06-8928. New PURPA Section 210(m) Regulations Applicable to Small Power Production and Cogeneration Facilities

Issued October 20, 2006.

AGENCY:

Federal Energy Regulatory Commission, DOE.

ACTION:

Final rule.

SUMMARY:

The Federal Energy Regulatory Commission (Commission) is amending its regulations governing small power production and cogeneration in response to section 1253 of the Energy Policy Act of 2005 (EPAct 2005), which added section 210(m) to the Public Utility Regulatory Policies Act of 1978 (PURPA).

DATES:

Effective Date: The rule will become effective January 2, 2007.

FOR FURTHER INFORMATION CONTACT:

Deborah Wyrick (Technical Information), Office of Energy Markets and Reliability, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, [phone]. Marka Shaw (Technical Information), Office of Energy Markets and Reliability, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, [phone]. Samuel Higginbottom (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, [phone]. Eric Winterbauer (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, [phone].

SUPLEMENTARY INFORMATION:

Before Commissioners: Joseph T. Kelliher, Chairman; Suedeen G. Kelly, Marc Spitzer, Philip D. Moeller, and Jon Wellinghoff.

I. Introduction

1. On August 8, 2005, the Energy Policy Act of 2005 (EPAct 2005)^[1] was signed into law. Section 1253(a) of EPAct 2005 adds section 210(m) to the Public Utility Regulatory Policies Act of 1978 (PURPA)^[2] which provides, among other things, for termination of the requirement that an electric utility enter into a new contract or obligation to purchase electric energy from qualifying cogeneration facilities and qualifying small power production facilities (QFs) if the Federal Energy Regulatory Commission (Commission) finds that the QF has nondiscriminatory access to one of three categories of markets defined in section 210(m)(1)(A), (B) or (C). Thus, to relieve an electric utility of its mandatory purchase obligation under PURPA, the Commission must identify which, if any, markets meet the criteria contained in 210(m)(1)(A), (B) or (C), and, if such markets are identified, it must determine whether QFs have nondiscriminatory access to those markets.

2. On January 19, 2006, the Commission issued a notice of proposed rulemaking (NOPR) proposing regulations to implement the provisions of the new PURPA section 210(m) and proposing to terminate the requirement that an electric utility enter into a new contract or obligation to purchase electric energy from QFs if the electric utility is a member of Midwest Independent Transmission System Operator, Inc. (Midwest ISO), PJM Interconnection, L.L.C. (PJM), ISO New England, Inc. (ISO-NE), or New York Independent System Operator (NYISO). After considering industry comments on the NOPR, the Commission issues this Final Rule amending the Commission's regulations to implement the requirements in section 210(m). We believe the regulations adopted in the Final Rule reflect Congress's intent to differentiate between three types of market structures, each of which presents differing factors relevant to our determination of whether QFs have access to a sufficiently competitive market to support elimination of the purchase requirement. Our Final Rule also recognizes the special circumstances faced by small QFs and, accordingly, applies a different test for this class of QFs. In addition to a presumption in favor of small QFs, the rule also recognizes that some QFs, irrespective of size, may not have the ability to sell in certain markets because of operational characteristics or other constraints.

3. The Commission received extensive comments on its NOPR.^[3] At one extreme are commenters who argue that the Commission may not address the mandatory purchase requirement issues by rulemaking and that competitive capacity and energy markets do not yet exist to support a generic finding that QFs in the four regional transmission organization/independent system operator (RTO/ISO) regions should lose the right to require electric utilities to purchase their electric output. At the other extreme are those who argue that the Commission, with limited exceptions, should eliminate the mandatory purchase requirement altogether.

4. We do not believe that either extreme reflects the letter or the spirit of section 210(m). The QFs who advocate that we may not or should not act at all by rulemaking fail to recognize that the Commission has broad latitude to act by either rulemaking or adjudication. Nowhere does section 210(m) preclude the Commission from acting by rulemaking. Moreover, where, as here, recurring and common issues of fact arise, acting by rulemaking is not only permissible, but provides more effective notice to and opportunity for participation by all affected parties. To some extent, generic findings about markets are inevitable, either by rulemaking or in the first utility specific filing concerning a specific market. Making generic findings by rulemaking provides affected entities, including QFs, a better opportunity to participate in the generic proceeding as well as the individual proceedings that will follow. Finally, the substantive arguments of these entities that underlie their procedural objections fail to recognize that Congress, in enacting section 210(m), explicitly recognized three different market structures and required the Commission to respect the differences in those markets when making determinations as to whether to rescind the purchase obligation. In essence, they are rearguing the very debates that Congress settled in adopting section 210(m).

5. We also do not agree with the position of utilities that advocate we should terminate the purchase obligation in summary fashion in this rulemaking. Although our action today respects the choice of Congress in establishing different tests for different market structures, we do not, in this rulemaking, terminate the purchase obligation of any utility. In this respect, we modify our approach in the NOPR. In contrast to the NOPR, in this Final Rule we establish only rebuttable presumptions that the purchase obligation should be eliminated with respect to certain QFs, not final determinations.

6. In sum, this Final Rule appropriately reflects Congressional intent in enacting section 210(m). It does not, as some commenters suggest, ignore the fact that Congress did not repeal PURPA section 210(a)'s directive that the Commission prescribe, and from time to time revise, such rules as it determines necessary to encourage cogeneration and small power production. Rather, it recognizes the fundamental change which Congress made to the statutory construct when it determined that “no electric utility shall be required * * * to purchase electric energy from” a QF if certain findings are made with respect to various markets. Our action properly implements Congressional intent in the new section 210(m) that the three different market structures present different considerations in determining whether to relieve utilities of the purchase obligation. Our action also properly recognizes that smaller QFs can face more significant challenges than larger QFs in accessing competitive wholesale markets. Our action continues to support QF development by ensuring that, where the requirements of section 210(m) are met, QF development will, as determined by Congress, be stimulated by market forces, and that where those requirements have not been met, QF development will continue to be stimulated as it is today through the mandatory purchase obligation. Finally, nothing in this Final Rule affects any electric utility's resource adequacy obligations, compliance with the Electric Reliability Organization's reliability standards, prudent utility practice to build or purchase reliable power at the most economical price, or resource portfolio obligations under state law including obligations to purchase renewable energy.

II. Executive Summary

7. This Final Rule amends the Commission's regulations in part 292 ^[4] (pertaining to electric utilities' requirement to purchase electric energy from or sell electric energy to a QF) to implement section 1253 of the EPAct 2005. As relevant here, section 1253 added a new section 210(m) to PURPA, which:

A. Provides for the termination of the requirement that an electric utility enter into new contracts or obligations to purchase electric energy from a QF, after appropriate findings by the Commission;

B. Preserves existing contracts and obligations to purchase electric energy or capacity from or to sell electric energy or capacity to a QF;

C. Provides for the reinstatement of the requirement to purchase electric energy from a QF, upon a showing that the conditions for terminating the requirement are no longer met; and

D. Provides for the termination of the requirement that an electric utility enter into new contracts to sell electric energy to QFs, after appropriate findings by the Commission.

The Commission is amending its Part 292 regulations to address the above section 210(m) provisions and also to provide a process for applying for the reinstatement of the requirement to sell electric energy to QFs upon a showing that the conditions for the removal of that requirement are no longer met.

A. Termination of the Mandatory Purchase Requirement That an Electric Utility Enter Into a New Contract or Obligation To Purchase Electric Energy From QFs

8. This Final Rule promulgates regulations that set forth the process by which electric utilities may apply to be relieved of the requirement that they enter into new contracts or obligations for the purchase of electric energy from QFs after August 8, 2005. New § 292.309 of the Commission's regulations describes the findings that the Commission must make to justify relieving an electric utility's obligation to enter into new QF purchase contracts. If the Commission finds that the QF has nondiscriminatory access to one of three wholesale markets described in the statute, the requirement that the electric utility enter into new contracts or obligations is terminated. These three wholesale markets, set forth in the statute in section 210(m)(1), and incorporated in the new Commission regulations at § 292.309, are:

(A)(i) Independently administered, auction-based day ahead and real time wholesale markets for the sale of electric energy; and (ii) wholesale markets for long-term sales of capacity and electric energy; or

(B)(i) Transmission and interconnection services that are provided by a Commission-approved regional transmission entity and administered pursuant to an open access transmission tariff that affords nondiscriminatory treatment to all customers; and (ii) competitive wholesale markets that provide a meaningful opportunity to sell capacity, including long-term and short-term sales, and electric energy, including long-term, short-term and real-time sales, to buyers other than the utility to which the qualifying facility is interconnected. In determining whether a meaningful opportunity to sell exists, the Commission shall consider, among other factors, evidence of transactions within the relevant market; or

(C) Wholesale markets for the sale of capacity and electric energy that are, at a minimum, of comparable competitive quality as markets described in subparagraphs (A) and (B).

