is that market participants that request and support an expansion or upgrade in accordance with their transmission organization’s prevailing rules for cost responsibility and allocation must be awarded a long-term firm transmission right for the incremental transfer capability created by the expansion or upgrade. The transmission organization tariffs must clearly and specifically provide for this arrangement, if they do not already. Guideline (3) addresses this requirement. This will enable load serving entities to obtain long-term rights that they may have requested but not received due to infeasibility.

20. Moreover, in this Final Rule we also require transmission organizations with organized electricity markets to explain how their transmission system planning and expansion policies will ensure that long-term firm transmission rights, once allocated, remain feasible over their entire term.

21. Together, these provisions will ensure that transmission systems are expanded where necessary to ensure the continued feasibility of allocated long-term firm transmission rights, while also giving market participants an explicit right to obtain new incremental transmission rights on a long-term basis, in accordance with the prevailing cost allocation methodology in the region.²⁵

22. We understand that specifying and allocating long-term firm transmission rights supported by existing transfer capability will raise difficult issues that must be addressed by transmission organizations and their stakeholders as proposals are developed to comply with this Final Rule. As we discuss in more detail, we believe that the approach we adopt in this Final Rule will give transmission organizations and their stakeholders sufficient flexibility to design long-term firm transmission rights that fit their prevailing market design while also ensuring that the rights have certain fundamental properties necessary to achieve Congress’s objectives in section 217(b)(4) of the FPA. We also clarify below that while each guideline permits flexibility in its implementation, transmission organizations with organized electricity markets must satisfy each of the guidelines in this Final Rule.

23. This Final Rule largely adopts the overall approach as well as the specific guidelines and definitions proposed in the NOPR. In response to the comments received, however, the Commission has made the following changes to the proposal, as discussed in this preamble:

24. Guideline (3) (Rights Made Available by Expansion Go to Parties That Pay for the Upgrade): We have removed the requirement that the term of long-term rights from expansion be equal to life of facility or a lesser term requested by the party paying for the upgrade. Based on the comments on the difficulty of defining life of facility, we will defer to transmission organizations to develop terms based on existing market rules and stakeholder needs. We encourage transmission organizations to harmonize the terms for long-term rights awarded for new capacity with the terms of long-term rights to existing transmission capacity as much as possible.

27. Guideline (4) (Term of Rights Must Be Sufficient to Hedge Long-Term Power Supply Arrangements): We have added a provision that transmission organizations and stakeholders may determine the length of terms and use of renewal rights to provide long-term transmission rights, but must offer coverage for at least a 10-year sequence. Our objective is to balance regional flexibility in defining terms of rights with the need to ensure that those terms are sufficient to allow load serving entities to hedge their long-term power supply arrangements.

29. Guideline (5) (Load Serving Entities with Long-Term Power Supply Arrangements Have Priority to the Existing System): We have revised this guideline in two respects. First, we have eliminated the preference for load serving entities with long-term power supply arrangements and replaced it with a broader preference for load serving entities in general vis-à-vis non-load serving entities. This broader preference is fully supported by the statute and better meets the needs of organized electricity markets. We believe that Congress’s intent in enacting section 217 was to provide long-term firm transmission service to load serving entities and that load serving entities in general should be “first in line” for long-term transmission rights when existing capacity is limited. As originally proposed, guideline (5) could have disadvantaged load serving entities who do not engage in long-term power supply arrangements, a result that we do not believe Congress intended. Proposed guideline (5) could have also presented difficult administrative burdens for transmission organizations, including the burden of evaluating power supply contracts to determine if they qualify for the preference. In addition to addressing these concerns, broadening the preference also makes it possible for transmission organizations to apply the same basic principles for allocating long-term firm transmission rights that they currently use for the initial allocation of short-term firm transmission rights, or auction revenue rights. As a result of this change in the guideline, load serving entities will not be required to provide evidence of a long-term power supply arrangement.

31. We have also revised guideline (5) to allow transmission organizations to place reasonable limits on the amount of existing transmission capacity made available for long-term firm transmission rights. We have done so in recognition of the expected reluctance of transmission organizations to commit all of their existing grid capacity to long-term firm transmission rights due to uncertainty regarding load growth, changes in power flows and the full funding requirement of this Final Rule. This will also help to accommodate load serving entities that prefer short-term rights. In addition, commenters claim that the principal need for long-term firm transmission rights is to support long-term power supply arrangements for base load generation, not peaking or intermediate generation.

33. Guideline (8) (Balance Adverse Economic Impacts): We have elected not to adopt this guideline in the Final Rule. This guideline is not needed as it requires, in effect, nothing more than adherence to the FPA requirement that public utility tariffs must be just and reasonable and not unduly discriminatory. Moreover, it could have been misinterpreted to require long-term firm transmission right proposals to meet a different or higher standard, something the Commission did not intend or believe that Congress intended.

35. Definition of “Long-Term Power Supply Arrangement”: Because we have deleted the reference to “long-term power supply arrangements” from guideline (5), that term is only used in guideline (4), relating to the term of long-term firm transmission rights. The Final Rule removes the specific definition of long-term power supply arrangements proposed in the NOPR, and addresses issues related to our definition of long-term power supply arrangements under guideline (4).

37. Transmission Planning and Expansion: This Final Rule requires that each transmission organization with an organized electricity market implement transmission system planning and expansion procedures to accommodate long-term firm transmission rights that are allocated or awarded to ensure that they remain feasible over their entire term. We also require each such transmission organization to make its planning and expansion practices and procedures publicly available, including both the actual plans and any underlying information used to develop the plans.

39. B. Definitions

40. 1. Organized Electricity Market

41. In the NOPR, the Commission proposed to define “organized electricity market” as “an auction-based market where a single entity receives offers to sell and bids to buy electric energy and/or ancillary services from multiple sellers and buyers and determines which sales and purchases are completed and at what prices, based on formal rules contained in Commission-approved tariffs, and where the prices are used by a transmission organization for establishing transmission usage charges.”²⁶ The Commission stated that it proposed this definition to ensure that the Final Rule in this proceeding applies to any transmission organization that is the transmission provider in its region and has a day-ahead and/or real-time bid-based energy market, administered by the transmission organization itself or by another entity. We sought comment on the scope of this proposed definition.

42. Comments

43. AMPA²⁷ and Public Power Council both argue that the proposed definition is too narrow and should be expanded to include “Day 1” RTO/ISO markets, non-RTO/ISO markets, and other forms of “organized markets” (which can include bilateral markets that use a form contract).²⁸ Public Power Council argues that the proposed definition could lock the Commission into adopting the types of markets described in the definition to the exclusion of other types of markets, and that section 217 of the FPA does not support the Commission’s narrow reading.

44. Other commenters argue that the definition should be narrowed. TAPS, for example, asserts that the Final Rule should not apply in regions where the OATT provides for long-term physical transmission rights, particularly the Southwest Power Pool. According to TAPS, the last clause of the definition of organized electricity markets (“where the prices are used by a transmission organization for establishing transmission usage charges”) excludes SPP because the prices produced by its imbalance market will not establish transmission usage charges. TAPS requests that the Commission clarify that as currently designed SPP will not be subject to the Final Rule.

45. PG&E, EPSA and TAPS all state that because the proposed rule primarily addresses markets that use locational market-based congestion management mechanisms like LMP and have FTRs, the Final Rule should clearly state that it only applies to those markets, and only addresses long-term financial transmission instruments. PG&E recommends that the Commission issue a parallel rule providing for long-term transmission rights in markets that do not use a market-based congestion management mechanism.

46. In reply comments, NRECA opposes proposals to narrow the definition of organized electricity market, arguing that the need for long-term firm transmission rights and the language of the statute are not limited to transmission organizations with locational pricing structures.

47. APPA states that it supports the proposed definition of organized electricity market, but suggests that it be revised to replace “auction-based market” with “a centralized market” because use of “auction-based” implies that buyers and sellers in RTO markets have more choice and autonomy than they do in practice.

48. Commission Conclusion

49. We will adopt the definition of organized electricity market proposed in the NOPR with one modification. Specifically, we modify the first clause of the definition to state that organized electricity market “means an auction-based day ahead and real time wholesale market . . . .” We make this modification to clarify the application of this Final Rule and ensure that the definition captures the transmission organizations with organized electricity markets using LMP and FTRs to which Congress directed the Commission to apply this Final Rule to in section 1233(b) of EPAct 2005. Today, those electricity markets do not offer financial transmission instruments supported by existing capacity with terms longer than one year, and thus entities are not able to obtain a “firm” transmission right on a long-term basis in those markets as section 217(b)(4) of the FPA directs. As a result, they are appropriately the focus of this Final Rule.

50. The Commission will not expand the definition to include other RTO/ISO regions (sometimes called “Day 1” markets), non-RTO/ISO transmission providers, or any other electricity market structure. Applying the Final Rule to non-RTO/ISO markets would not be appropriate because EPAct 2005 requires us to implement section 217(b)(4) in this rulemaking in “transmission organizations with organized electricity markets,” and non-RTO/ISO transmission providers by definition are not transmission organizations.²⁹ And while Public Power Council is correct that there may be other electricity market structures, the definition we adopt here is only for the purposes of this Final Rule and is crafted to ensure that the appropriate entities are subject to the Final Rule. Additionally, as we noted in the NOPR, non-RTO/ISO transmission providers and other RTO/ISOs offer long-term physical transmission service under the Order No. 888 OATT without rates that vary with congestion costs.³⁰ The Commission recently issued a NOPR in Docket Nos. RM05-25-000 and RM05-17-000 that would institute reforms to the OATT. It is more appropriate to consider in that rulemaking any issues related to the application of section 217(b)(4) of the FPA to the other markets identified by commenters, particularly issues related to coordinated, open and transparent transmission system planning.

51. In response to TAPS, we clarify that SPP is not subject to this Final Rule because its current market design does not fit within the definition of organized electricity market that we adopt for purposes of this rule.

52. Finally, we decline to revise the “auction-based” language as APPA requests. This language simply recognizes that the organized electricity markets Congress intended to be subject to this Final Rule are those that utilize auction mechanisms for the buying and selling of electric energy. We note that we are adopting this definition for the purposes of this Final Rule only, and do not intend that it will necessarily apply in other contexts.

53. 2. Load Serving Entity and Service Obligation

54. We proposed to define “load serving entity” and “service obligation,” for purposes of the proposed rule, exactly as Congress defined those terms in new section 217 of the FPA. Specifically, we proposed to define load serving entity as “a distribution utility or electric utility that has a service obligation.”³¹ We proposed to define service obligation as “a requirement applicable to, or the exercise of authority granted to, an electric utility under federal, State or local law or under long-term contracts to provide electric service to end-users or to a distribution utility.”³²

55. Comments

56. APPA, E.ON, NRECA, PG&E and Public Power Council all express support for the proposed definitions.

57. Several commenters (including Industrial Consumers, CAISO, NARUC, National Grid and SDG&E) argue that the proposed definitions in the NOPR would exclude several entities that should be eligible for long-term firm transmission rights because they are not a “distribution utility” or “electric utility.” These entities include industrial customers who serve their own load pursuant to state law, several types of retail service providers, community aggregators, and various non-public utilities. The comments generally seek clarification that all of these various entities are “load serving entities” for purposes of this rule.

58. More specifically, Industrial Consumers and Alcoa explain that while many large industrial customers are permitted under state law to self-supply their own load, usually by registering as a retail provider, not all of these states use the term “load serving entity.” Industrial Consumers argue that entities who have qualified as retail electric providers under state law meet the definition of “electric utility” under EPAct 2005, and request that the Commission unambiguously state that entities who are qualified to serve retail load under state law, including those self-supplying, are load serving entities for purposes of the Final Rule and thus qualify for long-term firm transmission rights.

59. Regarding retail service providers, several commenters (including CAISO, EEI, NARUC and National Grid) seek clarifications regarding whether various types of service providers in retail access states are load serving entities under the proposed definition. NARUC notes that states with retail choice programs either may have multiple sellers of electricity to end users, or may use an auction process whereby the distribution utility takes delivery of the power supply and bills the cost to customers, making it the only seller.³³ To protect and accommodate these choices made by the states, and to be consistent with Congress’ intent that the protections in section 217 of the FPA be available to all customers, it asks the Commission to clarify that all of these entities are “electric utilities” and/or “distribution utilities,” thereby making them load serving entities and eligible to obtain long-term firm transmission rights.³⁴ OMS, noting specifically that Illinois utilities will soon be required to use an auction process to procure supply and that auction winners under this format would not meet either definition, asks the Commission to revise the definition of load serving entity to replace “a distribution utility or electric utility” with “an entity,” and revise the definition of service obligation to replace “electric utility” with “entity.” EEI and National Grid both note that under certain retail access structures service obligations (including the default service obligation) may be reassigned for terms that are less than the term of long-term firm transmission rights. EEI asserts that the proposed definition of load serving entity should be clarified to be simply the distribution utility, unless its service obligation has been reassigned, while National Grid suggests that the load serving entity should be the electric utility when it holds the service obligation, and the distribution utility in the first instance. National Grid also asserts that the Commission should clarify that the term “electric utility” is defined in section 3(22) of the FPA (any “person or Federal or State agency . . . that sells electric energy”), which would encompass both municipal utilities and merchant suppliers not normally subject to state regulation.

60. Santa Clara asserts that the definition of load serving entity should include non-public utilities (as defined in section 201(f) of the FPA), subsidiary agencies of non-public utilities, and entities in which non-public utilities hold an interest (such as joint action agencies), since each either serve load under statutory obligations to serve or facilitate such service. Similarly, California DWR and MWD argue that the Commission should revise the definition of load serving entities to include water pumping entities.³⁵ They assert that in new section 217(g) of the FPA, Congress recognized a need to expand the definition of load serving entity to include such entities.³⁶ To comply with section 217(g), California DWR and MWD contend that the Commission should revise the proposed definition to define load serving entity to mean “a distribution utility, or an electric utility that has a service obligation, or other wholesale transmission user that owns generation facilities, markets the output of federal generation facilities, or holds rights under one or more wholesale contracts to purchase electric energy, for the purpose of meeting a service obligation.”³⁷

61. MSATs seek clarification that as stand-alone transmission companies that do not own generation or distribution facilities, buy or sell energy, serve loads or act as transmission customers or market participants, they are not considered load serving entities under the Commission’s proposed regulations.

62. Ameren asks the Commission to clarify that the definition of service obligation includes future obligations, and not just obligations existing at the effective date of the Final Rule, which it states will provide certainty and reassure load serving entities that long-term firm transmission rights will continue to be made available in the future.

63. Commenters (including CAISO, PG&E and NU) also raise issues and seek clarification specifically with regard to the application of the service obligation definition in retail access frameworks, and particularly seek clarification as to whether a default service obligation is a “service obligation.” According to CAISO, these clarifications are important because they will impact the eligibility rules for long-term firm transmission rights and the rules for transferring those rights as end-users switch providers. Commenters such as PG&E assert that entities holding the default service obligation, even though they may not be serving the load now, must be able to plan to meet that load should they be required to serve it in the future. Coral Power states that the definition of service obligation should be expanded because as proposed by the Commission, it only applies to distribution companies or entities that provide electric service to end-users under contracts. It argues that the definition should include wholesale power suppliers that provide hedging services to competitive retail suppliers or that have assumed load obligations under default service or retail access programs.

64. Commenters (including NU and PG&E) also raise issues with the “long-term contracts” language in the definition, arguing that it has the potential to discriminate against load serving entities in retail access jurisdictions, since such entities do not typically enter into long-term power supply contracts. NU argues that in New England, the definition would favor municipal utilities (whose customers are not included in retail access programs) and utilities from outside the region that serve load through New England resources.³⁸ Accordingly, it asks that the Commission narrow the definitions to limit eligibility for long-term firm transmission rights to entities that serve customers within the same region.

Commission Conclusion

65. In the Final Rule, the Commission is adopting the definitions of load serving entity and service obligation provided by Congress in EPAct 2005 and proposed in the NOPR. We believe using these definitions as Congress provided them will most closely effectuate the intent of Congress in section 217(b)(4) of the FPA. We will, however, offer several clarifications.

66. At the outset, we note that the definition of load serving entity is important in this Final Rule only in that it establishes a priority in the allocation of long-term firm transmission rights when necessary under guideline (5). It does not determine eligibility for long-term firm transmission rights, as some commenters suggest. All market participants are eligible for long-term firm transmission rights.

67. In response to National Grid, we clarify that the term “electric utility,” as used in the definition of load serving entity, is defined in section 3(2) of the FPA as “a person or Federal or State agency (including an entity described in section 201(f)) that sells electric energy.”³⁹ This expansive definition will cover many of the entities for which commenters seek clarification as to their status as load serving entities.

68. With regard to large industrial customers who self-supply their own load, while some of these entities may not technically ”sell . . . electric energy,” we construe them to be load serving entities for purposes of this Final Rule, to ensure that Congress’s objectives in section 217 of the FPA are fulfilled. Thus, transmission organizations should treat them as such when complying with this rule.

69. With regard to non-public utilities, the Commission notes that the definition of electric utility discussed above, as amended by EPAct 2005, includes “an entity described in section 201(f)” of the FPA, i.e. non-public utilities. As a result, they are within the definition of load serving entity, provided, of course, that they have a service obligation. Additionally, in response to California DWR and MWD, we note that the definition of load serving entity provided by Congress appears to already capture water pumping entities, which are non-public utilities. New section 217(g) of the FPA provides that “[t]he Commission shall ensure that any entity described in section 201(f) that owns transmission facilities used predominately to support its own water pumping facilities shall have, with respect to the facilities, protections for transmission service comparable to those provided to load serving entities pursuant to this section.”⁴⁰ In light of this Congressional directive, we clarify, to the extent necessary, that water pumping entities with the characteristics described in section 217(g) are load serving entities for purposes of this Final Rule.

70. MSATs request that we clarify that stand-alone transmission companies are not load serving entities for purposes of this rule. We clarify that as described by MSATs, stand-alone transmission companies that do not own generation or distribution facilities, buy or sell energy, serve loads or act as transmission customers are not load serving entities for purposes of this Final Rule. We emphasize, however, that this clarification should not be read broadly to suggest that other types of stand-alone transmission companies (either existing or that might be developed) with different characteristics from those described by MSATs will not be load serving entities under this Final Rule. The Commission will consider these issues on a case-by-case basis, as necessary.

71. In response to those seeking clarifications regarding various types of retail service providers, we note that many retail service providers will be a “person . . . that sells electric energy,” thus making it an electric utility and, consequently, they can be a load serving entity provided they have a service obligation. The Commission cannot decide here, however, whether each possible entity operating in state retail electric markets will meet the definition of load serving entity. We agree with NARUC, however, that Congress intended to broadly protect the ability of load serving entities with service obligations to obtain transmission service. Thus, transmission organizations should ensure that different types of retail service providers that have service obligations are accommodated when implementing the Final Rule.

72. As noted above, commenters raising issues regarding the application of the service obligation definition in retail access frameworks focus primarily on the default service obligation, which generally (with variation from state-to-state) requires the entity subject to that obligation to provide electric service to customers who do not have another supplier (either because they did not choose one or because their supplier left the market). Under the definition provided by Congress, a default service obligation only becomes a service obligation for purposes of this rule when the entity holding the default obligation is actually required to serve the load, i.e. when the competitive supplier either stops serving the load or the load switches to the default supplier. A default service obligation only becomes “a requirement applicable to, or the exercise of authority granted to” the default supplier when it must actually serve the load. We understand the concerns expressed by PG&E and others that a utility holding the default service obligation must plan to serve that load should it be required to do so in the future. Transmission organization rules currently provide that auction revenue rights (ARRs) or FTRs will generally “follow the load” in instances where load switches suppliers; guideline (6), discussed below, also requires that long-term firm transmission rights allocated to load serving entities be reassignable. As a result, when default suppliers assume the service obligation, they will receive transmission rights that they can use to serve the default load. While we are aware that those transmission rights may not match the resources that the default supplier will use to serve the load, this is a problem that already exists today, and is not a result of our adoption of Congress’s definition of service obligation. Transmission organizations may consider whether any rules are necessary (such as allowing or requiring holders of long-term transmission rights to turn back those rights for reallocation) to deal with this problem.

73. We decline to revise the definitions of load serving entity and service obligation to replace “distribution utility or electric utility” and “electric utility” with “an entity,” as requested by OMS. Congress chose to use these terms to limit these definitions, and we are not persuaded to change them here, and do not believe such a change is necessary to address OMS’s concern. While OMS may be correct that auction winners under Illinois’ procurement mechanism may not meet these definitions, the Illinois utilities that procure electric energy under this mechanism and resell it to their customers (under their service obligation) presumably meet the definitions of load serving entity and service obligation, and thus should be able to obtain long-term firm transmission rights to deliver that energy to load. Similarly, we decline to define load serving entity to be only the distribution utility, unless its service obligation has been reassigned, as requested by EEI, or to be the distribution utility in the first instance, as requested by National Grid. This would limit the definition provided by Congress, which chose to include electric utilities (other than distribution utilities) that have service obligations in the definition, and we are unsure how these revisions would address EEI and National Grid’s concerns. As we note above, when load serving obligations are reassigned, the new entity serving that load will be a load serving entity and have a service obligation under the definitions in this Final Rule, and associated transmission rights will “follow” that load. Any problems associated with transmission rights whose term is longer than the transferred service obligation may be addressed in proposals to implement this rule; revising these definitions do not appear to resolve such concerns.

74. In response to Ameren, we clarify that the definition of service obligation, as written by Congress and adopted by the Commission in this Final Rule, includes future service obligations and not simply those existing on the effective date of this rule. Nothing in that definition, or in section 217(b)(4)’s charge that the Commission exercise its FPA authority in a manner that facilitates the planning and expansion of transmission facilities and enables load serving entities to obtain long-term firm transmission rights, suggests that service obligations should be limited to those existing as of the effective date of this rule.

75. Finally, we will not revise the definition in response to the concerns raised by NU and PG&E regarding the “long-term contracts” language in the definition of service obligation. The definition provides that a service obligation is either “a requirement applicable to, or the exercise of authority granted to, an electric utility under Federal, State, or local law or under long-term contracts . . . .” (emphasis added). Thus, having a long-term contract to serve load is not necessary to have a service obligation under this definition. Load serving entities in retail access jurisdictions will be interpreted to have a service obligation under this rule if they are either required, or have been given authority, under state law to provide electric service. Thus, we do not believe the definition results in any discrimination against load serving entities in those jurisdictions or gives any favor to municipal utilities not included in retail access programs.

76. 3. Long-Term Power Supply Arrangement

77. We noted in the NOPR that while new section 217(b)(4) of the FPA requires the Commission to exercise its authority to enable load serving entities to obtain long-term firm transmission rights “for long-term power supply arrangements made . . . or planned” to meet service obligations, Congress did not define “long-term power supply arrangements” in the legislation.⁴¹ Based on language in section 217(b)(1) of the FPA, we proposed to define long-term power supply arrangements as “the ownership of generation facilities, rights to market the output of Federal generation facilities with a term of longer than one year, or rights under one or more wholesale contracts to purchase electric energy with a term of longer than one year, for the purpose of meeting a service obligation.”⁴²

78. Comments

79. NRECA and PG&E support the proposed definition. Public Power Council also supports the proposed definition with two “editorial suggestions.” First, it suggests removing the phrase “with a term of longer than one year” after “Federal generation facilities” because it is redundant. Second, it suggests replacing the word “rights” where it appears before the phrase “to market the output of Federal generation facilities” with “authority or obligation,” since federal Power Marketing Agencies (like BPA) have a statutory obligation, rather than a “right,” to market the output of their facilities.⁴³

80. Commenters taking issue with the proposed definition addressed three primary issues: (1) the “longer than one year” language, (2) whether the definition should include specific criteria, and (3) whether the definition unduly discriminates against load serving entities in retail access states.

81. APPA argues that the Commission should not define “long-term power supply arrangements” as “longer than one year,” and should instead harmonize this definition with minimum term of long-term firm transmission rights discussed in guideline (4). PJM and TAPS also state that this language is unreasonable, and argue that “long-term power supply arrangements” should be defined as those with a minimum term of 10 years. According to TAPS, this change would appropriately limit the availability of long-term rights to those long-term power supply arrangements most poorly served by annual FTRs, particularly baseload and renewable power arrangements with terms longer than 10 years.

82. Some commenters suggest that the Commission revise the definition of “long-term power supply arrangements” to require that they have certain specific characteristics. CAISO and PG&E, for example, suggest that to make more transparent the process of validating requests for long-term rights, “long-term power supply arrangements” should designate specific resources. Others argue that to prevent inefficient allocations of long-term firm transmission rights, the Commission’s definition should require “long-term power supply arrangements” to be firm for their entire term, specify specific amounts of energy, and be for both capacity and energy. Wisconsin Electric suggests that the definition exclude peaking facilities. Wisconsin Electric also asks that the Commission clarify that long-term leasing arrangements or other arrangements, in addition to ownership, qualify as “long-term power supply arrangements.”

83. In response to CAISO, CMUA states that while it agrees that contracts with flexible points of delivery are an implementation issue that must be addressed, it is concerned that CAISO’s proposed modification is too narrow. According to CMUA, if CAISO’s proposed modification would make long-term transmission rights available only for unit contingent contracts, it would create upheaval in the bilateral markets of the West, where power supply contracts with multiple resources are common.

84. NSTAR suggests that the combination of this definition and guideline (5) results in a long-term firm transmission right that is not available to (and thus unduly discriminates against) load serving entities that provide default service in retail access states because such entities do not enter into “long-term power supply arrangements,” as defined in the rule. According to NSTAR, these entities do not generally own generation and do not enter into long-term power supply contracts either because of the variable nature of their service obligation from year to year or because state regulatory requirements limit them to short-term power purchase agreements. According to NSTAR, requiring long-term power supply arrangements (including generation ownership or purchased power contracts) would conflict with section 217’s overall purpose to protect the transmission rights of all end users and deal a blow to competitive retail electric markets by benefiting long-term rights holders at the expense of retail access loads holding shorter-term rights. NSTAR suggests that the Commission correct this problem by adding “or other arrangements for the purpose of meeting a service obligation on a long-term basis” to the definition.

85. Commission Conclusion

86. As discussed in more detail below, the Commission is removing from guideline (5) the requirement that, in order to have priority in the allocation of long-term firm transmission rights from existing capacity, a load serving entity must hold long-term power supply arrangements. Therefore, that term is only used in the final regulations in guideline (4), relating to the term of long-term firm transmission rights. Accordingly, we are removing the definition of long-term power supply arrangements from the Final Rule, and will generally discuss issues related to our definition of long-term power supply arrangements under guideline (4), particularly with regard to the length of such arrangements. The discrimination arguments raised by certain parties in response to the proposed definition are discussed under guideline (5).

87. 4. Transmission Organization

88. In the NOPR, we proposed to define “transmission organization” as “a Regional Transmission Organization, Independent System Operator, independent transmission provider, or other independent transmission organization finally approved by the Commission for the operation of transmission facilities.”⁴⁴ This proposed definition is similar to the definition of transmission organization provided by Congress in EPAct 2005, except that we added the term “independent.” We explained in the NOPR that we added “independent” because we interpret section 1233(b) of EPAct 2005 to require that long-term firm transmission rights be made available by independent entities that are approved by the Commission (either currently or in the future) to operate transmission facilities and have organized electricity markets.

89. Comments

90. EPSA, PG&E and PJM all support the Commission’s proposal to include “independent” in the definition of transmission organization.

91. APPA and AMPA, while supportive of the Commission’s addition of the word “independent” to the definition of “transmission organization” provided by Congress, note that this addition raises questions regarding the level of independence required to be considered a “transmission organization.” Both raise the question of whether ICT’s are “transmission organizations.” APPA argues that an ICT should not be considered an independent transmission organization because it is employed and paid solely by the transmission-owning utility. APPA adds, however, that it assumes the Commission will apply a “flexible, yet vigilant” standard to determine the independence of transmission organizations.⁴⁵ AMPA, for its part, asserts that given the broad intent of EPAct 2005, the Commission should consider applying the NOPR to all organized electricity markets with independent transmission providers, to ensure that all load serving entities will receive protection for their service obligations and long-term price certainty.

92. Public Power Council, on the other hand, specifically opposes the addition of the word “independent,” arguing that it unduly restricts the definition adopted by Congress, which intended that any organization finally approved by the Commission for the operation of transmission facilities (whether or not independent) would fall under the statute. According to Public Power Council, Congress instead chose to qualify “other transmission organization” with the phrase “finally approved by the Commission for the operation of transmission facilities,” meaning any such transmission organization falls under the statute whether or not it is independent.

93. Commission Conclusion

94. The Commission will adopt the definition of transmission organization proposed in the NOPR. In section 1233(b) of EPAct 2005, Congress narrowed the Commission’s implementation efforts to “Transmission Organizations . . . with organized electricity markets,” even though the overall directive of section 217(b)(4) applies more broadly. We believe that it is reasonable to interpret the more focused directive in section 1233(b) as principally requiring that the Commission implement section 217(b)(4), through rulemaking, in the current independent RTOs and ISOs that operate centralized markets for the purchase of electric energy and/or ancillary services, and any similar transmission organizations that are created in the future. This does not mean, however, that the requirements of section 217(b)(4) will not apply to other transmission providers. The Commission is simply adopting a definition of transmission organization for purposes of this Final Rule that it believes comports with Congress’s intent, expressed in section 1233(b) of EPAct 2005, that the Commission act specifically with regard to transmission organizations with organized electricity markets.

95. In response to comments concerning the level of independence required to be a transmission organization, we note that prior to approving transmission organizations (such as RTOs and ISOs) with organized electricity markets, the Commission makes specific findings, based on established standards, that the entity is independent from market participants. We do not believe any further determination or separate standard is required for purposes of this rule.

96. With regard to comments seeking to clarify whether proposed independent coordinators of transmission are transmission organizations under this Final Rule, we note that these proposals are still developing. Moreover, to date none of these proposed entities has proposed to implement an organized electricity market as defined in this Final Rule. As a result, the Commission will not address whether such entities meet the definition of transmission organization unless and until such time as they propose to establish an organized electricity market.

97. C. Commission Interpretation of EPAct 2005 Requirements

98. In addition to the comments below regarding our flexible approach in the NOPR, several entities submitted comments generally addressing our interpretation of the requirements of new section 217(b)(4) of the FPA and section 1233(b) of EPAct 2005 with respect to long-term firm transmission rights in organized electricity markets. Comments regarding specific interpretations of the statutory requirements that we made in connection with the proposed guidelines are addressed elsewhere in this Final Rule.

99. Comments

100. Long-Term Transmission Rights from Existing Capacity

101. Some commenters, particularly Cinergy, Coral Power and NYISO, argue that the Commission misinterprets section 217(b)(4) and section 1233(b) of EPAct 2005 as requiring the long-term firm transmission rights be made available from existing capacity. They assert that those provisions only require the Commission to exercise its authority to facilitate the planning and expansion of transmission facilities in a manner that allows load serving entities to secure long-term transmission rights. Thus, they contend that the Commission inappropriately gives independent effect to the second clause of the statute (“enables load serving entities to secure firm transmission rights . . . on a long-term basis”), when the true thrust of the law is its first clause (“[t]he Commission shall exercise . . . [its] authority . . . in a manner that facilitates the planning and expansion of transmission facilities . . .”). The second clause, they contend, only modifies the first.

102. In reply comments, APPA, New England Public Systems, NRECA, Peabody, and TAPS urge the Commission to reject Cinergy’s interpretation of the statute. In general, they state that the Commission correctly reads section 217(b)(4) as providing two directives: (1) facilitating transmission planning and expansion, and (2) enabling load serving entities to obtain long-term transmission rights for their long-term power supply arrangements. TAPS argues, for example, that nothing in the statute’s long-term rights clause restricts such rights to new capacity, as Cinergy and others suggest, and further asserts that such a reading would inappropriately “sell short” and render both the long-term rights and planning provisions a nullity. Similarly, APPA contends that if planning and expansion were all Congress sought to address, it would not have included the second clause of section 217(b)(4).

103. Need to Require Long-Term Financial Rights

104. Cinergy and others note a difference between long-term transmission rights and long-term FTRs. According to Cinergy, load serving entities can already acquire long-term transmission rights, and Congress would have used “and” instead of “or” if it intended to require RTOs to also provide long-term FTRs.⁴⁶ IPL similarly argues in its reply comments that the creation of long-term firm transmission rights or long-term financial transmission rights is not statutorily mandated, and as a result must be justified in the record, since it is a “stark departure from past practices.”⁴⁷ IPL states that section 217(b)(4) is properly implemented by ensuring that load serving entities can obtain either firm or financial transmission rights on a long-term basis.

105. In response to these arguments, APPA argues that the term “firm transmission rights” was meant to refer to the physical transmission rights that exist in non-transmission organization markets (since the statute covers all regions), and that the inclusion of the phrase “or equivalent tradable or financial rights” was intended to address the FTRs used in transmission organization markets. According to APPA, the network service contract and associated payment toward the fixed cost of the transmission system does not cover transmission congestion costs. Only an FTR covers these costs and “firms up” the total cost of transmission service, APPA contends. Finally, it, along with NRECA and TAPS, state that if Cinergy’s assertion that transmission organizations already provide long-term transmission rights in compliance with the statute is correct, then section 217(b)(4) was unnecessary and did nothing.

106. Disruption of Current Market Designs or Allocation Methods

107. Some entities, including IPL, Midwest ISO and NYISO, argue that Congress did not intend for the Commission, when implementing section 217(b)(4), to disrupt current market designs or existing transmission rights allocation methodologies. Of these entities, some argue that nothing in section 217 suggests that the Commission require major changes to the existing auction-based FTR systems, and that it would be consistent with section 217 for the Commission to allow transmission organizations to retain their current systems so long as they offer long-term financial transmission rights. Midwest ISO, for example, asserts that section 1233(c) of EPAct 2005 provides that Congress did not intend for the Commission to disrupt existing market designs that already offer long-term FTRs. Similarly, NYISO asserts that nothing in section 217 requires major changes to auction-based FTR systems, noting that this section expressly recognizes that financial rights can be equivalent to physical rights and expressly protects established FTR allocation systems. According to NYISO, the Commission could, consistent with section 217, allow transmission organizations and their stakeholders to retain their current systems so long as they offer long-term FTRs. IPL states, in part, that Congress was aware of the current transmission rights constructs in the organized markets, and by using the phrase “or equivalent tradable or financial rights,” “at the very least left open the possibility that the Commission might use existing financial rights designs to achieve the statutory objectives.”⁴⁸ NYISO also contends that nothing in section 217 requires transmission organizations to offer any rights with longer terms than they already do, noting that section 217 only requires that rights be “long-term” without saying what that means. PJM, while generally supportive of the Commission’s NOPR, nevertheless notes that section 217(c) preserved existing FTR allocation methodologies, and argues that Congress sought to complement rather than replace current transmission rights allocation methods.

108. NYAPP, in reply comments, objects to NYISO’s contention that nothing in section 217 requires transmission organizations to offer any rights with longer terms than they already do, arguing that this interpretation would render section 217(b)(4) a nullity.

109. Midwest TDUs notes in its reply comments that Midwest ISO is subject to a specific directive to consider the preservation of existing transmission rights. Specifically, Midwest TDUs point out that under section 217(c), which shields the other established transmission organizations from the impact of section 217(b)(1) through (b)(3), Midwest ISO is subject to that section’s “provided, however” clause, thus requiring the Commission to take into account existing rights held by a load serving entity as of January 1, 2005 (prior to the commencement of the Midwest ISO organized electricity market).

110. Commission Conclusion

111. As noted above, many of the specific interpretations of section 217(b)(4) of the FPA made by the Commission are discussed below with regard to the guidelines adopted in this Final Rule. However, in this section we address more general comments regarding our interpretation in the NOPR of the requirement of section 217(b)(4) and section 1233(b) of EPAct 2005.

112. First, the Commission believes it correctly interpreted section 217(b)(4) of the FPA as containing two separate directives: (1) to exercise its authority to facilitate planning and expansion of transmission facilities, and (2) to enable load serving entities with long-term power supply arrangements used to meet their service obligations to obtain firm transmission rights on a long-term basis. We conclude that this interpretation of the statute is the most reasonable.⁴⁹ Cinergy’s interpretation of the relevant statutory language as requiring only that the Commission facilitate planning and expansion of transmission facilities in a manner that that allows load serving entities to secure long-term transmission rights is unreasonable in light of the actual statutory language used by Congress. When it drafted section 217(b)(4), Congress separated the first clause (requiring that the Commission exercise its FPA authority to facilitate the planning and expansion of transmission facilities) and the second clause (“and enables load serving entities to secure firm transmission rights . . . on a long-term basis”) with a comma, indicating two separate requirements. The comma is also followed with the word “and,” further suggesting that Congress intended them as two separate directives. No language in the statute suggests that the two clauses are part of a single directive to the Commission.

113. Moreover, a reading of section 217 in its entirety suggests that Congress intended for the Commission to both facilitate planning and expansion and enable that load serving entities can obtain long-term firm transmission rights. As a whole, section 217 is directed to protecting the ability of load serving entities with native load service obligations to obtain firm transmission service to satisfy those service obligations.⁵⁰ Directing transmission organizations with organized electricity markets to provide long-term firm transmission rights from both new and existing capacity is fully consistent with this statutory directive. Furthermore, if Congress only intended to direct the Commission to facilitate planning and expansion of transmission facilities in a manner that enables load serving entities to obtain long-term firm transmission rights, it would not have included the long-term firm transmission rights language in a second, separate clause. Finally, the directive in section 1233(b) of EPAct that the Commission implement this provision within one year in transmission organizations with organized electricity markets (where only annual rights to existing capacity are available) strongly suggests that Congress intended for the Commission to direct such transmission organizations to begin offering long-term rights from existing capacity. A reasonable interpretation is that Congress believed FTRs to capacity at the time of enactment were not sufficiently long, and therefore directed the Commission to make longer-term rights to existing capacity available.

115. We disagree with comments suggesting that section 217(c) immunizes existing market designs and transmission rights allocation methods from the implementation of section 217(b)(4). The “savings clause” in section 217(c) specifically provides that “[n]othing in subsections (b)(1), (b)(2), and (b)(3)” of section 217 shall affect the existing or future methodologies of certain transmission organizations; that clause expressly omits subsection (b)(4) from its protections. As a result, section 217 permits the Commission to require changes to existing market designs and transmission rights allocation methods if necessary to implement section 217(b)(4). This does not mean that the Commission will require such changes or that section 217(b)(4) requires changes to existing designs and allocations in all cases; if a transmission organization can offer long-term firm transmission rights that satisfy each of the guidelines in this Final Rule while retaining its current systems, it may do so. We emphasize, however, that transmission organizations must provide long-term firm transmission rights that satisfy each of the guidelines in this Final Rule even if doing so requires changes to existing systems.

116. Additionally, we disagree with suggestions that transmission organizations already provide long-term firm transmission rights, and that creation of long-term financial transmission rights in this rulemaking is unnecessary. While transmission organizations may provide firm “physical” transmission rights on a long-term basis, the cost of transmission service in transmission organizations that use LMP to manage congestion is dependent on the cost of that congestion. We agree with APPA that for a transmission right to be “firm,” it must be firm as to both quantity and price. In the LMP context, this means “firm transmission rights” must be firm as to both the “physical” component of the right and the “financial” component of the right. FTRs can hedge congestion costs (when matched to the physical path of the transmission right) and make transmission rights in an LMP system “firm,” but are currently only available for one year. As a result, to comply with the directives of section 217(b)(4) and section 1233(b) of EPAct 2005, transmission organizations with LMP and FTRs will need to offer FTRs with longer terms to truly enable load serving entities to secure firm transmission rights on a long-term basis. Further, we disagree with Cinergy’s contention that the “or equivalent tradable or financial rights” language in the statute suggests that transmission organizations can offer either long-term physical rights or long-term financial rights. Rather, we agree with APPA that this language was intended to address the FTRs used in transmission organizations with organized electricity markets and congestion management systems (primarily LMP) that impact the cost of transmission service. We read this language as requiring the Commission to exercise its FPA authority to enable all load serving entities to obtain firm transmission rights on a long-term basis, whether they are located in a region with more traditional “physical” transmission rights or a region that uses LMP and FTRs.

117. Finally, we disagree with NYISO’s contention that section 217 does not require transmission organizations to offer transmission rights with longer terms than those they currently offer. While some transmission organizations could in theory have sufficiently long-term transmission rights and thus would not be required to offer longer terms, if the current transmission rights offered by all transmission organizations were sufficient, it is unclear why Congress would have included the second clause of section 217(b)(4) at all. Moreover, it is reasonable to conclude that Congress believed not all transmission organizations were offering sufficient long-term firm transmission rights given that it focused the Commission’s attention in section 1233(b) of EPAct 2005 on those entities, and given the fact that long-term firm transmission rights are available today in regions without transmission organizations with organized electricity markets. We believe it is reasonable to conclude that Congress was aware that the current terms for transmission rights offered by transmission organizations were insufficient and drafted section 217(b)(4) of the FPA and section 1233(b) of EPAct 2005 together to require that they offer rights with longer terms.

118. D. Commission’s Approach, Regional Flexibility, and Regional Seams Issues

119. In the NOPR, the Commission proposed a flexible regional approach to satisfying the requirements of section 1233(b) of EPAct 2005. Specifically, we proposed to establish a set of guidelines for the design and administration of long-term firm transmission rights in organized electricity markets. Following the establishment of these guidelines in the Final Rule, we proposed to allow each transmission organization subject to the rule to develop specific long-term firm transmission right designs through its usual stakeholder process that would fit the prevailing regional market design.

120. We stated that this flexible approach was appropriate because there is no “one size fits all” long-term firm transmission right design that could be implemented in each of the various transmission organization markets. However, we stated further that flexible regional development must occur within guidelines, to ensure that the specific long-term firm transmission rights ultimately proposed by transmission organizations have certain properties that are fundamental to meeting the objectives of section 217(b)(4) of the FPA. Nonetheless, the NOPR stated our intent that the guidelines form only a framework for further, more specific development of long-term firm transmission right designs through the usual stakeholder process of each transmission organization, and noted that the guidelines should provide enough flexibility to allow transmission organizations and their stakeholders to develop a specific long-term firm transmission right design that fits the prevailing market design and meets the needs of market participants in that region.

121. Finally, we noted the potential that this flexible regional approach could lead to regional seams issues, and sought comments on any features of long-term firm transmission rights that, if not consistent across transmission organizations, could interfere with the effective operation of regional markets.

122. Comments

123. Several commenters, including Industrial Consumers, Kentucky PSC, LADWP, LIPA, Midwest ISO, MSATs, NARUC, National Grid, NYDPS, NYISO, PJM, Public Power Council, SoCal Edison, and Wisconsin Electric all support the Commission’s proposal to develop guidelines, as opposed to specific long-term firm transmission rights designs, to allow for regional flexibility. Many of these commenters argue that regional flexibility is essential, given that each transmission organization has developed its own market design to meet the needs of its stakeholders and to accommodate regional differences (including different operating practices). They contend that regional flexibility is also necessary to honor the transitions already agreed to by transmission organization stakeholders.

124. While the commenters were virtually unanimous that a “one-size fits all” approach to implementing long-term firm transmission rights would not be appropriate, the comments raise issues regarding the amount of flexibility that the Commission should provide. Some commenters, including Dominion, EEI, ISO-NE, and NSTAR argue for more flexibility, including flexibility within the requirements of each guideline. For example, EEI states that the Commission should issue only “basic principles” that focus on “reasonable outcomes,” and should treat the guidelines as “a general direction for future action” instead of imposing them as prescriptive requirements.⁵¹ EEI also suggests that the Commission alter the general direction under section (d) of the proposed regulations to provide that “[t]ransmission organizations . . . should to the extent they find reasonable given their existing arrangements make available long-term transmission rights that satisfy the following guidelines.”⁵² Further, EEI contends that no single guideline can or should be mandatory, and that transmission organizations and their stakeholders should be given the first opportunity to balance the guidelines to best meet market participant needs. ISO-NE argues that section 217(b)(4) permits substantial flexibility, since it does not require several design features (including creating a “perfect hedge” for load serving entities, a particular length of term, or a priority mechanism.) New York Transmission Owners argue that the Commission should clarify that the guidelines are not binding or mandatory obligations, and that they do not predetermine any particular result or design for long-term firm transmission rights.

125. Some commenters in New England and New York, including NU and Coral Power, note that there has not been great demand for long-term firm transmission rights in those regions. Accordingly, NU argues that the Commission should allow regional flexibility in determining the extent to which such rights are needed.⁵³ In reply, New England Public Systems assert that the clear statutory directive makes arguments regarding the lack of interest in long-term rights or the lack of need for such rights irrelevant.⁵⁴

126. NSTAR states more generally that imposing a Final Rule on long-term firm transmission rights that is inconsistent with the structure of a transmission organization market, particularly a well-developed market reflecting an extensive history of market operations, would be “disruptive and counter-productive.”⁵⁵ Accordingly, NSTAR advocates that the Final Rule allow the greatest latitude possible to stakeholders in established transmission organization markets to develop rules for long-term firm transmission rights. It argues that section 217(c) of the FPA (stating that subsections (b)(1), (b)(2) and (b)(3) do not affect existing or future transmission right allocation methodologies) recognizes the historical practices followed by transmission organizations and permits the Commission to defer to such practices, even if they are deemed to differ from practices embodied in subsections (b)(1) through (b)(3) of section 217.⁵⁶

127. Reliant states that the Commission should recognize ongoing stakeholder-driven efforts in several existing transmission organizations to develop long-term firm transmission rights, and provide sufficient leeway for such markets to provide access to long-term rights.

128. BPA states that in general it supports the Commission’s flexible approach, and states that the Commission should allow sufficient flexibility so as not to preclude formation of transmission organizations with regionally-developed characteristics, such as the developing proposals in the Northwest.⁵⁷ It argues that the Final Rule should address how the guidelines will apply to transmission organizations in the process of forming organized electricity markets.

129. Midwest ISO states that the Commission should consider the detrimental effect some of the proposed guidelines could have on Midwest ISO market participants and should ensure that the terms it ultimately adopts allow sufficient flexibility to ensure that they can work in the Midwest ISO markets.

130. Others, including APPA, New England Public Systems and TAPS, argue that regional flexibility should not be offered too broadly. They assert that the Commission should make clear that the Final Rule gives regions the flexibility to decide how to implement long-term rights, but not the flexibility to decide whether to implement them at all. NRECA also supports some regional flexibility, but states that there must be adequate minimum guidelines to ensure that the objectives of section 217 of the FPA are met. APPA and TAPS both assert that the Commission explicitly require transmission organizations to fully comply with the provisions of the Final Rule, and also suggest that the Commission consider renaming the guidelines “requirements” or “standards” to ensure that there is no implication that the guidelines are only advisory and may be disregarded. Similarly, PG&E, while also supportive of the Commission’s approach, recommends that the Commission further require transmission organizations “to fulfill the guidelines of the ultimate rule to the maximum extent compatible with the realities of their market and legal environment.”⁵⁸

131. Some commenters, including Midwest TDUs and Industrial Consumers, express concern that the use of stakeholder procedures will not result in the development of long-term firm transmission rights that satisfy the intent of the Commission and Congress. Midwest TDUs express concern that “the stakeholder process will be used to eviscerate long-term rights” given the Midwest ISO’s “evident resistance to long-term rights” and the opposition of some Midwest ISO stakeholders.⁵⁹ They state further that “[i]mplementation of these Congressionally-mandated rights in a manner that achieves their crucial purpose cannot depend on TDUs’ ability to overcome Midwest ISO’s resistance or out-vote other stakeholders.”⁶⁰ Industrial Consumers state that they and other industrial and customer groups have had concerns that some transmission organization stakeholder processes do not have the proper balance to guard against one side of the market gaining an upper hand over the other. Accordingly, Industrial Consumers recommend that the Commission provide guidance to ensure that the stakeholder processes used to develop long-term firm transmission rights will include a balanced composition of stakeholders, and require each compliance filing to include a statement by the transmission organization that the stakeholder process was fair and impartial and did not discriminate against load and load serving entities.

132. With regard to the potential for the Commission’s flexible approach to create regional seams issues, comments address both the potential for seams between transmission organizations and between transmission organization regions and non-transmission organization regions. Some commenters, including APPA and PG&E, note that different term lengths for long-term firm transmission rights and different processes for the allocation of long-term rights (including different timetables) are two areas where seams could arise. TAPS states that the Commission should require transmission organizations to provide a mechanism that allows load serving entities to obtain long-term transmission rights that cross seams and ensure that those rights continue if new or different seams emerge, and should require transmission organizations to coordinate their schedules for allocating long-term rights that cross seams. BPA also notes the possibility that a load serving obligation might be met with a resource outside the transmission organization, and states that in such situations “the transmission organization should continue to provide long-term transmission service for such deliveries under existing and renewed transmission contracts.”⁶¹

133. TAPS and Wisconsin Electric express specific concerns regarding the potential for seams to develop between Midwest ISO and PJM. TAPS contends that the Commission should require close coordination between Midwest ISO and PJM with regard to the definition of long-term firm transmission rights and the process for obtaining such rights, arguing that a load serving entity should be able to obtain rights crossing the border on a consistent timeline (ideally through a single process) to support a commitment to baseload resources needed in both transmission organization regions. Wisconsin Electric argues that there must be consistency between the two regions with regard to the allocation of long-term firm transmission rights to ensure that a “financial wall” does not develop, which would inhibit the ability to flow energy under long-term contracts between the regions.

134. MidAmerican states that the Commission should require compliance filings to address resulting seams and how they will be resolved. MidAmerican, as well as NARUC, also note that these issues can and should be addressed in the Joint Operating Agreements and Seams Operating Agreements between transmission organizations. NARUC urges the Commission to clarify that tariff provisions designed to award long-term transmission rights will not adversely impact these seams agreements, and clarify that long-term rights granted within a transmission organization will not confer rights on the holder outside that market. According to NARUC, these clarifications are necessary to ensure that costs for upgrades or expansions are not transferred between transmission organizations or a transmission organization and non-transmission organization utility and to ensure that transmission rights in other regions are not adversely impacted.

135. Comments also generally addressed seams that might arise between transmission organizations and non-transmission organization regions. APPA, for example, notes that non-transmission organization regions use physical rights, and as a result financial and physical rights must coexist to ensure that future power supply and transmission service arrangements are not adversely impacted. CMUA states that because CAISO operates a market based on financial rights, while the rest of the Western Interconnection consists of bilateral markets with physical rights, any regional stakeholder process to develop long-term firm transmission rights in CAISO should include the Western Electricity Coordinating Council (WECC), neighboring control areas and relevant transmission owners in the West.⁶²

136. Commission Conclusion

137. In this Final Rule, the Commission adopts the guidelines approach and the allowance for regional flexibility set forth in the NOPR. This approach will appropriately recognize regional differences in market design, while ensuring that long-term firm transmission rights have certain properties that are fundamental to satisfying the mandate of Congress in section 217(b)(4).

138. In response to comments seeking additional flexibility, we emphasize that we are adopting the guidelines approach to ensure that transmission organizations have the flexibility to design long-term firm transmission rights that fit their prevailing market design. This flexibility is not intended and should not be interpreted to allow transmission organizations the latitude to decide whether long-term firm transmission rights should be implemented at all. Congress has directed in both section 217(b)(4) of the FPA and section 1233(b) of EPAct 2005 that load serving entities have the ability to obtain long-term firm transmission rights to meet their reasonable needs to satisfy their service obligations. Congress also specifically directed that such rights be implemented in the transmission organizations with organized electricity markets, through section 1233(b)’s charge that the Commission implement section 217(b)(4) within one year in those regions. As a result, the implementation of long-term firm transmission rights by transmission organizations with organized electricity markets is mandatory.

139. We reject comments suggesting that the guidelines be treated as merely general directives. As noted above, the guidelines are intended to ensure that long-term firm transmission rights have certain properties we believe are necessary to fulfill Congress’ directives. Particularly, the guidelines are designed to ensure that the long-term firm transmission rights are truly “long-term” and “firm,” and that they can be used to deliver the output of long-term power supply arrangements to load serving entities, as section 217(b)(4) requires. As a result, transmission organizations must satisfy each of the guidelines when complying with the Final Rule. We have modified the proposed regulatory text to clarify this requirement.

140. With regard to flexibility within each guideline, the Commission believes that each of the guidelines already provides sufficient flexibility to allow transmission organizations to satisfy them in a manner that fits their individual market design. Each of the guidelines state basic, fundamental properties that long-term firm transmission rights must possess, but are not prescriptive market design mandates. Thus, while proposals to comply with this Final Rule must satisfy each of the guidelines, we believe each of the guidelines may be satisfied in any number of ways, and we do not intend that the guidelines predetermine any particular design.

141. In response to comments suggesting that there has been little demand for long-term firm transmission rights in New York and New England, we note that we agree with New England Public Systems that regardless of the level of interest in such rights, Congress has mandated that they be available to meet load serving entities reasonable needs. Thus, while we are adopting a flexible approach, that flexibility does not extend to deciding whether such rights are needed, as NU suggests it should. The fact that only a few stakeholders in a particular region seek long-term firm transmission rights can be a design consideration, however, as we discuss in more detail elsewhere in this Final Rule.

142. BPA asks that the Commission address how the guidelines will apply to transmission organizations with organized electricity markets that are being developed, and asks that we retain sufficient flexibility so that regional efforts to develop a transmission organization in the Northwest are not precluded. As we state above, we conclude that the guidelines approach in the Final Rule provides enough flexibility to ensure that long-term rights can be developed with regional characteristics while still meeting the statutory objectives of section 217(b)(4). Entities in the process of forming transmission organizations should take into account the requirements of this Final Rule and how the market designs they file will satisfy the rule.

143. In response to the comments of Industrial Consumers and Midwest TDUs regarding the use of stakeholder procedures to develop specific long-term firm transmission rights proposals, we do not believe it is necessary to specifically direct that any particular stakeholder procedures be used. Transmission organizations have Commission-approved procedures in place that specify the stakeholder process and conditions and criteria by which they may file proposals with the Commission. Comments suggesting that such procedures are flawed are outside the scope of this proceeding.

144. Regarding the potential for regional seams, the comments indicate that seams are most likely to develop where the terms of long-term rights and the procedures (including timelines) for allocating such rights are not sufficiently coordinated. We agree with commenters that transmission organizations should consider these issues when complying with the Final Rule. Additionally, we agree that revising the already existing seams agreements between transmission organizations, if necessary, could be one vehicle to address seams issues related to long-term rights that arise between transmission organizations. Accordingly, we direct each transmission organization to explain in its compliance filing how its proposal addresses potential seams issues, particularly with regard to the term of the long-term rights offered and the procedures and timelines for obtaining such rights. With regard to potential seams between transmission organizations, each transmission organization should also explain why it has or has not elected to revise its seams agreements.

145. E. Guidelines for the Design and Administration of Long-Term Firm Transmission Rights in Organized Electricity Markets

146. Guideline (1) – Specify Source, Sink and Quantity

147. As proposed in the NOPR, guideline (1) stated that the long-term firm transmission right should be a point-to-point right that specifies a source (injection node or nodes) and sink (withdrawal node or nodes), and a quantity (MW). The discussion of this guideline pointed out that flowgate rights were not precluded from consideration as long as they could hedge a point-to-point transmission schedule.

148. Comments

149. Guideline (1) is generally supported by commenters. Most commenters recognize that current transmission organization market designs for specifying and allocating transmission rights largely adopt the source point and sink point requirements of guideline (1). But there are exceptions. In particular, some commenters note that ISO-NE does not allocate auction revenue rights on a point-to-point basis.

150. Flexibility in Source and Sink Designation

151. Several commenters request that guideline (1) explicitly recognize nodal aggregations, such as zones or hubs, as sources and sinks.⁶³ ISO–NE notes that spot market purchases by load are priced on a zonal basis in its system and that allocation of zone-to-zone long-term transmission rights would be more desirable than allocation of point-to-point rights. PJM Public Power Coalition, Public Power Council and Strategic Energy request that guideline (1) should not be interpreted to require that long-term rights are tied to specific generation resources, but rather to points or aggregates on the transmission system. Several commenters note that the boundary nodes can serve as sources or sinks.

152. Other source/sink designation issues pertaining to guideline (1) were raised by commenters that are, or will be, transmission customers but that are located outside the transmission organization markets. SMUD stresses that in California, long-term rights must be developed for transmission customers that use through and out service. SMUD argues that the Commission should require that allocation criteria for long-term rights will not be dependent upon where load is located, but rather on whether, by its use of the system, the customer will make substantial contribution to recovery of the transmission system’s fixed costs.

153. Consistency of Current Market Rules with Guideline 1

154. Some commenters state that the current rules for allocating ARRs and auctioning FTRs in ISO-NE are not consistent with guideline (1) in combination with guideline (7). New England Public Systems notes that under the ISO-NE market rules, most ARRs are allocated among congestion-paying load serving entities on a zonal load ratio share basis. Each such load serving entity is paid the auction clearing price of an average FTR in the zone times the ratio of its peak load to the zonal peak load. This rule does not offer assurance that the revenues received will be sufficient to enable the load serving entity to acquire a specific point-to-point FTR across a particular congested path. New England Public Systems thus requests that the Commission confirm that in New England, FTRs awarded under the current rules cannot simply be extended in term. Instead, under guidelines (1) and (7), ISO-NE should provide either the allocation of point-to-point long-term transmission rights or point-to-point long-term ARRs that can be converted to long-term transmission rights.

155. Other Issues

156. CMUA, NRECA and SMUD argue that guideline (1) should be modified and clarified so that it does not rule out long-term rights with properties of Order No. 888 network service rights for network transmission customers. In particular, these commenters argue that long-term firm transmission rights should afford the customer the flexibility to change receipt and delivery points without penalty. In contrast, Cinergy argues that long-term rights should not be allowed to have characteristics of Order No. 888 network rights.

157. CMUA and SMUD request that guideline (1) not limit the ability of transmission organizations to consider other types of rights that meet the commercial needs of load serving entities. In particular, they discuss contractual rights that are “bidirectional” in nature to support seasonal power supply arrangements in the West and for which they propose option transmission rights in each direction of the transaction.

158. There were several miscellaneous comments on guideline (1). PJM states that the Final Rule would benefit from clarification that there are no requirements with respect to the nature of the right – i.e., physical versus financial – and explicitly state that this issue will be determined by the regions. We address this issue in Section II.F, “Alternative Designs for Long-Term Firm Transmission Rights.” APPA requests that as part of compliance with guideline (1), each transmission organization should be required to establish rules that prevent gaming of the long-term rights allocation by swapping of generation resources. This issue was raised by several other parties in conjunction with guideline (5) and we address it there.

159. Commission Conclusion

160. We will adopt guideline (1) without modification. The primary objective of guideline (1), consistent with section 217(b)(4), is to allow a load serving entity to obtain a long-term firm transmission right for purposes of hedging congestion charges associated with delivery of power from a long-term power supply arrangement to its load. Moreover, as several commenters noted, guideline (1) is largely consistent with existing designs for FTRs in the organized electricity markets operated by transmission organizations.

161. Flexibility in Source and Sink Designation

162. We clarify that guideline (1) permits specification of long-term firm transmission rights to hedge zonal or hub pricing where, for example, congestion prices are calculated using a weighted average of the locational marginal prices within a zone. Guideline (1) also permits specification of long-term transmission rights from points on the network, such as boundary locations, that are not the locations of specific generators. For customers with through and out service, we would expect that transmission organizations will establish long-term firm transmission rights corresponding to the terms and conditions of existing transmission contracts. However, if quantity limits are established for the allocation of long-term firm transmission rights, then rules may be needed to determine the eligibility of through and out service, based, for example, on historical usage patterns.

163. Consistency of Current Market Rules with Guideline (1)

164. Based on the comments, only ISO-NE has adopted a financial rights model for transmission rights that does not directly allocate rights that are point-to-point to eligible market participants. We will require ISO-NE to adopt rules for allocation of long-term firm transmission rights that are consistent with guidelines (1) and (7). However, as discussed below, we note that ISO-NE does not have to provide the same allocation rules for short-term rights as it does for long-term rights.

165. We understand that in some organized electricity markets, particularly in regions with substantial divestiture of generation capacity and retail choice such as that of ISO-NE, hedging particular generation resources with financial transmission rights is not the prevailing approach; rather, buyers and sellers have adopted portfolio approaches to power supply contracts and hold financial transmission rights based on their expected revenues from congested transmission paths rather than on their ability to hedge specific resources. We do not intend for this Final Rule to obstruct that business model, but note that other entities in these regions are not following such a business model. As a result, they seek transmission rights that hedge congestion charges associated with delivering power from particular generators to their load. Guideline (1) is intended to support the ability of load serving entities to obtain point-to-point long-term transmission rights that will hedge particular long-term power supply arrangements. Guideline (7) is intended to support the ability of load serving entities to obtain such rights without having to purchase the rights in an auction. We will thus require all transmission organizations to offer long-term firm transmission rights that are consistent with these guidelines. This is not to say that transmission organizations like ISO-NE must adopt new allocation rules and apply them for both short-term rights and long-term rights. To the extent that a transmission organization can satisfy requests for long-term firm transmission rights under these guidelines, but stakeholders prefer remaining with existing rules for short-term rights, we will consider proposals that use such a “two-track” approach. At the same time, as we discuss in guideline (2), there might be advantages to harmonizing at least some rules between short-term and long-term rights to ensure that the rules encourage efficient nominations and equitable allocations.

166. Other Issues

167. We will not modify guideline (1) to require allocation of long-term transmission rights with properties of Order No. 888 network service, as requested by NRECA and SMUD. In general, we have not precluded any design that stakeholders could agree on, but we do require that designs support equitable allocation of transmission rights (see discussion in Section II.F, “Alternative Designs for Long-Term Firm Transmission Rights”). The right to change receipt and delivery points without penalty could, under most rules for allocation of financial transmission rights, deprive other load serving entities of their eligible rights.⁶⁴ Hence, the rules in organized electricity markets generally require parties that are converting Order 888 network rights to financial rights to select a fixed distribution of source points for their total MW eligibility over their network resources.

168. We will not modify guideline (1) to explicitly support “bidirectional” transmission rights. CMUA defines such rights as “option” rights in either direction. We discuss the difficulties in allocating option rights equitably in Section II.F, “Alternative Designs for Long-Term Firm Transmission Rights.” There are other solutions. Sufficient granularity of the transmission rights specified as obligation rights would allow the rights to better track the power flows in contractual arrangements. Guideline (1) also does not preclude flowgate rights, which have option properties. All of these approaches, and possibly others, could be used to address situations where power flows change direction on a regular basis.

169. Guideline (2) - Long-Term Hedge That Cannot Be Modified

170. As proposed in the NOPR, guideline (2) stated that the long-term firm transmission right must provide a hedge against locational marginal pricing congestion charges (or other direct assignment of congestion costs) for the period covered and quantity specified. Once allocated, the financial coverage provided by the right should not be modified during its term except in the case of extraordinary circumstances or through voluntary agreement of both the holder of the right and the transmission organization. We refer to the provision that the payments from the rights should not be prorationed (with the exceptions as mentioned) as “full funding.”

171. The NOPR sought comments on how to fully fund the long-term rights. Since the transmission organization is revenue neutral, fully funding the rights requires that a revenue shortfall is collected from some set of market participants to make holders of the rights whole. The NOPR asked whether such charges should be allocated to transmission owners that are responsible for maintaining and expanding the transmission capacity supporting the long-term firm transmission rights when the revenue shortfalls are due to inadequate maintenance or expansion. The NOPR further asked for comment on whether there are appropriate methods for allocating such charges that also provide appropriate incentives for transmission usage, maintenance and expansion. The NOPR also noted that payments to already awarded long-term rights may be pro-rationed in the case of extraordinary circumstances, such as a sustained unplanned outage of a large transmission line. Such situations may require alternative rules for financial settlement of the rights.

172. Comments

173. Guideline (2) drew strongly opposing views with regard to full funding for the term of the long-term transmission right and the question of who should pay to support full funding. Some commenters opposed full funding, arguing that it is not a viable option. Those who held this view also typically argued that full funding should be an option to be determined on a regional basis, and should not be mandated by the Commission. Other commenters strongly supported full funding. Among the latter commenters, and among those that opposed full funding but recognized that the Commission may nevertheless require it, there was significant disagreement over the set of market participants that should pay to provide the full funding guarantee and under what conditions. In particular, transmission owners were strongly against the proposal that they should provide a “backstop” to support full funding and rejected arguments that such a rule would have a positive incentive effect on transmission maintenance and investment.

174. There was general support for the proposal that extraordinary circumstances may result in a suspension of full funding, but several commenters requested clarification on what constitutes such circumstances.

177. Full Funding: Criticisms and Alternative Proposals

178. Several commenters oppose the proposed full funding requirement.⁶⁵ OMS and Midwest ISO state that full funding is inequitable, would cause significant cost shifting between market participants, and is beyond the scope of section 217(b)(4). Midwest ISO argues that requiring a “perfect” hedge clearly exceeds a load serving entity’s “reasonable” needs. Moreover, cost shifting would take place because, if entities eligible for long-term firm transmission rights have priority in the allocation of transmission rights (as proposed in guideline (5) in the NOPR), they may limit the quantity of short-term rights available. Further, Midwest ISO is concerned that other parties may have to pick up revenue shortfalls associated with the long-term rights.

179. EEI, IPL, Midwest ISO, MSATs and OMS argue that full funding is a higher level of certainty for transmission rights than was available historically. Outside the organized markets, firm point-to-point and network transmission service have never been fully guaranteed. Rather, they have always been subject to potential curtailment through TLRs. They have also been subject to rate increases and redispatch costs. EEI argues that a long-term right that strives to provide a “perfect hedge” would be too expensive and that the Commission should instead aim for balance in the protection offered. IPL argues that section 217(b)(4) does not mandate a zero-risk solution for load serving entities, but rather to address their reasonable needs. IPL suggests that the Commission interpret what properties of financial transmission rights would provide reasonable risk mitigation equivalent to firm transmission rights under the OATT.

180. TAPS replies to such arguments by noting that it is seeking full funding only for long-term firm transmission rights used to deliver the output of baseload resources. Hence, for the remaining transmission usage, the holder would be exposed to uncertainty over the allocation of rights and hence congestion cost exposure.

181. Midwest ISO argues that full funding is not always necessary to provide a full hedge. This is because the revenues from point-to-point FTRs used to hedge congestion charges associated with a particular resource or portfolio of resources can be either greater than or less than the congestion charges paid by transmission customers.

182. CAISO argues that each transmission organization should be allowed to determine the rules for revenue sufficiency of financial transmission rights in a manner that best weighs the equities in each regional market. Similarly, CPUC is concerned that establishing a long-term revenue guarantee at the start of the CAISO’s LMP markets will “tie the hands” of the CAISO if it needs to adjust the market design to improve implementation.

183. ISO-NE, which does not currently fully fund transmission rights, emphasizes the difficulty of assigning funding responsibility. ISO-NE urges the Commission to conserve stakeholder, transmission organization and Commission resources by not creating new sources of conflict in a region.

184. AEP argues that by creating fully funded long-term rights, guideline (2) does not provide flexibility to recognize system changes over the long-term. Similarly, IPL states that locking in rights shifts risks between parties rather than mitigating risk and may create greater risks over time. The transmission organization should be allowed to pre-define methodologies to adapt the rights to changing circumstances.

185. A number of commenters argue that full funding could provide disincentives for investment in transmission. For example, AEP argues that when doing proper planning and with the right incentives, the transmission organization must be continuously revising its forecasts of transmission and generation availability (e.g., additions and retirements) to meet load growth. This will change the electrical configuration of the grid. By fixing transmission rights over the long-term with the full funding revenue requirements, the transmission organization could inhibit construction of new facilities that would provide greater benefits to customers.

186. Xcel argues that providing full funding in the event of a long-term change in grid capability could result in a perpetuation of windfall revenues or severe losses for holders of transmission rights and unjust socialization of those costs across the industry.

187. AF&PA believes that guideline (2) may be extremely difficult to implement in a nondiscriminatory fashion because of valuation issues associated with estimates of congestion cost for extended periods.

188. As an alternative to full funding, several commenters argue that in the event of revenue shortfalls, pro-rationing of payments should be the rule for long-term rights (as it is currently for annual FTRs in organized markets other than NYISO). NU argues that treating long-term rights differently from short-term rights would be discriminatory. Reliant argues that any prorationing of transmission rights payments due to revenue shortfalls should be allocated on a MW by MW basis to all transmission rights regardless of their terms. Beyond this principle, the Commission should let regional approaches determine the details. Cinergy and SoCal Edison state that in the event of revenue shortfalls, payments to holders of long-term rights should be rationed on a pro-rata basis. SoCal Edison argues that holders of long-term rights should factor the risk of revenue pro-rationing into the prices that they pay to procure those rights and into their long-term energy and capacity contracts.

189. In light of these concerns, a number of commenters argue, for various reasons, that the Commission should not mandate full funding, but rather leave it to regions to determine whether or not to pursue full funding.⁶⁶

190. MSATs propose that full funding could be a voluntary insurance made available by third-party providers for an insurance premium. MSATs request that this option be considered in the Final Rule.

191. OMS argues that the full funding guarantee for long-term rights will make such rights more valuable relative to annual rights, assuming that the latter remain subject to pro-rationing. OMS argues that there could be two possible consequences: first, transmission organizations will be extremely conservative in the quantity of long-term rights that they allocate, and second, there will be a significant reduction in rights available for the annual allocation. Load serving entities will seek long-term rights and if the transmission organization cannot honor all requests, significant cost shifts will result. Hence, OMS proposes that fully funded long-term rights should be assessed a risk premium.

192. Ameren argues that rather than attempt to address the issue of revenue insufficiency through full funding guarantees, the solution is to address flaws in the transmission organization’s simultaneous feasibility model. Ameren argues that if the modeling was more accurate, the allocation of financial transmission rights would be less likely to become revenue inadequate and uplift would be minimized. Ameren prefers that any remaining uplift associated with transmission rights should be assigned pro rata over all financial transmission rights holders.

193. Full Funding: Support and Clarification

194. A number of commenters are supportive of full funding of long-term rights.⁶⁷ However, there were differences in the scope of coverage that they proposed and how the costs of full funding would be allocated.

195. NYISO states that it is already in compliance with guideline (2) because its financial transmission rights (Transmission Congestion Contracts) are already fully funded, with transmission owners paying any revenue shortfalls. However, New York Transmission Owners argue that the transmission rights allocated in New York to support native load are not currently consistent with guideline (2) because they are allocated annually and the quantities may not be the same each year. To fix the quantities from year to year, they argue that NYISO would presumably have either to reduce the quantity allocated, create counterflow rights, or eliminate the simultaneous feasibility test, all of which could create congestion rent shortfalls in the day-ahead market. New York Transmission Owners argue that each of these choices is “unpalatable” and would upset the result of negotiations among them that led to the current allocation methodology. Hence, they argue that it is critical that the Commission ensure that NYISO and stakeholders have flexibility in the development of the rules for long-term rights.

196. TAPS argues that the full funding guarantee would place the burden on the transmission organizations to be accountable for the performance of the transmission rights that they allocate. TAPS further argues that to provide true certainty, guideline (2) should be paired with “requirements that (1) the full cost associated with securing long-term rights (and applicable renewals) be established with reasonable certainty up front; and (2) RTOs broadly allocate responsibility for funding revenue shortfalls for long-term rights consistent with guideline (2)’s price stability goal.”⁶⁸

197. New England Public Systems argue that full funding is consistent with the underlying principles of Order No. 888 and with section 217(b)(4). Under Order No. 888, holders of transmission contracts have the right to renew service when contracts expire, and transmission providers are required to plan and expand facilities to meet transmission customer needs. Transmission providers also bear redispatch costs, which provided a further incentive to expand transmission capacity to accommodate known or predictable uses. APPA similarly argues that full funding is consistent with section 217(b)(4). This is because that requirement is intended to provide financial certainty over the transmission component of the “all in” cost of a long-term generation resource.