We interpret section 210(m)(1) to require the Commission to eliminate the purchase obligation in markets which meet the criteria of section 210(m)(1)(A), (B) or (C) if QFs have nondiscriminatory access to such markets. These three wholesale markets are characterized in this rule in short-hand terms as “Day 2” markets (auction based day-ahead and real-time markets), “Day 1” markets (auction based real-time markets but not auction based day-ahead markets), and comparable markets, respectively.^[5] The Final Rule finds that the Midwest ISO, PJM, ISO-NE, and NYISO all meet the criteria of section 210(m)(1)(A). These RTOs are independently administered and offer auction-based day ahead and real time wholesale markets for the sale of electric energy; and within the regions represented by these RTOs there is nondiscriminatory access to wholesale markets for long-term sales of capacity and electric energy. Therefore, except for the rebuttable presumptions set forth below, the member electric utilities of these four RTO/ISOs will be eligible for relief from the requirement to enter into new contracts for the purchase of QF electric energy.

9. The Final Rule creates three rebuttable presumptions:

(A) For all three of the above markets, with the exception of the 20 megawatt (MW) presumption discussed next, the Final Rule finds that the existence of an open access transmission tariff (OATT), or a reciprocity tariff filed by a non-jurisdictional utility, pursuant to the Commission's open access regulations,^[6] creates a rebuttable presumption, under section 210(m)(1), that QFs have “nondiscriminatory access to” the relevant wholesale markets.^[7]

(B) For all three of the above markets, the Final Rule establishes a rebuttable presumption that QFs with a net capacity no greater than 20 MW, do not have nondiscriminatory access to wholesale markets.^[8] Unless an electric utility seeking the right to terminate its requirement to purchase small QF power specifically rebuts this small QF presumption, and that electric utility's request is granted by the Commission, a small QF would be eligible to require the electric utility to purchase its electric energy.

(C) The Final Rule finds that the four RTO/ISOs with “Day 2” markets, i.e., the Midwest ISO, PJM, ISO-NE, and NYISO, qualify as markets under section 210(m)(1)(A) and establishes a rebuttable presumption that these organizations provide large QFs (above 20 MWs net capacity) interconnected with member electric utilities with nondiscriminatory access to the “Day 2” wholesale markets set forth in section 210(m)(1)(A). An electric utility member of one of these four RTO filing for relief from the requirement to purchase will need to refer to this rebuttable presumption in the Final Rule as part of its application. When it files an application for relief from the purchase requirement it must also submit certain information, including information about transmission constraints within its service territory, in order to give potentially affected QFs information that may be useful in rebutting the presumption that they have access to all aspects of the applicable “Day 2” markets.^[9] A QF above 20 MWs net capacity may rebut the presumption of nondiscriminatory access by showing that it in fact lacks access.

10. The rule does not find that any markets meet the statutory criteria at this time other than the four listed RTO/ISOs (Midwest ISO, PJM, ISO-NE, and NYISO) and the Electric Reliability Council of Texas (ERCOT) (discussed below). There will be a rebuttable presumption that QFs above 20 MWs net capacity have nondiscriminatory access to these markets if they are eligible for service under a Commission-approved OATT or Commission-filed reciprocity tariff.

11. With respect to the California Independent System Operator (CAISO), and the Southwest Power Pool (SPP), which have only “Day 1” markets, it would be premature to find now that the CAISO and SPP would meet the criteria of section 210(m)(1)(A) once their ongoing market redesigns become effective. However, we find that: the CAISO and SPP meet the section 210(m)(1)(B)(i) criterion because they are Commission-approved regional transmission entities that provide transmission and interconnection services pursuant to open access transmission tariffs that provide nondiscriminatory treatment to all customers. A member electric utility of the CAISO or SPP may rely on this finding in its application to be relieved of the obligation to enter into new contracts to purchase QF electric energy, but must make all the other showings required under section 210(m)(1)(B) before its request may be granted.

12. The Final Rule finds that ERCOT meets the criteria of section 210(m)(1)(C). ERCOT offers wholesale markets for the sale of capacity and electric energy that are of comparable competitive quality as the markets described in sections 210(m)(1)(A) and (C). Therefore, except for the rebuttable presumptions set forth herein, the member electric utilities of ERCOT will be eligible for relief from the requirement to enter into new contracts for the purchase of QF electric energy.

13. New § 292.310 of the Commission's regulations sets forth the filing requirements for an application by an electric utility seeking to terminate its requirement to enter into new purchase contracts with QFs. Among other things, the regulations require the electric utility to list the names and addresses of all potentially affected QFs, existing or under development. After notice and comment, the Commission will issue an order making a final determination within 90 days of the application, as required by section 210(m)(3).

B. Preservation of Existing Contracts

14. The Final Rule preserves the rights or remedies of any party under existing contracts or obligations, in effect or pending approval before the appropriate state regulatory authority or non-regulated electric utility on or before August 8, 2005, to purchase electric energy from or to sell electric energy to a QF. This provision is stated in the new § 292.314 of the Commission's regulations. The Final Rule defines the term “obligations” broadly to encompass any legally enforceable obligation established through a state's implementation of PURPA.

C. Reinstatement of the Mandatory Purchase Requirement

15. The Final Rule also sets forth a process by which a QF may seek the reinstatement of the requirement to purchase electric energy, by showing that the conditions necessary for the removal of the requirement to purchase are no longer met. After notice, including notice to the affected utilities, and comment, the Commission will issue an order within 90 days of the application. This process is set forth in the new § 292.311 of the Commission's regulations. A QF's request may be specific (and limited) to itself alone, generic for the entire service territory of an electric utility, or regional in scope. The Commission will address the merits of each request as warranted by the circumstances presented in each case.

D. Termination of the Requirement To Sell Electric Energy to QFs

16. The Final Rule provides for applications to remove the requirement to enter into new contracts to sell electric energy to QFs. The statute provides that if the Commission finds that competing retail electric suppliers are willing and able to sell and deliver electric energy to a QF, and the electric utility is not required by state law to sell electric energy in its service territory, the requirement to sell should be terminated. The new § 292.312 of the Commission's regulations describes this process. The Final Rule makes no findings or presumptions with respect to an electric utility's obligation to sell electric energy to QFs.

E. Reinstatement of the Requirement To Sell Electric Energy to QFs

17. Finally, the Final Rule provides for applications to reinstate the requirement of an electric utility to sell electric energy to QFs, by showing that the conditions necessary for the removal of the requirement to sell are no longer met. After notice and comment, the Commission will issue an order within 90 days if the required showing is made. Applications for reinstatement are addressed in the new § 292.313 of the Commission's regulations.

F. Recovery of Prudently Incurred Costs Relating to QF Power Purchases

18. The Final Rule does not adopt new regulations implementing section 210(m)(7), regarding an electric utility's recovery of prudently incurred costs relating to purchases of electricity from QFs.

III. Background

A. History of Section 210 of PURPA

19. When Congress enacted section 210 of PURPA, it required the Commission to prescribe such rules as the Commission determined necessary to encourage cogeneration and small power production, including rules requiring electric utilities to offer to purchase electric energy from and sell electric energy to QFs. Additionally, section 210 of PURPA authorized the Commission to exempt QFs from certain federal and state laws and regulations if necessary to encourage cogeneration and small power production.

20. A cogeneration facility is defined in the Federal Power Act (FPA) ^[10] as a facility which produces electric energy and steam or forms of useful energy (such as heat) which are used for industrial, commercial, heating, or cooling purposes.^[11] Thus, cogeneration facilities simultaneously produce two forms of useful energy, namely electric energy and heat. Cogeneration facilities can use significantly less fuel to produce electric energy and steam (or other forms of energy) than would be needed to produce the two separately.

21. Small power production facilities, as defined in the FPA, use biomass, waste, or renewable resources, including wind, solar energy and water, to produce electric energy and have a power production capacity which, together with any other facilities located at the same site, is not greater than 80 megawatts.^[12] Reliance on these sources of energy can reduce the need to consume fossil fuels to generate electric power.

22. Prior to the enactment of PURPA, a cogenerator or small power producer seeking to establish interconnected operation with a utility faced three major obstacles. First, utilities were not generally willing to purchase this electric output or were not willing to pay an appropriate rate for that output. Second, utilities generally charged discriminatorily high rates for back-up service to cogenerators and small power producers. Third, a cogenerator or small power producer which provided electric energy to a utility's grid ran the risk of being considered a public utility and thus being subjected to extensive state and federal regulation.

23. Section 210 of PURPA was designed to remove these obstacles. Each electric utility is required under section 210 to offer to purchase available electric energy from cogeneration and small power production facilities which obtain qualifying status. The rates for such purchases from QFs must be just and reasonable to the ratepayers of the utility, in the public interest, and must not discriminate against cogenerators or small power producers. Rates also must not exceed the incremental cost to the electric utility of alternative electric energy (also known as the electric utility's “avoided costs”). Section 210 also requires electric utilities to provide electric energy to QFs at rates which are just and reasonable, in the public interest, and which do not discriminate against cogenerators and small power producers. Rates for the purchase of energy from and the sale of energy to a QF are set by the appropriate state regulatory authority or non-regulated utility pursuant to the Commission's regulations, 18 CFR 292.301-308 (2006).