198. A number of commenters, including TAPS, Public Power Coalition and Wisconsin Electric, propose that long-term rights should be allocated for a limited quantity of load serving entities’ load, specifically base-load. A few commenters, such as TAPS, also include rights to renewable generation resources. Hence, full funding would only extend to that quantity of rights. PJM agrees that a limited application of full funding is feasible.

199. A number of parties note that full funding will require a consistent approach to transmission planning and expansion to minimize the potential for cost shifting. We address the relationship of long-term firm transmission rights and transmission planning and expansion in Section II.E, “Transmission Planning and Expansion.”

200. BPA suggests that while locational marginal pricing may not be the congestion pricing model adopted in the Pacific Northwest, the principles underlying guideline (2) should be upheld. BPA argues that cost stability for long-term transmission should prevail over concerns about equity and fairness of the allocation of long-term rights and associated costs among market participants.

201. Full Funding Cost Allocation

202. On the proper allocation of responsibility for revenue shortfalls, several commenters supporting full funding argue that some or all of the revenue shortfalls encountered by long-term rights should be funded by transmission owners. Industrial Consumers argues that transmission organizations cannot manage risks associated with financial transmission rights, and that such risks can only be managed by transmission owners.

203. A few commenters that support the assignment of full funding uplift to transmission owners argue for limits on the obligations of transmission owners. PJM Public Power Coalition states that transmission owners should be held accountable for inadequate maintenance practices or poor system planning and any resulting long-term rights funding shortfall should be assigned to them. Similarly, BP Energy argues that revenue shortfalls should be assigned to transmission owners only if they are due to negligence. NRECA and TAPS argue that the assignment of revenue shortfalls to transmission owners is appropriate only if the transmission owner fails to fulfill in good faith the transmission organization’s instruction to plan and construct transmission facilities. Absent that situation, TAPS argues that funding responsibility should be broadly shared by all users of the transmission grid on a pro rata basis, since the failure is the transmission organization’s failure to plan and expand the system.

204. Most transmission owning utilities and some other commenters argue that transmission owners should not be required to fully fund long-term rights (under most circumstances).⁶⁹ First, several of these commenters note that when a transmission owner joins a transmission organization, it cedes short-term control (e.g., redispatch) of the transmission system, and as a result cannot manage any parties’ exposure to congestion charges. Second, in the planning process, it is the transmission organization that must undertake the planning for upgrades and approve new transmission facilities to reduce congestion. Third, decisions of siting authorities and input of stakeholders significantly affect location of new facilities and when they are brought on-line. Fourth, due to the nature of power flows in a large regional transmission organization, it may be difficult to determine exactly which transmission owners are responsible for changes in transmission capability. Fifth, just as important to revenue adequacy as building new facilities is the design of the transmission rights and the modeling used in their allocation. Under most transmission organization rules, transmission owners cannot directly reduce the quantity of rights that are allocated or auctioned to manage their exposure to full funding uplift charges (although some commenters note that guideline (2) may create an incentive for the transmission owner to do so indirectly by providing the transmission organization with conservative ratings for transmission facilities). Moreover, transmission organizations control the development and implementation of the models that underlie FTR allocation. Sixth, transmission transfer capability is often affected by factors outside the transmission owners’ and transmission organization’s control, such as loop flow. Seventh, transmission owners would need the ability to raise transmission rates to cover funding obligations, through FERC and/or state commissions. IPL notes that since a proposed transmission facility (required for purposes of transmission rights held by others) may have limited local benefits, state approvals may be difficult to obtain.⁷⁰ Finally, IPL and PG&E argue that requiring transmission owners to fully fund long-term rights would serve as an incentive for transmission owners to leave transmission organizations.

205. IPL and Reliant argue that the Commission should not attempt to use the revenue sufficiency rules for long-term rights as an incentive for transmission investment, which is better addressed through separate incentives.⁷¹ MSATs argue that the Commission cannot shift costs to transmission owners “based solely on the mere theory that doing so might create some potentially worthwhile incentives.”⁷² MSATs argue that those supporting making transmission owners the “backstop” funders of long-term rights have failed to provide a “sustainable justification” for such a requirement.⁷³ Ameren argues that second guessing transmission owners’ business decisions after a transmission outage or bottleneck would only distract attention and effort from planning, funding and designing needed expansions and repairs. For the reasons stated above, IPL and PG&E state that assigning full funding to transmission owners is arbitrary and unreasonable because it not consistent with cost causation principles.

206. MSATs note that transmission owners that are transcos (firms that own regulated transmission assets only) would be particularly problematic because such firms do not hold FTRs. MSATs ask that the Commission recognize that such a requirement would directly conflict with the transco business model for two primary reasons. First, transcos are neither transmission customers nor market participants. Hence, requiring transcos to take a position in the transmission rights markets would be inconsistent with their business model. It would also be inequitable to transcos. Second, transcos rely on a revenue stream that is far more concentrated than that of a vertically integrated utility. MSATs claim that the liability associated with underfunded transmission rights could exceed a transco’s total transmission service-dependent revenue in some cases.

207. Allegheny argues that while it can support full funding, the transmission organization should be responsible for providing full funding through its transmission customers. Allegheny recommends that this charge be assessed on all long-term firm and network transmission customers. In a similar vein, PG&E argues that while full funding is desirable, it should be allocated to transmission organization customers, who benefit from long-term investment in energy infrastructure.

208. Several commenters propose that only the holders of long-term transmission rights be collectively allocated the costs of any revenue inadequacy associated with the rights.⁷⁴ For example, Duquesne recommends that holders of transmission rights be allocated any costs associated with deficiencies in transmission revenues, because these parties benefit from the transmission rights markets. IPL argues that pro rata sharing of funding shortfalls by all load serving entities with long-term rights is the only reasonable approach in the absence of a clear cost-causation relationship.

209. Midwest ISO proposes that to the extent that market participants should be responsible for long-term rights revenue shortfalls, a mechanism to ensure such cost recovery should be made part of “economic” transmission upgrades. Economic upgrades should be defined to include those required to maintain FTR feasibility based on a cost- benefit analysis. In contrast, APPA argues that the transmission planning process should take account of long-term rights and designate transmission facilities to maintain the feasibility of the rights as “reliability” upgrades.

210. TAPS argues that assignment of revenue shortfalls to holders of long-term rights would be the equivalent of pro-rationing the rights. Similarly, in its reply comments, APPA argues that holders of long-term rights should not be assigned funding shortfalls due to the failure of the transmission organization to plan for and ensure construction of necessary transmission facilities. APPA also notes that holders of long-term rights that are not transmission owners are least able to ensure that the transmission system can support them.

211. A number of parties express concern that funding of transmission rights may not be equitable between long-term and short-term rights.⁷⁵ CAISO argues that when considering rules for revenue inadequacy, long-term rights should not have elevated status over short-term rights. They maintain that even holders of long-term rights will typically hold some level of short-term rights. In parts of the West, where patterns of supply have a great deal of annual variability, giving longer-term rights preferential status will be inequitable with respect to the holders of short-term rights.

212. Cinergy, Midwest ISO and Suez are concerned that the funding guarantees in guideline (2) will shift costs from long-term contract holders to short-term contract holders. They argue that such cost-shifting will be unduly discriminatory and preferential and violate the Federal Power Act. Reliant agrees that cost-shifting will occur and proposes that the Commission provide a forum for discussion of “best practices” to maximize the availability of short-term and long-term rights to all customers.

213. In reply, APPA argues that because long-term firm transmission rights support long-term power supply arrangements, and the holders of such rights would be committed to paying a share of transmission fixed costs over the period of the rights, there is a legal and policy rationale for giving long-term rights more protection from proration or revenue insufficiency than holders of short-term rights.

214. Definition of Extraordinary Circumstances

215. Several commenters supported generally the inclusion of the exception to full funding under “extraordinary circumstances.”⁷⁶ No commenters argued against such an exception, although several asked for clarification. ISO-NE encourages the Commission to clarify the definition of “extraordinary circumstances” that would permit modification of the financial coverage provided by long-term transmission rights.

216. TAPS asks that the definition of “extraordinary circumstances” be clarified such that it is only applied in the event of a catastrophic regional problem such as a widespread blackout or a massive force majeure event. TAPS argues that the example in the NOPR of a sustained unplanned outage of a large transmission line is “precisely the type of situation when an LSE should not be stripped of its long-term rights.”⁷⁷ TAPS argues that in the event of a sustained line outage, long-term rights should remain fully funded and the shortfall uplifted, for example, on a load ratio basis. Similarly, APPA argues that the suspension of full funding should take place only if the situation should be “truly extraordinary” and not a contingency that should have been anticipated in routine transmission planning.

217. NRECA is concerned that the exception for “extraordinary circumstances” will undermine the certainty that guideline (2) is supposed to confer. NRECA requests that the Commission clarify when this exception would apply or remove it from the guideline.

Other Issues

218. BP energy argues that the full funding rule could result in market gaming in the event of a transmission outage. BP Energy suggests that the Commission consider the methodology to limit gaming adopted by ERCOT and the Texas PUC. When there is a revenue insufficiency, ERCOT limits the payment on an oversold FTR to its “legitimate hedge” value as established by substituting the resource’s marginal cost for the LMP at the source (generation) node of the FTR. Any remaining revenue shortfall is uplifted to all FTR holders.

219. Proposed Revisions of Guideline 2

220. Several commenters propose revisions to guideline (2). EEI proposes to revise the guideline to state that the rights are financial, apply only to day-ahead congestion charges, and are subject to the transmission organization’s rules and terms established prior to the introduction of long-term rights. EEI suggests that the guideline specify that the long-term right “should” rather than “must” provide a fully funded hedge.

221. In their reply comments, APPA, NRECA and TAPS oppose EEI’s proposed revisions, arguing that they seek to weaken guideline (2) and frustrate Congress’s purpose in enacting section 217(b)(4). In particular, they argue that EEI seeks to make full funding non-mandatory and subject to the transmission organization’s existing rules rather than the Commission’s guideline. In addition, NRECA argues that the rights should not be limited to financial rights or to day-ahead markets.

222. In addition to removing the requirement of full funding, IPL proposes adding the requirement that “revenue shortfall funding shall be shared by all load serving entities that receive allocations of long-term financial transmission rights unless the transmission organization identifies a clear cost causation relationship that warrants other treatment and develops an appropriate allocation methodology through the stakeholder process and specifies that methodology in its tariff and contractual arrangements.”⁷⁸

223. PJM proposes that guideline (2) be revised such that the “quantity specified” in the guideline is modified by “such quantity to reflect, at a minimum, the baseload requirements of LSEs, as determined by the respective transmission organization/ISO regions.”⁷⁹

224. Commission Conclusion

225. We will adopt guideline (2) with minor modifications.⁸⁰ Given that the term full funding has become shorthand for the financial coverage requirements of this guideline, we add this term in parentheses. Finally, because under market designs approved heretofore it is financial rights that provide revenues explicitly, we specify that the full funding requirement applies to financial long-term rights.

226. Thus guideline (2) as adopted in this Final Rule reads as follows:

227. The long-term firm transmission right must provide a hedge against locational marginal pricing congestion charges or other direct assignment of congestion costs for the period covered and quantity specified. Once allocated, the financial coverage provided by a financial long-term transmission right should not be modified during its term (the “full funding” requirement) except in the case of extraordinary circumstances or through voluntary agreement of both the holder of the right and the transmission organization.

231. Requirement of Full Funding

232. We believe that the full funding requirement satisfies Congress’ express directive in section 217(b) (4) that load serving entities with service obligations be able to obtain “firm” transmission rights or their equivalent on a long-term basis. In our view, “firmness” in this context refers primarily to two properties of the long-term transmission rights: stability in the quantity of rights that a load serving entity is allocated over time and “price certainty” for the load serving entity that seeks to hedge congestion charges associated with a particular generation resource or transmission path. If the rights are financial, which they are in almost all organized electricity markets, the latter property essentially requires minimizing the uncertainty in the ability of the rights’ holders to cover congestion charges with the revenue from their transmission rights over the term of the rights.  In our view, the objective of less uncertainty in revenues over the period of financial long-term rights will be aided by full funding.  Hence, we find that full funding is consistent with the objectives of section 217(b) (4).

233. Full funding may have additional positive effects. By stabilizing the expected congestion hedge offered by the right, full funding should assist in financing generation investments that are dedicated to particular loads and assume consistent use of particular transmission paths over long periods, such as base-load plants. Stabilizing the expected value of the long-term rights may also improve their tradability. Further, the transmission organization and transmission owners may have incentives to minimize any resulting uplift through improved transmission system operations, planning and investment. We recognize that there may also be negative incentives from full funding, depending on how any uplift costs are allocated. For example, a transmission owner with long-term rights that poorly maintains its transmission network and causes more instances of deratings that result in congestion revenue shortfalls could be partially subsidized by other transmission owners that have better maintained systems. As we discuss below, transmission organizations and their stakeholders have latitude to propose a full funding uplift allocation to provide better transmission maintenance incentives, if they so choose.

234. There are also methods that could be used to minimize exposure to uplift caused by full funding. First, all current organized electricity markets that allocate financial transmission rights bank congestion surpluses (congestion revenues collected in excess of payments owed to transmission right holders) in a reserve fund over time so as to pay transmission rights in periods of congestion revenue shortfall. For example, in PJM, payments to transmission rights are only pro-rationed when the surplus fund is exhausted. If there is surplus remaining at the end of the year, it is distributed to market participants. This same principle could be applied to long-term financial rights, except that the surplus would be retained across multiple years. Second, as a few commenters suggested, a premium could be charged for fully funded long-term rights, which the transmission organization could additionally apply to such a reserve fund to minimize uplift charges or to set up an insurance policy for the rights holders themselves. Finally, as we discuss elsewhere in this Final Rule, transmission expansion provides a hedge against congestion revenue shortfalls.

235. A number of commenters, including AEP and IPL, are concerned that full funding will reduce the transmission organization’s flexibility in adjusting holdings of transmission rights over time as system conditions change and perhaps render some rights infeasible. AEP is concerned that this might adversely affect transmission investment. While we appreciate these concerns, we must note that the purpose of this Final Rule is to provide more assurance regarding congestion charge hedges over a longer time frame than is available now. This necessarily implies a decreased ability to adjust holdings of transmission rights over time. This Final Rule allows substantial latitude to transmission organizations regarding such things as setting terms and renewal rights for long-term firm transmission rights, placing limits on the amount of capacity made available to those rights, and allowing full funding to be relaxed under extraordinary circumstances. We believe this strikes an appropriate balance between assuring long term congestion charge hedges and reliable operation of the grid. We encourage transmission organizations and stakeholders to consider other measures that allow the transmission organization to deal with revenue insufficiencies over time.

236. Several commenters argue that the Commission should not establish financial rights that offer some load serving entities a “perfect hedge” financially that is superior to the physical rights that they held prior to the formation of the organized market. We agree. We do not envision full funding as a perfect hedge. Since the transmission organization is revenue neutral, costs associated with the full funding guarantee must be allocated on some basis among market participants.  Our guidelines do not establish a subset of load serving entities that would be exempt from such costs, although we discuss how the costs should be distributed in the paragraphs that follow.

237. Full Funding Cost Allocation

238. In general, we will allow transmission organizations the discretion to propose a method for allocating any uplift charges that result from fully funding long-term firm transmission rights. However, certain options proposed by commenters could result in unreasonable outcomes. We discuss some of these below.

239. One approach proposed by commenters would be to charge uplift necessary to support full funding directly to the load serving entities that hold the long-term firm transmission rights that have been made infeasible. Such a rule would largely undercut the relative congestion price certainty provided by full funding and would hence probably not be a reasonable outcome.

240. A second related approach would be to charge uplift to support full funding to a subset or the full set of load serving entities that hold long-term firm transmission rights. In this case, the degree to which the full funding requirement was adversely impacted would depend on the size of the set. In some regions, a small group of load serving entities may opt for long-term rights, in which case this rule could have almost the same impact as assignment of uplift directly to the holders of the rights made infeasible. On the other hand, if most load serving entities in a region opted for long-term rights (up to their eligibility), then the distribution of uplift charges over the set of rights holders would have a lesser impact and could be reasonable from all parties’ perspective. Further, if transmission organizations decide to apply full funding also to short-term transmission rights, as discussed below, another potentially reasonable approach would be to distribute uplift charges over holders of both short- and long-term rights.

241. Both the NOPR and many of the comments on the NOPR discussed the possible assignment of uplift necessary to support full funding to transmission owners. Commenters discussed several variants, including the current NYISO rules that assign all or most of such uplift to support full funding of annual FTRs to transmission owners, and other more targeted proposals, such as the assignment of uplift costs in relation to performance of transmission maintenance. The Commission will allow regional discretion on these options and will examine the reasonableness of such proposals on a case-by-case basis.

242. Some commenters argue that full funding of long-term rights would cause cost-shifting that would be unduly discriminatory and preferential with respect to short-term rights holders. We find that section 217(b)(4) can be reasonably interpreted to establish a due preference for load serving entities that seek to obtain long-term firm transmission rights. We have explained our interpretation of the relationship of firmness and full funding. However, as noted above, we encourage transmission organizations to evaluate whether the requirement to fully fund long-term rights, should be paired with full funding of short-term rights. Currently, most transmission organizations pro-ration payments to short-term FTRs in the event of a revenue shortfall. When fully funded long-term firm transmission rights become available, entities that would prefer to hold short-term rights may have an incentive to seek longer-term rights if the former are not fully funded and depending also on any other rules that affect the properties of transmission rights. Providing the same funding guarantee to all financial transmission rights and focusing on mechanisms to minimize the potential for uplift, as discussed above, could help load serving entities choose rights with term lengths that best suit their needs.

243. Definition of Extraordinary Circumstances

244. As noted above, we will adopt the provision in guideline (2) that allows for full funding of long-term firm transmission rights to be suspended in the event of extraordinary circumstances. This exception was intended to relieve the burden on parties that could be unreasonably impacted by the full funding requirement in such situations. There was general support for this provision, although a number of commenters sought further definition and clarification of extraordinary circumstances so that the exception would not be used to unreasonably narrow the application of the full funding requirement.

245. We agree with commenters that if the extraordinary circumstances exception is defined too broadly, it could be used to unreasonably diminish the value of full funding. Accordingly, we clarify that the definition of extraordinary circumstances, for purposes of this Final Rule, is limited to force majeure events that both render the set of outstanding long-term transmission rights infeasible and leave the transmission organization revenue inadequate, including both revenues from collection of congestion charges and availability of funds from a congestion charge surplus fund.

246. In response to APPA, we further clarify that transmission system contingencies that were considered in the allocation of transmission rights should be excluded from the definition of extraordinary circumstances. In general, the allocation of transmission rights will be subject to a contingency-constrained simultaneous feasibility test and hence such contingencies should not lead to revenue inadequacy if they occur as expected in the modeling assumptions. We recognize that the set of contingencies modeled by the transmission organization may change over time and this should be taken into account in the allocation of transmission rights. There may be further restrictions on the definition of extraordinary circumstances that are needed, and we will consider these as they are presented in compliance proposals.

247. TAPS argues that the conditions for suspension of full funding or application of alternative funding rules should be limited to “catastrophic” regional problems. TAPS is concerned that otherwise, holders of long-term rights will be exposed to congestion charge risk in periods when they most need coverage. While we recognize TAPS’ concern, there is no obvious standard approach to this issue and so we find it more appropriate to allow transmission organizations and stakeholders to develop proposals. For example, in the event of extraordinary circumstances there could be a dollar amount that the transmission organization stakeholders agree to as an upper limit for full funding uplift before pro-rationing of payments to transmission rights holders begins. In addition, the rules for pro-rationing payments may themselves include averaging of uplift similar to full funding. Finally, in all likelihood, system emergencies that are catastrophic will lead to a suspension of market pricing and financial settlement rules and long-term transmission rights would presumably fall under those rules.

248. Other Issues

249. In response to BP Energy’s concerns about market gaming associated with fully funded transmission rights in the event of a transmission outage, we will not endorse the methods being adopted by ERCOT, but will consider any approach that transmission organizations propose to ensure that the full funding guarantee is not subject to market manipulation.

250. Guideline (3) – Rights Made Available by Expansions Go to Parties That Pay for the Upgrade

251. As proposed in the NOPR, guideline (3) stated that long-term firm transmission rights made feasible by transmission upgrades or expansions must be available upon request to any party that pays for such upgrades or expansions in accordance with the transmission organization’s prevailing cost allocation methods for upgrades or expansions. The term of the rights should be equal to the life of the facility (or facilities) or a lesser term requested by the party paying for the upgrade or expansion.

252. We also sought comment on the appropriate rules in the event that an entity that funds a capacity expansion seeks rights on existing transmission capacity to support a request for long-term rights.

253. Comments

254. Guideline (3) was generally supported by commenters, a number of whom noted that it roughly paralleled the existing rules for awards of transmission rights to parties that fund transmission upgrades and expansions. Of the existing transmission organizations, ISO-NE and PJM already provide long-term incremental rights for transmission upgrades, although their rules for assignment of such rights differ. New York ISO and Midwest ISO are developing such rules.

255. ISO-NE states that it awards auction revenue rights for transmission upgrades consistent with the intent of guideline (3) and that their term continues as long as the costs of the upgrades are supported or for the life of the upgrade, if shorter. PJM states that guideline (3) is generally consistent with its current rules, but notes that its rules for term lengths are slightly different from the proposed guideline, as discussed below.

256. New York ISO states that its tariff provides for the creation of incremental Transmission Congestion Contracts (TCCs) for upgrades. However, LIPA argues that NYISO has not finalized its process for awarding expansion rights, and that this has a negative impact on parties that construct additional transmission capacity.

257. As discussed above, Cinergy takes issues with what it argues is the Commission’s overly broad reading of section 217(b)(4) of the FPA.  Cinergy urges the Commission to “provide a clear distinction between rights associated with transmission expansion and those for other long-term uses” and adopt a shorter term for long-term firm transmission rights over existing capacity, to provide a trial period to assess impacts on the system.⁸¹ Similarly, NSTAR argues that only customers who finance transmission capacity expansion are entitled to long-term rights.

258. Conversely, New England Public Systems and NRECA seek clarification that load serving entities that are not directly paying for upgrades or expansion are not prevented from obtaining long-term rights.

259. Scope of Guideline 3

260. Many commenters ask that the scope of guideline (3) be clarified. In particular, commenters sought clarification of the types of transmission expansions the guideline was describing.

261. IPL and Midwest ISO argue that the long-term rights awarded for expansions should be subject to the same rules that will apply to other long-term rights. IPL proposes that guideline (3) be modified to emphasize that rights are awarded subject to the transmission organization’s annual allocation metholodogies. Midwest ISO argues that rights for expansions should have no more or less certainty in terms of MW quantity or funding than any other long-term financial instrument.

262. Cinergy requests that guideline (3) make clear that entities who fund upgrades or expansions should “enjoy the same rights to compensation and the same access to existing transmission capacity whether or not they are LSEs.” Cinergy also asks for clarification that long-term rights for expansion are to be made available only to entities that make an upgrade for the purposes of transmission service from generation to load, and that such rights should not be available for upgrades that are undertaken through the transmission organization planning process for pool facilities.

263. Similarly, SDG&E requests that the Commission clarify that the recipients of long-term rights are those that actually pay the revenue requirements associated with the expansion or upgrade. In particular, SDG&E is concerned that third-party transmission sponsors that seek revenue recovery through rate base are not awarded transmission rights. E.ON argues that load serving entities that request transmission upgrades but do not fund such upgrades nor purchase a long-term transmission contract should not be eligible for long-term rights.

264. Several commenters, including Industrial Consumers and TANC, seek clarification that long-term rights will not be awarded to transmission projects that are subsequently rolled into rates.

265. A number of commenters raised questions about the relationship of guideline (3) and cost allocation methods for transmission upgrades and expansion. National Grid requests confirmation that guideline (3) does not require regions to revise their prevailing cost allocation methods. National Grid infers that guideline (3) refers to a model of participant funding and requests clarification that regions that have not adopted participant funding do not need to revise their methods. PJM also argues that the Commission should not disturb existing cost allocation methodologies by addressing the issue of participant funding versus socialization of costs.

266. TAPS requests that the Commission make clear that guideline (3) does not tie the availability of long-term rights from new transmission capacity to participant funding. TAPS asks that at a minimum, the guideline should make clear that where transmission organizations have moved to other methods of funding upgrades, long-term rights should be available from that capacity.

267. AEP cautions that because transmission upgrades are lumpy in nature, it is often difficult to assign properly the costs of transmission additions to those parties that receive the benefits. AEP notes that due to the difficulties in assigning such costs, there may be free-riders. Consequently, the transmission organization should conduct a regional planning process that identifies the upgrades and expansions that provide the greatest benefit to the region and funds this capacity through regional rate design.

268. Term of Rights for Upgrades and Expansion

269. Commenters differed over guideline (3)’s provision that long-term firm transmission rights allocated to the builders of new transmission facilities should be for the life of the facility. AF&PA and NRECA supported the proposal. However, other commenters argued for a fixed term of a long period rather than life of facility, which could be difficult to define. PJM currently offers rights for a maximum of 30 years and argues that this places a realistic term on the life of the facility and balances the rights of the party paying for the upgrade with market efficiency. Midwest ISO and Xcel similarly argue that awards should be of fixed terms and not facility life. PJM Public Power Coalition supports the PJM term of 30 years, but urges that holders of such rights should be given the opportunity to refuse the rights on an annual basis. CAISO notes that once a transmission project is built and energized, the responsibility for its maintenance may be transferred to a transmission owner separate from the merchant sponsor. Hence, CAISO recommends that the Commission consider allowing transmission organizations to develop standardized terms of long-term transmission rights to be allocated to merchant transmission projects, rather than require allocation for the life of the facility.

270. Several commenters, including EEI, National Grid and PG&E, suggest that the transmission planning horizon presented a natural limit to at least the initial term of rights awarded for new facilities. National Grid argues that awards of rights for the life of facility are impractical because transmission plans currently are only 5 – 10 years in length and hence any awards beyond the planning horizon are “speculative.” Instead, rights should be granted for the duration of the planning horizon and as they expire, new rights can be reconfigured and allocated based on the capacity conditions and relative cost contributions prevailing at the time. Similarly, EEI and PG&E argue that based on the planning horizon, the terms of awarded rights should be the shorter of the expected feasibility of the transmission rights or the expected lifetime of the new facility.

271. In reply comments, APPA, NRECA and TAPS oppose arguments to shorten the term of rights awarded for expansion to the term of the planning horizon of the organized market. APPA notes that planning horizons could be much shorter than the life of the transmission facility for which the long-term rights holder has paid or the duration of a long-term power supply arrangement.

272. Cinergy argues that section 217(b)(4) does not specify awards of rights for the life of new transmission facilities and suggests instead that long-term rights should be awarded for the repayment period of the initial investment. At the end of this period, according to Cinergy, the investor will have recovered its investment and the transmission expansion will be rolled into the transmission charges paid by transmission users. Cinergy also suggests retiring the long-term rights on a schedule that reflects the repayment of the invested capital.

273. Incremental Upgrades and Use of Existing Capacity

274. In response to our question in the NOPR regarding whether rights for upgrades would require rights to the existing transmission system to make a long-term firm transmission right feasible and whether specific rules were necessary to accommodate such needs, a number of commenters argued that the Commission misunderstood the procedures for awarding incremental rights for expansion. For example, NYISO notes that any awards for new transmission facilities are evaluated in terms of their incremental transmission capacity, under which existing rights will be simultaneously feasible with the new rights. NYISO urges that the Final Rule clarify that new firm transmission rights can be awarded for increasing transfer capacity that is feasible and that does not render existing rights infeasible. Similarly, Ameren and Cinergy argue that for transmission expansion, the default rule should be that the entity that pays for the expansion should be entitled only to incremental rights. Such entities could obtain rights to existing capacity through subsequent reconfiguration auctions.

275. Reliant states that entities that fund expansions should unambiguously receive the full allocation of rights associated with the expansion and the same non-discriminatory access to obtain rights to existing capacity as all other market participants. Further, Reliant states that to the extent an expansion needs access to the existing capacity, each region should have the flexibility to develop procedures to account for how existing capacity can be utilized to facilitate new investment.

276. Some commenters have other questions about the relationship of rights awarded for expansions and those assigned on existing transmission capacity. CPUC questions whether awards for expansions might interfere adversely with rights to existing capacity awarded based on service obligations. PG&E and SoCal Edison request that the Commission clarify that under guideline (3), parties that fund transmission upgrades or expansions do not obtain priority to existing transmission capacity. Further, the final rule should clarify the method for determining the amount of rights made feasible by the upgrade.

277. Other Issues

278. CAISO requests that the Commission make clear within this rulemaking that transmission organizations have the responsibility and authority for determining, based on their own engineering studies, the incremental transfer capacity added to the grid by a merchant transmission project.

279. OMS reads guideline (3) as applying to cases where a load serving entity requests a new or changed designated network resource and is required by the ISO to make transmission upgrades. The OMS notes, referring to Midwest ISO, that such upgrades are based on zonal deliverability and not on the ability to grant transmission rights from the resource to load. OMS argues that if the generator is located distantly from load, and the potential transmission rights for the required upgrade are valuable, then the entity eligible for those transmission rights may nominate them in early tiers of the nomination and thus take up transmission capability that others may need. That is, the process of awarding transmission rights for capacity deliverability upgrades may create a result inconsistent with the goal of allocating transmission rights on a priority basis to parties that are seeking to serve load. TAPS similarly argues that the Commission must recognize that transmission planning based on point-to-point transmission rights is “at odds” with the increasing reliance on the aggregate deliverability standard for network resource designation in Midwest ISO. In reply comments, Midwest ISO argues that deliverability upgrades are related to the ability to meet supply adequacy requirements and not to guarantee the ability to receive FTRs from point to point.

280. Midwest ISO argues that care must be taken such that parties that fund upgrades are not given the opportunity to seek awards of rights in excess of the actual change in transmission capability.

281. APPA argues that load serving entities that funded transmission upgrades should be given the opportunity to own the facilities (in addition to collecting transmission rights). CMUA also supports joint ownership, but notes that in California, such ownership may require long-term rights of different kinds over the same facility.

282. Commission Conclusion

283. We will modify guideline (3) in the Final Rule to remove the proposed requirement that transmission rights be granted for the life of a new transmission facility (the last sentence of the proposed guideline). The revised guideline will now read:

284. Long-term firm transmission rights made feasible by transmission upgrades or expansions must be available upon request to any party that pays for such upgrades or expansions in accordance with the transmission organization’s prevailing cost allocation methods for upgrades or expansions.

286. Scope of Guideline (3)

287. Our intention in guideline (3) was to address transmission rights awarded to entities that fund transmission upgrades and expansions through direct cost assignment.  Our subsequent discussion in this section applies only to such upgrades or expansions. All transmission organizations now allow transmission customers to fund capacity expansions and receive the transmission rights that are made possible by those expansions, although some of these transmission organizations have yet to develop exact term lengths and rules for awarding such rights.  Guideline (3) does not address the award of transmission rights made possible by transmission upgrades that are rolled into transmission rates.  When such transmission upgrades come into service, the transmission rights that result from such investments will be made available as rights from “existing capacity” and are thus addressed in guideline (4).  Prevailing cost allocation rules will apply.

288. Term of Rights for Upgrades and Expansion

289. As noted, we will modify guideline (3) by removing the last sentence, which requires that the term of a long-term transmission right awarded for an upgrade or expansion is equal to life of facility. Based on the comments of PJM and other parties on the difficulty of defining life of facility, we will let transmission organizations and stakeholders determine the appropriate terms. However, we encourage transmission organizations to harmonize the terms for long-term rights to existing transmission capacity and new transmission capacity as much as possible.

290. Some commenters, such as National Grid, PG&E and EEI, argue that the term of rights to new transmission capacity should be shortened from the terms offered currently (e.g., PJM currently offers 30 year fixed terms) because transmission planning horizons are only 5-10 years. We believe that this change would unnecessarily introduce uncertainty into the development of merchant funded transmission facilities and, in most cases, it would not allow the funding party to receive the full benefits of its investment. Since the rights awarded for expansion are incremental rights, there is less possibility that they will be made infeasible by changes in the allocated set of rights to the remainder of the grid.

291. In response to LIPA’s concern that New York ISO has not finished its rules for awards of long-term rights for transmission expansion, this guideline will require that transmission organizations develop and file tariff sheets and rate schedules for long-term rights for the types of expansions discussed in this section by the time that they award long-term rights for existing capacity.

292. Incremental Upgrades and Use of Existing Capacity

293. We clarify that under guideline (3), parties that fund transmission upgrades and expansions will be eligible for incremental transmission rights and not entitled to obtain transmission rights to existing transmission capacity held by others. However, each transmission organization will need to establish rules by which interconnection customers that construct new generation facilities and are eligible for long-term firm transmission rights can obtain rights to existing transmission capacity, as per guidelines (4) and (5).

294. Other Issues

295. We agree with OMS that rights awarded for transmission expansions made to support deliverability requirements for generator interconnection are not necessarily consistent with rights to hedge congestion charges associated with delivering power from the generator to load. This distinction between upgrades to support reliability (e.g., to qualify as a capacity resource) and those made to support transmission usage has been long-standing in the transmission organizations with organized electricity markets. However, we do not believe that the allocation of such transmission rights to support deliverability upgrades should interfere with the allocation of rights to others, since the rights would be incremental. Therefore, we will not address the rules for awards of such rights here.

296. Guideline (4) – Term of Rights Must be Sufficient to Hedge Long-Term Power Supply Arrangements

297. As proposed in the NOPR, guideline (4) stated that long-term firm transmission rights must be made available with term lengths (and/or rights to renewal) that are sufficient to meet the needs of load serving entities to hedge long-term power supply arrangements made or planned to satisfy a service obligation. The length of term of renewals may be different from the original term. The discussion of guideline (4) emphasized that term lengths and/or rights to renewal should be sufficient to meet the needs of transmission customers seeking to hedge congestion charges associated with long-term power supply arrangements made or planned to satisfy a service obligation.

298. The NOPR sought comment on the appropriate lengths of terms, whether regional flexibility in setting term lengths is needed, or whether a more specific set of terms (i.e., standardized, such as 10 years) should be established by this rule. The NOPR also sought comment on the relationship between the term of the long-term rights and the transmission organization’s planning cycle and whether the planning cycles should be modified to accommodate the issuance of long-term rights. On the issue of rights to renewal, the NOPR allowed that transmission organizations may propose reasonable criteria regarding the availability of renewal rights and the price for renewal. Further, we proposed that the transmission organization may require minimum notice periods for initiation, renewal, cancellation or conversion that accommodate the transmission organization’s planning cycle or other administrative considerations. The NOPR further sought comments on the relationship between rights to renew and transmission planning.

299. Comments

300. Many commenters requested that the Commission allow regional flexibility when establishing the rules for long-term firm transmission rights to existing transmission capacity.⁸² However, as discussed below, some of these parties made suggestions for minimum terms and rules for renewal rights.

301. Several of the transmission organizations cautioned against the Commission mandating term lengths. Midwest ISO states that the transmission organization must have sufficient flexibility to define and allocate long-term FTRs of different terms. OMS argues that the coordination of the term of the rights with the planning process must be left to each transmission organization. CAISO also argued that many different combinations of term lengths and renewal rights could be implemented that would meet the objectives of Section 217(b)(4). Each transmission organization should be allowed to examine the appropriate rules with its stakeholders.

302. In contrast, Santa Clara argues that load serving entities should set the terms that they need, and that transmission organizations should be required to accommodate those terms.

303. ISO-NE argues that guideline (4) presents a number of concerns, including the difficulty in analyzing the feasibility of the rights, uncertainty over how to evaluate load serving entities’ arrangements “planned” to satisfy a service obligation, necessity for administrative arrangements to review long-term power supply arrangements that qualify a load serving entity for long-term rights and to monitor for manipulation, and accounting for potential terminations of and modifications to such arrangements. ISO-NE asks that because of the difficulties in determining feasibility of long-term rights, the Commission should “avoid specifying excessive terms lengths,” rather letting transmission organizations and stakeholders develop appropriate proposals.

304. Reliant suggests that if the stakeholder process is ineffective in determining term lengths, then the Commission may find it appropriate to develop a more specific set of terms.

305. Cinergy argues that guideline (4) goes beyond the intent of Section 217(b)(4), which it argues is directed exclusively toward transmission expansion. However, Cinergy agrees that transmission organizations should individually develop long-term rights. Cinergy also objects to the notion that the Section 217(b)(4) requires providing load serving entities with hedges.

306. Comments on Specific Term Lengths

307. Some commenters propose specific term lengths, ranging from shorter to longer terms. Beginning with proposals for shorter terms, Midwest ISO asks that the definition of “long-term” be redefined to include terms of one year to offer the transmission organization maximum flexibility to establish rights of short durations but with renewal options that may suit participants in retail choice states. DC Energy proposes adding one year to the term of FTRs each year to allow the market to develop in an orderly and incremental fashion. Strategic Energy supports terms of two years as a starting point.

308. CAISO discusses, for purposes of illustration, the possibility of two year rights with priority for renewal over requests for new rights. SDG&E recommends that one year CRRs are implemented for the first year of the CAISO MRTU project (“Release 1”), with longer-term CRRs reserved for the next phase of the market (“Release 2”).

309. CAISO further argues that because transmission owners have the ability to withdraw from the ISO with a two-year exit notice, duration of transmission rights longer than two years is “potentially questionable coverage as the CAISO will not be capable of enforcing such instruments upon a transmission owners’ exit.”⁸³ CAISO asks that the Commission consider this issue. In reply comments, SMUD notes that CAISO has signed 20 year firm transmission agreements with WAPA on the Pacific intertie. SMUD suggests that CAISO condition exit of a transmission owner on honoring existing contracts. It also notes that since transmission organization membership is voluntary, there is no long-term rights construct that does not involve the risk of exit.

310. NYISO argues that it is “quite possible that one-year, two-year or five-year rights” will be sufficient to meet the needs of transmission customers with long-term power supply arrangements. NYISO notes that it has previously offered 2 and 5 year Transmission Congestion Contracts, but that market participant interest is limited, due in part to the retail competition in New York state. Coral Power also supports terms in the one to five year range. IPL supports terms of no longer than three years, at least for an initial period to gain market experience. Similarly, Cinergy proposes an initial trial period of rights with terms from 2-5 years. Morgan Stanley proposes terms ranging from three to five years. It argues that terms shorter than three years are not likely to be sufficient for investor certainty, while terms longer than five years will fail to create sufficient liquidity to attract buyers and increase the risk of revenue insufficiency.

311. A number of commenters suggested minimum terms. BPA suggested a minimum term of 5 years to support stability in transmission system planning. Other commenters suggested a 10 year term, including AEP, APPA, CMUA, PJM Public Power Coalition, NCPA and TAPS. APPA suggests a minimum term of 10 years outside of retail access environments, and also supports longer terms for transmission rights to support new baseload and renewable generation resources. PJM Public Power Coalition also states that ideally, terms would span 20 to 30 years or more, reflecting the terms of financing.

312. PG&E supports fixed terms and/or renewal rights that provide coverage of 5 to 30 years, consistent with the term and quantity of the service obligation. PG&E further states that transmission organizations should have the flexibility to propose more granular rights to ease administration and transfer when appropriate as well as potentially to increase the availability of short-term rights during the effective term.

313. NRECA states that long-term rights should have maximum periods that match the term of the long-term power supply arrangement. Central Vermont, NYAPP, Redding, Santa Clara, SMUD and Wisconsin Electric present similar views.

314. A number of commenters emphasized that the term of the long-term rights should be commensurate with, or at least not exceed, the transmission planning horizon.⁸⁴ For some commenters, such as Industrial Consumers, this would be a maximum term length with no opportunities for renewal. For others, this would be the basic term length with renewal rights. Some observers, such as Industrial Consumers, note approvingly that some transmission organizations are considering extending the planning horizon from 5 years to 10 years. National Grid requests that the Commission clarify that the “sufficiency” standard under guideline (4) “means nothing more than a term based on rational planning studies.”⁸⁵ National Grid argues that terms beyond such planning studies would make the associated rights “purely speculative.” NU argues that rights with terms extending beyond the planning horizon would “unreasonably transfer risk of congestion to participants who are not in a position to control that risk.”⁸⁶

315. NRECA argues that the transmission planning cycle should be at least 10 years to provide adequate support for infrastructure investment. AEP and Allegheny support the alignment of the term of long-term firm transmission rights with the 10-year transmission planning cycle that is being developed by PJM. PJM Public Power Coalition argues that transmission planning cycles should be modified to account for the terms of transmission rights that extend beyond current cycles.

316. EEI supports the concepts of long-term transmission rights with terms commensurate with the length of the planning horizon, but states that the planning horizons are just one of a number of issues that might be considered in determining term length. Other factors could include whether the system is constrained, the length of time it reasonably takes to expand the system, existing uses of the system, and the demand for long-term and short-term rights on the system. Further, stakeholders may consider the volume of grandfathered rights and their expiration dates, expected generation retirements, and the nature of renewal rights.

317. In contrast, CAISO does not see a compelling reason for tying the terms of transmission rights to the transmission planning cycle. CAISO argues that financial transmission rights do not carry physical characteristics. Hence, the problem of insuring their value over the long-term is fundamentally a cost allocation issue and is only one of many factors to be taken into account in assessing particular transmission projects. CAISO thus asks that the Commission allow transmission organizations to consider the issue of term length as a matter both of market design and transmission planning without imposing any specific linkage between the two.

318. New England Public Systems similarly argues that the creation of long-term rights should not in and of itself change the transmission organization’s planning cycle. In its reply comments, New England Public Systems argues that long-term rights should be integrated into the planning process, becoming part of the baseline for each planning cycle. In that sense, it contends, the planning cycle should not be a constraint on the term of the rights.

319. Similarly, IPL argues that planning cycles can not be designed to support financial transmission rights because of the large number of variables that determine a feasible allocation and the likelihood of changes in those variables over time. Hence, regardless of whether the terms of the long-term rights are linked to transmission planning cycles, there will be a need to periodically re-examine the feasibility of particular allocations of rights and make corresponding modifications in the allocation if needed. IPL further argues that this periodic evaluation and revision of the rights would still allow the holder an “adequate hedge.” IPL supports this position by arguing that the load serving entity is entitled only to a reasonable hedge, not an absolute guarantee that it will never bear congestion costs. IPL proposes that guideline (4) be revised to link term length to the concept of a “reasonable” hedge and to limit the potential for revenue shortfalls. ⁸⁷

320. PG&E argues that the relevant issue in determining the length of the term is not the planning horizon but rather the term of the service obligation. PG&E notes that “the Commission has approved many contracts with terms beyond ten years, and has never suggested that such obligations should be limited to the planning horizon.” Similarly, TAPS argues that the transmission organization’s planning horizon cannot be a basis for restricting terms, including renewals, to a period shorter than the load serving entity’s resource commitment.

321. Finally, PG&E argues that the effectiveness of long-term transmission rights will be best served if the terms have sufficient granularity, such as peak and off-peak periods in the day, the week, the month or season.

322. Renewal Rights, Minimum Notice Periods and Termination

323. A number of commenters argue that renewal rights can be used to extend the period covered by long-term transmission rights. Ameren suggests that rather than prescribe a single term length for all long-term rights, transmission organizations should focus on providing renewal rights. For example, Ameren argues that FTRs with annual rollover rights would be far more flexible than long-term FTRs with set terms. Ameren proposes that a load serving entity with a power supply arrangement of longer than one year be given the option to roll over the FTR each year subject to verification that the power supply arrangement will be in effect for the next year and the load serving entity is nominating no more than its forecast load for the subsequent year. Ameren points out that this approach is consistent with the auction requirements in states with retail choice, where load serving entities will need access to long-term rights even though their power supply contracts will only be one-year in length.

324. Similarly, Cinergy argues that one-year transmission rights with renewal rights would “provide a measure of long-term benefit while still preserving the ability to modify the underlying rights themselves on an annual basis.”⁸⁸ Cinergy is also concerned that entities with long-term transmission rights not simply be able to cancel the rights unilaterally. Instead, the “rights must be relinquished in a manner than allows the market to value and ration them appropriately.”⁸⁹

325. TAPS supports Ameren’s proposal for one-year rights with assured rollover rights (but offers also its own proposal for rolling 10-year terms, discussed below). TAPS suggests that such regional variations might be acceptable as long as load serving entities can achieve long-term price stability for the full duration of their long-term resource commitments. Similarly, New England Public Systems argues that the combination of term lengths, renewal rights and cancellation rights must be “sufficiently flexible” to enable load serving entities to tailor their long-term rights coverage to their specific needs. It is willing to support rights of short duration “so long as LTTR renewal rights [are] sufficiently robust to ensure the continuation by [load serving entities] of needed rights.”⁹⁰

326. TAPS, Industrial Consumers and New England Public Systems support a rolling 10-year term that affords the holder unconditional renewal rights. For example, in the first year, the holder of the 10-year right would inform the transmission organization whether it wanted the right in year 11, in year two whether it wanted the right in year 12, etc. Industrial Consumers states that there is a critical need that investors for new base-load generation perceive that firm transmission rights and renewal rights are available for up to 20 years or longer. Xcel similarly argues that at the end of the initial term of long-term rights, which could be up to the length of the planning horizon, renewal would take place on a one year basis as long as the obligation to serve still exists.

327. Other commenters were concerned that reliance on renewal rights would erode the durability of long-term rights. CMUA states that renewal rights introduce uncertainty over issues such as changes in rates, changes in the simultaneous feasibility test, and the incorporation of other changes since the long-term right was granted.

328. Industrial Consumers argues that renewal rights should be limited to load serving entities that can demonstrate that the renewal is needed to support a long-term power supply arrangement. Similarly, BPA supports the principle that renewal rights may be subject to limitations that tie the long-term transmission service to long-term power supply arrangements, to ensure that renewal rights are not over-allocated.

329. National Grid argues than any renewal right should be “narrowly tailored,” as any renewal beyond the applicable planning horizons would be “just as speculative” as a long-term right with an initial term beyond such horizons.⁹¹ Instead, renewals would have to be subject to evaluation and reconfigured to reflect system conditions through the renewal term.

330. NSTAR argues that renewal rights for long-term rights are discriminatory because the “guidelines do not allow direct access load served under short-term contracts to qualify for long-term rights on a renewal basis, even though the contracts under which they are served will be extended into the future or will be replaced by new contracts.”⁹² For example, under some interpretations the guidelines could allow a load serving entity with a 2-year right to extend the right indefinitely while the holder of a one-year right would not be eligible for such renewals.

331. NYISO argues that the Commission should allow auction-based renewal systems, such as that offered by NYISO. NYISO argues that renewal of rights without market pricing would be “inimical to the design of auction-based systems that are meant to fairly re-allocate rights based on economics and the interests of end-users.”⁹³ Moreover, renewals without market pricing would likely reduce the availability of transmission rights because holders of the rights could retain them indefinitely. Another issue is that through the annual auctions, counterflow transmission rights are purchased, making additional transmission rights feasible. If the counterflow rights were not renewed, then at least some of the long-term renewal rights would be rendered infeasible. NYISO further argues that the concept of a set “price” for renewal may also be antithetical to the market auction model that it employs, because such prices may not be consistent with the auction outcomes.

332. In contrast, TAPS argues that renewals should be at no additional cost. TAPS argues that firm delivery and long-term rights are part of the “core responsibility” of the transmission provider and not an additional cost. TAPS states that at an absolute minimum, any renewal charges should be fixed and fully disclosed by the transmission organization before the initial term begins.

333. SMUD argues that rather than renewal rights, the Commission should allow holders of long-term rights the ability “to apply the right of first refusal protections accorded OATT customers under Order No. 888.”⁹⁴

334. Regarding minimum notice periods for renewal or cancellation. APPA supports an “appropriate” notice period. BPA argues that the minimum notice period for exercising a right to renew should be one year. Cinergy is concerned that holders of the rights should not be able to cancel them “unilaterally.”⁹⁵ Rather, the rights must be relinquished in a manner that allows the market to value and ration them appropriately. Wisconsin Electric states that any long-term protection should terminate when a unit is taken out of service or the agreements are terminated, even if that is prior to the expected life or term of the agreement.

335. Other Issues

336. There was some concern among commenters regarding the seams implications of different term lengths among organized markets. NRECA expresses concern that adjoining regions may assign different terms for long-term rights that this will cause seams problems. NRECA requests the Commission require coordination between adjoining transmission organizations to ensure that the rights are not “illogically matched” to their supply arrangement.⁹⁶

337. A number of commenters emphasized the need for short-term transmission rights to co-exist with long-term rights. Allegheny stated that the final rule should preserve the ability of market participants to obtain allocations of shorter-term rights, including first priority FTR allocations to historic resources. Cinergy is concerned that in states with retail choice, load serving entities would often have to overcome state regulatory obstacles to make long-term power supply arrangements, needed to acquire long-term transmission rights. This would leave such entities limited to a “second-tier” allocation.

338. EEI proposes specific revisions for guideline (4) to reflect consideration of existing uses of the system. It suggests that the availability of long-term rights should be limited “to the extent reasonable in light of the existing uses of the system.”⁹⁷ In addition, it argues that the term “should” should be substituted for “must” with respect to provision of the rights. Finally, it suggests modifying the last sentence of the guideline as follows (additions underlined): “The length and conditions under which the term of renewals is offered may be different than the original term.” APPA and NRECA oppose EEI’s proposed modifications to guideline (4). Both commenters are concerned with the substitution of the term “should” for “must”, which they argue is intended to weaken the requirement.

339. Commission Conclusion

340. We will adopt guideline (4) with a modification to indicate a 10-year minimum term that transmission organizations must be able to offer. Transmission organizations and stakeholders will have substantial latitude to determine how to achieve long-term coverage through combinations of transmission rights of specific terms and renewal rights along with transmission planning and expansion procedures that support long-term rights.

341. The revised guideline (4) reads as follows:

342. Long-term firm transmission rights must be made available with term lengths (and/or rights to renewal) that are sufficient to meet the needs of load serving entities to hedge long-term power supply arrangements made or planned to satisfy a service obligation. The length of term of renewals may be different from the original term. Transmission organizations may propose rules specifying the length of terms and use of renewal rights to provide long-term coverage, but must be able to offer firm coverage for at least a 10-year period.

344. Term Lengths for Rights to Existing Capacity

345. We agree with those commenters, including most transmission organizations, who state that this guideline should not mandate a standard term length for long-term firm transmission rights. Given that there is little experience with long-term transmission rights in organized electricity markets, and that different regions may find that different combinations of terms lengths and/or renewal rights best fit their stakeholder interests and pre-existing rules for transmission rights, we will allow regional flexibility in defining the terms of long-term transmission rights that are offered.  However, section 217(b)(4) of the FPA makes clear that long-term transmission rights should be made available to allow load serving entities to hedge congestion charges associated with deliveries from long-term power supply arrangements. Hence, term lengths must be sufficient to achieve that objective, either alone or in concert with renewal rights.

346. While we allow regional flexibility in defining the terms of long-term firm transmission rights, we will require that transmission organizations make available transmission rights and renewal rights that provide coverage for a period of at least 10 years.  This will ensure that transmission rights are offered that meet the reasonable needs of load serving entities to obtain transmission service for long-term power supply arrangements used to meet service obligations while allowing transmission organizations and their stakeholders flexibility in designing rights that suit regional needs. Transmission organizations can offer this 10-year coverage through any mix of term lengths and renewals that stakeholders agree to, as long as the coverage is “firm”, meaning that the quantity of the rights allocated is fixed over the 10 year period and that the rights are fully funded. Renewal rights may be subject to provisions, such as adequate notice, that address the transmission organization’s planning needs and adequate hedging of the load serving entity’s long-term power supply arrangements.

347. A number of commenters urged that the term of rights remain relatively short, for example, two to three years, for at least an interim phase. Again, our requirement for a minimum 10-year coverage does not necessarily require 10-year transmission rights if no load serving entity requests such rights. Other commenters argued that the rights should be of sufficient length, such as a minimum of 5 years, to assist in transmission planning. The 10-year coverage period that we require here will assist such planning, but we leave it up to transmission organizations and stakeholders to determine how best to harmonize the long-term firm transmission rights and transmission planning cycles.

348. Further, as we note above with regard to the proposed definition of long-term power supply arrangements, APPA, PJM and TAPS generally argue that long-term power supply arrangements should be considered those with a minimum term of at least 10 years. This Final Rule focuses primarily on providing long-term firm transmission rights to cover power supply arrangements with those lengths of terms. Nonetheless, in different transmission organizations, the accommodation of other lengths of power supply arrangements might be considered important. Here, however, our focus is providing load serving entities with long-term power supply arrangements to meet their service obligations with the opportunity to obtain long-term firm transmission rights that will support the financing and construction of new infrastructure. Therefore, we find that setting a 10-year minimum term as a benchmark is appropriate, while also leaving the transmission organizations with sufficient flexibility to offer terms of other lengths.

349. We emphasize that the 10-year minimum term in this guideline is a benchmark. The fundamental requirement of this guideline is that transmission organizations offer rights with terms that are sufficient to hedge long-term power supply arrangements. In regions where such rights are typically longer than this benchmark, transmission organizations may need to offer longer terms and/or renewal rights beyond the initial term. Hence, we expect that most transmission organizations will develop rules to either begin new 10-year coverage terms at the end of each 10-year period or to provide renewals on a rolling basis to support long-term power supply arrangements. We understand from the comments that because of the likelihood that transmission system changes will take place over the 10-year period, stakeholders may have to agree to some reasonable process for modifications of holdings of transmission rights in between allocation periods. We will consider proposals that address such issues in the individual transmission organization compliance filings.

350. PG&E urged sufficient granularity in the terms of long-term rights, such as monthly rights, daily peak and off-peak rights, etc. We agree that more granularity assists in creating transmission rights terms that can better fit actual transmission usage patterns, and thus improves market efficiency. Stakeholders and transmission organizations must determine how much granularity is desirable at the introduction of long-term rights; increased granularity can be introduced over time.

351. In answer to NYISO’s concern that entities in its service territory may not desire long-term rights, we reiterate that such rights must be offered and available to load serving entities. As we discuss above, EPAct 2005 mandates that such rights be available.

352. While we recognize CAISO’s concern that load serving entities awarded long-term rights could withdraw from the ISO’s market before the termination of the right, we do not see this as a limitation on granting rights with terms greater than the notice period for withdrawal. A transmission organization may establish rules for disposition and possible termination of allocated rights in the event of a withdrawal.

355. Other Issues with Renewal Rights, Minimum Notice Periods and Termination

356. Currently, load serving entities in most organized electricity markets are generally eligible to nominate financial transmission rights or auction revenue rights up to their peak load if they pay transmission access charges. The eligibility to nominate rights (or to renew a load serving entity’s rights) is currently long-term; it is available each year to entities that serve load and pay the access charges, but is subject to the simultaneous feasibility test for nominations or the results of an auction. These latter requirements help ensure revenue adequacy but introduce some uncertainty into the actual year-to-year awards of transmission rights that this rule seeks to stabilize for some percentage of eligible rights. Also, as discussed in guideline (2), there may not be full funding of the annual rights, which adds further uncertainty as to their value.

357. Some commenters suggest additional restrictions or eligibility requirements on renewal rights. Under guideline (2), we discuss that full funding of the rights may require, for example, a premium payment. However, to renew the rights for new terms, there is not an obvious need for new conditions. Given the current rules for short-term rights, there should be little to change in the renewal process when long-term rights are offered as long as the transmission system is being planned and upgraded to accommodate the rights. As suggested by APPA, to renew allocated long-term rights, load serving entities should be required to commit to paying the transmission access charges for the period of the allocated right, whether an auction revenue right or a financial transmission right.

358. In response to NSTAR’s concern that renewal rights for long-term firm transmission rights are discriminatory with respect to short-term rights, as we note above, short-term transmission rights are renewable each year for an annual term.

359. We agree with commenters that a minimum notice period should be required for renewing a long-term right. In general, the longer the term of the right, the longer should be the minimum notice period. We will allow transmission organizations and stakeholders to determine the specific notice periods they will propose to apply, however.

360. Other Issues

361. As noted above, several commenters stated in response to the proposed definition of long-term power supply arrangements that the Commission should require that such arrangements have certain specific characteristics, including specific designation of generating resources. The Commission will decline to adopt specific criteria for long-term power supply arrangements. First, as discussed in more detail below, we are removing from guideline (5) the requirement that a load serving entity must hold “long-term power supply arrangements” to receive an allocation priority, which should alleviate concerns regarding the difficulties associated with the validation of such arrangements by transmission organizations. Moreover, the comments suggest that long-term power supply arrangements may have different characteristics in different regions based on the prevailing practices of load serving entities in those areas. Accordingly, to the extent transmission organizations and their stakeholders believe that specification of criteria for long-term power supply arrangements remains necessary to comply with the Final Rule, we will allow the regions the flexibility to develop such specifications and propose them in compliance filings to this rule.

362. In response to NRECA’s concern with seams issues, we discuss these issues above with regard to regional flexibility.

363. Several commenters seek to revise guideline (4) to include restrictions on the quantity of long-term rights that can be obtained. We discuss such restrictions under guideline (5).

364. With regard to EEI’s proposed modifications of guideline (4), we agree with APPA and NRECA that the substitution of the word “should” for the word “must” in the first sentence of the guideline would weaken the requirement. Hence, we will not adopt that modification.

365. Guideline (5) – Load Serving Entities with Long-Term Power Supply Arrangements Have Priority to the Existing System

366. As proposed in the NOPR, guideline (5) stated that load serving entities with long-term power supply arrangements to meet a service obligation must have priority to existing transmission capacity that supports long-term firm transmission rights requested to hedge such arrangements. In the NOPR, the Commission noted that, while section 217 does not require that long-term firm transmission rights be made available only to load serving entities with service obligations, the Commission interprets that section to require that load serving entities with long-term power supply arrangements to satisfy a service obligation be given a preference in securing long-term firm transmission rights. Therefore, the NOPR proposed that when rights requested by eligible parties with priority (or parties without priority that are being accommodated) are not simultaneously feasible given existing transmission capacity, the transmission organization may adopt methods to allocate the requested rights to the parties prior to granting such rights. The NOPR asked for comments on such methods, and on whether section 1233 of EPAct 2005 and new section 217(b)(4) of the FPA support placing reasonable limits on the award of long-term rights. Section 217(b)(4) states that the Commission must exercise its authority to meet the “reasonable needs” of load serving entities to satisfy their service obligations.

367. Also, the NOPR noted that, in making available long-term firm transmission rights, the transmission organization may have to incorporate estimates of load growth into the award of such rights. This raises the concern that if the load growth assumptions are overstated some load serving entities could be awarded more long-term firm transmission rights than needed, and the associated transmission capacity would not be available for allocation of transmission rights to others. The NOPR asked for comment on this issue and any rules or other safeguards that address it.

374. Comments

375. General Arguments for and against the Proposed Priority

376. A number of commenters support the proposal to give priority to load serving entities with long-term power supply arrangements to meet a service obligation.⁹⁸ For example, APPA states that load serving entities that are willing to make a long-term commitment to pay their allocated share of the RTO’s fixed transmission system costs (including the costs of transmission upgrades allocated to customers under that RTO’s Commission-approved transmission cost allocation mechanism) should have a priority claim on the transmission facilities for which they are obligated to pay. FirstEnergy argues that the Commission’s guidelines should grant preferential access to load serving entities with long-term power supply arrangements in order to promote development of generation and transmission infrastructure, and to dampen price volatility.

377. However, many commenters oppose the priority granted in proposed guideline (5),⁹⁹ with some claiming that the proposed priority would be unduly discriminatory.¹⁰⁰

378. Cinergy states that FPA section 217 does not require the Commission to grant preferential rights to load serving entities, and SDG&E states that there is absolutely no statutory support for the “preference” or “priority” language of guideline (5). According to SDG&E, a much more faithful and economically sound reading of the "meets the reasonable needs" language of the EPAct 2005 is that long-term purchasers of power should be accommodated by the new guidelines by providing opportunities for them to secure long- term firm transmission rights, but they should not be able to acquire such rights at the expense of holders of power supply arrangements of a shorter duration. Morgan Stanley asserts that the Commission has a fundamental duty to prevent unduly discriminatory practices in transmission access, and allowing for a preference-based allocation approach as part of the Final Rule would run counter to such a duty. Moreover, NYISO states that interpreting section 217 to grant preferences to certain classes of load serving entities would contradict section 206 of the Federal Power Act, as well as Commission precedent and policy against undue discrimination and preferences in a competitive marketplace.

379. Allegheny recommends that, consistent with the process currently used in PJM, firm transmission rights should be allocated based on load and be available to all load serving entities serving that load. It believes that no preference should be given in the firm transmission right allocation process to load serving entities with longer-term power supply contracts to serve the same load or to load serving entities that were serving load first. BP Energy states that, as currently written, guideline (5) might be interpreted to permit a load serving entity to displace an existing holder simply because the existing holder's power supply arrangements last for a shorter period of time.

380. Reliant states that, among the unintended consequences of the Commission’s proposal are that such a preference: (1) encourages load serving entities to enter into sham long-term agreements and other gaming, (2) distorts the competitive playing field in a manner that undermines and complicates progressive retail choice models, (3) forces load serving entities to hold long-term rights to avoid being short­changed in the short-term allocation processes, and (4) discourages independent generation investment.

381. NSTAR states that the deficiencies of the proposed rule can be corrected by following the statutory language. According to NSTAR, this would be accomplished by redefining “long-term power supply arrangements” as contained in proposed section 41.1(a)(5) by deleting “or” and by adding at the end of that provision the following phrase: “or other arrangements for the purpose of meeting a service obligation on a long-term basis.”

382. With regard to the argument that a load serving entity with a long-term commitment to pay its allocated share of the RTO’s fixed transmission costs is deserving of priority access to long-term firm transmission rights, BP Energy claims that the argument is flawed because all electric consumers end up paying their allocated share, whether they receive service underlain by long-term or shorter-term supply arrangements. Also, National Grid argues that establishing priorities to any new long-term transmission rights based on the length of terms of supply transactions makes little economic or operational sense. From the standpoint of fundamental fairness, National Grid believes that the allocation of transmission rights should be based on the relative contributions of the customers to the costs of the transmission system at the time the rights are made available. Coral Power believes that creating a perpetual preference for remaining capacity based on the theory that customers have paid for some type of service in the past is unreasonable.

383. Cinergy believes that if the Commission permits load serving entities to secure long-term transmission rights to existing transmission capacity on the basis of existing long-term contracts, then it will not only separate load serving entities as a favored class above other transmission customers, it will also create a favored class among load serving entities themselves.

384. Several commenters, however, express the view that there is nothing inherently unduly discriminatory about the priority set forth in proposed guideline (5).¹⁰¹ For example, NRECA states that it is not discriminatory to grant a higher priority to longer-term transmission service; Order No. 888 has done that for years. In any event, NRECA argues that new section 217(b)(4) of the FPA requires that the Commission regulate under the FPA in a manner that enables load serving entities to obtain long-term transmission rights for their long-term power supply arrangements; so the priority for long-term power-supply arrangements is built into the statute, and there is no undue discrimination, as section 217(k) makes clear.

385. APPA states that assuming that a situation were to arise in which the RTO had insufficient rights available to grant both full long-term firm transmission right and firm transmission right allotments, APPA does not believe that it would constitute an “undue preference” to fulfill the needs of long-term firm transmission right holders first. New England Public Systems states that what is unduly discriminatory is the status quo, in which current market rules provide those who enter into short-term transactions the tools with which to hedge their risks but deprives load serving entities with longer-term power supply arrangements of the tools they need to hedge the risks they face. According to New England Public Systems, rectifying this situation cures undue discrimination; it does not create it.

386. Limits on Long-Term Firm Transmission Rights

387. A number of commenters that either support, or do not oppose, the priority for load serving entities as proposed in guideline (5), state that it may be reasonable to place limits on the amount of capacity that can be allocated as long-term firm transmission rights.¹⁰² However, New England Public Systems submits that the specific nature and terms of any such mechanisms are best left to negotiation among the affected stakeholders prior to the transmission organizations’ compliance filings.

388. TAPS states that “reasonable needs” of load serving entities in organized markets must at least include the long-term firm transmission rights needed to support investment in baseload and renewable resources. While TAPS believes that long-term firm transmission right coverage for peaking resources is not necessary, it states that intermediate resources are a closer question. PJM argues that at some baseline level of usage of the transmission system it is reasonable to expect long-term transmission rights to be fully funded (absent significant transmission system outages), as the transmission system should be designed and constructed to meet the baseline requirements of all of its users.

389. E.ON believes that priority firm transmission rights that would otherwise fail the simultaneous feasibility analysis should be allocated on an equitably reduced basis to all qualified load serving entities. However, BPA states that, for a new transmission organization forming in the Pacific Northwest’s unique hydro-based system, it supports granting long-term transmission rights to all existing rights holders, even if those rights are not simultaneously feasible under the most conservative assumptions possible.

390. Several commenters, including some that do not support the priority of guideline (5), state that, if the priority is adopted, limits should be placed on the amount of transmission capacity allocated to long-term firm transmission rights in order to protect those entities that rely on short-term rights.¹⁰³ For example, DTE states that it expects the introduction of long-term firm transmission rights to reduce the availability of short-term firm transmission rights, and care should be taken to ensure that current users of short-term firm transmission rights are not negatively affected. It argues that allocations to other load serving entities should be made only after distribution utilities have been assured sufficient long-term firm transmission rights to meet their current and future native load requirements.

391. Xcel proposes that no more than 50% of an entity’s peak load be eligible for a long-term financial transmission right. Xcel states that this value should be static (i.e. should not allow for load growth) based on a historical reference year such as the year preceding the first allocation. Strategic Energy suggests that an RTO might limit long-term hedges to the lowest daily system peak over the previous planning period.

392. Some commenters do not agree with proposals to limit the amount of transmission capacity that is available for long-term firm transmission rights.¹⁰⁴ NRECA states that it does not understand how such an approach does not run afoul of the language of new FPA section 217. Ameren states that the preference that EPAct 2005 gives to load serving entities with long-term power supply arrangements to meet their service obligations reflects Congress’ judgment that load serving entities engaging in long-term contracting and investment to meet their service obligations should be supported with access to long-term firm transmission rights; therefore, Ameren submits that this preference should not be undermined by limiting capacity available for long-term firm transmission rights. TANC states that the Commission should not allow transmission organizations the ability to limit the amount of transmission capacity available to support long-term firm transmission rights, but should instead require transmission organizations to actively manage the level of long-term firm transmission rights necessary to meet entities' current native load obligations, including load growth estimates.

393. Rules for Determining Priority

394. Some commenters offer specific recommendations concerning the rules for determining when an entity is entitled to receive priority with respect to long-term firm transmission rights.¹⁰⁵ For example, Public Power Council recommends that, pursuant to section 217(d), the transmission rights not used to meet service obligations may be applied to other uses of the system. According to Public Power Council, this necessarily means that the transmission rights must first be offered to load serving entities and after their needs are met, they are released to others.

395. PG&E argues that the preference, at least with respect to initial allocations, should be in accordance with the term and quantity of the service obligation, reflected as load share in the future term. For those transmission organizations that adopt auctions to follow initial allocations, PG&E recommends that stakeholders should address the issue of whether shortage of available long-term firm transmission rights relative to demand should trigger a validation procedure such that load serving entities seeking to meet long-term service obligations are given preference, or whether the auction price should determine priority.

396. Morgan Stanley states that it is not necessarily opposed to the auction revenue right allocation methodologies that are based on the amount of load served by a party. However, in Morgan Stanley’s view, it is crucial that any auction revenue right grants be independent of the status of the organization, i.e., whether it is a load serving entity.

397. As to the definition of a “Long-term Power Supply Arrangement” that would be eligible for the long-term protections, DC Energy states that the power supply agreement must be firm for its term and must provide for energy from one or more specific generators in specific amounts. Wisconsin Electric believes that a key eligibility criterion is whether such arrangement includes not just energy, but energy and capacity. It claims that an energy only transaction does not indicate long-term control of the unit. Cinergy believes that preferential access to existing transmission capacity that is secured on the basis of long-term power supply arrangements should be limited to new long-term power supply arrangements for new generation.

398. Using Long-Term Firm Transmission Rights to Grandfather Existing Uses

399. A number of commenters address the issue of whether or not historical uses of the transmission system should be given priority for granting long-term firm transmission rights.¹⁰⁶ FirstEnergy states that the Commission’s proposal is a reasonable response to the legislative mandate so long as “a preference” means that current supply arrangements are given a priority over past or historical supply patterns no longer in place. Coral Power states that the guidelines are not being proposed against a clean slate, noting that many ISOs have already established grandfathered arrangements. Coral Power is concerned that a preference could be used to needlessly expand grandfather rights that were allocated to electric utilities when the RTO/ISOs were formed.

400. PJM states that, while it believes it is fair to establish a historical load/long-term firm transmission rights preference, it also recognizes the need to create a process to accommodate new long-term rights to cover load growth and new long-term contracts. PJM notes that its long-term firm transmission right proposal will address these issues.

401. Eligibility Issues

402. A number of commenters offer recommendations with respect to the rules for determining which entities should be eligible to receive priority in the allocation of long-term firm transmission rights.¹⁰⁷ For example, Manitoba Hydro submits that the Commission should ensure that the guidelines provide that if a market participant other than a load serving entity has a contractual obligation to a load serving entity to provide transmission rights and to take associated congestion risk, it should have priority to long-term transmission rights in the same manner as would the load serving entity.

403. ISO-NE contends that generators may need these firm transmission rights as much as load serving entities, because generators’ bilateral contracts with load can place the congestion risk on the generator. In reply, New England Public Systems states that if load serving entities with service obligations and long-term power supply arrangements are given a priority in obtaining long-term firm transmission rights, contracts will be structured or restructured in order to place the congestion risk on the party that can most effectively hedge it. NRECA states that, if a load serving entity wishes to sell its long-term firm transmission rights for a period of years to a power supplier that is also the transmission customer, NRECA believes it should be able to do so.

404. LIPA contends that the guidelines in proposed section 40.1(d) do not specifically incorporate the standards of FPA section 217(b)(4) or make clear that long-term firm transmission rights must be available to all market participants consistent with a transmission organization’s individual market design. LIPA states that, while the availability of long-term firm transmission rights to all participants could be implied within the rule, and while certain guidelines address necessary elements of long-term firm transmission rights to promote use of such rights by load serving entities, the existing ambiguity can be removed by modification of the general rule.

405. Some customers argue that the priority for long-term firm transmission rights should extend to customers that are outside the transmission organization’s control area. E.ON claims that, as currently proposed, utilities that either do not belong to an RTO, or have no organized electricity market in which they can participate, cannot expect any priority in the allocation of long-term firm transmission rights into or out of an organized market. E.ON urges the Commission to consider granting priority to a load serving entity that satisfies the provisions of FPA section 217(a), either owns or has firm rights to the output of a capacity resource located within the boundaries of an adjacent RTO, and has acquired from that RTO transmission service necessary to deliver energy to the load serving entity’s load located outside of the adjacent RTO. TANC states that long-term firm transmission rights should be provided first to entities with native load service obligations that contribute to the embedded cost of the transmission systems, including entities that may not be within the transmission organization's control area.

406. Industrial Consumers argues that load serving entities in trust for loads, or loads directly, should be allocated short-term and long-term transmission rights on a pro rata basis as necessary to serve the total load. Alcoa states that priority also should be extended without discrimination to end users that act as their own load serving entities. CMUA adds that entities eligible in California for long-term firm transmission rights should include California's large state and local water agencies, which represent a significant portion of the state's energy usage, and are part of wholesale markets, but which do not serve retail load.

409. Retail Access Issues

410. Many commenters claim that the proposed priority would undermine state-mandated retail access programs and harm competitive retail suppliers.¹⁰⁸ Allegheny submits that the Commission should not create a situation in which load serving entities that participate in state-mandated supply procurement programs will be given a lower priority in long-term firm transmission right allocations. Constellation claims that the preference for longer-term supply resources would discriminate against competitive retail suppliers with service obligations in two respects. First, vertically integrated utilities with long-term resources could receive a priority with respect to capacity, blocking smaller retail providers from gaining access or entry to markets to compete effectively. Second, a preference for longer-term firm transmission rights would discriminate against the shorter-term firm transmission rights that allow competitive retail providers with service obligations to more closely match shifts in their load, which, according to Constellation, can occur frequently, even daily.