24. Since Congress enacted PURPA, electric utilities have complained that their requirement to purchase from and sell to QFs, as implemented by the Commission in 18 CFR 292.303(a)-(b), was not economically beneficial and that they were purchasing energy they did not need and selling energy they did not want to sell. In 1995, the Commission clarified that determinations of the avoided-cost rate must take into account all alternative sources including third-party suppliers and an electric utility does not pay for electric energy it does not need.^[13] In the past decade, with the development of exempt wholesale generators (EWGs) introduced by the Energy Policy Act of 1992,^[14] the implementation of open access transmission via Order No. 888, the advent of ISOs and RTOs and organized markets, the Commission's new interconnection requirements, and increasing competition in wholesale electric markets as well as some retail electric markets, Congress has debated whether to repeal PURPA altogether, or to revise it. The result is new section 210(m), which is the subject of this rulemaking, and new section 210(n), which was addressed in Docket No. RM05-36-000.^[15]

B. New Section 210(m)

25. Section 210(m) of PURPA is titled “Termination of Mandatory Purchase and Sale Requirements.” The section revises the rights and obligations between electric utilities and QFs. Section 210(m)(1) requires the Commission to terminate the requirement of an electric utility to enter into a new contract or obligation with the QF if it finds that a QF has nondiscriminatory access to a market described in section 210(m)(1)(A), (B) or (C). Section 210(m)(2) states that after the date of enactment, no utility will be required to enter into a contract to purchase from or sell to a new cogeneration facility, unless the facility meets the criteria for new cogeneration facilities established by the Commission in implementing section 210(n) of PURPA. Section 210(m)(3) provides that an electric utility may file “an application for relief from the mandatory purchase obligation” on a service territory-wide basis and provides that the Commission must make a final determination on such an application within 90 days of the application. Section 210(m)(4) provides that a QF, a state agency, or other affected person may apply for an order reinstating the electric utility's “obligation to purchase electric energy under this section” upon a change in the market. Section 210(m)(5) provides for the termination of the requirement that an electric utility enter into a new contract or obligation to sell electric energy to a QF upon a finding that specified competitive conditions exist. Section 210(m)(6) provides that nothing in section 210(m) affects the rights or remedies of any party under any contract or obligation in effect or pending approval before the appropriate state regulatory authority or nonregulated utility on the date of enactment of section 210(m). And finally, section 210(m)(7) provides that the Commission shall issue and enforce such regulations as are necessary to ensure that an electric utility that purchases electric energy or capacity from a QF in accordance with a legally enforceable obligation entered into or imposed under section 210 of PURPA recovers all prudently incurred costs associated with the purchase.

C. NOPR

26. On January 19, 2006, the Commission issued a NOPR containing its proposal to implement section 210(m) of PURPA. Generally, the Commission proposed to incorporate the language of section 210(m) in its regulations. While section 210(m) permits electric utilities to file applications for relief from the mandatory purchase requirement, and requires the Commission to act on such applications within 90 days, the Commission determined in the NOPR that it is appropriate to act generically as much as possible. Specifically, section 210(m)(1)(A) is most suitable for such a generic implementation and the Commission proposed to make generic findings that certain markets meet the section 210(m)(1)(A) criteria. The NOPR concluded that the most reasonable interpretation of section 210(m)(1)(A) is that it was crafted to apply to regions in which ISOs and RTOs administer auction-based day ahead and real time wholesale markets for the sale of electric energy; and wholesale markets for long-term sales of capacity and electric energy are that these are available to participants/QFs in these markets.^[16] The Commission proposed in the NOPR that it would make a generic finding that the Midwest ISO, PJM, ISO-NE, and NYISO provide markets that meet the requirements of section 210(m)(1)(A) and therefore utilities that are members of those ISOs or RTOs meet the criteria for relieving those electric utilities of the requirement to enter into new contracts or obligations with QFs.^[17] Because the Commission proposed to make a generic finding with respect to 210(m)(1)(A), the Commission proposed that the electric utilities that are members of these four RTO/ISOs submit a compliance filing instead of filing applications for relief of the purchase requirement pursuant to 210(m)(3). In the compliance filing, the electric utility would demonstrate: (1) Membership in the RTO/ISO; (2) that the Commission has made a final finding that the RTO/ISO it is a member of provides nondiscriminatory access to a section 210(m)(1)(A) market; (3) a list of all potentially affected QFs; and (4) the QFs have the rights to request service under the OATT.^[18]

27. The Commission concluded that QFs have nondiscriminatory access to transmission and interconnection if they have access to utilities providing service under an Order No. 888 OATT (or to utilities providing service under a Commission-accepted reciprocity tariff) and interconnection services pursuant to the Commission's interconnection rules.^[19] The Commission also proposed, however, that there be a rebuttable presumption that a utility provides nondiscriminatory access if it has an open access transmission tariff in compliance with our pro forma OATT (or a Commission-approved reciprocity tariff) and that QFs or any other affected party should be allowed to rebut that presumption, for example, by providing specific and credible evidence that the QF does not have nondiscriminatory access to wholesale markets.^[20] The Commission noted that improper implementation of an OATT is more properly the subject of a complaint.

28. Further, the Commission proposed in the NOPR that other markets, i.e., both non-auction-based markets and non-RTO/ISO markets described in section 210(m)(1)(B) and (C), would not be addressed generically in this rulemaking but would be addressed on a case-by-case basis in response to applications filed pursuant to the Commission's implementation of section 210(m)(3) of PURPA, i.e., pursuant to the proposed § 292.310 of the Commission's regulations.^[21] The Commission proposed that subsequent changes to market conditions in all markets, i.e., markets described subparagraphs (A), (B) and (C) also would be handled on a case-by-case basis as well. Applications for termination of the requirement to enter into new contracts or obligations to purchase from QFs in markets described in subparagraphs (B) and (C) would be addressed pursuant to the proposed § 292.310 of the Commission's regulations. An application to reinstate the requirement that a utility enter in the new contracts or obligations to purchase from QFs, alleging subsequent changes to market conditions, would be addressed pursuant to the proposed § 292.311 of the Commission's regulations. The Commission noted that it must make a finding regarding an application for relief of the purchase requirement and that the finding must be made within 90 days of the date of such application. The Commission stated that it expected an application for relief to be fully supported by documentation upon which the required finding can be made.^[22]

29. Of the approximately 2,000 pages of comments the Commission has received to its NOPR, a large portion of the comments focused on the standards applicable to utilities within the “Day 2” RTO/ISOs and the procedures for utilities within “Day 2” markets to claim relief from the purchase requirement. Based on careful consideration of the comments submitted in response to the NOPR, the Commission adopts a Final Rule that makes certain modifications and clarifications to the approach in the NOPR.

IV. Discussion

A. Section 210(m)(1)

30. The new PURPA section 210(m)(1) amends the statutory requirement that electric utilities purchase electric energy from QFs and states that:

* * * No electric utility shall be required to enter into a new contract or obligation to purchase electric energy from a qualifying cogeneration facility or a qualifying small power production facility under this section if the Commission finds that the qualifying cogeneration facility or qualifying small power production facility has nondiscriminatory access to—

(A)(i) Independently administered, auction-based day ahead and real time wholesale markets for the sale of electric energy; and (ii) wholesale markets for long-term sales of capacity and electric energy; or

(B)(i) Transmission and interconnection services that are provided by a Commission-approved regional transmission entity and administered pursuant to an open access transmission tariff that affords nondiscriminatory treatment to all customers; and (ii) competitive wholesale markets that provide a meaningful opportunity to sell capacity, including long-term and short-term sales, and electric energy, including long-term, short-term and real-time sales, to buyers other than the utility to which the qualifying facility is interconnected. In determining whether a meaningful opportunity to sell exists, the Commission shall consider, among other factors, evidence of transactions within the relevant market; or

(C) Wholesale markets for the sale of capacity and electric energy that are, at a minimum, of comparable competitive quality as markets described in subparagraphs (A) and (B).

1. Three Standards for Relief

a. NOPR

31. Section 210(m)(1) defines under what conditions the Commission must relieve an electric utility of the obligation to enter into a new contract or obligation to purchase electric energy from a QF. Essentially, section 210(m)(1) establishes three different standards for relief from the purchase requirement depending on whether: (1) Electric utilities are members of “Day 2” RTO/ISOs; (2) electric utilities are members of “Day 1” RTO/ISOs; and (3) electric utilities are in neither “Day 2” nor “Day 1” RTO/ISOs. The NOPR interpreted the language of section 210(m)(1) as to what conditions must exist for the three types of markets and sought comments.