411. Exelon notes that, in New Jersey and Illinois, the state commissions have determined that the public utilities should procure customers' requirements through a competitive auction procedure approved by the Commission. Exelon states that the rules of the auction preclude the utilities from entering into contracts of more than a few years' duration.

412. Regarding the effect of long-term firm transmission rights on retail access, Redding, APPA and TAPS take a different view. APPA states that the desire of retail suppliers like Constellation and the members of EPSA for flexibility has to date prevented load serving entities in retail choice regions that wish to hedge transmission congestion associated with their long-term base load and renewable resources from doing so. APPA asserts that, while suppliers in retail choice areas may value flexibility, the associated short-term arrangements do not support the substantial new investments in generation needed to meet resource adequacy or fuel diversification needs. Similarly, TAPS states that is bad policy to force all load serving entities in all states to share that fate (i.e., denying all consumers the benefits of low cost energy) simply because some states may have concluded that is the right decision for those serving retail load within their state.

413. Obtaining Long-Term Firm Transmission Rights through Capacity Expansions

415. Some commenters argue that the long-term needs of load serving entities should be met through the transmission organization’s planning and expansion process, not by granting priority access to long-term firm transmission rights supported by existing capacity.¹⁰⁹

416. Constellation states that section 217(b)(4) requires the Commission to be proactive in ensuring that the needs of all load serving entities with a service obligation (regardless of the duration of that service obligation) are met through planning and expansion of transmission facilities and enabling load serving entities to secure firm transmission rights on a long-term basis, not to extend an undue preference for existing transmission capacity to load serving entities with long-term supply arrangements at the expense of other load serving entities with service obligations. NRECA agrees that the Commission does have an obligation under section 217 to facilitate transmission planning and expansion so as to support long-term power-supply and transmission arrangements. However, NRECA asserts that the Commission also has a specific duty to act in a manner that “enables load serving entities to secure firm transmission rights … on a long-term basis for long-term power supply arrangements.”

417. Market, Efficiency and Gaming Issues

418. A number of commenters argue that the proposed priority will impede the development of competitive markets and create inefficient economic incentives. ¹¹⁰ For example, EEI states that long-term firm transmission right holders will have the incentive to resist infrastructure enhancements to the system that adversely affect the value of their long-term firm transmission rights. Also, SDG&E contends that, on transmission paths that are expected to have relatively higher levels of congestion, e.g., where the transmission rights are expected to be more valuable, an incentive is created to enter into long-term commodity transactions in order to secure the priority. According to SDG&E, such incentives are misplaced and could distort efficient contracting decisions. NYISO believes that rather than having an incentive to contract for the least cost resources to meet their load, load serving entities would have an incentive to enter into contracts on the "wrong" side of binding transmission constraints, because they would receive valuable transmission rights as a reward for executing such contracts.

419. Other commenters take the opposite view, arguing that the proposed priority would lead to more efficient investment decisions and lower costs in the long run.¹¹¹ FirstEnergy states that the availability of long-term service is needed to facilitate investment in new generation capacity and transmission infrastructure.

420. APPA argues that the primary role of long-term firm transmission rights would be to support base load and renewable generation resources needed to support load serving entity service obligations. Those resources are not sited based on whether they are on the “right” or “wrong” side of a constraint, but on a myriad of factors, including proximity to fuel sources, access to rail transportation and availability of renewable resources (e.g., wind or geothermal). APPA states that the failure of RTOs to offer long-term firm transmission rights is stifling investment in base load and renewable generation resources, and in the associated transmission facilities needed to bring these resources to loads.

421. Several commenters express concern that the proposed priority would create an incentive for load serving entities to acquire excess long-term firm transmission rights in order to sell the excess at a profit, and could lead parties to enter into “sham” contracts.¹¹²

422. ISO-NE contends that a direct, costless allocation of LT-firm transmission rights, or an auction in which only load serving entities may purchase LT-firm transmission rights, would amount to a wealth transfer to the load serving entities at the expense of other market participants. According to ISO-NE, this is because the load serving entities would acquire the LT-firm transmission rights at a price below their value and have every incentive to resell them on the secondary market for a profit. Midwest ISO states that this guideline may give parties an incentive to enter into “sham” contracts intended to accomplish nothing but establishing rights to valuable long-term firm transmission rights.

423. Ameren believes that the concern that load serving entities will nominate excessive amounts of long-term firm transmission rights is easily addressed by limiting the amount of long-term firm transmission rights allocable to a load serving entity based on its expected load, including load growth, during the upcoming year and using state regulatory processes to police nominations. APPA states that the RTO can take the matter up with the load serving entity on a case-by-case basis if it believes that the long-term firm transmission right allocation of the load serving entity does not appropriately reflect load growth.

424. PG&E notes that the EPAct 2005’s focus on the “long-term service obligation,” its predication of the threshold amount of Transmission Rights on those “power supply arrangements” that constitute “reasonable needs,” as well as the EPAct 2005’s provisions for shifting long-term Transmission Rights in parallel with load migration, provides ample opportunity for protection against “sham contracts” and the possibility of windfall to load serving entities, so long as the statutory terms are well defined. APPA states that it and its members are willing to agree to reasonable limitations on long-term firm transmission rights, including restrictions on resale and requirements that holders actually have generation resource arrangements covering the specified sources and sinks, to avoid creating such perverse financial incentives. Also, New England Public Systems notes that TAPS has proposed dispatch-contingent option long-term firm transmission rights that only generate a payment to the load serving entity when the resource at issue is run and do not require payment by the load serving entity when congestion is reversed. Alternatively, New England Public Systems states that long-term firm transmission right settlements could be subject to true up at year end based on actual load levels.

425. Allowing for Load Growth in Long-Term Firm Transmission Rights and the Need for Accurate Load Forecasts

426. Some commenters argue that priority in the allocation of long-term firm transmission rights should extend to provisions for load growth and unforeseen changes in the need for long-term rights.¹¹³ Public Power Council argues that the preference should require RTOs and ISOs to set aside future rights for the load growth of these entities and the Commission should ensure that the transmission system is planned and expanded to accommodate growth.

427. Allegheny argues that incremental firm transmission rights to cover increases in generation capacity resources, load growth or other factors should also be granted as part of the long-term firm transmission right allocation process, but only to the extent that the underlying transmission system can support the feasibility of such additional firm transmission rights. AEP believes it is inappropriate for auction revenue right allocations to be locked into a configuration that may bear no resemblance in year 10 to the simultaneous feasibility tests run in year one. Industrial Consumers believes that the load serving entity or a load that is serving itself should have access to additional capacity rights for unforeseen load growth, and similarly, the load serving entity or load serving itself should be required to surrender that portion of its rights for the amount of any permanent load reduction.

428. PJM Public Power Coalition argues that if, during the roll-over term of the long-term transmission rights, a load serving entity’s load is reduced below the level of its long-term transmission rights, that entity’s roll-over right should be reduced to its then current load level, so that the entity does not have priority to transmission capacity it will not use to serve its load.

Administrative Burden

429. Midwest ISO states that the Commission’s requirement that transmission organizations provide load serving entities priority to existing transmission capacity is problematic for several reasons. First, transmission organizations will have to undertake extensive, burdensome, and costly administrative processes in order to evaluate contracts to determine whether they satisfy the criteria applicable and ensure that the power supply contracts are in fact necessary to serve load and are long-term. Midwest ISO argues that the transmission organizations should not be placed in the position of evaluating long-term contracts to ensure they legitimately qualify for priority of the transmission capacity. In response, APPA notes that many Regional Reliability Councils have long undertaken auditing of load serving entity power supply portfolios to determine if their regions have adequate generation resources. APPA claims that the term of power supply agreements is usually relatively easy to ascertain, and annual reporting by the load serving entities on their generation resource portfolios, plus oversight and investigation by the RTO’s Market Monitor if gaming is suspected, should be sufficient to keep load serving entities honest. APPA also notes that, under section 30 of the Order No. 888 OATT, Network Customers have to designate new resources by providing the required information to the Transmission Provider. Hence, in APPA’s view, Network Customers are accustomed to having to verify their claimed generation resources.

Commission Conclusion

430. We will adopt guideline (5) with revisions to eliminate the preference for load serving entities with long-term power supply arrangements and replace it with a general preference for load serving entities vis-à-vis non-load serving entities. Also, as discussed below, we will revise guideline (5) to allow the transmission organization to place reasonable limits on the amount of existing transmission capacity that it will make available for long-term firm transmission rights.

431. Although we believe section 217(b)(4) of the FPA would support a preference for load serving entities with long-term power supply arrangements, we agree with those commenters, such as SDG&E, that claim that EPAct 2005 should not be construed to require that a preference be given to this class of load serving entities at the expense of load serving entities that prefer short-term power supply arrangements. In our view, a broader preference for load serving entities in general vis-à-vis non-load serving entities is fully supported by the statute and indeed better meets the needs of today’s organized electricity markets.

432. The overall thrust of new section 217 of the FPA, read in its entirety, is the protection of transmission rights used to satisfy native load service obligations.¹¹⁴ Given the reality that transmission capacity is limited, and that the amount that can reasonably be made available for long-term transmission rights may be lesser still, we believe that section 217 of the FPA provides a general “due” preference for load serving entities to obtain long-term firm transmission service. Moreover, section 217(d), which provides that the Commission may make transmission rights that are not used to meet a load serving entity’s service available to other entities, strongly indicates that Congress intended for load serving entities to be “first in line” for long-term transmission rights that are made available.

433. An important advantage of revising guideline (5) in this manner is that, in most cases, the transmission organization will be able to apply the same basic principles for allocating long-term firm transmission rights that it currently uses for the initial allocation of short-term firm transmission rights, or auction revenue rights. To explain, we note that most transmission organizations now use straightforward methods to allocate firm transmission rights (or auction revenue rights) annually to all load serving entities that support the embedded costs of the transmission system. Some of these methods take explicit account of the load serving entity’s current or historical power supply arrangements in determining its allocation priority. However, as revised, guideline (5) neither requires nor prohibits the consideration of power supply arrangements in determining this priority. Guideline (5), as revised, only requires that load serving entities have priority over non-load serving entities in the allocation of long-term firm transmission rights. This means that, in most cases, load serving entities can continue to receive the same allocation of firm transmission rights (or auction revenue rights) that they have received in the past. In addition, by eliminating from guideline (5) the priority for load serving entities with long-term power supply arrangements, we are making it possible for the transmission organization to propose an allocation method that eliminates any obligation on the part of either the transmission organization or the load serving entity to demonstrate or verify that the load serving entity holds a qualifying long-term power supply arrangement.

434. In addition, revising the guideline in this manner effectively addresses the objections of most commenters that oppose guideline (5) as proposed in the NOPR. Importantly, it largely eliminates the potential for load serving entities that prefer short-term power supply arrangements, or are precluded from entering into long-term arrangements, to be disadvantaged in the allocation of firm transmission rights. In particular, load serving entities in retail access states can continue to receive and use their allocated firm transmission rights as short-term instruments, if that best suits their business model. Also, load serving entities that prefer short-term firm transmission rights (or are limited to them by law) will not feel compelled to request long-term firm transmission rights (or enter into sham contracts) out of fear that they might otherwise lose out in the firm transmission right allocation process. We do not believe that Congress intended these results when it enacted section 217 of the FPA, particularly given the statute’s overall focus on protecting the transmission rights of load serving entities with service obligations. Finally, the transmission organization will not face the administrative burden of having to evaluate power supply contracts to determine if they qualify for the preference.

435. In the NOPR, we asked for comments on whether section 1233 of EPAct 2005 and new section 217(b)(4) of the FPA support placing reasonable limits on the award of long-term rights. Because of uncertainty regarding load growth, changes in power flows and other factors, the Commission expects that the transmission organization may be reluctant to commit all of its existing capacity to long-term firm transmission rights, especially in light of guideline (2)’s full funding requirement. Also, commenters claim that the principal need for long-term firm transmission rights is to support long-term power supply arrangements only for base load generation, not peaking or intermediate generation. Therefore, we conclude that the transmission organization and its stakeholders should be given flexibility to determine the level at which a load serving entity may nominate long-term firm transmission rights as long as that level does not fall below the “reasonable needs” of the load serving entity. This level can be expressed in a variety of ways, for example as a straightforward measure of load, such as minimum daily peak load or 50 percent of maximum daily peak load. In this regard, we note that some commenters argue that the allocation of long-term firm transmission rights should include provisions for load growth, to include the loss of long-term firm transmission rights when load declines. Rather than specify an approach here, we will provide the transmission organization and its stakeholders with flexibility to propose an approach for incorporating load growth in the allocation process, if it is incorporated at all.

436. The Commission emphasizes that revising guideline (5) in this manner should not significantly reduce the access to long-term firm transmission rights that a load serving entity with long-term power supply arrangements would have had under guideline (5) as originally proposed. Under that proposal, load serving entities with power supply arrangements of more than one year (per our proposed definition of long-term power supply arrangements) would have qualified for an allocation preference; our revision only expands the preference to include load serving entities that have power supply arrangements of less than one year. Moreover, most supporters of proposed guideline (5) agree that a transmission organization will have valid reasons to place a limit on the amount of system capacity that it makes available to support long-term firm transmission rights. Also, most of the commenters that support guideline (5) as proposed do not include among the reasons for their support the need to link the award of long-term firm transmission rights to long-term power supply arrangements. Rather, their comments are principally directed against any notion that load serving entities with short-term firm transmission rights should receive special consideration in the allocation process. Finally, the other guidelines adopted here ensure that the long-term firm transmission rights will support long-term power supply arrangements, as Congress intended.

437. Our decision to make explicit the transmission organization’s right to propose reasonable limits on the amount of capacity made available for long-term firm transmission rights, as well as to provide the more limited preference that we are adopting in the Final Rule, requires that we revise guideline (5) to read as follows:

Guideline (5): Load serving entities must have priority over non-load serving entities in the allocation of long-term firm transmission rights that are supported by existing transmission capacity. The transmission organization may propose reasonable limits on the amount of existing transmission capacity used to support long-term firm transmission rights.

438. Commenters such as Manitoba Hydro and ISO-NE argue that the preference should extend to certain entities that do not meet the strict definition of load serving entity, such as generators that have a contractual obligation to a load serving entity.¹¹⁵ The Commission disagrees. Extending the preference to entities that do not meet the definition of load serving entity, as clarified in this Final Rule, would likely defeat the purpose of providing the preference. Once load serving entities have received their allocated firm transmission rights, those firm transmission rights and any additional firm transmission rights available from remaining system capacity can be offered to non-load serving entities (as well as other load serving entities) through a secondary auction, bilateral trades or another method of allocation. This is consistent with section 217(d) of the FPA. Also, as noted by New England Public Systems, a load serving entity that has a contractual arrangement with a generator or other entity that allocates congestion risk in a particular way can structure its contract with that entity as necessary to achieve the desired risk sharing.

439. Industrial Consumers, Alcoa and CMUA state that certain end users should receive the preference provided by guideline (5). As we stated above in our clarification of the definition of load serving entity, any end user, such as an industrial consumer or a large water agency, that is allowed under state law and regulation to participate in wholesale markets as a power purchaser should be construed as a load serving entity under the Final Rule and, accordingly, should receive all of the rights and obligations of a load serving entity.

440. E.ON asks that a load serving entity outside of a transmission organization’s boundaries be given priority, under certain conditions, to long-term firm transmission rights on the transmission organization’s transmission system. On this matter, the Commission agrees with TANC that long-term firm transmission rights should be made available first to those entities that have an obligation to serve load within the transmission organization’s service territory and are required to contribute to the embedded cost of the transmission organization’s transmission system. Any entity that has neither an obligation to serve load on the transmission organization’s transmission system, nor an obligation to pay the embedded costs of that system, should not be given a preference to acquire long-term firm transmission rights supported by the system’s existing capacity.

441. LIPA states that the proposed guidelines do not specifically incorporate the standards of FPA section 217(b)(4), or make clear that long-term firm transmission rights must be available to all market participants, and therefore should be revised. We do not believe that any revision is necessary. The guidelines, taken as a whole, are designed to implement the relevant requirements of EPAct 2005, including the provisions of FPA section 217(b)(4). We believe that the guidelines as revised in this Final Rule provide the clarity that LIPA seeks. Further, we have made clear both in the NOPR and in this Final Rule that long-term firm transmission rights must be available to all market participants; this guideline serves only as a “tiebreaker” between load serving entities and non-load serving entities when existing transmission capacity is limited.

442. Finally, we note that several commenters express concern that the preference as proposed in guideline (5) will lead market participants to resist infrastructure enhancements, enter into sham contracts, or make inefficient investment decisions. We conclude that, by eliminating the priority for load serving entities with long-term power supply arrangements, and by allowing limits to be placed on the amount of capacity available for long-term firm transmission rights, the Final Rule should virtually eliminate any incentive that a load serving entity might otherwise have to hoard long-term firm transmission rights, enter into sham agreements or resort to other types of gaming and inefficient decision-making. Indeed, the Commission agrees with APPA that a likely greater source of inefficiency is the unavailability of long-term firm transmission rights in organized electricity markets, which may be impeding needed investments in generation resources and transmission upgrades. Nevertheless, if a transmission organization and its stakeholders conclude that additional steps must be taken to avert such problems, the transmission organization may propose appropriate measures as part of its compliance filing.

Guideline (6) – Rights are Reassignable to Follow Load

443. As proposed in the NOPR, guideline (6) stated that a long-term transmission right held by a load serving entity to support a service obligation should be re-assignable to another entity that acquires that service obligation. The NOPR stated that a successor load serving entity should assume any cost responsibility that holding the long-term transmission right entails. We stated that this proposal is consistent with section 217(b)(3)(A) of the FPA, which requires that transmission rights held by a load serving entity as of the date of enactment of EPAct 2005 for the purpose of delivering energy it has purchased or generated to meet a service obligation be transferred to a successor load serving entity. The NOPR noted that the short-term transmission rights currently offered by transmission organizations are generally reassignable to successor load serving entities. The NOPR also noted that a transfer of a service obligation might occur pursuant to a state commission order, or might occur in a state with retail competition if load chooses a new supplier.

444. The NOPR asked for comments regarding whether reassignability should apply to all long-term firm transmission rights, regardless of how those rights were obtained, and whether a holder of long-term rights should receive compensation when its rights are reassigned.

445. Also, the NOPR noted that section 217(b)(4) of the FPA does not discuss whether long-term firm transmission rights should be fully tradable among market participants. We stated that allowing such rights to be fully tradable could raise issues of equity, since a load serving entity that acquired the rights through a preference could then possibly sell or trade the rights at a profit. This might give load serving entities the incentive to acquire excess long-term firm transmission rights in order to take advantage of profit opportunities. However, the NOPR noted that full tradability may bring benefits to the market, and allow those that could not obtain long-term rights in the initial allocation to obtain such rights later. The NOPR asked for comments on these issues.

Comments

General Support for Guideline (6)

446. Many commenters express strong support for proposed guideline (6).¹¹⁶ AEP states that a transmission right to support a service obligation should stay with the load and, therefore, be re-assignable to another entity that may acquire the service obligation. APPA supports guideline (6) and states that such assignability should be required regardless of how those rights were obtained.

447. Cinergy supports the adoption of guideline (6) in principle because it believes that market liquidity provides for more efficient economic outcomes and that the problems associated with other guidelines may be mitigated to some degree by directing that long-term transmission rights be re-assignable. BPA states that this policy should accommodate other open access policies where the long-term transmission rights of the original load serving entity would transfer (1) to other load serving entities that successfully compete to serve loads under state retail access programs, or (2) to wholesale power suppliers that successfully compete to meet load serving entity service obligations.

Need for Flexibility

448. Some commenters urge the Commission to permit flexibility in the way transmission organizations implement this guideline. Reliant states that the Commission should permit organized electricity markets and their stakeholders to best determine the reassignment of long-term transmission rights. EEI states that flexibility is important in the application of this guideline because it will present administrative burdens with respect to tracking reassignments on a frequent basis. CMUA states that, given the different retail choice regimes in different regions, or the lack of retail choice in some, implementation is best left to the relevant regions.

Should Reassignment be Optional or Mandatory?

449. NYISO states that this proposal is reasonable provided that the rights may be reassigned, not that they automatically be reassigned, at least in the case of transmission organizations with grandfathered auction based systems under FPA section 217(b) (3). Similarly, Xcel states that reassignment itself must not be mandated; the reassignment should be at the option of the holder of the right and the entity to which the service obligation transfers. PJM Public Power Coalition states that because these long-term rights can become a liability under certain circumstances, entities should be able to trade, transfer, or decline to exercise the rights.

450. Suez Energy states that guideline (6) might be interpreted in a way that destroys retail competition because incumbents might argue that long-term firm transmission rights are merely re-assignable at the choice of the incumbent supplier, and that the incumbent should be allowed to retain valuable long-term firm transmission rights for existing network service. Conversely, Suez Energy is concerned that an incumbent supplier that invested badly could argue that the financial burden of a now burdensome investment in transmission infrastructure is reassignable to a new supplier.

451. ISO-NE believes that the Commission should examine proposals for mandatory re-assignment carefully where the load serving entity picking up the service obligation has a different set of long-term supply arrangements that may not correspond with the path for the existing long-term firm transmission right, or if the successor load serving entity may not wish to utilize a long-term supply strategy at all.

Rules Governing Reassignment

452. Several commenters offered proposals for rules that would govern the reassignment of long-term firm transmission rights in specific instances.¹¹⁷ The CAISO asks the Commission to clarify guideline (6) to state that the transmission organization should adopt provisions to require that either allocated long-term firm transmission rights or their equivalent financial value be transferred from one load serving entity to another to reflect transfers of load serving obligation. The CAISO believes that by allowing load serving entities to transfer the financial value of long-term firm transmission rights when their load serving obligation migrates, instead of insisting on the transfer of the actual long-term firm transmission rights, the underlying principle that the allocated long-term firm transmission rights are the property of the end-use customers can be maintained without precluding the trading of allocated long-term firm transmission rights by load serving entities.

453. SoCal Edison recommends that the only circumstances in which long-term rights should be reassigned are if: (1) the original right was allocated (i.e. any rights purchased bilaterally or in an auction would not be transferred regardless of any load migration); and (2) the load-gaining entity has the ability to utilize the same source/sink pair that was used to allocate the long-term right to the load-losing entity; and (3) the load losing entity can no longer use the entire long-term transmission right for the output/load upon which the long-term right was initially awarded to the load-losing entity. PG&E agrees that no transfer should occur until such time as a load serving entity’s remaining service obligation is less than the megawatt quantity of its long-term firm transmission rights. Also, PG&E believes that the statutory intent to link long-term transmission rights to long-term power supply arrangements would be realized if transmission rights or equivalent payments are made only to those load serving entities that gain long-term service obligations and that also obtain commensurate long-term power supply arrangements. However, APPA claims that SoCal Edison’s condition (2) seems unnecessarily stringent and asserts that, if the transmission organization can reconfigure the long-term firm transmission rights at the time of transfer, then this should be permitted.

454. Redding contends that when the Commission raises the issue of assignability it implicitly raises the question of portfolio strategy. Redding argues that, if the load serving entity has long-term transmission rights and long-term supply arrangements that were not utilized to serve the customer with retail choice, then the customer's decision to change providers should not result in the reassignment of a long-term transmission right. Redding contends that there would be an argument for transfer of the transmission right only if the customer can demonstrate that it either directly or indirectly had a liability that transferred to the new provider or remained with the customer.

455. Midwest ISO states that the entity that acquires the service obligation may not want the particular long-term firm transmission right, but may prefer a different firm transmission right with a source that matches the supply portfolio of the new load serving entity. Moreover, the firm transmission right may have negative value and the new load serving entity may not want it at all. To the extent the Commission permits such re-assignment, Midwest ISO recommends that reasonable restrictions be imposed. For example, Midwest ISO states that the Final Rule should limit the impact of this issue by (1) limiting the amount of long-term firm transmission rights to a small proportion of load serving entity’s load, and (2) limiting the term of the firm transmission right. In response, APPA states that it prefers its proposed suggestions of minimum hold times, minimum periods for any resale, or a requirement that the new holders have generation resources and loads for the points specified in the long-term firm transmission rights, or the Commission’s suggestion that long-term firm transmission right holders only be able to return their long-term firm transmission rights to the transmission organization.

456. SDG&E states that any reassignment mechanism that links specific long-term firm transmission rights to individual loads will become administratively burdensome if the switching of load between load serving entities is active, with the transmission organization potentially forced to track thousands of long-term firm transmission rights that are reduced to fractions of megawatts.

457. Alcoa states that an end user that acts as its own load serving entity must be afforded the same opportunity as a load serving entity to reassign its long-term transmission rights to another entity that acquires a service obligation for its load.

Compensation Issues

458. Some commenters provided recommendations concerning what, if any, compensation should be paid when a long-term firm transmission right is reassigned to a successor load serving entity.¹¹⁸ APPA states that compensation is a matter to be dealt with by the transferee and transferor load serving entities. BPA states that all of the costs and liabilities associated with the transferred rights should follow to the new load serving entity. However, BPA recommends that limitations on re-assignment, particularly issues relating to compensation pricing policy, be left to the regions to resolve.

459. The CAISO submits that the load serving entity that has lost a portion of its service obligation should not be compensated for any long-term firm transmission rights it transferred to another load serving entity for that load. AF&PA states that, if long-term firm transmission rights are paid for by the holder at fair market value, they should be property of the holder, and should be assignable by the holder for value or otherwise in its discretion. Ameren recommends that there be no compensation for firm transmission rights returned to the transmission organization by a load serving entity. Santa Clara states that if the holder is carrying the risk that the congestion cost could increase and create more value or decrease and make it less valuable, the holder should not be forced to return the rights at the cost at which they were allocated to them.

Trading

460. A number of comments focused on the question of whether or not long-term firm transmission rights should be tradable.¹¹⁹ AEP supports the concept of trading long-term transmission rights as an appropriate way to facilitate risk management by load serving entities. TANC argues that, if after meeting its native load obligations an entity has surplus transmission rights, the market is enhanced by the availability of such surplus rights. Cinergy believes that long-term transmission rights acquired under FPA section 217(b)(4) should be fully tradable. Also, Cinergy encourages the Commission to allow market participants that acquire long-term transmission rights by investing in transmission upgrades to trade those rights for a profit, as that provides even greater incentive to build transmission improvements.

461. In SMUD’s view, giving customers the right to assign their unused physical transmission rights temporarily will reduce the likelihood of hoarding and will serve as a congestion management tool. In NRECA’s view, allowing long-term rights to be tradable would allow load serving entities a way to reconfigure their portfolios of long-term firm transmission rights as their situations change.

462. Ameren states that making long-term firm transmission rights fully tradable among market participants would enhance the efficiency of the congestion management program, as it would enable the firm transmission rights to go to those parties that value them most highly. It also would allow entities that are not load serving entities to obtain long-term firm transmission rights, assuming they value them highly enough to win them in the market.

463. PG&E states that, because shifts in service obligations may be temporary and may be reversed, reassignment of long-term firm transmission rights with shifts in service obligations and power supply arrangements should be conditioned on assurances that future shifts of such service obligations and power supply arrangements are accompanied by a return of the accompanying long-term firm transmission right. PG&E argues that, while it would be appropriate to allow trading or transfer of the long-term firm transmission right for interim periods, the long-term firm transmission right itself should remain attached to the service obligation and not be separately transferable.

464. IPL argues that there should not be a requirement that long-term rights are tradable, and recommends that the Commission allow the transmission organizations flexibility to specify the general terms of reassignments related to load shifts. Public Power Council claims that making the rights fully tradable raises fairness questions if the seller received a preference due to the use of the right to meet a service obligation and the buyer did not. If the rights were sold to another load serving entity for the purpose of meeting that other entity’s service obligations, however, Public Power Council believes that the fairness issue would be avoided.

Gaming and Arbitrage

465. A number of commenters express concern that, if the long-term firm transmission rights are reassignable and tradable, a load serving entity might have an incentive to acquire excess long-term firm transmission rights for financial gain.¹²⁰ EPSA states that it would be inappropriate for the Commission to allow utilities to profit from the sale of any long-term firm transmission rights that are obtained via a preferential priority. EPSA claims that vertically-integrated utilities with long-term contracts could hoard long-term firm transmission rights, blocking smaller retail providers from gaining access or entry to markets and competing effectively.

466. Ameren claims that concerns about possible arbitrage are addressed by its proposal to place a limitation on firm transmission right nominations based on a load serving entity’s load. APPA recommends that load serving entities holding long-term firm transmission rights must have in their generation portfolios actual resources (owned or contracted for) and loads corresponding to the receipt and delivery points that the long-term firm transmission rights cover. APPA also suggests restrictions on the resale of long-term firm transmission rights in the form of minimum hold periods and minimum periods for resale of any right. However, APPA states that any such restrictions would have to be balanced against the need to “recycle” long-term firm transmission rights to ensure the most efficient use of the transmission rights. APPA states that a reasonable approach would be the Commission’s suggestion that holders of long-term firm transmission rights be permitted only to return their long-term firm transmission rights to the RTO, and not to earn any profit on their direct sale to another market participant. TAPS claims that its recommended dispatch-contingent firm transmission rights would have very limited appeal for market participants interested in firm transmission right speculation.

467. Minnesota Power urges the Commission not to allow creation of a large secondary market in which market participants are able to inflate the price of long-term transmission rights or to use the long-term transmission rights as an economic position in the market. Minnesota Power suggests that the long-term transmission rights should be directly linked to, and tradable only with, the underlying generation rights or long-term purchase rights.

Commission Conclusion

468. The Commission will adopt guideline (6) as proposed in the NOPR, but will provide transmission organizations and their stakeholders with flexibility to determine specific rules for reassignment of long-term firm transmission rights. We note that most, if not all, transmission organizations now have rules governing the reassignment of firm transmission rights when load migrates from one load serving entity to another. The introduction of long-term firm transmission rights should not in itself require a change in the basic structure of these rules. In at least some transmission organizations, reassignment is achieved through a reallocation of auction revenue rights, with a provision to allow the auction revenue rights to be converted into firm transmission rights.

469. In general, the issue of reassignment should arise only in the context of firm transmission rights (short-term or long-term) that are allocated preferentially to a load serving entity in accordance with guideline (5). If a load serving entity acquires firm transmission rights through an auction or as a result of funding a transmission upgrade, it should not be required to reassign such rights because any entity is free to acquire firm transmission rights in this manner. Also, a load serving entity that acquires long-term firm transmission rights to support the financing of a new generating facility should not, in general, be required to give up those rights simply because some of its load migrates to another load serving entity. However, a possible exception may arise if the original load serving entity were to lose so much of its load that the total of its long-term firm transmission rights exceeds its remaining load. In this case, as noted by PG&E, some mandatory reassignment may be justified.

470. The Commission believes that all long-term firm transmission rights should be tradable. Allowing tradability provides the load serving entity with flexibility to manage its transmission rights portfolio and helps to ensure that long-term firm transmission rights go to the market participants that value them most highly. Reassignments may be temporary. However, long-term firm transmission rights that the load serving entity obtains preferentially through an allocation process should be tradable only with the proviso that any trades may be subject to recall if load migrates to another load serving entity. Making the long-term firm transmission rights subject to recall ensures that they can be reassigned if necessary to follow migrating load, consistent with section 217(b)(3)(A) of the FPA. We note, however, in a transmission organization where reassignment is accomplished through a reallocation of auction revenue rights, rather than the firm transmission rights themselves, there may be no need for such a proviso. In this case, reassignment would be accomplished through a financial transfer, allowing the actual long-term firm transmission rights to remain with the original load serving entity. This should satisfy the CAISO’s request that the Commission permit either the allocated long-term firm transmission rights or their equivalent financial value to be transferred from one load serving entity to another to reflect a transfer of load serving obligation. In addition, allocating auction revenue rights would also eliminate any need to place restrictions on reassignments, such as requiring the successor load serving entity to hold a supply contract that uses the same source/sink pair used by the original load serving entity.

471. Also, when reassignment of auction revenue rights or firm transmission rights is mandated due to a shift in load serving responsibility, any cost responsibilities associated with the holding of such rights, such as payment of transmission access charges, should shift from the original load serving entity to the successor load serving entity. No other compensation should be required. Again, the specific rules for accomplishing this should be left to the transmission organization and its stakeholders. With regard to firm transmission rights or long-term firm transmission rights that are acquired by auction or as a result of funding a transmission upgrade, the Commission believes (as noted above) that in general there should be no restrictions on trading such rights. Transfers should be permitted to occur at prices negotiated by the buyer and seller.

472. In response to Alcoa, the Commission notes that an end user that is permitted under state law to participate in wholesale markets may acquire, trade and reassign long-term firm transmission rights in accordance with guideline (6) in the same manner as other load serving entities, as discussed above under guideline (5).

Guideline (7) – Auction Not Required

473. As proposed in the NOPR, guideline (7) stated that the initial allocation of the long-term firm transmission rights shall not require recipients to participate in an auction. The Commission noted that, currently, most transmission organizations either allocate transmission rights directly to eligible parties, or allocate auction revenue rights directly and then conduct a transmission rights auction in which parties with and without allocated rights can participate. If an auction model is adopted or continued by the transmission organization, the Commission proposed to require that any long-term rights allocated as auction revenue rights be capable of being directly converted to transmission rights without participation in the auction. This was to allow any party that feels uncertain about valuing its rights commercially to have them allocated directly. This guideline did not preclude interested parties with long-term rights from participating in the auction if they choose.

Comments

General Support for Guideline (7)

474. Many commenters express strong support for proposed guideline (7).¹²¹ For example, APPA states that the long-term firm transmission right allocation called for under guideline (7) is appropriate because it comports with section 217(b)(4) of EPAct 2005. Also, APPA believes that it at least partially restores the transmission rights that APPA members in transmission organization regions lost when full LMP-based markets were implemented.

475. NRECA claims that, because load serving entities pay the largest share of the existing and future transmission system costs, they should not have to bid for the right to use a system that they paid for and that was planned and built to serve their needs. However, NRECA states that it is not opposed to the use of auctions for residual or secondary rights and for voluntary dispositions of primary rights, consistent with current practice. PG&E recommends that, if any additional long-term firm transmission rights remain after the initial allocation process, such firm transmission rights should be made available for auction. PG&E states that, as experience with long-term firm transmission rights in LMP environments shows them to be functioning in an efficient and predictable manner, auctions could increasingly be used for long-term firm transmission right issuance without detracting from the goals of EPAct 2005. Public Power Council states that it does not endorse the use of an auction, but if an auction is used to allocate scarce rights, the Commission should permit only entities with a preference to participate in the auction in order to ensure that the price is not artificially inflated.

476. Central Vermont states that guideline (7) must be modified to provide parties with certainty concerning the value of their directly-allocated long-term transmission rights. Specifically, parties will not have certainty about the value of their long-term transmission rights if the initial allocation of rights also includes exposure to negative congestion charges between points, which are unavoidable and very difficult to assess in value.

477. In reply comments, APPA and New England Public Systems disagree with the contention of some commenters that FPA section 217(b)(4) permits the Commission to make a load serving entity’s ability to obtain a long-term firm transmission right, or the financial equivalent thereof, turn on whether the load serving entity is willing to pay more than other bidders. New England Public Systems states that transmission customers were not required to outbid other potential customers for firm transmission rights under the Order No. 888 regime in place prior to the advent of LMP-based markets, and load serving entities with service obligations met through long-term power supply arrangements should not be required to do so now.

478. TAPS notes that Midwest ISO argues that it would be difficult for a transmission organization to value the congestion hedge provided by a long-term right. TAPS argues that, by advocating allocation through auction, a transmission organization essentially assigns this same task to load serving entities that have far less information or control over the planning and expansion process.

Support for the Use of an Auction

479. Many commenters express strong support for the use of an auction mechanism for allocating long-term firm transmission rights and object to what they view as guideline (7)’s prohibition on using an auction for that purpose.¹²² For example, IPL states that the guidelines should not preclude rights allocated by auction because transmission organizations and stakeholders should be allowed to determine whether an auction mechanism is the most equitable and efficient way to allocate rights. IPL contends that EPAct 2005 does not preclude auctions, does not specify a particular allocation methodology, and does not require that load serving entities receive rights for free. IPL argues that EPAct 2005 merely requires that load serving entities be able to acquire and use such rights and therefore the guidelines should not eliminate this flexibility. Also, Cinergy states that it strongly opposes guideline (7), claiming that there is no support in FPA section 217 for the notion that auctions should be foreclosed. Cinergy argues that auctions are the best available means of determining the initial value of transmission rights and it makes no sense for the Commission to exempt load serving entities from participating in them when that is the mechanism other market participants use. In Cinergy’s view, guideline (7) ensures that no market mechanism will be available to address the unduly discriminatory free-rider problem caused when only some load serving entities obtain long-term rights.

480. DC Energy believes that, to the maximum extent possible, market-based solutions should be used to allocate and to establish prices for firm transmission rights. DC Energy asserts that robust auctions will maximize the value of firm transmission rights and increase overall market efficiency by allowing the parties that value firm transmission rights the most to acquire them. It believes that transmission users that acquire firm transmission rights outside of an auction process may pay less for firm transmission rights than those who would bid on them, resulting in a decrease in auction revenues which translates into an increase in transmission costs. Furthermore, DC Energy argues that transmission customers that hold firm transmission rights without having to pay fair market value for them will not utilize generation resources in the most efficient manner and will cause a sub-optimal dispatch due to indifference over supply options.

481. In reply to APPA’s argument that longer-term transactions should be favored because they will send the proper economic signals for transmission facilities construction based on long-term power supply commitments, Coral Power argues that appropriate economic signals cannot be established under a system that does not auction rights on a non-discriminatory basis. It claims that transmission paths that are valued highly in successive short-term auctions are candidates for upgrades or for other solutions that might be more economic, such as the siting of local generation. Coral Power argues that a system that combines preferential allocations in long-term firm transmission rights with short-term competitive auctions for available transmission rights will only distort the market.

482. Morgan Stanley states that the Final Rule must not allow for the allocation of long-term firm transmission rights without the use of an auction mechanism based on sound market principles and uniform credit eligibility standards. Morgan Stanley argues that allocation of long-term firm transmission rights through a non-discriminatory auction, for terms that can be liquidly traded, will generate needed price signals for market participants. Conversely, in Morgan Stanley’s view, preferential allocation of long-term firm transmission rights likely would: (1) reduce the amount of capacity available to the market; (2) result in a barrier to competitive entry; (3) cause price signals to be blunted; (4) facilitate hoarding, and (5) create an increased bias in favor of regulatory outcomes as opposed to a market-based solution.

483. DTE recommends that, once auction revenue rights or long-term firm transmission rights are allocated to market participants, the regional stakeholder process should determine under what future conditions, if any, long-term firm transmission rights may be auctioned or traded. It states that this is a long-term market development issue that will be unique to each region.

484. National Grid states that, to the extent that there are uncertainties as to a customer’s ability to obtain such rights in an auction, the regions can address that concern through consideration of rights of first refusal or other auction rules. National Grid adds that nothing prevents the holder of auction revenue rights from bidding for the underlying transmission rights and/or trading the auction revenue rights for transmission rights. National Grid states that, in keeping with the Commission’s general approach to allow regions the flexibility to achieve consensus, the Commission should strike guideline (7) or revise it to allow for the possibility of mandatory auctions and the assignment of auction revenue rights if the regions deem these features to be appropriate.

485. EPSA states that in markets with allocation of auction revenue rights or similar rights, regions may choose to continue to allocate such rights without the use of an auction. However, EPSA states that auction revenue rights are not the same as financial transmission rights and stakeholders may or may not include them in long-term firm transmission right programs. EPSA submits that the guidelines should be clear on what they assume will be included as baseline requirements or elements for the rules that will underpin all long-term firm transmission right programs in organized markets, and should not preclude a region from requiring an auction process to transparently value all firm transmission rights, including long-term firm transmission rights. AEP states that a load serving entity should always have the right to directly convert auction revenue rights into firm transmission rights through the auction process, and would be comfortable with such a conversion taking place outside of the auction process.

486. SDG&E states that load serving entities that have both long-term and short-term power supply agreements have "reasonable needs," and the statute does not value the "needs" of one more than the other. SDG&E believes firm transmission right auctions are useful because they allow all load serving entities to seek whatever mix of firm transmission rights they believe would he most valuable in terms of hedging their power supply portfolios, thereby enhancing the load serving entity’s attractiveness to potential loads. AF&PA recommends that, in the absence of permitting auctions, the Commission should clearly provide guidance as to the appropriate methodology for determining the value of such long-term hedges.

487. Reliant proposes that guideline (7) be modified to state: “Guideline (7): The initial allocation of the long-term firm transmission rights shall provide for a non-discriminatory and transparent auction but not require recipients to sell their rights into that auction.” APPA, however, states that it opposes this language because it is too vague.

ISO-NE’s Auction Mechanism

488. ISO-NE strongly urges the Commission to provide transmission organizations and their stakeholders with the flexibility to consider allocating long-term firm transmission rights by auction, consistent with existing New England practices. ISO-NE argues that the economic benefits of auction-based allocation are well understood and have been accepted by the Commission in its orders on New England’s current market design and in other proceedings. According to ISO-NE, entities such as PJM that initially allocated firm transmission rights directly to load have shifted to an auction-based allocation for compelling reasons. ISO-NE adds that, if the Commission were to preclude an allocation by auction, it is unclear how the long-term firm transmission right acquired by a load serving entity auction revenue right holder would be valued.

489. NEPOOL states that a requirement that long-term firm transmission rights be directly allocated to load serving entities has the potential to be especially disruptive to an organized market such as in New England, where there is a mature auction mechanism in place that allocates one hundred percent of the firm transmission rights. According to NEPOOL, that same auction mechanism could be used to allocate long-term firm transmission rights, along with all other firm transmission rights, while still ensuring that load serving entities are able to acquire the long-term firm transmission rights they need. This protection of load serving entities could be assured, for example, through a tie-breaker mechanism, under which, if a load serving entity with a long-term commitment and another market participant are bidding the same price for an long-term firm transmission right, the load serving entity would have priority and would get the long-term firm transmission right. NEPOOL states that, in New England, load serving entities receive a direct allocation of auction revenue rights and would be able to use their auction revenue right revenues to bid into the auction for long-term firm transmission rights, thus providing them the ability, combined with a tie-breaker mechanism, to acquire the long-term firm transmission rights they need. Also, Morgan Stanley states that it supports this direct allocation of auction revenue rights so long as such direct allocation remains independent from the allocation of long-term firm transmission rights.

490. New England Public Systems counters that the auction revenue right/firm transmission right structure in New England is inadequate to hedge congestion risk and is not equivalent to firm transmission even on a short-term basis; thus, simply extending the term of such products cannot satisfy the statute’s requirements. According to New England Public Systems, most auction revenue rights in New England are allocated among congestion-paying load serving entities on a zonal load ratio share basis. In effect, each such load serving entity is paid the auction clearing price of an average firm transmission right in the zone times the ratio of its peak load to the zonal peak load. New England Public Systems argues that there is no assurance that revenues thus received will be sufficient to enable the load serving entity to acquire a specific firm transmission right across a particularly congested path. New England Public Systems asserts that auction revenue rights that (a) do not necessarily cover the cost of transmission congestion at a specific location, and (b) cannot be converted directly to long-term firm transmission rights that do hedge the risk of transmission congestion at a specific location are not the “equivalent” of the firm transmission rights that section 217(b)(4) requires.

491. Also, New England Public Systems states that an auction revenue right in itself is not the financial equivalent of a firm transmission right, because auction revenue right revenues generally are socialized and distributed on the basis of zonal load ratio share. According to New England Public Systems, if a load serving entity is outbid for a valuable firm transmission right, it receives only a fraction of the auction revenue generated by the winning bid yet remains exposed to congestion along the associated path. New England Public Systems states that, aside from the socialization issue, even path-specific long-term auction revenue rights could leave their holders exposed to significant congestion costs unless there is a right to convert long-term auction revenue rights to long-term firm transmission rights.

492. Finally, in reply comments, New England Public Systems notes that ISO New England argues that entities such as PJM that initially allocated firm transmission rights directly to load have shifted to an auction-based allocation for compelling reasons. However, New England Public Systems contends that PJM’s auction is not the exclusive means of acquiring firm transmission rights in that region. It notes that PJM permits self-scheduling of firm transmission rights (in essence, allowing an auction revenue right holder to convert its auction revenue right into an firm transmission right) under some circumstances, but requires that the self-scheduled firm transmission right have exactly the same source and sink points as the auction revenue right. According to New England Public Systems, these aspects of PJM’s existing system for allocation of short-term transmission rights fatally undercut ISO New England’s attempt to rely on the PJM precedent as support for extending the New England approach (which lacks direct conversion rights) to long-term firm transmission rights.

NYISO’s Auction Mechanism

493. NYISO argues that the guideline (7) proposal does not apply to it because it has already engaged in an allocation process that assigned the rights to transmission congestion contract auction revenues to the New York transmission owners. NYISO claims that the same allocation would apply to any longer-term transmission congestion contracts that are issued as a result of this proceeding. NYISO states that its transmission congestion contract auction and allocation rules have already been approved by the Commission and are grandfathered under section 217(c) of the FPA. Therefore, according to NYISO, it does not appear that Proposed guideline (7) is at odds with existing NYISO rules. NYISO states that, in any event, the Commission should clarify that Proposed guideline (7) is not intended to discourage auctions for long-term firm transmission rights beyond the initial allocation of revenue rights.

494. In response to NYISO, NYAPP states that section 217(c) of EPAct 2005 does not serve to "grandfather" any RTO allocation mechanisms under section 217(b)(4), only subsections (b)(1), (b)(2), and (b)(3). The Commission's authority to modify a transmission organization's current methods for allocation of transmission rights is specifically preserved for the implementation of section 217(b)(4). In NYAPP’s view, NYISO should still have to comply with guideline (7).

PJM’s Auction Mechanism

495. Reliant states that any allocation of long-term rights should include a transparent auction process that allows participants to evaluate the value of such rights, and that the existing PJM auction revenue rights process is a good market example that meets the varied needs of all market participants.

496. Strategic Energy argues that any allocation of transmission hedges should be provided via auction revenue right, with the option, but not the obligation, to convert the auction revenue right to an firm transmission right on a concurrent source/sink path, as is the current PJM practice. Strategic Energy claims that the auction revenue right facilitates load migrations and the equitable migration of the value of transmission hedges with the load. However, Strategic Energy states that its support of the auction revenue right/firm transmission right allocation and auction model is mitigated by concern that initial allocation of auction revenue rights should not be provided to long-term uses to the detriment of short-term uses, such as annual or shorter-term hedging frequently employed by competitive retail suppliers.

Commission Conclusion

497. We will adopt guideline (7) as proposed in the NOPR. However, as we explain below, we clarify that guideline (7) does not preclude a transmission organization from using an auction to allocate long-term firm transmission rights; it only precludes requiring a load serving entity to submit a winning bid in an auction in order to acquire long-term firm transmission rights.

498. The Commission agrees with commenters such as APPA, NRECA and CMUA that argue that load serving entities that are obligated to pay the embedded costs of the transmission system should be able to receive an equitable share of long-term firm transmission rights without having to submit a competitive bid for those rights. As APPA points out, guideline (7) provides the load serving entity with transmission rights that are more akin to long-term network and point-to-point service rights of Order No. 888 than to the short-term rights offered in today’s organized electricity markets. Also, the Commission does not interpret EPAct 2005 as requiring the use of an auction to allocate long-term firm transmission rights, or as preventing the Commission from modifying the allocation method currently used by any transmission organization. As we have noted elsewhere in this preamble, section 217(b)(4) of the FPA is not included in the list of subsections that section 217(c) states shall not affect existing or future transmission organization allocation methodologies.

499. Nevertheless, the Commission agrees with those commenters that point out the many benefits that auctions can bring to the allocation process. As DC Energy notes, auctions can maximize the value of transmission rights and increase overall market efficiency by allowing the parties that value firm transmission rights the most to acquire them. Also, as Coral Power notes, transmission paths that are valued highly in successive short-term auctions are candidates for upgrades or for other solutions that might be more economic, such as the siting of local generation. We note, however, that some of these commenters interpret guideline (7) as precluding the use of an auction to allocate long-term firm transmission rights. For example, Cinergy asserts that guideline (7) ensures that no market mechanism will be available. Further, Cinergy states that there is no support in FPA section 217 for the notion that auctions should be foreclosed and that it makes no sense for the Commission to exempt load serving entities from participating in them when that is the mechanism other market participants use.

500. The Commission clarifies that we do not intend for guideline (7) to foreclose all transmission right auctions. Indeed, the Commission believes that an auction can be an integral part of a process for the fair and efficient allocation of long-term firm transmission rights that also satisfies the fundamental requirement of guideline (7). For example, one such allocation process is the method now used by PJM to allocate annual firm transmission rights. As noted by New England Public Systems, PJM uses a process that first allocates auction revenue rights to load serving entities and then allows each load serving entity the option to convert its auction revenue rights directly into annual firm transmission rights with identical sources and sinks. In effect, each load serving entity in PJM may, at its option, bid the value of its auction revenue rights into the auction as a “price-taker” knowing that it will win the bid for the firm transmission rights that correspond to the sources and sinks of its respective auction revenue rights. As a price-taker, the load serving entity will not know in advance the price it must pay for the firm transmission rights that it acquires, but it is secure in the knowledge that the value of its auction revenue rights will cover exactly the cost of the firm transmission rights. Such a process could be readily adapted to the allocation of long-term firm transmission rights.

501. The principal advantage of this approach is that, consistent with guideline (7), it allows the load serving entity to obtain its long-term firm transmission rights without having to submit an explicit price bid in an auction, yet at the same time it exposes the load serving entity to a competitive auction price signal that will promote efficient-decision making. Of course, as long as the load serving entity desires long-term firm transmission rights with the same source and sink points as its allocated auction revenue rights, it may simply bid the value of those auction revenue rights into the auction and receive those rights. However, because it is exposed to the auction price signal, the load serving entity acquires information that may cause it to adopt a different bidding strategy in subsequent auctions. For example, if the auction clearing price for the long-term firm transmission rights that correspond to a load serving entity’s auction revenue rights is very high, while the clearing price for other long-term firm transmission rights is low, the load serving entity may determine that it would prefer to submit an explicit price bid for the lower-priced rights and forego the opportunity to convert its auction revenue rights into the corresponding long-term firm transmission rights. In this way, the load serving entity obtains valuable, albeit lower-priced, rights and also receives auction revenues equal to the difference between the value of its auction revenue rights and the total amount it must pay for the lower-priced rights. In addition, the higher-priced rights that correspond to the load serving entity’s auction revenue rights are now made available to other auction participants that value them more highly, thus achieving the goal identified by DC Energy.

502. In this regard, we note that DC Energy is concerned that transmission customers that obtain firm transmission rights without having to pay fair market value for them will not utilize generation resources in the most efficient manner, and Coral Power argues that this could result in a highly inefficient generation siting decision. Similarly, Morgan Stanley is concerned that guideline (7) will lead to competitive entry barriers, hoarding and blunted price signals. We disagree. Even when a load serving entity holds auction revenue rights with a direct conversion right, it can be expected to behave in an economically rational manner because it always has an incentive to forego its conversion right if it stands to gain financially from submitting a price bid for alternative rights in the long-term firm transmission rights auction.

503. EPSA notes that in markets with allocation of auction revenue rights, regions may choose to continue to allocate such rights without the use of an auction. However, EPSA states that auction revenue rights are not the same as firm transmission rights and wants the guidelines to be clear on what elements must be included in all long-term firm transmission rights programs. Also, Strategic Energy states that initial allocation of auction revenue rights should not be provided to long-term uses to the detriment of short-term uses. Although the Commission believes that allocation methods that combine a direct allocation of auction revenue rights with a transmission rights auction offer many advantages, we will not prescribe here the process by which a transmission organization must allocate auction revenue rights, or ultimately long-term firm transmission rights, to a load serving entity or other market participant. We recognize that, today, transmission organizations use a variety of allocation methods, but no one method has emerged as being clearly superior to all others. We, therefore, will provide each transmission organization and its stakeholders with the flexibility to propose an approach that meets regional needs and satisfies each of the guidelines in this Final Rule, subject to Commission approval.

504. A number of comments were directed specifically at the auction mechanisms currently used by ISO-NE and NYISO. Based on the comments of New England Public Systems, it appears that the allocation process now used by ISO-NE does not permit a direct conversion of auction revenue rights into corresponding firm transmission rights. If so, the process does not meet the requirements of guideline (7) for allocating long-term firm transmission rights and must be modified. Also, with respect to NYISO’s auction mechanism, NYAPP is correct in noting that section 217(c) of EPAct 2005 does not prevent the Commission from modifying the allocation processes of any transmission organization under section 217(b)(4). Therefore, contrary to the view of NYISO, guideline (7) applies to its allocation process in the same way that it applies to the allocation processes of all other transmission organizations.

505. Finally, Central Vermont states that guideline (7) must be modified to provide market participants with certainty concerning the value of their long-term transmission rights if the initial allocation of rights includes exposure to negative congestion charges. We will not modify guideline (7) to address this concern. However, we will provide the transmission organization and its stakeholders with flexibility to include, within the proposed allocation process, specific rules to address such matters should they arise.

Guideline (8) – Balance Adverse Economic Impacts

506. As proposed in the NOPR, guideline (8) stated that the allocation of long-term firm transmission rights should balance any adverse economic impact between participants receiving and not receiving the right. The NOPR noted that, to the extent that the capacity of the transmission system is encumbered by entities holding long-term firm transmission rights, entities that prefer short-term transmission rights, such as load serving entities operating in retail states, will have fewer rights available to them than they have under current annual allocation schemes. In addition, to the extent awarded long-term rights become infeasible due to unforeseen changes in the physical properties of the transmission system, the payment obligations to holders of long-term firm transmission rights would have to be funded by others.

507. The NOPR stated that, in general, it should be possible for the transmission organization to introduce long-term firm transmission rights in a way that balances economic impacts, for example, by placing a limit on the amount of system capacity that is available to support long-term rights. Also, the NOPR stated that if the long-term right is an “option” right that encumbers more system capacity than an “obligation” right, the holder of such a right could be required to assume greater cost responsibility.

508. The NOPR noted that the transmission organization might provide for a secondary market or auction that would provide an opportunity for transmission customers to obtain long-term rights on either a long-term or short-term basis from those holding long-term rights. The NOPR proposed to allow the transmission organization flexibility to propose methods for pricing transmission rights and related services that are appropriate for its region and are the product of a stakeholder process.

509. The NOPR asked for comments on any measures that should be adopted to protect against the impacts of a decision by a holder of an “obligation” right to leave the transmission organization when the feasibility of other transmission rights depend on that holder’s counterflows.

Comments

General Comments on the Need for guideline (8)

510. Several commenters argue that the principles embodied in guideline (8) are important, and some believe that they should be the primary focus in the allocation of long-term firm transmission rights.¹²³ AF&PA states that principles embodied in guideline (8) should be seen as controlling the application of all the other guidelines. AF&PA states that the Commission must not return to a pre-OATT world where certain entities claim the exclusive right to use the transmission system for their benefit, and all competing usage is viewed as incremental or marginal.

511. Midwest ISO states that the nature and scope of financial hedging instruments for users of long-term transmission ultimately should be defined in well-functioning markets. Midwest ISO argues that any mandate that transmission organizations provide such instruments must carefully balance the potential benefits to some market participants against the potential costs to other market participants. IPL states that, as proposed, the guidelines are not balanced and do not meet this standard.

512. NYISO believes that it is possible that long-term firm transmission rights can be introduced without inequities, particularly if transmission organizations are permitted to retain existing systems without major changes. CMUA also believes the equity concerns raised in guideline (8) may in practice not prove difficult to reconcile. Nevertheless, CMUA is concerned that transmission organizations and certain stakeholders might attempt to use guideline (8) to effectively eviscerate long-term firm transmission rights, in violation of FPA section 217(b)(4).

Comments Suggesting that guideline (8) is not Needed

513. Some commenters argue that guideline (8) is not needed or requires clarification.¹²⁴ For example, BPA suggests that this guideline be deleted from the Final Rule, as the issues it raises can be addressed under other guidelines. Furthermore, BPA states that it is not appropriate to require transmission organizations to balance the adverse economic impacts between those receiving the right and those that do not.

514. TAPS states that guideline (8) should be removed. However, if some “reasonableness” guideline is retained, it should be reworded as “avoidance of undue impacts,” to recognize that some impacts are “due” and reasonable. In addition, TAPS is concerned that guideline (8) establishes criteria that are not called for by section 217(b)(4) and could be used to undermine Congress’s clear directive. In response, Midwest ISO agrees with TAPS that section 217(b)(4) does not expressly require that a balance be struck between those that receive long-term firm transmission rights and those that do not. However, Midwest ISO claims that section 217(b)(4) also does not expressly require the Commission to provide load serving entities unlimited and fully-funded long-term firm transmission rights to hedge congestion costs associated with long-term power supply arrangements.

515. In addition, TAPS notes that the NOPR describes as an adverse impact the potential that the long-term rights will result in the availability of fewer rights for entities that prefer short-term rights. TAPS states that this has always been the case under the Order 888 OATT. TAPS claims that a transmission provider is not entitled to turn down a long-term firm request to keep capacity available for those who wish to make short-term or non-firm use of the system.

516. Industrial Consumers argues that, if the total available rights (short- and long-term) are insufficient to meet the needs of end-use customers (an indication that the owners of the transmission system are mismanaging the maintenance and planning of their assets) it may be necessary to ration the rights, but still preserve the preference to holders of long-term rights. In Industrial Consumers’ view, the real issue here is not that economic interests are not appropriately balanced, but that transmission owners have abrogated their responsibilities.

517. Alcoa states that it is not clear whether the Commission intends that there will be a redistribution of costs and benefits between those entities holding firm transmission rights and those that do not.

Conflicts between Guideline (8) and Other Guidelines

518. Cinergy states that it completely agrees with guideline (8), but claims that this guideline is not achievable in light of the other guidelines proposed by the Commission. Midwest ISO maintains that, while the implementation of this guideline is essential, the implementation would be difficult because it is in direct conflict with the requirement for full funding of long-term firm transmission rights (guideline (2)) and the priority extended to long-term firm transmission right holders (guideline (5)). NYISO states that the same problem applies to proposed guideline (4) to the extent that the Commission interprets it to require non-market based renewal rights for long-term transmission rights. National Grid recommends that the Commission treat these conflicting guidelines more as goals rather than minimum requirements.

Need for Regional Flexibility in the Application of Guideline (8)

519. SoCal Edison states that, because issues of balance are intricate and require both judgment and familiarity with the local market and system issues, the Commission should leave the specifics of such a balance to the transmission organizations. Similarly, IPL urges the Commission to allow the transmission organization the flexibility to develop certain long-term transmission rights parameters such as pricing and availability.

Importance of Protecting the Status Quo

520. Some commenters recommend that guideline (8) be implemented in a way that protects existing short-term rights holders and market rules.¹²⁵ For example, Constellation states that the Commission should not adopt policies that harm the existing competitive wholesale and retail markets. Constellation asserts that a policy that articulates a preference for long-term supply arrangements is such a policy. Constellation states that, if the Commission decides to unwind the current, competitive market structure by setting aside existing transmission capability for long-term uses, then guideline (8) must be a critical factor in the Commission’s approval of any long-term firm transmission right proposal so that the Commission can ensure that there are no adverse impacts on other market participants. In Constellation’s view, any long-term firm transmission right proposal must identify harm that will be caused by its implementation, such as the reduction of hedging opportunities for shorter-term uses, and propose mitigation for such adverse consequences.

521. EEI argues that since load serving entities and other transmission customers in PJM, Midwest ISO, NYISO and ISO-NE have made supply and investment decisions in reliance on Commission-approved allocations, the Commission should not reverse its prior decisions by changing these allocations and market structures. EEI argues that it would be disruptive and unfair to require any changes to the underlying agreements and understandings that formed the design of these four transmission organizations. In response, APPA argues that the equities cut both ways. APPA claims that during the transition to “Day Two” transmission organization markets, many public power load serving entities lost valuable Order No. 888 OATT and grandfathered transmission rights, leaving their power supply arrangements subject to unanticipated transmission congestion charges. According to APPA, these entities have since been attempting to conduct business under a construct of locational marginal pricing and firm transmission rights that is essentially hostile to their business model. In addition, APPA argues that Congress contemplated that making long-term firm transmission rights available to load serving entities under section 217(b)(4) might indeed require revisiting the prior allocation of firm transmission rights in RTO regions. Further, NRECA claims that Congress has already issued the mandate and determined the appropriate balance of costs and benefits; it has not authorized the Commission or transmission organizations to undertake a cost/benefit analysis of whether the statutory mandate is justified or the balance struck by statute appropriate.

Issues Regarding Cost Shifting

522. Several commenters express concern that requiring transmission organizations to make available long-term firm transmission rights could harm market performance and shift costs unnecessarily or unfairly among market participants.¹²⁶ For example, Strategic Energy submits that introduction of multi-year rights will cause cost shifts if holders of such rights are allocated congestion risk coverage greater than that accorded to other parties.

523. BP Energy states that to ensure the balancing of any adverse economic impacts, guideline (8) should be modified to state explicitly that the allocation of incremental long-term firm transmission rights to one party can not result in subsidization of those rights by other parties, i.e., there can be no significant shifting of generation redispatch costs or fixed transmission costs as the result of new supply arrangements entered into by load serving entities receiving long-term rights to parties not subject to those agreements.

524. BP Energy also argues that, if parties seeking long-term rights are able to shift congestion costs to others, they will have no disincentive to enter into supply arrangements that reduce (because of their relative location on the grid) the absolute amount of transmission rights that an organized market can allocate while maintaining revenue sufficiency. Similarly, in ISO-NE’s view, allocation of free long-term firm transmission rights to load serving entities versus an auction of long-term firm transmission rights to generators, traders and other entities creates equity and distortion issues.

525. Some commenters address the problem of balancing adverse impacts in light of the NOPR’s proposed requirement for full funding of long-term firm transmission rights.¹²⁷ For example, IPL argues that the adverse economic impact of a long-term financial transmission rights allocation stems in large part from the shortfall funding obligation. IPL urges the Commission not to require entities to share this obligation to the extent those entities do not receive benefits from the allocation and do not bear direct responsibility for congestion costs. According to Midwest ISO, the Commission’s proposal to guarantee load serving entities priority of existing transmission capacity with fully-funded long-term firm transmission rights for the entire capacity of their supply contracts may result in significant costs on other market participants, increase the costs of transmission organization membership, and significantly reduce the availability of firm transmission rights to meet short-term firm transmission right holders’ requests.

Pricing and Cost Responsibility for Long-Term Firm Transmission Rights

526. Some commenters state that they agree with the NOPR’s statement that "to the extent that the long-term right relieves the holder of the obligation to pay congestion costs, the value of that congestion hedge should be reflected in the price of the long-term right, insofar as possible."¹²⁸ In this regard, BP Energy argues that two scenarios are apparent. First, where the same or electrically similar (mutually exclusive) rights are sought by multiple parties, the party willing to pay the most might acquire them through a competitive process, such as an auction. Alternatively, the party seeking such long-term rights can, consistent with guideline (3), pay for the necessary “transmission upgrades and expansions” to receive the “rights made feasible” by that expenditure. In the case where existing capacity is sought by multiple parties, and auctions are not available, BP Energy argues that the only equitable and reasonable method of capacity allocation, consistent with the Commission’s holding that “the value of that congestion hedge should be reflected in the price of the long-term right” is to honor existing rights allocations, while expediting capacity upgrades and expansions to meet needs exceeding available transmission capacity.

527. Midwest ISO states that the notion that the price of the long-term right should reflect the value of the congestion hedge is problematic because it is unclear how transmission organizations would reflect the value of the congestion hedge in the price of the long-term firm transmission right. Midwest ISO argues that the best way to determine the value of such a congestion hedge would be through a market mechanism such as an auction, which would be inconsistent with guideline (7).

528. Some commenters argue that long-term firm transmission rights holders should not, in general, be allocated a cost differential.¹²⁹ Ameren states that load serving entities that are allocated long-term firm transmission rights are providing the steady, long-term revenue stream to transmission owners that allows them to invest in upgrades and expansions to the system, and thus, should not be assessed a premium charge. TAPS states that if long-term rights are limited to base load and renewable resources for which the grid should be planned in any event, it is unreasonable to impose an additional cost burden on long-term right holders. TAPS states that the Commission should make clear that it will not accept proposals that would defeat the purpose of long-term rights by pricing them out of the reach of load serving entities. Also, TAPS supports the Commission’s proposal to leave the pricing associated with long-term rights to RTO compliance filings. However, TAPS believes that the transmission organization compliance process will go more smoothly if the Final Rule includes a new guideline providing that the pricing of long-term rights should support and not frustrate section 217(b)(4)’s directive to enable load serving entities to secure such rights.

529. With respect to firm transmission right options, Strategic Energy states that to the extent that firm transmission right options can be accommodated, they should be offered, subject to the recognition that such products encumber substantially more system capacity than obligations, and therefore should be valued accordingly. Also, TAPS and OMS agree that those wanting long-term firm transmission right options should be willing to pay for the additional cost of providing such an instrument. OMS submits that one possible way of doing this is to first allocate long-term firm transmission right obligations, and then allow those receiving long-term firm transmission right obligations the option of converting the firm transmission right obligation to a firm transmission right option.

Proposals to Limit the Adverse Impact of Long-Term Firm Transmission Rights

530. NSTAR and CAISO argue that some of the concerns the Commission raises under guideline (8) can be addressed by making long-term firm transmmission rights identical to short-term rights in every way but duration. In NSTAR’s view, section 217(b)(4) does not require differences between long-term firm transmission right characteristics and firm transmission right/auction revenue right characteristics except for duration. NSTAR argues that failure to harmonize any future long-term firm transmission rights with the current market and transmission tariff would be disruptive of existing arrangements and destabilize power supply planning.

531. Some commenters argue that the balance that the Commission seeks under guideline (8) can be achieved with the aid of secondary auctions and other market mechanisms.¹³⁰ For example, NRECA recommends using a voluntary secondary auction in order to allow reconfiguration of long-term firm transmission rights. NRECA states that this would allow shorter term rights that are unused to be auctioned to load serving entities without longer term service obligations, which could mitigate any potential adverse effect experienced by those that do not receive long-term firm transmission rights.

532. Several commenters suggest that adverse impacts associated with the introduction of long-term firm transmission rights can be reduced by limiting the amount of transmission capacity that is made available for those rights.¹³¹ For example, Reliant supports placing a limit on the amount of system capacity available to support long-term rights as this would reduce the likelihood that the rights may become infeasible, which in turn would reduce the possibility that the burden of funding the allocated rights would eventually fall onto other market participants.

533. APPA states that it is amenable to discussion of mechanisms that transmission organizations could use to minimize to the extent possible the adverse impacts of long-term firm transmission right allocations on the firm transmission rights available to other transmission customers. APPA proposes therefore that the Commission reformulate guideline (8) to reflect this approach: “Long-term firm transmission rights should be allocated in a manner that minimizes, to the extent possible, adverse impacts on participants not receiving such rights.” APPA states that any such mechanisms would have to be specific to each transmission organization and could include some combination of: (1) restrictions on the overall portion of the existing transmission system that could be allocated to support long-term firm transmission rights and (2) limits on each load serving entity’s own long-term firm transmission right holdings, based on some percentage of the load serving entity’s own loads.

534. In response, PJM states that the APPA rewrite of guideline (8) may go too far and potentially eliminate the ability of transmission organizations to preserve their existing priorities for short-term firm transmission rights with the new long-term firm transmission rights. As a result, PJM asks that guideline (8) not be amended. Rather, PJM urges the Commission to examine whether the appropriate balance called for in guideline (8) has been addressed in individual transmission organization filings.

Rules for Withdrawing from Membership in an RTO

535. With regard to whether measures are needed to address events such as the departure of long-term firm transmission right holders from the transmission organization, APPA states that the transmission organization will likely have to handle such events on a case-by-case basis. Ameren states that covering the impact of exit on long-term firm transmission rights may require additional language in transmission organization tariffs and/or members’ agreements.

536. TAPS argues that transmission dependent utilities have no control over whether their host transmission owner seeks to withdraw from an RTO or switch RTOs. In TAPS’s view, transmission dependent utilities therefore should be held harmless from such decisions. If, upon withdrawal, the host transmission owner reverts to a physical rights regime, TAPS states that the transmission dependent utility’s long-term right should be adapted to that regimen. If the host transmission owner switches transmission organizations, TAPS states that the new transmission organization should be required to honor the transmission dependent utilities’ long-term rights.

Commission Conclusion

537. The Commission will delete guideline (8) in the Final Rule. Commenters make a strong case that guideline (8) is not needed. Our principal purpose in including guideline (8) was to ensure that the requirements of section 217(b)(4) of the FPA are implemented in a manner that is just and reasonable and not unduly discriminatory, which is our legal duty under the FPA. Neither we nor, in our view, Congress intended to require long-term firm transmission right proposals to meet a different or higher standard. Indeed, as noted by APPA, TAPS, CMUA and others, opponents of long-term firm transmission rights could attempt to interpret guideline (8) in a way that would effectively eviscerate long-term firm transmission right proposals. Also, we agree with BPA’s statement that the issues raised by guideline (8) can be effectively addressed through the application of other guidelines. Nevertheless, while we are deleting guideline (8), we believe that meeting our obligation under the FPA to ensure that rates are just and reasonable and not unduly discriminatory will still require that we assess the impact of long-term rights proposals on those not receiving the rights.

538. We note that several commenters overstate the adverse effects of introducing long-term firm transmission rights, particularly in light of the revised guidelines that we are adopting herein. For example, Midwest ISO states that providing load serving entities with priority to receive, from existing transmission capacity, fully-funded long-term firm transmission rights to support the full amount of their supply contracts may place significant costs on other market participants, increase the costs of transmission organization membership, and significantly reduce the availability of firm transmission rights to meet short-term firm transmission right holders’ requests. However, by (1) expanding the priority of guideline (5) to all load serving entities and (2) allowing limits to be placed on the amount of existing transmission system capacity that is made available for long-term firm transmission rights, the Commission is taking important steps in this Final Rule to reduce, if not eliminate, problems associated with cost shifting and the reduced availability of short-term transmission rights to load serving entities that prefer them. As we explained in the discussion of guideline (5) above, as a result of these changes, the transmission organization should be able to design a comprehensive allocation process for short-term and long-term transmission rights that largely replicates the equitable distribution of short-term rights that occurred in the past for those entities that still want them. Indeed, to the extent that long-term rights and short-term rights have the same properties except for duration, as suggested by NSTAR and CAISO, even the full-funding requirement should not lead to significant cost shifting among classes of rights holders if all rights holders are given similar full-funding protections.¹³² In any event, as noted by Reliant, placing a limit on the amount of system capacity available to support long-term rights will reduce the likelihood that the rights may become infeasible, which in turn will reduce the possibility that the funding burden will eventually fall onto other market participants.

539. Also, BP Energy states that if long-term rights holders are able to shift generation redispatch and other congestion costs to others, they will have no incentive to enter into supply arrangements that maximize the number of transmission rights that can be allocated while maintaining revenue sufficiency. Similarly, ISO-NE argues that allocation of free long-term firm transmission rights to load serving entities versus an auction of such rights to all entities creates equity and distortion issues. We disagree. Well designed long-term firm transmission rights should result in no significant equity issues or economic distortions. As noted, cost shifting and equity issues are largely addressed by our revisions to guideline (5). As to economic distortions, these largely can be avoided by making firm transmission rights available through a process that combines a direct allocation of auction revenue rights with an auction of firm transmission rights, as explained in our discussion of guideline (7). Also, as NRECA notes, the availability of a voluntary secondary auction would allow reconfiguration of long-term firm transmission rights and make available shorter-term rights to entities that were not able to obtain long-term firm transmission rights.