32. The NOPR explained that the first standard for relief is established in section 210(m)(1)(A) of section 210(m)(1), which applies to “Day 2” markets with wholesale bilateral long-term contracts for the sale of capacity and electric energy available to participants. The Commission indicated that, under section 210(m)(1)(A)(ii), there was no requirement, given the statutory language, to consider “evidence of transactions within the relevant market” when determining whether QFs have nondiscriminatory access to “wholesale markets for long-term sales of capacity and electric energy.” The Commission suggested that Congress presumed QFs, which have “nondiscriminatory access to” ISO and RTO regions with auction-based day ahead and real time markets, have nondiscriminatory access to long-term sales of electric energy and capacity wholesale markets outside the interconnected utility. The Commission proposed to find that Midwest ISO, PJM, ISO-NE, and NYISO meet the requirements of section 210(m)(1)(A).

33. The second standard for relief is established in section 210(m)(1)(B), which the Commission found to be intended to apply in “Day 1” RTO/ISOs, i.e., those that do not have both auction-based day ahead and real time markets. Section 210(m)(1)(B) provides for termination of the requirement that an electric utility enter into a new contract or obligation to purchase electric energy from a QF so long as there is (i) a Commission-approved regional transmission entity providing nondiscriminatory transmission and interconnection services; and (ii) “competitive wholesale markets that provide a meaningful opportunity” to sell capacity and energy on both a short- and long-term basis and energy on a real-time basis (emphasis added) to buyers other than the utility to which the QF is interconnected. In the NOPR, the Commission stated that “meaningful opportunity” is to be determined by the Commission after considering, among other factors, “evidence of transactions within the relevant market.” The Commission indicated that taken together, the terms “competitive,” “meaningful opportunity” and “evidence of transactions” suggest that Congress intended that termination of the purchase requirement in a “Day 1” market only if it could be established that QFs had opportunities to make long-term and short-term sales of capacity and long-term, short-term and real-time sales of energy into competitive wholesale markets.

34. The third standard for relief is established in section 210(m)(1)(C) of section 210(m)(1). Under this standard, the purchase requirement is removed in wholesale markets for the sale of capacity and electric energy that are, “at a minimum,” of comparable competitive quality as markets described in subparagraphs (A) and (B). The Commission explained that although this provision is not clear on its face, its reference to subparagraphs (A) and (B) requires the Commission to be mindful, in interpreting the provision, of the two types of requirements that are embodied in those sections, i.e., (1) nondiscriminatory access to transmission and interconnection services, and (2) competitive short-term and long-term markets that provide a meaningful opportunity to sell to buyers other than the utility to which the QF is interconnected.

b. Comments

35. ELCON, AWEA, Caithness and Public Interest Organizations (PIOs),^[23] for example, state that Congress did not repeal the mandatory purchase requirement and that the Commission has a continuing obligation to promote QF development. This, they contend, can only be accomplished by assuring that markets meet criteria that guarantee that QFs will enter into contracts with electric utilities of similar quality to those that they received prior to the enactment of section 210(m) of PURPA before the mandatory purchase obligation can be terminated. ELCON appears to suggest that there is only one standard for relief from the purchase requirement: “assurance of a competitive market.” ^[24] In essence, ELCON argues that sections 210(m)(1)(A), (B) and (C) establish a single standard for terminating the mandatory purchase obligation. ELCON states that section 210(m) authorizes the Commission to grant relief from the purchase requirement “if and only if a viable market exists.” ^[25] ELCON expresses its concern that because discrimination continues and the markets are flawed, competition and on-site generation will be discouraged. AWEA and Caithness state that the Commission should grant relief from the purchase requirement only in markets which are “sufficiently competitive.” ^[26] EPSA argues that the mandatory purchase requirement can be terminated only where the Commission finds that the “economic and technical equivalent to mandatory purchase is available through a competitive market.”^[27] PIOs argue that electric utilities have to demonstrate that QFs do, in fact, have physical and economic access to all of the required markets on a nondiscriminatory basis. The American Chemistry Council contends that the mandatory purchase requirement can be terminated only in those situations where wholesale markets have evolved to ensure the long-term commercial viability of QFs which enables QFs to attract investment capital and facilitates QF development; the American Chemistry Council urges the Commission to interpret section 210(m)(1) in such a manner.

36. NPRA reminds the Commission that the main purpose of cogeneration is not to serve the needs of an electric power grid or “market,” but, rather, it is to serve the interconnecting industrial thermal and electrical load. Consequently, NPRA argues that the operation of these facilities may require different market features than are required by utility electric generation or merchant generation. NPRA argues that Congress intended to terminate the “must take” requirement only when it can be demonstrated that an electric market supports not only the role of merchant power, but the retention and encouragement of cogeneration. In other words, while a market may prove an efficient and viable alternative for a merchant plant, it does not necessarily ensure that it is an efficient and viable alternative for sales of power by a cogeneration facility.

c. Commission Determination

37. We disagree with commenters' interpretation of the statutory standard for relief from the requirement that an electric utility enter into a new contract or obligation to purchase electric energy from a QF. There is nothing in section 210(m) to suggest that Congress intended to ensure a QF's commercial viability. Nor does the statute require the Commission to find that the “economic and technical equivalent to mandatory purchase is available through a competitive market” before it terminates the requirement that an electric utility enter into a new contract or obligation to purchase electric energy from QFs. Although we certainly agree with the QF commenters that Congress did not repeal the mandatory purchase requirement in its entirety, Congress clearly left the Commission with no choice but to eliminate the mandatory purchase requirement for utilities operating in certain markets upon certain findings being made. The fact is that the language of section 210(m)(1) provides that an electric utility shall be relieved of the requirement to purchase from a QF if the Commission makes certain findings, which findings do not include a determination that the “economic and technical equivalent to mandatory purchase is available through a competitive market.” This is not what section 210(m) says, nor would it make any sense to infer such an interpretation. Competitive markets do not, by definition, impose “mandatory” purchase obligations on buyers. Buyers choose among differing sellers based on their relative cost, reliability, etc. The QFs making this argument therefore ignore the relevant statutory language and, in doing so, reargue the debate before Congress when it enacted section 210(m).

38. The most reasonable interpretation of section 210(m)(1) is that Congress, in setting forth discrete tests for three different types of markets, was requiring the Commission to differentiate among these markets, and the differing circumstances they present, in determining whether a utility must be relieved of the mandatory purchase obligation. Although the statute is ambiguous in certain respects, it clearly reflects Congressional intent that the Commission differentiate among these three markets in making its determination regarding whether to terminate the purchase obligation. This approach not only reflects a natural reading of the words of the statute, it also is reasonable given the nature of the determination being made. There is little debate in this proceeding that Day 2 organized markets, as a general matter, provide greater opportunities for QFs (and other independent generators) to compete than unorganized markets because of the existence of day-ahead and real-time energy markets that allow all competing generators to submit bids to participate in the market on a nondiscriminatory basis. Although other markets—including “Day 1” markets and non-organized markets—also provide opportunities for independent generators to compete, it is not surprising that Congress would find that, as a general matter, they have less formalized structures for doing so and, hence, utilities seeking relief from the purchase obligation in those markets would bear a heavier evidentiary burden to obtain relief. The Commission cannot, as some commenters in effect ask us to do, simply collapse the three discrete tests into one test that requires an electric utility to demonstrate that a QF will remain economically viable if the purchase requirement is eliminated. This would make the three different statutory standards meaningless.

2. The Nondiscriminatory Access Requirement of Section 210(m)(1) and the OATT

a. NOPR

39. Section 210(m)(1) provides for termination of the requirement for an electric utility to enter into a new contract or obligation to purchase from a QF if the QF has “nondiscriminatory access” to a wholesale market described in section 210(m)(1)(A), (B), or (C). In the NOPR, the Commission proposed that there be a rebuttable presumption that a utility provides nondiscriminatory access if it has an Order No. 888 OATT (or a utility providing service under a Commission-approved reciprocity tariff). The Commission stated that QFs or any other party should be allowed to rebut that presumption, but that improper implementation of an OATT is more properly the subject of a complaint to ensure that the OATT is properly implemented.

b. Comments

40. ELCON and virtually every other commenter from the QF industry argue that the Commission erred in the NOPR by proposing a rebuttable presumption that a utility provides “nondiscriminatory access” to the market conditions identified in section 210(m)(1)(A), (B), or (C) if it has an OATT in compliance with the Commission's pro forma OATT, or a Commission-approved reciprocity tariff. They argue that the proposal reflects an overly simplified interpretation of the statute's “nondiscriminatory access” requirement and that the mere existence of transmission rights under an OATT does not necessarily ensure that QFs have nondiscriminatory access to markets. ELCON and the QF industry argue that barriers that discriminate against QFs could exist notwithstanding the adoption of an OATT. The California Cogeneration Council (CCC), for instance, states that these barriers could be present in ISO policies that make it more difficult or burdensome for QFs to participate in a market as compared with other types of generators or market participants. ELCON and the QF industry argue that section 210(m)(1) requires the Commission to consider such potential barriers, and to evaluate whether QFs truly have nondiscriminatory access to alternative markets, before concluding that the requirements of section 210(m)(1) have been met.