540. Finally, with regard to whether measures need to be adopted to address events such as the departure of long-term firm transmission right holders from the transmission organization, the Commission agrees with APPA and Ameren that issues related to the withdrawal of an entity from a transmission organization are best addressed in the transmission organization’s members’ agreement’s terms for exit and should be reviewed on a case-by-case basis. As Ameren notes, the addition of long-term firm transmission rights may require additional language in transmission organization tariffs or members’ agreements. The Commission encourages transmission organizations and their stakeholders to consider the need for such language and to include any proposed revisions in their compliance filings.

F. Transmission Planning and Expansion

541. In the NOPR, the Commission noted that section 217(b)(4) of the FPA requires the Commission to exercise its authority “in a manner that facilitates the planning and expansion of transmission facilities to meet the reasonable needs of load serving entities to satisfy the service obligations of the load serving entities.” Accordingly, the Commission proposed to require that transmission organizations ensure that the long-term firm transmission rights they offer remain viable and are not modified or curtailed over their entire term. The Commission noted that, because the proposed guidelines would require that transmission organizations guarantee the financial coverage of the long-term firm transmission rights, transmission organizations would need to have an effective planning regime in place, and might need to expand the system to ensure that the long-term firm transmission rights can be accommodated over their entire term.

542. The Commission stated that it would not propose specific planning and expansion procedures in the NOPR, but rather each transmission organization and its stakeholders should develop appropriate methods for ensuring that long-term firm transmission rights are supported by adequate planning and expansion procedures. The Commission encouraged transmission organizations to propose such procedures as part of their filings in compliance with the Final Rule, and stated that it will consider them in light of the direction in section 217(b)(4) of the FPA that the Commission exercise its FPA authority to facilitate the planning and expansion of transmission facilities. The Commission asked for comments on whether it should require that transmission organizations file their transmission planning and expansion procedures and specific plans. It also sought comment on whether, alternatively, the Commission should require that transmission organizations file the plans and procedures for informational purposes to allow the Commission to monitor their adequacy for ensuring the viability of the long-term firm transmission rights.

543. The Commission noted that the pro forma OATT adopted by the Commission in Order No. 888 requires transmission providers to expand capacity, if necessary, to satisfy the needs of network and point-to-point transmission service customers. The Commission also noted that its Notice of Inquiry concerning the pro forma OATT sought responses from interested parties on specific questions relating to this requirement, including: (1) whether this provision has met transmission customers’ needs, and (2) whether public utility transmission providers have fulfilled these obligations.¹³³ In the NOPR, the Commission asked for comments addressing these questions in the specific context of the transmission organizations with organized electricity markets that are the subject of this rulemaking.

544. Finally, in the NOPR, the Commission asked for comments on whether the definition of native load service obligation in section 1233 of EPAct 2005 is the same as the approach the Commission took in Order No. 888, with particular emphasis on how the native load preference has been applied in the organized electricity markets that are the subject of this rulemaking.

Comments

Need for Transmission Planning - General

545. A number of commenters assert that the need for long-term transmission planning and expansion goes well beyond the need to provide for long-term firm transmission rights.¹³⁴ AEP states that proper planning of a robust transmission system is imperative to meeting long-term economic and reliability needs, which is a much bigger issue than hedging long-term transmission risks.

546. NCPA recommends that all transmission planning processes include the following: (1) needs defined on a comparable basis, based on analysis of all projected load serving entity loads and resources, and published, consistently-applied standards; (2) opportunities for all TDUs to participate in the joint planning process, and to validate and gain confidence in transmission planning models; (3) colorblind selection of plans to be implemented; (4) a dispute resolution process; and (5) plans and inputs that are transparent.

Transmission Organization’s Responsibility for Transmission Planning

547. A number of comments address the role of the transmission organization in the transmission planning process.¹³⁵ AEP believes that the transmission organization should conduct regional transmission planning and be the primary driver of providing long-term connections between economic power sources and load centers. AEP argues that the transmission organization should provide for a mechanism that links the granting of any long-term transmission rights and the construction of transmission to make those rights feasible. Constellation asserts that this will provide a mechanism to ensure that the system is not overbuilt to ensure long-term firm transmission rights.

548. TAPS believes that transmission organizations must be held accountable for planning and expanding the grid to ensure load-specific deliverability sufficient to support the continued simultaneous feasibility of all long-term rights issued, taking into account other rights that require preservation. TAPS states that RTOs (and transmission owners, if RTOs aggregate the transmission plans of their member transmission owners) should be required to have an inclusive joint planning process that meets the needs of TDUs on the same basis that TOs’ similar needs are met. In TAPS’s view, to meet the needs of new organized electricity markets, RTOs must be able to deliver crucial transmission upgrades, not just assemble consolidated lists of projects.

Transmission Planning to Accommodate Long-Term Firm Transmission Rights

549. A number of commenters stress that the transmission organization’s planning and expansion protocols must take into consideration the long-term firm transmission rights that are issued.¹³⁶ For example, Ameren submits that the parameters of long-term firm transmission right elections must be embedded in the RTO’s planning process. Ameren states that this will require the RTO to identify for its transmission owners the term of each long-term power supply arrangement associated with each firm transmission right on each transmission owner’s system, so that the expansion plans the transmission owners submit to the RTO incorporate any expansions necessitated by the long-term supply arrangements. Ameren asserts that ensuring load serving entities’ priority access to long-term firm transmission rights will give load serving entities the same rights and ability to “lock in” long-term firm transmission to support their long-term power supply arrangements that they enjoyed under Order No. 888 before RTOs and RTOs’ organized electricity markets. MSATs states that it agrees with such observations but also believes that long-term firm transmission rights should not become the principal driver of the transmission planning and expansion process.

550. MSATs argues that distinguishing between reliability and economic projects in the context of transmission planning is inconsistent with the concept of long-term firm transmission rights. MSATs asserts that firm transmission rights are economic rights that are intended to insulate holders from the economic consequences of congestion, and building and maintaining the transmission capacity needed to honor multi-year firm transmission rights may or may not be necessary to meet applicable reliability criteria. MSATs adds that, conversely, planning and constructing transmission facilities based solely on reliability criteria may not ensure the transmission capacity needed to honor long-term firm transmission rights. Thus, MSATs states that the distinction between economic and reliability projects is directly at odds with the type of transmission planning that is needed to honor long-term firm transmission rights.

551. Similarly, IPL states that the Commission should separately address physical delivery risk and financial risks stemming from congestion charges because the two risks are substantially different and efforts to address these risks that do not distinguish between them are likely to be counterproductive. IPL states that the Commission should not attempt to use financial transmission rights to provide an incentive toward investment by transmission owners because the Commission’s goal of ensuring that necessary upgrades are performed is better addressed separately from congestion charge hedging. In IPL’s view, congestion charge hedging is the singular legitimate purpose of a financial transmission rights mechanism.

552. IPL states that the Commission and the transmission organizations are undertaking a number of efforts to ensure that delivery risk is mitigated through proper transmission planning and expansion. IPL states that these efforts, which have no direct connection with allocations of long-term financial transmission rights, are the appropriate fora in which to address mitigating delivery risk by making sure adequate transmission infrastructure is available to meet the reasonable delivery needs of load serving entities and others.

553. Midwest ISO states that transmission upgrades and expansion should be dictated by the transmission planning studies that ensure deliverability of generation to serve load, not participants’ firm transmission right nominations. However, in response, APPA states that long-term firm transmission rights are intended to ensure exactly that: deliverability of generation to serve load on a specific resource-to-load basis, and at a reasonably ascertainable transmission cost that is not subject to volatile transmission congestion. According to APPA, since transmission planning and long-term firm transmission rights are both intended to ensure deliverability of generation to load, it is absolutely appropriate to take account of long-term firm transmission rights in an RTO’s transmission planning process. In addition, NRECA states that it is impossible to square Midwest ISO’s comment with the terms of FPA section 217(b)(4) . According to NRECA, if that section means anything, it is that public utility transmission providers must plan and expand the transmission grid so as to enable load serving entities to obtain long-term firm transmission rights.

EPAct 2005 Requirements for Transmission Planning and Expansion

554. Some commenters argue that EPAct 2005 requires the Commission to adopt specific transmission planning procedures as part of this rulemaking or another proceeding.¹³⁷ For example, National Grid claims that EPAct 2005 section 1233(b) requires the Commission to address how it intends to implement section FPA 217(b) (4) and not just the portions of FPA section 217 (b)(4) that speak to long-term transmission rights. To fulfill its statutory obligation, National Grid submits that the Commission should adopt a set of clear guidelines for transmission planning and expansion along with its proposed guidelines for long-term transmission rights. If the Commission does not adopt planning guidelines in its Final Rule in this proceeding, National Grid recommends that the Commission state how it intends to discharge its obligations under the first sentence of FPA section 217(b)(4) and EPAct 2005 section 1233(b) to assure adequate planning. According to NRECA, FPA section 217(b)(4) does not merely require the provision of long-term firm transmission rights; it requires the Commission to facilitate the planning and expansion of transmission facilities. In this regard, NRECA states that public utility transmission providers should be required to conduct open joint transmission planning processes that allow all load serving entities to participate on a comparable basis to public utility transmission providers. NRECA adds that these planning processes should accommodate both reliability and economic needs.

555. In its reply comments, MSATs states that the Commission should identify key attributes that should be incorporated into the RTO's planning process.

556. Reliant recommends that the Commission undertake a parallel rulemaking to address the long-term needs of customers outside of organized markets. If the Commission chooses not to proceed with such a separate rulemaking, Reliant urges the Commission to utilize Docket No. RM05-25-000, Preventing Undue Discrimination and Preference in Transmission Services.

557. Taking a contrary view, NYISO states that section 217(b)(4) should not be interpreted as mandating the overhaul of existing ISO/RTO transmission planning and expansion processes. NYISO notes that, with respect to New York, the Commission has approved a robust and transparent planning process that calls for stakeholder participation and input, and the NYISO’s Comprehensive Reliability Planning Process is undertaking its first comprehensive review of the reliability needs of the New York bulk power system. NYISO asserts that making wholesale changes to this process would be premature and unnecessary.

Requirement for Filing Transmission Plans

558. Some commenters state that the Commission should require transmission organizations to file their transmission planning protocols and their most recent transmission plans as part of their compliance filings in this proceeding.¹³⁸ APPA states that they should be required to explain in their long-term firm transmission right filings how those protocols and plans will take into account the need to accommodate the allocated long-term firm transmission rights for their full terms and will ensure the construction of any transmission facilities required to support them. APPA argues that if the Commission believes that this showing is not persuasive, then the transmission organization should be required to take action to revise its transmission planning protocol. However, APPA recommends that such action be undertaken in a separate proceeding so as not to delay initial implementation of long-term firm transmission rights. Also, TAPS and NCPA submit that for those transmission organizations that use transmission owner transmission plans as inputs for the transmission organization’s plan, the transmission owners should be required to make a similar filing. However, in response to APPA, MSATs states that the type of review contemplated by the APPA would be administratively burdensome and unlikely to prove beneficial. Also, Midwest ISO notes that such plans are already available as public documents.

559. BPA expresses support for the principle that transmission organizations should file their planning and expansion procedures and specific plans for informational purposes with the Commission. BPA believes that doing so helps assure that information on planning is widely available to interested persons. However, BPA states that Commission approval of such informational filings should not be required.

560. Many commenters argue strongly that the Commission should not impose additional filing requirements on the transmission organizations.¹³⁹ For example, SDG&E argues that unless Commission-jurisdictional entities have an opportunity to review the similar plans and procedures of non-jurisdictional transmission entities, the latter entities could obtain an unfair competitive advantage over the former entities. Moreover, SDG&E states that transmission planning is resource-intensive, and the effort required to plan, site, design and build new transmission is enormous. SDG&E asserts that the resources allocated to those efforts should not be diverted to further regulatory review that is not proven to be needed to ensure the viability of long-term firm transmission rights associated with the planned transmission lines.

561. ISO-NE views a requirement to file its system expansion plans as a significant departure from past Commission practice. ISO-NE argues that similar types of highly technical studies generally have not been subject to a filing requirement. For example, ISO-NE points out that although interconnection studies represent a type of study akin to the core of system expansion plans, they have never been filed with the Commission.

562. PJM states that it currently is required to file the proposed cost allocations resulting from its regional transmission expansion plan with the Commission, and the proposed allocations are subject to Commission approval. PJM recommends that the Commission not require filing of the entire plan absent being presented with a legitimate issue. In reply comments, NRECA urges the Commission to require that such plans be filed, even if only for informational purposes, to monitor compliance with the Final Rule in this proceeding and section 217(b)(4).

Meeting Native Load Requirements

563. In response to the request for comments in the NOPR on whether the definition of native load service obligation in section 1233 of EPAct 2005 is the same as the approach the Commission took in Order No. 888, some commenters addressed the subject of how that preference has been applied in organized electricity markets.¹⁴⁰ APPA states that application of the native load preference set out in new FPA sections 217(b)(1) and (2) to the various RTO regions is governed by new FPA sections 217(c) and (f). APPA asserts that these sections were hard-fought and carefully negotiated as to each RTO region, and states that the Commission should honor the legislative compromises embodied in those sections.

564. PJM states that, within PJM, native load receives a preference to system capacity by virtue of being allocated auction revenue rights, which can be converted to firm transmission rights at the discretion of the holder of the right. Midwest TOs states that, by guaranteeing long-term firm transmission rights, Midwest TOs believes the NOPR may result in reduced firm transmission rights for native load customers who receive firm transmission rights in the annual assignment process currently used by the Midwest ISO. Midwest TOs recommends that the Commission clarify that it intends for all load serving entities, including vertically integrated utilities that are just using existing generation to serve their loads, to be eligible to seek long-term firm transmission rights. According to Midwest TOs, to do otherwise would be to discriminate against the native load of vertically integrated companies.

Commission Conclusion

565. The Commission will require that each transmission organization with an organized electricity market implement a transmission system planning process that will accommodate the long-term transmission rights that are awarded by ensuring that they remain feasible over their entire term. FPA section 217(b)(4) requires the Commission to exercise its authority under the FPA in a manner that facilitates the planning and expansion of transmission facilities, and to enable load serving entities to obtain long-term firm transmission rights. To implement that section in a transmission organization with an organized electricity market, as required by section 1233(b) of EPAct 2005, we believe that the transmission organization must plan its system to ensure that allocated or awarded long-term firm transmission rights are feasible.¹⁴¹ FPA section 217(b)(4) itself, by including both the requirement to facilitate planning and expansion and the requirement to provide long-term transmission rights, supports the Commission’s authority to impose this requirement. Moreover, given the full funding requirement of guideline 2, appropriate planning for long-term firm transmission rights is essential to ensure that any charges to other market participants to cover revenue shortfalls do not become unjust, unreasonable or unduly discriminatory.

566. To implement this requirement, we will require each transmission organization to include in its compliance filing an explicit statement of how its planning and expansion practices will take into account the need to accommodate allocated or awarded long-term firm transmission rights for their full terms, including the construction of transmission facilities (as well as a basis for allocating cost responsibility) that may be needed to support them. We will also require that each transmission organization make its planning and expansion practices and procedures publicly available, including both the actual plans and any underlying information used to develop the plans. Also, any holder of long-term firm transmission rights that believes that the transmission organization is not fulfilling its obligation to ensure the adequacy of the long-term firm transmission rights over their full term can seek relief through the transmission organization’s internal complaint procedures or by filing a complaint with the Commission. The Commission will address problems on a case-by-case basis, and if necessary, require the transmission organization to revise its planning and expansion practices to better accommodate long-term firm transmission rights.

567. The Commission notes that, to meet the requirements that we are imposing here, as well as the full-funding requirements of guideline (2), a transmission organization must plan its system such that a long-term firm transmission right, once awarded, remains viable throughout its full term without requiring the long-term firm transmission right holder to pay directly for any additional transmission upgrades that may be required to maintain the feasibility of the right over its term. Accordingly, the transmission organization must include, along with upgrades needed for system reliability, any upgrades needed to support the long-term firm transmission right over its full term in its base plan for system expansion. While this may require changes in the transmission organization’s planning protocols, we disagree with MSATs that it requires the transmission organization to draw a distinction between economic and reliability projects that is incompatible with transmission planning. Indeed, the transmission organization may choose to make no distinction between reliability upgrades and those needed to maintain the feasibility of long-term firm transmission rights.

568. In addition, we note that when a transmission customer enters into a long-term power supply arrangement and is willing to pay for any transmission expansion or upgrades which may be necessary in order to make long-term firm transmission rights feasible over the entire term of the contract, that expansion or upgrade must be incorporated into the transmission organization’s planning process. This will require that the expansion plans that transmission owners submit to the transmission organization incorporate any expansions necessitated by such long-term supply arrangements. We believe that it is important for the regional planning process to take account of any upgrades or expansions of the transmission system that may be required to ensure FTRs needed to support long-term power supply arrangements are available.

569. The Commission agrees with commenters such as NRECA that observe that FPA section 217(b)(4) does not merely require the provision of long-term firm transmission rights; it requires the Commission to facilitate the planning and expansion of transmission facilities. However, the Commission is considering issues concerning its broader mandate to exercise its FPA authority to facilitate planning and expansion (which applies to all regions) to Docket No. RM05-25-000, the Order No. 888 OATT reform rulemaking.

G. Alternative Designs for Long-Term Firm Transmission Rights

570. We noted in the NOPR that FPA Section 217(b)(4) recognizes that there may be alternative designs for long-term firm transmission rights. The NOPR noted that for most transmission organizations, the most straightforward design for long-term transmission rights is likely to be an extension of their existing design for allocation of auction revenue rights or FTRs, perhaps with some modifications of certain rules and procedures (such as creditworthiness standards and transmission planning). The NOPR discussed, and we did not preclude, alternative designs for such rights, including departures from the existing market designs.

Comments

Clarification of Terms

571. Several commenters argue that the Commission is unclear about its use of the terms “firm transmission rights” and “financial transmission rights.” IPL states that section 217(b)(4) uses the term “firm” to mean physical rights, and financial to refer to purely financial rights. In contrast, the NOPR appears to use the terms interchangeably. IPL states that “resolution of this confusion is critical because the NOPR dually implies that it is (a) proposing certain modifications to an existing financial transmission rights paradigm, and (b) that it is imposing a physical rights structure in organized electricity markets where that concept is anathema to [LMP].”¹⁴² National Grid also states that the NOPR is unclear as to the status of whether firm means solely physical rights and asks for clarification that the Commission is not implying a preference for physical rights. Reliant asks that the Commission clarify that by firm transmission rights, it does not mean physical rights, but rather that financial rights in LMP markets are equivalent to firm rights.

572. In contrast, TANC argues that the firm transmission rights cited in section 217(b)(4) were intended to be physical rights and that even though the statute recognizes financial transmission rights, Congress sought to determine that it favors another methodology, namely physical transmission rights.

Physical versus Financial Rights

573. In addition, a number of commenters also had views on whether long-term firm transmission rights should be physical or financial rights. Most commenters assumed that the rights under consideration in most organized markets are financial rights without having to make the requirement explicit, as reflected in their comments on auction revenue rights and FTRs. However, a number of parties, including CAISO, EEI, IPL, National Grid, NEPOOL, NU, NSTAR, NYISO, Reliant, SDG&E and SoCal Edison asked that the Commission be more explicit that the rights under consideration should be financial rights only, in particular in markets that currently have financial rights.

574. These commenters argue that physical rights would have deleterious effects on the LMP markets. For example, ISO-NE argues that introducing physical scheduling rights would create an economic loss for the region because of less efficient dispatch of resources, significant administrative burdens for system users and the ISO, and new seams with the ISO’s region. National Grid observes that holders of physical rights would be insulated from redispatch costs, which would be inequitably shifted to holders of financial rights or to transmission owners.

575. PG&E argues that while it supported a financial rights model for CAISO, the approach of the Final Rule should allow, but not require, alternative designs to recognize that stakeholders in different markets may prefer different cost-benefit balances. PJM similarly urges that the Final Rule clarify that respective regions should determine the nature of the transmission right, whether physical or financial.

576. Several commenters supporting financial rights are also concerned that the Final Rule does not establish a mix of physical and financial rights.¹⁴³ NU argues that a “carve-out” for physical long-term rights would reduce available capacity for shorter-term FTRs and distort the auction market for them. NYISO argues that “financial rights models can bring as much certainty as physical rights while allowing for a fuller and more efficient utilitization of transmission capacity.”¹⁴⁴ PJM, while supporting regional flexibility to design physical or financial rights, urges that, with the exception of approved grandfathered agreements, there should not be a mix of physical and financial rights as a bifurcated system would be unworkable. EEI cautions that a move toward long-term physical rights for some market participants would undermine the competitive markets.

577. NYTOs suggested that the Commission establish a regulatory definition of long-term transmission right that clarifies that such a right encompasses both physical and financial rights to the use of the transmission system. Such a definition should state that in organized electricity markets, market participants have the physical right to schedule but then receive financial rights to hedge congestion charges.

578. Several parties, including LADWP, Modesto, NRECA, Redding, SMUD, Santa Clara, and TANC, argue that long-term rights should be physical rights or rights with some characteristics of physical rights. For example, LADWP states that the rights should have certain characteristics, including the following: the right to schedule power up to the holder’s share of the transmission facility rating; the ability to market non-scheduled transmission capacity to others; a fixed charge responsibility not otherwise dependent on operating conditions; losses provided for as in the project agreement; and not subject to rules set by non-participants. LADWP argues that these assurances along with proper planning and investment are necessary to provide the certainty necessary for transmission investment.

579. Santa Clara states that no financial instrument can achieve a truly effective hedge against congestion costs, and that only explicit physical rights (denominated solely in terms of MW of capacity) can secure a load serving entity against transmission costs. Santa Clara thus proposes that long-term firm transmission rights are physical rights. SMUD argues that physical rights coupled with resale and assignment rights (akin to the gas pipeline open access model) could capture most of the efficiencies of the financial rights/LMP model. In the west, Redding and SMUD argue that CAISO’s pending implementation of a financial rights market make it the only entity in the region to use that model and will create seams that diminish trade with the rest of the region.

580. Santa Clara and TANC argue that physical transmission rights that mirror OATT rights have more stable pricing and allow holders to hedge the risk of fluctuating congestion charges. Hence, they will facilitate planning and construction of new generation facilities and other long-term supply arrangements.

581. In contrast to some comments noted above, several supporters of physical rights argued that systems that mix physical and financial rights are necessary. LADWP supports the co-existence of financial and physical rights, such as the CAISO’s MRTU proposal to reserve capacity on its interties for Existing Transmission Contracts and Transmission Ownership Rights. LADWP also proposes that holders of such rights would be insulated from congestion costs when prices reverse direction. TANC argues that physical transmission rights of various types are already accommodated in several transmission organization markets that have financial rights, for example, as grandfathered rights.

582. Some commenters noted that in some organized markets, some degree of long-term physical rights have already been grandfathered. Coral Power is concerned that the scope of grandfathered rights could be “needlessly” expanded. DC Energy argues that in New York ISO, such rights have already accommodated those with the greatest contractual rights to long-term transmission service.

Alternative Types of Financial Rights

583. Several commenters, including Allegheny, Constellation, EEI, Kentucky PSC, and PG&E, stress that FTR option rights should not be available in the allocation of long-term firm transmission rights. This is because such option rights encumber too much transmission capacity, resulting in a reduction in the quantity of rights available. Instead, the long-term transmission rights should be specified as FTR obligation rights. Some of these commenters would be willing to accommodate options at a later date. NEPOOL states that the Commission should neither require nor preclude options.

584. APPA agrees that FTR option rights would likely be unworkable, but proposes instead its concept of a “hybrid long-term transmission right” that would only provide congestion revenues in the hours that the holder of the right schedules transmission and up to the quantity scheduled. Such a right would also not require obligation payments in the event that the prices at the locations specified in the right change direction (that is, a higher price at the injection point than at the withdrawal point). TAPS proposes that long-term rights are “dispatch-contingent” FTRs, which would only pay revenues when the generation resource is dispatched. In all other hours, the FTR would not pay revenues, nor require obligation payments.

Commission Conclusion

Clarification of Definitions and Choice Between Financial and Physical Rights

585. As noted elsewhere in the Final Rule, we interpret Section 217 (b)(4) to require that load serving entities be able to obtain long-term firm rights, whether as physical rights or as equivalent financial rights. In the discussion of guideline (2), we interpreted the firmness requirement in the financial rights context to include a fixed (MW) quantity over the life of the right and stability in the revenue stream from the right through full funding. This roughly parallels the quantity and financial stability of long-term physical transmission contracts. Because we believe that under our guidelines financial rights are as firm as physical rights outside organized electricity markets, we have used the terms firm and financial interchangeably at times. We have not used the term firm to imply a preference for physical rights.

586. We will not require that long-term firm transmission rights in organized electricity markets be physical or financial rights.  However, we also will not require that transmission organizations with existing or approved designs for financial transmission rights create a new long-term physical right, such as an Order No. 888 network service right, upon request of a load serving entity. Instead, as discussed in our guidelines, we have sought to provide guarantees of financial “firmness” alongside the existing physical firmness of transmission scheduling in the organized electricity markets (that is, decreased frequency of TLRs).

Alternative Types of Financial Rights

587. While many commenters have warned against allowing allocation of long-term option financial rights, no commenter has requested such rights. We agree with commenters that allocation of long-term financial transmission option rights would present severe equity problems in most organized electricity markets. At best, if all eligible parties requested option rights, the set of allocated rights would be greatly reduced compared to an allocation of obligation rights. An alternative approach to obtaining options would be to allocate long-term auction revenue rights as obligations and let entities purchase option rights through an auction.

588. Schedule-contingent or dispatch-contingent financial transmission rights could present similar equity problems to options in allocation and, unlike option FTRs, possibly create poor scheduling or dispatch incentives.¹⁴⁵ These types of contingent rights could present revenue adequacy problems because while they are not paid when they do not schedule or dispatch, if they are base-load plants this will likely only take place when the prices at the injection and withdrawal locations are reversed. That is, the unit will not be scheduled when it is needed to make counterflow payments to support the revenue adequacy of other transmission rights. As a result, the transmission organization would either have to model the rights as options in the allocation of transmission rights or make arbitrary decisions to limit the quantity of rights it allocates. Further, dispatch-contingent rights could have incentives for inefficient dispatch, since the right is only paid when a source generator produces output. In that case, the holder of the right will have less flexibility to purchase cheaper power from the spot market in the presence of congestion because it will lose the revenues from its rights.

H. Miscellaneous Comments

589. SMUD states that the uncertainty associated with marginal loss charges is at least as big a hedging problem as that posed by congestion charges. SMUD argues that marginal loss pricing is not required under the locational marginal pricing model. CMUA, Santa Clara and SMUD urge the Commission to direct that transmission organizations either eliminate marginal loss charges or offer transmission customers with long-term rights the same full hedge against loss charges as against congestion charges.

Commission Conclusion

590. We do not interpret section 217(b)(4) as addressing marginal loss charges. Each transmission organization operating an organized electricity market has established methods for refunds of marginal loss surplus based on stakeholder discussion. We will not overturn those decisions here.

I. Implementation of the Final Rule and Compliance Issues

591. In the NOPR, the Commission proposed to direct each public utility that is a transmission organization with an organized electricity market, within 180 days of the publication of a Final Rule in the Federal Register, to either: (1) file with the Commission tariff sheets and rate schedules that make available long-term firm transmission rights that are consistent with the guidelines set forth in section (d) of the Final Rule; or (2) file with the Commission an explanation of how its current tariff and rate schedules already provide for long-term firm transmission rights that are consistent with the guidelines set forth in paragraph (d) of the Final Rule. We stated our intent that during this 180-day period, transmission organizations subject to the rule will work with their stakeholders (through their usual stakeholder process) to develop a long-term firm transmission right that will harmonize prevailing market design with the guidelines set forth in the Final Rule. For any transmission organization that is approved by the Commission after the 180-day time period, the Commission proposed that the transmission organization be required to satisfy the requirements of the Final Rule prior to commencing operation.

Comments

592. APPA, New England Public Systems, and Vermont DPS all support the Commission’s proposed implementation procedures. New England Public Systems states that if any transmission organization determines that it will not be able to meet the 180-day timetable, the Commission should require that it submit a detailed explanation of the cause of the delay and a detailed schedule for completing and submitting its compliance filing. PG&E supports the compliance filing timeline, and suggests that those deadlines be expanded to address due dates that would follow the future adoption of market-based congestion management programs by a transmission organization. PG&E also recommends that a parallel rule be adopted for long-term firm transmission rights in markets that do not use market-based congestion management systems.

593. SMUD argues that the Commission’s proposed compliance procedures contain an insufficient directive to ensure timely compliance, particularly because it would allow transmission organizations to submit proposed tariffs with no proposed effective dates. Accordingly, SMUD states that the Commission should issue a Final Rule by August 8, 2006, and clarify that compliance tariffs and rate schedules must be effective 60 days after their filing, to ensure that long-term firm transmission rights are available within about a year.

594. Several commenters, including AF&PA, IPL, ISO-NE, NEPOOL and OMS, argue that the 180-day deadline proposed in the NOPR for transmission organizations to make filings in compliance with the Final Rule is “unrealistic” given the complexity of the issues involved and the transmission organizations’ other ongoing projects. IPL suggests that the Commission lengthen the time for stakeholder procedures and compliance filings to 365 days, followed by an additional 365-day period during which the transmission organizations will implement their long-term rights mechanism. IPL also suggests that the Commission allow transmission organizations to phase in long-term rights over time. OMS requests that the Commission permit transmission organizations to report on the status of their stakeholder procedures in 180 days, and then set a specific filing date for tariff changes based on that status report.

595. ISO-NE also requests that the Commission lengthen the 180-day time period for developing and filing a proposal to comply with the Final Rule, stating that a strict requirement to formulate a long-term firm transmission right design within that time frame could present insurmountable challenges since it is also in the process of developing other important market reforms as part of its Wholesale Market Plan.

596. NYISO states that it will likely be able to meet the proposed 180-day deadline, provided the Commission’s Final Rule clarifies that only limited changes to the current market design need to be considered. It explains that it may need additional time, however, if the Final Rule requires more modifications of existing systems. New York Transmission Owners suggest that if changes to the NYISO market are required, the Commission should allow it to develop a procedure to phase in such changes to avoid market disruptions that could affect the availability of short-term and intermediate transmission rights.

597. CAISO notes in its initial comments that it faces unique challenges in implementing long-term firm transmission rights because it is in the process of implementing a complete market redesign, which includes a transition to LMP.¹⁴⁶ To implement this redesign by November 2007, CAISO states that it will be difficult, if not impossible, to expand the scope of the initial market design. According to CAISO, to adopt long-term transmission rights before the start of the new market it would be necessary to develop a “hybrid” instrument that could be used in both the current market and new market. Developing this instrument, it states, would divert resources from its effort to implement the new market. Accordingly, CAISO asks that it not be required to implement, prior to the start of its redesigned market, any “hybrid” long-term transmission rights product.

598. Furthermore, given its current process and timeline for implementing the market redesign, CAISO states that it most likely would not be able to fulfill the requirements of the Final Rule under the proposed compliance schedule. Accordingly, it states that the Commission should not require it to have long-term FTRs in place until at least one year after the start of its new markets. CAISO notes that its market participants lack experience with short-term financial rights. As a result, it contends that it could not have a meaningful stakeholder debate on the design and implementation of long-term rights, and urges the Commission to allow it the same opportunity to gain experience with LMP that other transmission organizations have had. Furthermore, it argues that it is important that market participants have a sufficient demonstration of the financial rights they will be able to receive under the market redesign before long-term rights are implemented.¹⁴⁷ As a result, CAISO seeks sufficient time for stakeholder discussions on alternate designs, and asks that it not be required to implement long-term financial rights before having at least one year of experience with LMP markets.

599. SoCal Edison, noting the same concerns regarding the timing of CAISO’s market redesign, argues that the Commission should revise its proposed compliance procedures to require a transmission organization that has filed a complete redesign of its organized electricity market to make a proposal for implementing long-term firm transmission rights after the revised market becomes effective, instead of within 180 days of the final rule. CPUC and SDG&E also express concerns with regard to the timing of CAISO’s implementation of long-term firm transmission rights. CPUC agrees with CAISO that it should be given a period of time to gain experience with LMP before implementing long-term rights, while SDG&E states that the Commission should, in the Final Rule, require CAISO to include long-term rights in its planned second release of the market redesign.

600. Conversely, CMUA, APPA and NCPA all suggest that accommodating long-term rights should be more easily accomplished in CAISO because it is not an established LMP market, and that it would be easier and less expensive to incorporate long-term rights into the market design rather than retrofit the market later. Nevertheless, CMUA opposes blanket application of the 180-day timeline to CAISO, and (along with TANC) urges the Commission to address CAISO’s implementation schedule for long-term firm transmission rights as part of its consideration of CAISO’s market redesign filing in Docket No. ER06-615-000.¹⁴⁸

601. Several commenters, including PG&E, SMUD, and Transmission Agency of Northern California, oppose CAISO’s request for deferral and argue that the Final Rule should apply to California upon its implementation of LMP as part of its market redesign. PG&E argues that CAISO’s reasoning that delaying deferral because it has not relied on short-term rights for as long as other transmission organizations “stands . . . EPAct on its head” and perpetuates the problem driving Congress to enact section 217(b)(4) of the FPA and section 1233(b) of EPAct 2005.¹⁴⁹ SMUD (and others) note that CAISO was directed by the Commission to develop a long-term firm transmission service more than eight years ago, and has not yet proposed such an option (including in its recent market redesign filing).¹⁵⁰ To avoid further delay, SMUD states that if a transmission organization cannot provide a long-term financial transmission right product within 180 days, it should be required to offer physical path arrangements until it can develop a financial product that meets the requirements of section 217(b)(4) and the Commission’s guidelines.¹⁵¹ SMUD also asserts that CAISO wrongly assumes both that implementing long-term rights will cause a delay in the start of its redesigned markets, and that there is urgency in implementing the market redesign.

Commission Conclusion

602. The Commission will adopt the implementation timetable proposed in the NOPR. We clarify what we expect transmission organizations subject to this Final Rule to file compliance proposals within 180 days of its effective date. Specifically, they must file proposed tariff sheets and rate schedules that would make available long-term firm transmission rights that satisfy each of the guidelines in the Final Rule. We recognize that the implementation of long-term firm transmission rights presents difficult issues, and that significant effort will be required to file compliance proposals within 180 days. Congress directed the Commission to act quickly, however, requiring in section 1233(b) of EPAct 2005 that we issue this Final Rule within one year of the legislation’s passage. We believe that this directive shows Congress’s intent that long-term firm transmission rights be made available as soon as possible.

603. Commenters (particularly ISO-NE) express concern that implementing long-term firm transmission rights on the proposed compliance timetable could negatively impact the ability of transmission organizations to complete work on other initiatives. We encourage transmission organizations to explore ways to reorder their priorities to ensure that this important Congressional directive is fulfilled. We will not rule out at this time the possibility that transmission organizations may seek permission from the Commission to reorder its schedule for market design changes, tariff changes or other projects that were directed by the Commission.

604. Some commenters suggest that the Commission permit transmission organizations to phase in tariff and market rule changes to introduce long-term firm transmission rights. We cannot decide here whether any particular proposal to phase-in long-term firm transmission would be just and reasonable. We remind transmission organizations again, however, that Congress intended the implementation of long-term firm transmission rights to occur as soon as possible. Any proposal to phase-in long-term firm transmission rights will be considered in light of this statutory directive.

605. We note that the final regulations require transmission organizations to file tariff sheets and rate schedules that make available long-term firm transmission rights that satisfy each of the guidelines within the 180-day timeframe. While SMUD asks us to specify that such tariff sheets and rate schedules be effective 60 days after filing, we do not believe it would be appropriate to prescribe effective dates now. Transmission organizations may need to synchronize the availability of long-term firm transmission rights with their existing allocation schedules. They may also need to take additional steps, such as making necessary software or procedural changes, to implement the rights after the Commission acts on their compliance proposals. As a result, we will consider effective dates on a case-by-case basis, again in light of Congress’s intent that long-term firm transmission be implemented as soon as possible.