41. In addition, ELCON and the QF industry state that the Commission has recognized that the intent of Order No. 888 concerning nondiscriminatory access to transmission has not been fully realized; first in Order No. 2000 ^[28] and more recently in the NOPR on Preventing Undue Discrimination and Preference in Transmission Service.^[29]

42. EPSA, Reliant and PIOs add that any tariff for transmission and interconnection services must incorporate changes consistent with the Commission's pro-competitive policies of Order No. 2000 and any further improvements determined as part of the notice of inquiry (NOI). EPSA argues that only then will the transmission and interconnection services be provided on a nondiscriminatory, pro-competitive basis.

43. Dow Chemical Company (Dow) states that there are numerous instances in which QFs effectively have no access to organized markets or to transmission services regardless of whether the utilities to which they are interconnected technically participate in organized markets or provide transmission and interconnection services on an open access basis. Dow states that instead, in such instances, the only entity physically capable of acquiring QF output is the utility with which the QF is interconnected. American Forest & Paper states that market rules designed for merchant generation are often highly discriminatory to QFs which, because of the thermal needs of a cogeneration QF's thermal host, have limited dispatchability and must often be operated in base load configurations. American Forest & Paper states that market rules designed around the dispatchability of resources which do not have attendant manufacturing facility obligations may discriminate unnecessarily and unreasonably against QFs. Council of Industrial Boiler Owners (CIBO) state that by finding that an OATT is sufficient to ensure nondiscriminatory access to markets, the Commission fails to consider the operational differences faced by QFs.

44. In addition, Commenters argue that the NOPR's proposal that there be a rebuttable presumption that a utility provides nondiscriminatory access if it has an OATT is in essence an irrebuttable presumption. ELCON and the American Chemistry Council state that although the Commission characterizes the presumption as “rebuttable,” it also states that the presumption “cannot be rebutted by an argument that the utility has not properly implemented or administered its OATT.”

45. ELCON argues that it will be difficult for the Commission to sustain on judicial review an irrebuttable presumption that the OATT provides nondiscriminatory transmission access for all QFs when its own NOI recognizes the continuation of patterns of abuse—if anything exacerbated as transmission owners feel the pressure of competition from independent generation. ELCON states that the concern over potential discrimination will only be exacerbated in a scenario like the Entergy Independent Coordinator of Transmission (ICT) where the utility and not the RTO provide service. ELCON states that while the problem of discrimination in transmission is pervasive, a fortiori, QFs of whatever size connected at distribution voltage do not have access to markets. ELCON states that the scenario of QFs connected at distribution voltage and the circumstances of small QFs illustrate why generic conclusions are inappropriate.

46. Further, Occidental Chemical Corporation (Occidental) argues that the Commission's conclusion that a complaint, rather than the application proceeding, is the only vehicle available to address a QF's concern that the OATT is being administered or implemented in a discriminatory manner is inconsistent with the plain language of the statute. Occidental states that a QF cannot provide meaningful comments on whether an electric utility's application meets the nondiscriminatory showing required by statute, if the QF is barred from raising issues regarding discriminatory administration or implementation of the OATT and can only raise such issues in a separate complaint proceeding. In addition, Occidental argues that it is unclear how the Commission could make a determination that QFs have nondiscriminatory access under an electric utility's OATT if the Commission bars, from the outset, all evidence that the OATT is being administered or implemented in a discriminatory manner.

47. PJM is concerned with the Commission's presumption for both section 210(m)(1)(B) and (C) that having an Order No. 888 OATT on file is enough to establish a presumption of nondiscriminatory access to the grid. PJM states that rather, the Commission should analyze particular facts and circumstances relative to concerns raised with potential access to the marketplace for QFs.

48. EEI, Allegheny Power, Alliant, Entergy, National Grid and PSNM/TNP agree with the NOPR's proposal. EEI states that QF commenters raise no compelling evidence that access provided pursuant to Commission-approved OATTs is deficient. EEI states that nondiscriminatory access is the standard set by Congress in EPAct 2005, and Congress was fully aware when it used this standard that the OATT is the mechanism for achieving nondiscriminatory access. Allegheny joins EEI in stating that the Commission should make a generic finding that QF access pursuant to a Commission-approved OATT meets the “nondiscriminatory access” test of section 210(m) for all markets, whether centrally organized and administered or not.

49. EEI states that the fact that the Commission is considering updating Order No. 888 through its ongoing NOI does not mean that reliance on the OATT as the current benchmark for nondiscriminatory access is inappropriate. EEI states that at this preliminary stage of the Commission's inquiry into whether changes to the OATT should be required, it is premature to predict what the Commission may or may not finally conclude with respect to the OATT. EEI states that by basing so much of their argument on the Commission's consideration of reforms to Order No. 888, QF commenters are in essence converting a Commission NOI into a Commission final rule. EEI states that even if the Commission fine tunes the OATT, it would not mean that existing open access practices pursuant to Commission-approved OATT are discriminatory. EEI states that if the Commission does ultimately require changes, QFs—like any other generator—will reap the benefit of those enhancements.

50. EEI further argues that where issues regarding implementation or administration of a particular OATT arise, a complaint pursuant to section 206 of the FPA is the established mechanism available to QFs (or any other generator or transmission customer) to raise such concerns. It states that in a complaint proceeding, the Commission has the ability to remedy any denial of open access that results from improper administration of an OATT, but that ability is not present under PURPA section 210(m), where the Commission's only authority is to reject an application for termination of the mandatory purchase requirement.

51. EEI argues against the QFs' claim that the Commission has made the presumption of nondiscriminatory access under an OATT essentially irrebuttable. It states that as the NOPR provides, QFs or any other party will be afforded the opportunity to provide “specific and credible evidence that the QF does not have nondiscriminatory access to wholesale markets.”

c. Commission Determination

52. Under section 210(m)(1), the Commission must find that the QF has “nondiscriminatory access” to the wholesale markets described in section 210(m)(1)(A), (B), or (C) in order to terminate the requirement that an electric utility enter into a new contract or obligation to purchase electric energy from a QF. The Commission proposed in the NOPR that there be a rebuttable presumption that a utility provides the nondiscriminatory access required in section 210(m)(1) if it has an open access transmission tariff in compliance with our pro forma OATT (or a Commission-approved reciprocity tariff). However, the Commission also proposed that QFs or any other affected party should be allowed to rebut that presumption, for example, by providing specific and credible evidence that the QF does not have nondiscriminatory access to wholesale markets.

53. The Commission reaffirms the determination in the NOPR that only issues not related to the provision of open access transmission under the OATT may be raised to rebut the nondiscriminatory access presumption. We disagree with arguments of ELCON and Occidental that a QF should be able to litigate open access implementation issues in the context of 90-day QF applications or that, as Occidental claims, use of complaint proceedings to address OATT implementation is inconsistent with the language of the statute. We also reject arguments that, because the Commission issued a NOPR to reform the OATT, that we can no longer adopt a presumption that a Commission-approved OATT meets the requirements of section 210(m) regarding nondiscriminatory transmission access.^[30] As we have found in market-based rate proceedings and other contexts, a transmission owner that has an OATT on file has met the obligation set forth in Order No. 888 to provide nondiscriminatory transmission access. Until we issue a Final Rule in RM05-25-000 that modifies Order No. 888, no more is required. Further, the FPA provides specific mechanisms, complaints under FPA section 206 or 306, to address allegations that a particular utility is not properly administering the OATT. We take very seriously allegations that a transmission owner is violating its OATT, but there are established statutory procedures for addressing such allegations. PURPA section 210(m) does not change this statutory framework.^[31]

54. As to PJM's argument that a filed Order No. 888 OATT is not enough to establish a presumption of nondiscriminatory access to the grid with respect to markets in subparagraphs (B) and (C) of section 210(m)(1), we find PJM to have misinterpreted the NOPR. Affected parties under subparagraphs (B) and (C) have the same opportunity to rebut the presumption of nondiscriminatory access as parties affected under subsection (A). We note that, in general, the evidentiary showings for relief from the requirement that an electric utility enter into a new obligation to purchase electric energy from a QF in section 210(m)(1)(B) are higher than the evidentiary showings in section 210(m)(1)(A), and the evidentiary showings in section 210(m)(1)(C) are higher than the evidentiary showings required in section 210(m)(1)(B).

55. Comments discussed above that are raised in the context of open access service but also touch upon concerns with market rules and or operational issues, for example, are addressed further below.

3. Other Market Access Issues Under Section 210(m)(1)

56. The Commission explained in the NOPR, and has confirmed in this rule, that the OATT adopted in Order No. 888,^[32] and interconnection rules, adopted in Order Nos. 2003 ^[33] and 2006,^[34] are designed to eliminate undue discrimination in the provision of transmission and interconnection services. However, in the NOPR the Commission recognized that small QFs may be in a unique situation with respect to nondiscriminatory access because they interconnect with the interconnected utility at a distribution level.^[35] In the NOPR, the Commission sought comment on whether the utilities' purchase obligation should be retained for small renewable projects. The Commission also sought comment on whether there may be other categories of QFs that lack nondiscriminatory access to RTO/ISO short-term or long-term wholesale markets for which the Commission should retain the utilities' purchase obligation. With respect to whether the purchase obligation should be retained for small renewable projects, the Commission sought comments on how to define “small,” e.g., 5 MWs or below, 20 MWs or below.^[36]

57. Commenters from the QF industry essentially argue that certain categories of QFs should be “exempt” from section 210(m)(1) because these QFs lack nondiscriminatory access to the markets described in section 210(m)(1)(A), (B), or (C). In general, they argue that QFs lack nondiscriminatory access if: (1) They are of a small size, (2) they have certain operational characteristics such that the QF cannot access a particular market, (3) they are interconnected at the distribution level, or (4) a combination of the above. As discussed further below, the comments we have received do not provide a justification for categorically exempting any category of QFs from any future orders which may terminate a utility's requirement to enter into new contracts or obligations to purchase from QFs. No class of QFs has been shown to uniformly lack nondiscriminatory access based on a single factor. We also agree with commenters, such as AEP, Entergy, Missouri River, Montana-Dakota, PJM Transmission Owners, PPL, Progress Energy and Xcel, that section 210(m) does not give the Commission authority to categorically exempt certain QFs from statutory provisions. However, we believe the record does support creating a rebuttable presumption that certain QFs may not have nondiscriminatory access to markets because of their small size.

a. Small Size

i. Comments

58. CIBO argue that smaller QFs typically are less able to predict their generation and power export/import levels due to unpredictable demand fluctuations. They state that while larger facilities may face similar unpredictable situations, they may have more latitude in selecting and operating alternative equipment and that latitude could allow for a higher level of power flow control. CIBO also argue that because of a QF's small size, the transmission charges involved in accessing the three markets described in section 210(m)(1), including locational marginal pricing and transition charges, can place a small QF in a position where it cannot reach those markets. Also, CIBO, AWEA, and Granite State argue that certain markets may require membership fees in order to participate in the market. CIBO state that a sufficiently large QF may face similar problems, but it presumably has greater resources to address those problems, and sufficient economic interest in the success of the generator to bring those resources to bear on the problem. On the other hand, they argue that a small QF is more likely to lack the resources and to have less economic incentive to apply those resources to the problem, especially in light of the staying power of its competition.

59. Granite State adds that most small QF hydroelectric plants, for example, are located in areas which do not provide direct access to RTO/ISOs. It states that small QF hydroelectric projects are generally located in areas remote from high voltage power lines, their locations being determined by the site of existing dams. Granite State states that the amount of generation from a small QF hydroelectric plant is dependent on the amount of water flowing through the turbines on a particular hour. It states that they have limited resources and the staff employed by these projects are generally engaged in the day to day operation of the projects. Granite State states that developers of small hydroelectric plants do not have the software, computer and monitoring equipment to integrate to RTO/ISO operations and, in many regions, would not even be eligible to bid their energy into these markets because they are too small for the applicable minimum block.

60. CIBO also argue that a small QF exemption, such as a MW limit, would provide an administrative advantage because it would be less likely to involve the QF and the Commission in additional proceedings and thus, avoid potential additional burden on parties and the Commission.

61. Although not arguing for a size exemption, EEI states that it would be appropriate to allow affected small QFs in all markets, including “Day 2” organized markets, to have an opportunity to demonstrate that they effectively lack nondiscriminatory access to those markets, despite their legal right to such access under an OATT.

62. EEI suggests that that the Commission could consider evidence of the following limited circumstances as a basis for finding that a small QF effectively may not have nondiscriminatory access to markets. One, where a small industrial cogenerator ^[37] (with a nameplate capacity of 5 MW or less) has: (a) highly variable thermal and electrical demand on a daily basis; (b) highly variable and unpredictable wholesale sales on a daily basis; and (c) no access to a mechanism to schedule transmission service or make sales in advance on a consistent basis, either because of the variability of its electricity production or because of market rules that prevent the QF from scheduling transmission service or participating in organized markets. Two, where a QF is very small,^[38] and cannot aggregate its electricity production with other nearby facilities, and can demonstrate that it is not directly or indirectly modeled in the energy management or market information system, cannot directly sell any product or service into the RTO or ISO market and appears to the RTO or ISO only as a reduction to load.

63. AEP, Entergy, FirstEnergy, Missouri River and Montana-Dakota, PJM Transmission Owners, PPL, Progress Energy and Xcel argue that no exemption should be allowed because: (1) All QFs are eligible to receive transmission service under the pro forma OATT, regardless of the level at which they are interconnected; (2) Congress has not given the Commission the authority to exempt QFs from the provisions of section 210(m); and (3) an exemption could lead to uneconomic QF “gaming” strategies through dividing generating facilities so that they are under the size limit for the mandatory purchase obligation to kick-in.

64. Other Commenters argue that no exemption should be granted in certain RTO/ISOs. PJM Transmission Owners and PPL Electric argue that PJM has developed special procedures to ensure that small generators, even those under 20 MW, have comparable access to energy and capacity markets. Specifically, the PJM Transmission Owners state that Subpart G of PJM's tariff is dedicated to small generators to provide clear and concise rules for these power producers to ensure that they have comparable access to participate in energy and capacity markets allowing load to rely upon such resources. PJM notes that since 1999, PJM has successfully interconnected numerous small projects. These include 44 projects rated between 5-20 MW and 28 rated at 5MW or less. It further states that the majority of these projects are sponsored by developers unaffiliated with transmission or distribution system owners. Montana-Dakota adds that QFs have nondiscriminatory access to the Midwest ISO markets regardless of size.

65. With regard to the Midwest ISO, several commenters such as Missouri River Energy and Montana-Dakota argue that no exemption is necessary for small QFs because small renewable projects have become very marketable given the current regulatory and political environment of increasing renewable portfolio standards.

66. As to NYISO and ISO-NE, National Grid states that they have generation interconnection policies in place for small as well as large generators. National Grid states that there are no minimum size requirements for a generator to join NEPOOL, and while the NYISO currently will not accept bids in the markets it administers from generators with 1 MW or less of capacity, that limitation is not immutable. It states that subject to that limitation, the market rules in ISO-NE and the NYISO allow settlement for all sizes of generators. NSTAR adds that there are sufficient privileges afforded to small renewable resources in NEPOOL, and regulatory requirements and monetary incentives in the New England states to sustain small renewable projects. The New York Transmission Owners argue that in NYISO, all facilities, including those with a capacity under 20 MW, have the same equal and nondiscriminatory access to all NYISO markets and all services offered by the NYISO under its tariffs. NYISO does not take a position on whether there should be an exemption. It states, however, that any unit, regardless of ownership or QF status, that has a generating capacity of two MWs or higher can bid directly into the NYISO markets.

67. As to what QF size should be considered “small,” the proposals varied significantly from 1 MW to 80 MWs.^[39] However, in general, most of the QF industry supports a 20 MW exemption, utilities generally support no exemption, and some entities are willing to support an exemption for very small QFs (i.e., smaller than 1 MW) in specific service territories. Granite State and American Energy argue that a 20 MW demarcation strikes a reasonable balance between small and large projects. The nameplate capacity of many renewable technologies like wind and hydro do not accurately reflect the annual generating capacity of such units due to the lower capacity factor dictated by the variability in available river flow and wind. Granite State states that the 20 MW limitation would provide the needed flexibility to ensure that small projects are protected.

68. In addition, ELCON, Granite State, AWEA, and Landfill Gas state that the 20 MW demarcation is consistent with: (1) Order No. 671; and (2) the Standardization for Small Generation Interconnection Agreements and Procedures, Order Nos. 2006 and 2006-A, which recognizes that small generators, i.e., 20 MW or below, should have different standards than large generators. AWEA also states that utilizing a 20 MW threshold for “small” generators will also avoid inconsistencies with state interconnection procedures which are designed around the current 20 MW threshold for “small” generators. Further, AWEA states that a 20 MW threshold will help prevent RTO/ISO market-participation costs from discouraging market participation and development of small generators.