606. Additionally, we clarify that for transmission organizations with organized electricity markets that are formed after the effective date of this Final Rule, we intend that such organizations will provide long-term firm transmission rights satisfying the guidelines in the regulations.. . We have made revisions to the proposed regulatory text to clarify that transmission organizations approved by the Commission in the future will be required to satisfy this Final Rule.

607. The Commission will require that all existing transmission organizations, including CAISO, make proposals to comply with the Final Rule on the same timetable. While we understand CAISO’s concerns regarding its pending market redesign efforts, we cannot address in this rulemaking of general applicability any possible plans for the phase-in or delayed implementation of long-term firm transmission rights. Even if we could, CAISO has not provided any timetable in its comments for implementing long-term firm transmission rights as required by section 217(b)(4) of the FPA and section 1233(b) of EPAct 2005. Therefore, CAISO must work with its stakeholders to develop and submit a compliance filing within the timetable prescribed in this Final Rule, and the Commission will consider any issues specific to CAISO or any proposals offered in its compliance filing for implementing long-term firm transmission rights in CAISO. Once again, we remind transmission organizations and their stakeholders, including CAISO, that Congress intends that the introduction of such rights occur as soon as possible.

III. Information Collection Statement

608. The Office of Management and Budget (OMB) regulations require approval of certain information collection requirements imposed by agency rules.¹⁵² Upon approval of a collection(s) of information, OMB will assign an OMB control number and an expiration date. Respondents subject to the filing requirements of this rule will not be penalized for failing to respond to these collections of information unless the collections of information display a valid OMB control number. This Final Rule amends the Commission’s regulations to implement some of the statutory provisions of section 1233 of EPAct 2005. Particularly, section 1233 of EPAct 2005 enacts a new section 217 of the FPA. New section 217(b)(4) requires the Commission to exercise its authority in a manner that facilitates the planning and expansion of transmission facilities to meet the reasonable needs of load serving entities to satisfy their service obligations, and enables load serving entities to secure long-term firm transmission rights to meet their service obligations. Section 1233(b) of EPAct 2005 directs that Commission to, by rule or order, implement this new provision in the FPA. This Final Rule requires transmission organizations with organized electricity markets to either file tariff sheets making long-term firm transmission rights available that are consistent with guidelines established by the Commission, or to make a filing explaining how their existing tariffs already provide long-term firm transmission rights that are consistent with the guidelines. Such filings will be made under Part 35 of the Commission’s regulations. The information provided for under Part 35 is identified as FERC-516.

609. The Commission submitted these reporting requirements to OMB for its review and approval under section 3507(d) of the Paperwork Reduction Act.¹⁵³ In the NOPR, comments were solicited on the Commission’s need for this information, whether the information will have practical utility, the accuracy of provided burden estimates, ways to enhance the quality, utility, and clarity of the information to be collected, and any suggested methods for minimizing the respondent’s burden, including the use of automated information techniques. No comments were received on these issues. Therefore, the Commission is retaining the estimates provided in the NOPR.

Burden Estimate: The Public Reporting burden for the requirements contained in the Final Rule is as follows:

Data Collection	Number of Respondents	No. of Responses	Hours Per Response	Total Annual Hours
FERC-516
Transmission Organizations with Organized Electricity Markets	6	1	1180	7,080

Total Annual hours for Collection: (Reporting + recordkeeping, (if appropriate) = 7,080 hours.

Information Collection Costs: The Commission seeks comments on the costs to comply with these requirements. It has projected the average annualized cost to be the total annual hours of 7,080 times $150 = $1,062,000.

Title: FERC-516 “Electric Rate Schedule Filings”

Action: Proposed Collections

OMB Control No: 1902-0096

Respondents: Business or other for profit, and/or not for profit institutions.

Frequency of Responses: One time to initially comply with the rule, and then on occasion as needed to revise or modify.

Necessity of the Information: This Final Rule implements the Congressional mandate of the Energy Policy Act of 2005 to make long-term transmission rights available in transmission organizations with organized electricity markets. This mandate addresses an identified need for transmission organizations with organized electricity markets to provide longer-term transmission rights that can aid load serving entities in financing long-term power supply arrangements to meet their service obligations. Making long-term firm transmission rights available will also provide increased certainty regarding the long-term costs of transmission service in organized electricity markets. As a result, long-term firm transmission rights will allow load serving entities to more effectively plan their power supply portfolios, and encourage load serving entities and other participants in organized electricity markets to make long-term investments in power supply arrangements.

Internal review: The Commission has reviewed the requirements pertaining to transmission organizations with organized electricity markets and determined the proposed requirements are necessary to meet the statutory provisions of the Energy Policy Act of 2005.

610. These requirements conform to the Commission’s plan for efficient information collection, communication and management within the energy industry. The Commission has assured itself, by means of internal review, that there is specific, objective support for the burden estimates associated with the information requirements.

611. Interested persons may obtain information on the reporting requirements by contacting: Federal Energy Regulatory Commission, 888 First Street, N.E., Washington, D.C. 20426 [Attention: Michael Miller, Office of the Executive Director, Phone: (202) 502-8415, fax: (202) 273-0873, e-mail: michael.miller@ferc.gov]. Comments on the requirements of the Final Rule may also be sent to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, D.C. 20503 [Attention: Desk Officer for the Federal Energy Regulatory Commission], e-mail: oira_submission@omb.eop.gov.

IV. Environmental Analysis

612. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment.¹⁵⁴ As we stated in the NOPR, the Commission has categorically excluded certain actions from this requirement as not having a significant effect on the human environment. Included in the exclusion are rules that do not substantially change the effect of legislation.¹⁵⁵ This Final Rule falls within this categorical exemption because it implements the requirements of EPAct 2005 relating to long-term firm transmission rights in organized electricity markets. Accordingly, neither an environmental impact statement nor environmental assessment is required.

V. Regulatory Flexibility Act Certification

613. The Regulatory Flexibility Act of 1980¹⁵⁶ generally requires a description and analysis of rules that will have significant economic impact on a substantial number of small entities. Most, if not all, of the transmission organizations to which the requirements of this Final Rule apply do not fall within the definition of small entities.¹⁵⁷ Therefore, the Commission certifies that this Final Rule will not have a significant economic impact on a substantial number of small entities. Accordingly, no regulatory flexibility analysis is required.

VI. Document Availability

614. In addition to publishing the full text of this document in the Federal Register, the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the Internet through the Commission’s Home Page (http://www.ferc.gov) and in the Commission’s Public Reference Room during normal business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, N.E., Room 2A, Washington D.C. 20426.

615. From the Commission's Home Page on the Internet, this information is available in the Commission’s document management system, eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field.

616. User assistance is available for eLibrary and the Commission's website during normal business hours. For assistance, please contact FERC Online Support at 1-866-208-3676 (toll free) or (202)502-8222 (e-mail at FERCOnlineSupport@FERC.gov), or the Public Reference Room at (202) 502-8371, TTY (202)502-8659 (e-mail at public.referenceroom@ferc.gov ).

VII. Effective Date and Congressional Notification

617. This Final Rule will be effective [insert date 30 days from publication in Federal Register]. The Commission has determined, with the concurrence of the Administrator of the Office of Information and Regulatory Affairs of OMB, that this rule is not a “major rule” as defined in section 351 of the Small Business Regulatory

Enforcement Fairness Act of 1996.¹⁵⁸ The Commission will submit the Final Rule to both houses of Congress and the Government Accountability Office.

List of Subjects in 18 C.F.R. Part 42

Electric power rates; Electric utilities.

By the Commission.

( S E A L )

Magalie R. Salas,

Secretary.

In consideration of the foregoing, the Commission amends Subchapter B, Chapter I, Title 18, Code of Federal Regulations, by adding a new Part 42 as follows:

* * * * *

SUBCHAPTER B – REGULATIONS UNDER THE FEDERAL POWER ACT

* * * * *

PART 42 – LONG-TERM FIRM TRANSMISSION RIGHTS IN ORGANIZED ELECTRICITY MARKETS

Sec.

42.1 – Requirement that Transmission Organizations with Organized Electricity Markets offer Long-Term Firm Transmission Rights

AUTHORITY: 16 U.S.C. § 791a – 825r and section 217 of the Federal Power Act, 16 U.S.C. §____.

§ 42.1 Requirement that Transmission Organizations with Organized Electricity Markets Offer Long-Term Firm Transmission Rights.

(a) Purpose. This section requires a transmission organization with one or more organized electricity markets (administered either by it or by another entity) to make available long-term firm transmission rights, pursuant to section 217(b)(4) of the Federal Power Act, that satisfy each of the guidelines set forth in paragraph (d) of this section. This section does not require that a specific type of long-term firm transmission right be made available, and is intended to permit transmission organizations flexibility in satisfying the guidelines set forth in paragraph (d) of this section.

(b) Definitions. As used in this section:

(1) Transmission Organization means a Regional Transmission Organization, Independent System Operator, independent transmission provider, or other independent transmission organization finally approved by the Commission for the operation of transmission facilities.

(2) Load serving entity means a distribution utility or an electric utility that has a service obligation.

(3) Service obligation means a requirement applicable to, or the exercise of authority granted to, an electric utility under Federal, State, or local law or under long-term contracts to provide electric service to end-users or to a distribution utility.

(4) Organized Electricity Market means an auction-based day ahead and real time wholesale market where a single entity receives offers to sell and bids to buy electric energy and/or ancillary services from multiple sellers and buyers and determines which sales and purchases are completed and at what prices, based on formal rules contained in Commission-approved tariffs, and where the prices are used by a transmission organization for establishing transmission usage charges.

(c) General rule.

(1) Every public utility that is a transmission organization and that owns, operates or controls facilities used for the transmission of electric energy in interstate commerce and has one or more organized electricity markets (administered either by it or by another entity) must file with the Commission, no later than [INSERT DATE 180 DAYS AFTER PUBLICATION OF FINAL RULE IN THE FEDERAL REGISTER], one of the following:

(i) Tariff sheets and rate schedules that make available long-term firm transmission rights that satisfy each of the guidelines set forth in paragraph (d) of this section; or

(ii) An explanation of how its current tariff and rate schedules already provide for long-term firm transmission rights that satisfy each of the guidelines set forth in paragraph (d) of this section.

(2) Any transmission organization approved by the Commission for operation after [INSERT DATE 180 DAYS AFTER PUBLICATION OF FINAL RULE IN THE FEDERAL REGISTER] that has one or more organized electricity markets (administered either by it or by another entity) will be required to satisfy this general rule.

(3) Filings made in compliance with this paragraph (c) must explain how the transmission organization’s transmission planning and expansion procedures will accommodate long-term firm transmission rights, including but not limited to how the transmission organization will ensure that allocated long-term firm transmission rights remain feasible over their entire term.

(4) Each transmission organization subject to this general rule must also make its transmission planning and expansion procedures and plans publicly available, including (but not limited to) both the actual plans and any underlying information used to develop the plans.

(d) Guidelines for Design and Administration of Long-term Firm Transmission Rights. Transmission organizations subject to paragraph (c) of this section must make available long-term firm transmission rights that satisfy the following guidelines:

(1) The long-term firm transmission right should specify a source (injection node or nodes) and sink (withdrawal node or nodes), and a quantity (MW).

(2) The long-term firm transmission right must provide a hedge against day-ahead locational marginal pricing congestion charges or other direct assignment of congestion costs for the period covered and quantity specified. Once allocated, the financial coverage provided by a financial long-term right should not be modified during its term (the “full funding” requirement) except in the case of extraordinary circumstances or through voluntary agreement of both the holder of the right and the transmission organization.

(3) Long-term firm transmission rights made feasible by transmission upgrades or expansions must be available upon request to any party that pays for such upgrades or expansions in accordance with the transmission organization’s prevailing cost allocation methods for upgrades or expansions.

(4) Long-term firm transmission rights must be made available with term lengths (and/or rights to renewal) that are sufficient to meet the needs of load serving entities to hedge long-term power supply arrangements made or planned to satisfy a service obligation. The length of term of renewals may be different from the original term. Transmission organizations may propose rules specifying the length of terms and use of renewal rights to provide long-term coverage, but must be able to offer firm coverage for at least a 10 year period.

(5) Load serving entities must have priority over non-load serving entities in the allocation of long-term firm transmission rights that are supported by existing capacity. The transmission organization may propose reasonable limits on the amount of existing capacity used to support long-term firm transmission rights.

(6) A long-term transmission right held by a load serving entity to support a service obligation should be re-assignable to another entity that acquires that service obligation.

(7) The initial allocation of the long-term firm transmission rights shall not require recipients to participate in an auction.

Appendix A – List of Commenters and Acronyms

Alcoa Inc. – Alcoa

Allegheny Energy Companies – Allegheny

Allete, Inc. (dba Minnesota Power) – Minnesota Power

Ameren Energy Companies – Ameren

American Electric Power Service Corporation - AEP

American Forest and Paper Association – AF&PA

American Public Power Association – APPA

Arizona Consumer-Owned Electric Systems – Arizona Systems

Arkansas Municipal Power Association – AMPA

Bonneville Power Administration – BPA

Borough of Chambersburg, Pennsylvania - Chambersburg

BP Energy Company – BP Energy

California Department of Water Resources, State Water Project - DWR

California Municipal Utilities Association – CMUA

California Independent System Operator Corporation - CAISO

Public Utilities Commission of the State of California – CPUC

Central Hudson Gas & Electric Corporation, Consolidated Edison Company of New York, Inc., LIPA, New York Power Authority, New York State Electric and Gas Corporation, Orange and Rockland Utilities, Inc., and Rochester Gas and Electric Corporation – New York Transmission Owners

Central Vermont Public Service Corporation – Central Vermont

Cinergy Services, Inc. – Cinergy

City of Redding, California - Redding

City of Santa Clara, California, Silicon Valley Power – Santa Clara

Constellation Energy Group, Inc. – Constellation

Coral Power, L.L.C. – Coral Power

DC Energy, L.L.C. – DC Energy

Dominion Resources, Inc. – Dominion

DTE Energy Company - DTE

Duquesne Light Company – Duquesne

Edison Electric Institute - EEI

E.ON U.S. – E.ON

Electricity Consumers Resource Council, American Iron and Steel Institute, Association of Businesses Advocating Tariff Equity, and Coalition of Midwest Transmission Customers – Industrial Consumers

Electric Power Supply Association – EPSA

Energy Producers and Users Coalition and Cogeneration Association of California – Energy Producers and Users/Cogeneration Association

Exelon Corporation - Exelon

FirstEnergy Service Company – FirstEnergy

Illinois Municipal Electric Agency - IMEA

Indianapolis Power & Light Company - IPL

ISO New England, Inc. – ISO-NE

Kentucky Public Service Commission – Kentucky PSC

Long Island Power Authority and LIPA – LIPA

Los Angeles Department of Water and Power – LADWP

Manitoba Hydro – Manitoba

Metropolitan Water District of Southern California - MWD

MidAmerican Energy Company – MidAmerican

Midwest Stand-Alone Transmission Companies – MSATs

Midwest Independent Transmission System Operator, Inc. – Midwest ISO

Midwest Transmission Owners – Midwest TOs

Modesto Irrigation District - Modesto

Morgan Stanley Capital Group Inc. – Morgan Stanley

National Association of Regulatory Utility Commissioners – NARUC

National Grid USA – National Grid

National Rural Electric Cooperative Association – NRECA

New England Power Pool Participants Committee – NEPOOL

New England Public Systems – New England Public Systems

New York Association of Public Power – NYAPP

New York Independent System Operator, Inc. – NYISO

New York Power Authority - NYPA

Public Service Commission of New York – New York PSC

Northeast Utilities – NU

Northern California Power Agency – NCPA

NSTAR Electric & Gas Corporation - NSTAR

Organization of MISO States – OMS

Pacific Gas and Electric Company – PG&E

PJM Interconnection, L.L.C. - PJM

Old Dominion Electric Cooperative, North Carolina Electric MembershipCorporation, Delaware Municipal Electric Corporation, Southern Maryland Electric Cooperative, and Allegheny Electric Cooperative – PJM Public Power Coalition

PPM Energy, Inc. – PPM Energy

Public Power Council – Public Power Council

Reliant Energy, Inc. – Reliant

Sacramento Municipal Utility District - SMUD

San Diego Gas & Electric Company – SDG&E

City of Santa Clara, California, Silicon Valley Power – Santa Clara

Southern California Edison Company – SoCal Edison

Strategic Energy, L.L.C. – Strategic Energy

Suez Energy North America, Inc. – Suez Energy

Transmission Access Policy Study Group – TAPS

Transmission Agency of Northern California – TANC

Vermont Public Service Board and Vermont Department of Public Service –Vermont Agencies

Wisconsin Electric Power Company – Wisconsin Electric

Xcel Energy Services Inc. – Xcel

1 The 60-day Notice (issued 8/26) appeared in the Federal Register at 74FR45434 (9/2/09). [The 30-day Notice was issued 11/9 (74FR59144, 11/17/09).]

2 Please note that, for OMB’s ROCIS system, the average cost per response has been aggregated and estimated as 1,192 hours/6 responses. Similarly, the average cost per response has been aggregated and estimated as $73,524.05/6 responses. More accurate and detailed burden and cost estimates are provided in this supporting statement where the burden and cost are split up: (1)for the filing requirement for a new transmission organization, and (2)for existing & new transmission organizations to make plans & procedures available to public.

3 Number of hours an employee works each year.

4 Pub. L. No. 109-58, § 1233, 119 Stat. 594, 957 (2005).

5 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 at 31,682 (1996), order on reh’g, Order No. 888-A, 62 FR 12274 (March 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), aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002).

6 Under functional unbundling, the public utility is required to: (1) take wholesale transmission services under the same tariff of general applicability as it offers its customers; (2) state separate rates for wholesale generation, transmission and ancillary services; and (3) rely on the same electronic information network that its transmission customers rely on to obtain information about the utility’s transmission system. Id. at 31,654.

7 Order No. 888 at 31,655; Order No. 888-A at 30,184.

8 Order No. 888 at 31,730.

9 Regional Transmission Organizations, Order No. 2000, FERC Stats. & Regs. ¶ 31,089 (1999), order on reh’g, Order No. 2000-A, 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).

10 Order No. 2000 at 30,992-93 and 31,014-15.

11 Id. at 31,015-17.

12 Id. at 31,024.

13 Id. at 31,106 et seq.

14 While “FTR” is sometimes used to refer to “firm transmission rights,” in this Final Rule we use this acronym to refer to the various forms of financial transmission rights that exist in organized electricity markets. In some markets, these are referred to as congestion revenue rights or transmission congestion contracts.

15 For a more detailed discussion, see Long-Term Firm Transmission Rights in Organized Electricity Markets, Notice of Proposed Rulemaking, 71 Fed. Reg. 6693 (Feb. 9, 2006), FERC Stats. & Regs. ¶ 32,598 at P 27 (2006) (NOPR). As we noted in the NOPR, ARRs confer the right to collect revenues from the subsequent FTR auction.

16 A detailed discussion of transmission rights in traditional and organized markets was presented in the NOPR at P 15-33.

17 The transmission provider may also need to curtail service to certain customers.

18 Notice Inviting Comments On Establishing Long-Term Transmission Rights in Markets With Locational Pricing and Staff Paper, Long-Term Transmission Rights Assessment, Docket No. AD05-7-000 (May 11, 2005) (Staff Paper).

19 Pub. L. No. 109-58, 119 Stat. 594

20 Pub. L. No. 109-58, § 1233, 119 Stat. 594, 958.

21 Id. at 960. Transmission organization is defined in EPAct 2005 as “a Regional Transmission Organization, Independent System Operator, independent transmission provider, or other transmission organization finally approved by the Commission for the operation of transmission facilities.” Pub. L. No. 109-58, § 1291, 119 Stat. 594, 985. Below, we adopt this definition with a minor modification for purposes of this Final Rule.

22See supra note 12.

23 As we discuss in more detail below, while we do not believe major changes to existing allocation procedures will be necessary, Congress did not intend to protect existing or future allocation methodologies from the implementation of section 217(b)(4) of the FPA. See new section 217(c) of the FPA, Pub. L. No. 109-58, § 1233, 119 Stat. 594, 958-59.

24 Capacity available would be limited to that which is generally available and excludes capacity that is the exclusive right of a participant, e.g., a participant that paid for such capacity and obtained FTRs for that payment.

25 We are not requiring any “obligation to build” that does not already exist under Order No. 888.

26 NOPR at P 8.

27 A list of commenters on the NOPR and the acronyms used to refer to them in this preamble is attached as Appendix A.

28 NRECA, while not recommending any change to the proposed definition, notes that the issues raised over the availability of long-term firm transmission rights also arise in transmission organizations without Day 2 markets and on the systems of non-independent entities.

29 This is not to say that there might not in the future be types of transmission organizations other than ISOs and RTOs approved by the Commission that operate transmission facilities and provide transmission service. The new FPA definition of transmission organization leaves open this possibility. At the current time, however, RTOs and ISOs are the only such organizations approved by the Commission.

30 While transmission organizations with organized electricity markets are also expected to have OATTs that meet the requirements of Order No. 888, the total cost of transmission service in those transmission organizations varies with the cost of congestion, and such transmission organizations only offer FTRs to hedge congestion costs with short-terms.

31 NOPR at P 7, citing Pub. L. No. 109-58, § 1233, 119 Stat. 594, 957. EPAct 2005 defines electric utility as “a person or Federal or State agency (including an entity described in section 210(f)) that sells electric energy.” Pub. L. No. 109-58, § 1291, 119 Stat. 594, 984.

32 NOPR at P 7, citing Pub. L. No. 109-58, § 1233, 119 Stat. 594, 958.

33 National Grid notes that pursuant to state law, its distribution utilities have at various times been required to contract with wholesale suppliers to meet their load obligations (including congestion cost exposure), while in other retail choice programs those responsibilities have been directly assigned to retail suppliers.

34 In its reply comments, NARUC reiterates its request, further stating that the Commission should clarify that vertically-integrated utilities, municipal utilities and cooperatives in traditionally regulated states, power suppliers in retail states, and distribution utilities or auction winners in other states are all “electric utilities” and/or “distribution utilities,” and thus eligible to obtain long-term firm transmission rights.

35 MWD notes that its water pumping operations require large amounts of power (roughly 2-3 percent of California’s total energy requirement), and that these operations require long-term transmission rights to achieve reliable water delivery.

36 Specifically, section 217(g) provides that “[t]he Commission shall ensure that any entity described in section 201(f) that owns transmission facilities used predominately to support its own water pumping facilities shall have, with respect to the facilities, protections for transmission service comparable to those provided to load serving entities pursuant to this section.” See Pub. L. No. 109-58, § 1233, 119 Stat. 594, 959.

37 Reply Comments of California DWR at 9.

38 Comments of NU at 3-4.

39 16 U.S.C. § 796(22) (2000), as amended by EPAct 2005, Pub. L. No. 109-58, § 1291(b)(1), 119 Stat. 594, 984.

40 Pub. L. No. 109-58, § 1291(b)(1), 119 Stat. 594, 984.

41 NOPR at P 9, citing Pub. L. No. 109-58, § 1233, 119 Stat. 594, 958.

42 NOPR at P 9.

43 Public Power Council notes that the Commission could also interpret rights as a description of these statutory obligations.

44 NOPR at P 6.

45 Comments of APPA at 11.

46 Comments of Cinergy at 14.

47 Reply Comments of IPL at 7.

48 Id.

49 See, e.g., Chevron. U.S.A., Inc. v. NRDC, Inc., 467 U.S. 837, 844-45 (1984) (noting that where Congress has expressly left a gap for an agency to fill, the agency’s interpretation of the statute is given weight unless it is “arbitrary, capricious, or manifestly contrary to the statute”); see also Acosta v. Gonzales, 439 F.3d 550, 552-53 (9th Cir. 2006) (noting that courts defer to agency regulations that are based on a permissible construction of the statute).

50 Common principles of statutory interpretation support reading section 217 as a whole to ascertain its intent. See, e.g., United States v. Andrews, 441 F.3d 220, 223 (4th Cir. 2006) (noting that statutory phrases are not construed in isolation, and are instead read as a whole).

51 Comments of EEI at 11.

52 Id. at 18.

53 NU notes in reply comments that a working group has been formed within NEPOOL to “address whether the development of [long-term transmission rights] in New England can be accomplished.” Reply Comments of NU at 1.

54 Reply Comments of New England Public Systems at 6-7.

55 Comments of NSTAR at 11.

56 New England Public Systems argues in response to NSTAR that section 217(c) does not provide any basis for the wide flexibility NSTAR advocates, since that section expressly omits reference to section 217(b)(4).

57 See also Reply Comments of BP Energy at 10 (agreeing).

58 Comments of PG&E at 5.

59 Reply Comments of Midwest TDUs at 6-7.

60 Id. at 7.

61 Comments of BPA at 5.

62 In response, CAISO notes that it has not and will not discourage such parties from participating.

63 See, e.g., AEP, Coral Power, IPL, ISO-NE, NEPOOL, Reliant and TAPS.

64 For example, consider a load serving entity that is eligible for 100 MW of FTRs and that requests that the entire quantity is sourced at each of four network resources that it has historically used, each of which is capable of providing the full amount, thus encumbering up to 400 MW of transmission capacity.

65 These include CAISO, EEI, IPL, ISO-NE, Midwest ISO, MSATs, NU, OMS, SoCal Edison and Xcel.

66 See, e.g., CAISO, CPUC, EEI, IPL, NEPOOL, NU, OMS, and Reliant.

67 See, e.g., Alcoa, Allegheny, APPA, BP Energy, CMUA, Coral Power, Industrial Consumers, New England Public Systems, NCPA, NRECA, NYISO, Peabody, PJM, PG&E, and TAPS.

68 Comments of TAPS at 15.

69 See, e.g., AEP, Ameren, BP Energy, Constellation, Dominion, Duquesne, EEI, IPL, Midwest ISO, MSATs, NU, NSTAR, PG&E, SoCal Edison and Xcel.

70 For example, Allegheny argues that if the Commission requires full funding by transmission owners, it must also establish a mechanism that allows for automatic pass-through of the costs to ratepayers.

71 For example, IPL cites the Commission’s rulemaking efforts with regard to establishing Electric Reliability Organizations and Transmission Pricing Reform, and also the work of Midwest ISO’s Regional Expansion Criteria and Benefits (RECB) Task Force. Comments of IPL at 6.

72 Comments of MSATs at 11 (citing North Carolina v. FERC, 584 F.2d 1003, 1014 (D.C. Cir. 1978) (emphasis in the original)).

73 Reply Comments of MSATs at 9.

74 See, e.g., Duquesne, E.ON, IPL, MSATs, NSTAR, and SoCal Edison.

75 See, e.g., CAISO, Cinergy, Midwest ISO, NSTAR, Reliant and Suez.

76 In support, see BP Energy, NYISO, and PJM Public Power Coalition.

77 Comments of TAPS at 16.

78 Comments of IPL at 8.

79 Reply Comments of PJM at 4.

80 PJM’s suggestion that the guideline incorporate quantity restrictions on the allocation of long-term firm transmission rights is addressed under guideline (5).

81 Comments of Cinergy at 8.  Cinergy states that this approach would involve adopting guidelines (1), (6) and (8) without modification, and guidelines (3) and (4) with modifications (discussed below).

82 See, e.g., Ameren, BPA, CAISO, Cinergy, EEI, IPL, KY PSC, Midwest ISO, NARUC, NRECA, NYISO, New York Transmission Owners, NU, OMS, PJM, Reliant, SDG&E, SoCal Edison, Strategic, and Wisconsin Electric.

83 Comments of CAISO at 13.

84 See, e.g., Allegheny, Cinergy, DTE, EEI, National Grid, NRECA, NU and Xcel.

85 Comments of National Grid at 21.

86 Reply Comments of NU at 4.

87 Comments of IPL at 12.

88 Comments of Cinergy at 33.

89 Id. at 35.

90 Reply Comments of New England Public Systems at 20.

91 Comments of National Grid at 22.

92 Reply Comments of NSTAR at 9.

93 Comments of NYISO at 18.

94 Comments of SMUD at 24.

95 Comments of Cinergy at 34.

96 NRECA invokes the “affected systems” approach of the Commission’s generator interconnection policies as the basis for this requirement. Comments of NRECA at 13.

97 Comments of EEI at 21.

98 See, e.g., SoCal Edison, Minnesota Power, CMUA, FirstEnergy, APPA, Central Vermont, Redding and SMUD.

99 ^? See, e.g., Cinergy, Allegheny, Reliant, CAISO and NSTAR.

100 ^? See, e.g., AF&PA, Xcel, Allegheny, EEI, NARUC, Morgan Stanley, BP Energy, Strategic Energy, ISO-NE, NYISO, EPSA, SDG&E, Midwest ISO, NYDPS and Constellation.

101 ^? See, e.g., NRECA, TAPS, APPA, SMUD, Redding, TANC and New England Public Systems.

102 ^? See, e.g., New England Public Systems, AEP, PJM, BPA, PJM Public Power Coalition and TAPS.

103 See, e.g., OMS, DTE, EEI, IPL, Reliant, Strategic Energy and Xcel.

104 See, e.g., NRECA, Ameren, Public Power Council and TANC.

105 See, e.g., Santa Clara, Public Power Council, PG&E, National Grid, Morgan Stanley, DC Energy, Cinergy, BP Energy and Wisconsin Electric.

106 ^? See, e.g., FirstEnergy, Coral Power, NYAPP, NRECA, PJM, Santa Clara, Redding and Suez Energy.

107 ^? See, e.g., Manitoba Hydro, Coral Power, CMUA, ISO-NE, New England Public Systems, PPM Energy, Midwest ISO, NRECA, IPL, PJM and LIPA.

108 ^? See, e.g., Allegheny, Cinergy, Constellation, Coral Power, Midwest ISO, Exelon, NARUC, OMS, Suez Energy, NEPOOL, National Grid, NU and NSTAR.

109 ^? See, e.g., E.ON, Constellation, EPSA, NYISO and Strategic Energy.

110 ^? See, e.g., EEI, EPSA, Reliant, Exelon, Constellation, SDG&E, NYISO and Midwest ISO.

111 ^? See, e.g., APPA, NYAPP, NRECA, DWR, CMUA, FirstEnergy and New England Public Systems.

112 ^? See, e.g., ISO-NE, Midwest ISO, NYISO, Coral Power, APPA and CPUC.

113 ^? See, e.g., Public Power Council, Allegheny, AEP, Industrial Consumers, PJM Public Power Coalition, Alcoa and FirstEnergy.

114 As noted above, common principles of statutory interpretation support reading section 217 as a whole to ascertain its intent. See, e.g., United States v. Andrews, 441 F.3d 220, 223 (4th Cir. 2006) (noting that statutory phrases are not construed in isolation, and are instead read as a whole).

115 See also our discussion of the definition of load serving entity in section II.A. above.

116See, e.g., PJM, NRECA, CMUA, Santa Clara, Xcel, Allegheny, Public Power Council, AEP, APPA, AF&PA, Minnesota Power, BPA, Strategic Energy, Coral Power and PJM Public Power Coalition.

117 ^? See, e.g., CAISO, SoCal Edison, PG&E, APPA, Redding, CMUA, Strategic Energy, Midwest ISO, SDG&E, BPA, TAPS and Alcoa.

118 ^? See, e.g., APPA, Allegheny, BPA, CAISO, Ameren, AF&PA, Santa Clara, Cinergy and OMS.

119 ^? See, e.g., AEP, Midwest ISO, TANC, Cinergy, SMUD, NRECA, OMS, Ameren, PG&E, Allegheny, IPL and Public Power Council.

120 ^? See, e.g., EPSA, Santa Clara, OMS, Ameren, APPA, CMUA, Minnesota Power, Cinergy and TAPS.

121 ^? See, e.g., Xcel, PJM, TAPS, SoCal Edison, SMUD, Alcoa, PJM-PPC Members, APPA, AEP, BPA, NRECA, PG&E, New England Public Systems, Public Power Council, Ameren, TANC, CMUA and Central Vermont.

122 ^? See, e.g., Cinergy, DC Energy, Coral Power, Morgan Stanley, EEI, IPL, DTE, National Grid, SDG&E, Midwest ISO, AF&PA, EPSA and Reliant.

123 ^? See, e.g., AF&PA, EPSA, Midwest ISO, IPL, NYISO, CMUA and National Grid.

124 ^? See, e.g., BPA, TAPS, Industrial Consumers and Alcoa.

125 ^? See, e.g., Coral Power, Constellation, Strategic Energy, and EEI.

126 ^? See, e.g., EEI, Strategic Energy, Suez Energy, BP Energy, ISO-NE and Midwest ISO.

127 ^? See, e.g., IPL, PJM, PJM Public Power Coalition and BP Energy.

128 See, e.g., Midwest TOs and BP Energy.

129 ^? See, e.g., TANC, NRECA, TAPS, Ameren, CMUA, NCPA and APPA.

130 See, e.g., NRECA, SMUD, Midwest ISO, Reliant, AF&PA, Strategic Energy and BPA.

131 ^? See, e.g., Reliant, Kentucky PSC, PJM, Santa Clara, SoCal Edison, AEP, CAISO, ISO-NE, Midwest ISO, OMS, NU, PG&E, APPA, TAPS and Wisconsin Electric.

132 See the discussion of these issues under guideline (2), above.

133 Since the issuance of the NOPR in this proceeding, the Commission has issued a NOPR concerning revisions of the Order No. 888 OATT in Docket Nos. RM05-25-000 and RM05-17-000.

134 ^? See, e.g., AEP, Constellation, Redding and MSATs.

135 ^? See, e.g., AEP, Constellation, TAPS, Midwest, TDUs and NCPA.

136 ^? See, e.g., OMS, Ameren, SMUD, EPSA, IPL, PJM, MSATs, Midwest ISO, NRECA and TAPS.

137 ^? See, e.g., National Grid, NRECA, MSATs, TANC and Reliant.

138 ^? See, e.g., APPA, TAPS, NCPA, BPA and SMUD.

139 ^? See, e.g., SDG&E, MSATs, Midwest ISO, IPL, NYISO, CAISO, SoCal Edison, PG&E, ISO-NE and PJM.

140 ^? See, e.g., APPA, PJM, AEP, Midwest TOs and Santa Clara.

141 This is not to suggest that we are requiring any “obligation to build” or other obligation that does not already exist under Order No. 888.

142 Reply Comments of IPL at 5.

143 These include BP Energy, ISO-NE, NU, NYISO, and PJM.

144 Reply Comments of NYISO at 7.

145 A “contingent” financial transmission right for the purposes of this Final Rule is a right that only collects revenues or owes payments (corresponding to the source and sink points and quantities specified in the right) under certain conditions. These rights differ from obligation FTRs in the following ways. A schedule-contingent right would only be eligible to collect revenues or obliged to make payments if it was scheduled in the day-ahead market of the transmission organization. A dispatch-contingent right would only be eligible to collect revenues or obliged to make payments if it produced energy in real-time (i.e., was dispatched). For further discussion see, e.g., Comments of TAPS.

146 This proposed market redesign was filed on February 9, 2006 in Docket No. ER06-615-000.

147 CAISO notes that it has conducted studies of the financial rights allocation, but that a dry run with market participants under the allocation rules filed with the Commission would be more accurate. It does not expect to complete such a dry run before the first quarter of 2007.

148 APPA states that it defers to this proposal.

149 Reply Comments of PG&E at 17.

150 See, e.g., Comments of SMUD at 40-41; Reply Comments of CMUA at 3, citing Pacific Gas and Electric Company, et al., 80 FERC ¶ 61,128 at 61,427 (1997).

151 According to SMUD, CAISO can implement physical long-term rights immediately, and in fact has done so for the Western Area Power Administration.

152 5 CFR 1320.13 (2005).

153 44 U.S.C. 3507(d) (2000).

154 Regulations Implementing the National Environmental Policy Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. Preambles 1986-1990 ¶ 30,783 (1987).

155 18 C.F.R. § 380.4(2)(ii) (2005).

156 5 U.S.C. §§ 601-12 (2000).

157 The RFA definition of “small entity” refers to the definition provided in the Small Business Act, which defines a “small business concern” as a business that is independently owned and operated and that is not dominant in its field of operation. See 15 U.S.C. § 632 (2000).

158 See 5 U.S.C. 804(2) (2000).