69. CIBO argue that “small” should be defined as 80 MW or less. They state that Congress already adopted 80 MW to reflect what is small in PURPA, which used 80 MW to treat as QFs small power production facilities with a net capacity of 80 MW or less that produce electricity from biomass, waste, renewable resources, geothermal resources, or any combination of these sources. In addition, CIBO argue that an 80 MW bright line would also resolve a number of the operational concerns faced by QFs. They argue that a QF of greater than 80 MW is more likely to interconnect to the grid at higher voltages, and less likely to interconnect at distribution voltages, thereby addressing a number of the transmission access issues, including in particular the distribution facilities charges that lower voltage QFs will face. Regardless of the interconnection voltage, CIBO argue that a QF of greater than 80 MW will more likely have an economic interest sufficient to seek to participate in the market and the resources to participate. Further, CIBO argue that a QF of greater than 80 MW will probably have more latitude in selecting and operating alternative equipment and that latitude can allow for a higher level of power flow control. Finally, they argue that an 80 MW bright line will not undercut what they claim is the Commission's goal of limiting PURPA abuse and would ensure that units benefiting from the mandatory purchase and sale obligations will in fact be the QFs that Congress has wanted to protect.

70. Granite State and USCHPA are open to a hybrid definition of “small” QF whereby small QFs with a nameplate capacity of 5 MW or less would automatically retain the right to make sales to their utilities at avoided cost rates. Those QFs with capacities of more than 5 MW and less than 20 MW would have the benefit of a rebuttable presumption in favor of retaining the utility's mandatory purchase obligation. UAE simply states that it believes that a small QF should be defined as less than 30 MW without elaboration.

71. PJM agrees that EEI's size limit exception (1 or 5 MWs) may be appropriate as applied to very small entities that do not aggregate their generation. PJM states, however, that in the PJM market resources rated below very small levels are permitted to aggregate for the purpose of submitting offers. Therefore, PJM concludes that a facility less than 100 kW may meet a “unique circumstances” standard. PJM states that it does not impose a size limit on modeling. PJM states that it requires that new resources rated higher than 10 MW, whether in the PJM market or behind the meter, as well as any new capacity resource intending to set real-time locational marginal pricing (LMP), must be explicitly modeled in the PJM Energy Management System network model. As to access, PJM states that the PJM market has a 100 kW minimum for offers to buy and sell in the Capacity and Day-Ahead Markets and 1 kW for offers in the Real-Time Market.

ii. Commission Determination

72. We believe that the record supports creating a rebuttable presumption ^[40] that certain QFs may not have nondiscriminatory access to markets because of their small size. In addition, we find that a reasonable and administratively workable definition of “small” is 20 MW. As a result, the Final Rule creates a rebuttable presumption that the requirement that an electric utility enter into new contracts or obligations to purchase from a QF remains in effect, in all markets, for QFs sized 20 MW net capacity ^[41] or smaller.^[42] This rebuttable presumption will apply to applications in markets described in section 210(m)(A), (B), or (C). To rebut this presumption, the filing electric utility will be required in its application to demonstrate, with regard to each small QF that it, in fact, has nondiscriminatory access to the market.

73. The Commission finds persuasive commenters' arguments that some QFs may not have nondiscriminatory access to one of the three markets described in section 210(m)(1)(A), (B), or (C) because of their small size. There was agreement among commenters representing both QFs and utilities that small size could affect a QF's ability to access markets. To varying degrees, the QF industry, EEI, and also PJM, recognized that small QFs may not have nondiscriminatory access to the three markets described in section 210(m)(1)(A), (B), or (C). There was not, however, consensus as to what constitutes “small” for purposes of identifying QFs that may not have nondiscriminatory access to markets.

74. In determining what constitutes “small” for purposes of the rebuttable presumption, we are not making a finding that all QFs smaller than a certain size lack nondiscriminatory access to markets. Rather, utilities seeking to terminate the requirement that they enter into new contracts or obligations to purchase from small QFs will be required to rebut the presumption that QFs sized 20 MW net capacity or smaller do not have access. A utility's demonstration must be filed as part of its application filed pursuant to section 292.310 of our regulations.

75. Commenters suggested various sizes as the demarcation between QFs that can access markets. CIBO suggested 80 MW as the logical demarcation point, pointing to the definition of “small power production facilities” in PURPA. Granite State, AWEA and Landfill Gas suggest that the Commission use 20 MW as the demarcation pointing to the Commission's use of 20 MW as being the demarcation between large and small generators for interconnection purposes and for purposes of QF exemption from sections 205 and 206 of the FPA.

76. Keeping in mind that we are creating a rebuttable presumption, and to include most small QFs that may lack nondiscriminatory access to markets within the presumption, we find that the 20 MW demarcation is reasonable. As pointed out by commenters, the Commission used 20 MW in Order No. 671 to exempt QFs that are 20 MW or smaller from sections 205 and 206 of the FPA. The Commission also used the 20 MW demarcation for eligibility for the interconnection rules contained in Order Nos. 2006 and 2006-A, which recognize that small generators, i.e., 20 MW or below, should be subject to different standards than large generators.^[43] In adopting this 20 MW demarcation in this proceeding, we recognize that no single per-MW demarcation is perfect. However, we believe that, in creating a rebuttable presumption, it is necessary to establish a clear demarcation and, as indicated, that 20 MW is appropriate for that purpose. We are influenced by the fact that the statute provides a very compressed 90-day time frame in which parties may provide the record support for a determination of whether a utility must be relieved of the purchase obligation. The statute does not provide time for lengthy litigation. Unlike other provisions of the FPA, which require notice and an opportunity for “hearing,” section 210(m)(a)(3) provides for notice and opportunity for “comment” and a final decision within 90 days of filing. Thus, it is consistent with the statutory framework to provide clear demarcations that will permit the Commission to make reasoned determinations within the 90-day period. After balancing all relevant considerations, we therefore adopt a clear demarcation of “small QF” in this Final Rule.

77. The Commission will not allow for gaming of this 20 MW rebuttable presumption. If parties are concerned that a QF has engaged in such gaming with regard to the certification or siting of a particular facility, we encourage those parties to bring their concerns to our attention. In any such proceeding, we will consider all relevant factors, including, but not limited to, ownership, proximity of facilities, and whether facilities share a point of interconnection. For purposes of evaluating proximity of facilities with regard to alleged gaming of this rebuttable presumption, we will not be bound by the one-mile standard set forth in 18 CFR 292.204(a)(2).

78. In order to rebut the 20 MW presumption, an electric utility will have the full burden to show that small QFs have nondiscriminatory access to the market of which the electric utility is a member. We will not specify, in this Final Rule, what evidence would be sufficient, but note that relevant evidence may include the extent to which the QF has been participating in the market or is is owned by, or is an affiliate of, a entity that has been participating in the relevant market.

b. Operational Characteristics and Transmission Constraints

i. Comments

79. Many commenters argue that dispatchability and intermittent resource characteristics do not allow QFs to have nondiscriminatory access to the markets described in section 210(m)(1)(A), (B), or (C). Several commenters argue that before the purchase requirement is lifted the Commission must consider the unique generation operational differences of certain QFs that affect their nondiscriminatory access to competitive markets. For example, American Forest & Paper states that real-time and day-ahead, bid-based markets are, in themselves, inadequate to support baseload operations of QFs with limited dispatchability. American Forest & Paper states that bidding into an hourly energy market subjects QFs to unworkable dispatch risks which may require either: (1) Bidding a price too low to support fixed cost recovery in order to ensure dispatch; or (2) jeopardizing industrial or other processes required to be primary under newly enacted section 210(n). Similarly, CIBO argues that the Commission should require an analysis of the operational issues, including, for example, the voltage level of the interconnection between the QF and the grid, and the fact that cogeneration thermal host limits the ability to dispatch a QF. It states that the mandatory purchase obligation should only be removed if it is demonstrated that markets are truly accessible to QFs, taking into consideration QF operational issues, including size, in some cases interconnecting at distribution voltage (with the attendant costs of paying for distribution adders), the different efficiency and operational constraints of industrial boilers, the different efficiency and operational constraints caused by industrial cogeneration hosts, and the impact of transmission charges, including locational marginal pricing and transition charges, on economically marginal QF generation.

80. Florida Industrial argues that the Commission should specifically retain the utility obligations to purchase for that category of “process-following” QFs that rely on a reject waste heat from an associated industrial manufacturing process for the production of electricity and thermal energy—and where the amount of reject waste heat varies with manufacturing production rates—such as in phosphate fertilizer manufacturing operations. It states that such process-following QFs generate at high efficiencies and consume little or no fossil fuels. However, because the rate of electric energy production varies (“follows”) in direct proportion to the underlying manufacturing processes, such QFs would find themselves at a significant and untenable disadvantage—especially with regard to deviation from schedule and energy imbalances, as well as other associated factors—if PURPA's mandatory purchase obligation were lifted in Florida.

81. In addition to EEI's comments regarding a QF's size as a contributor to a lack of nondiscriminatory access, EEI states that it would also be appropriate to allow affected QFs in all markets, including “Day 2” organized markets, to have an opportunity to demonstrate that they effectively lack nondiscriminatory access to those markets, despite their legal right to such access under an OATT where an existing QF ^[44] is located in an area in which persistent transmission capacity constraints effectively cause the QF to have neither physical ^[45] nor financial access ^[46] to markets outside the persistently congested area and there is not a sufficient opportunity to relieve the transmission constraint or to sell its output or capacity within the area on a short-term and long-term basis because of the transmission constraint.

ii. Commission Determination

82. While we agree with commenters that there may be factors unique to a QF that prevent its nondiscriminatory access to one of the three markets described in section 210(m)(1), we do not believe that any factor, other than small size, has been shown in this rulemaking to be an appropriate basis on which the Commission can establish a rebuttable presumption of lack of nondiscriminatory access. Unlike the size limitation discussed above, operational characteristics and transmission limitations are not susceptible to a clear demarcation for purposes of establishing a rebuttable presumption. We do believe, however, that by establishing a rebuttable presumption based on size, we in effect capture some of the operational issues expressed by commenters. Accordingly, the final rule does not establish a rebuttable presumption specific to operational characteristics.

83. However, with respect to the rebuttable presumption that QFs larger than 20 MW net capacity in the four listed RTO/ISOs do have access to markets, QFs larger than 20 MW may seek to rebut this presumption in their response to applications pursuant to section 210(m)(3) of PURPA and § 292.310 of our regulations. The comments suggest that a QF may rebut the presumption by showing, for example, one or more of the following factors. Although we do not make any final determinations herein as to whether any such factor, standing alone, is sufficient to rebut the presumption of market access, we do agree with the commenters that these factors are relevant to the question of whether the purchase obligation should be terminated and, upon an appropriate evidentiary showing, may be sufficient to rebut that presumption:

(A) The QF has certain operational characteristics that effectively prevent the QF's participation in a market. Such operational characteristics might include, but are not limited to: (a) Highly variable thermal and electrical demand (from the QF host) on a daily basis, such that the QF cannot participate in a market; or (b) highly variable and unpredictable wholesale sales on a daily basis.

(B) The QF has no access to a mechanism to schedule transmission service or make sales in advance on a consistent basis, either because of the variability of the QF's electric energy production or because of market rules that prevent the QF from scheduling transmission service or participating in organized markets. Such operational characteristics might include, but are not limited to, dispatchability or some other characteristic.

(C) A QF lacks access to markets due to transmission constraints. A QF may show that it is located in an area where persistent transmission constraints in effect cause the QF not to have access to markets outside a persistently congested area to sell the QF output or capacity.

84. In evaluating transmission constraints, the Commission will consider, on a case-by-case basis, among other things, the opportunity for QFs, on a nondiscriminatory basis, to obtain transmission upgrades to relieve constraints and whether the structure of the relevant market provides for the opportunity for the QF to sell notwithstanding the constraint.

c. Distribution Level

i. Comments

85. AWEA and others point out that the problems for QFs connecting at the distribution level include: (1) Wheeling charges over distribution to reach RTO/ISO markets; (2) costs associated with access to the RTO/ISO market; and (3) other costs and procedural barriers that can be unilaterally imposed by the distribution utility to deny or hinder access to the market.

86. Many commenters including AWEA, argue that QFs are typically located in areas which do not provide direct access to competitive wholesale markets, such as RTO/ISO markets. AWEA states that, instead such facilities are forced to connect to the distribution market operated by competing utilities. AWEA states that utilities and state commissions—not FERC or RTOs—control who can interconnect at the distribution level and charge costs that are prohibitive for many QFs. AWEA states that because QFs cannot reach the RTO/ISO without incurring significant costs to interconnect at the distribution level, access is typically uneconomic for QFs. AWEA states that accordingly, these QFs have no opportunity to sell power in a competitive market. AWEA states that there is no way to ensure fair and nondiscriminatory treatment to QFs forced to interconnect with a competing utility. NPRA states that a competitive market in which the utility baseloads its own generation and seeks “competitive” solutions for peaking power may not fairly accommodate the sale of capacity and energy from non-dispatchable QF generating facilities.

87. Other commenters disagree with the argument that the Commission should retain the mandatory purchase obligation for QFs interconnected at the distribution level. They argue that whether a QF interconnects at the distribution or transmission level is irrelevant because it has nondiscriminatory access to competitive markets through open access transmission and interconnection services. Central Vermont and Southern California Edison Company (SCE) state that under Order Nos. 2003-C and 2006-A all of the utility's facilities, including its distribution facilities, that are used to implement a sale for resale or to transmit electricity in interstate commerce are subject to the nondiscriminatory requirements of the utility's OATT. In addition, EEI and SCE state that QFs may take advantage of the interconnection provisions of section 210 of the FPA, under which they can obtain services at Commission-determined rates, terms and conditions. Also, EEI points out that section 1.11 of the pro forma OATT makes clear that a generator interconnected at the distribution level is entitled to request transmission service under the OATT.

88. PJM states that regardless of whether a resource interconnects at the transmission or distribution level, it is entitled in PJM to obtain interconnection service and open-access delivery service. SCE argues that if the Commission does not adopt a generic finding that generators have open access on a nondiscriminatory basis to the local distribution facilities of all Commission-regulated utilities, there is support for such a finding as to the State of California, given the existence of Wholesale Distribution Access Tariffs

ii. Commission Determination

89. The connection of a QF to distribution-level facilities can present two different issues: (i) Whether the utility owning the distribution facilities will permit the QF to have access to markets and (ii) if that access is granted, whether any associated distribution charges are sufficient to negate that access for purposes of applying section 210(m). As to the first question, we agree that a denial of actual access to distribution facilities for purposes of selling power into the wholesale market would constitute sufficient evidence to find that section 210(m) has not been satisfied (and hence to retain the mandatory purchase obligation). We recognize that open access transmission service, adopted in Order No. 888,^[47] and interconnection rules, adopted in Order Nos. 2003 ^[48] and 2006,^[49] are designed to eliminate undue discrimination in the provision of transmission and interconnection services but do not address certain distribution level issues. Indeed, the Commission does not have jurisdiction over all distribution level facilities,^[50] and thus QFs interconnected to those facilities face access issues that are different from the access issues that are faced by QFs interconnected directly to RTO/ISO facilities.^[51] Although we do not believe the record supports any generic findings that QFs interconnected at a distribution level do not have non-discriminatory access to markets, a QF may be able to show, based on its specific circumstances, that it does not have such access to markets as a result of not being able to obtain non-discriminatory access to distribution facilities. Thus, for purposes of the rebuttable presumption that QFs above 20 MWs in the four ISOs/RTOs (ISO-NE, NYISO, PJM and Midwest ISO) have non-discriminatory access to markets, QFs may be able to rebut the presumption by, e.g., demonstrating a denial of actual access to distribution facilities for the purposes of selling power to the wholesale market. Moreover, we note that, for small QFs (many of whom may be connected at distribution level), the utility must also overcome the rebuttable presumption that such small QFs do not have sufficient access to markets to satisfy section 210(m).

90. With respect to the second issue, we find that the imposition of a charge for access to the distribution system does not mean that the QF does not have “access” to competitive markets. A QF wishing to access competitive markets is expected to pay the reasonable charges, whether for transmission or distribution facilities, that are associated with such action. There is nothing in section 210(m) that suggests otherwise. Thus, the requirement to pay an interconnection charge, transmission charge, or distribution charge, in and of itself, is not an indication that a QF does not have nondiscriminatory access to a market.

4. Burden of Proof

a. NOPR

91. In the NOPR, the Commission proposed to make generic findings that certain markets satisfy the conditions of section 210(m)(1)(A). In addition, the Commission proposed to create a rebuttable presumption that the Order No. 888 OATT provides nondiscriminatory access to markets.

b. Comments

92. American Chemistry Council, Caithness, American Forest & Paper, CCC, CIBO, Occidental, PIOs, Dow, and ELCON argue that the burden of establishing that the section 210(m) criteria are met is placed squarely on the electric utility seeking relief from the must purchase requirement. Several of these commenters argue that the Commission erred in making generic determinations for section 210(m)(1)(A). All of these commenters argue that section 210(m)(3) shows Congressional intent that electric utilities can be relieved only after careful consideration on a utility-specific service territory basis—not on a broader region-wide basis. ELCON and many others claim that the Commission has a statutory obligation to make facility-specific determinations that nondiscriminatory access to long-term markets truly exists. Industrial Energy Consumers add that the statute requires that the utility make a specific showing, supported by evidence, about the existence of and nondiscriminatory access to long-term markets. ELCON and others contend that the statute does not provide the Commission with the discretion or legal authority to abandon this QF-level analysis in favor of a generic analysis. Granite State is concerned that a generic finding will adversely affect small developers because they would not receive actual notice of the elimination of the mandatory purchase requirement.

93. The CCC argues that section 210(m) requires utilities to make principal showings demonstrating that market conditions justifying removal of the mandatory purchase requirement exist. It states that QFs then have the ability to rebut the utilities' presentations. The CCC states that the NOPR turns this scheme on its head by making initial, unsupported conclusions regarding the existence of market opportunities for QFs without any utility submission or evidence, and then shifting the burden to QFs to rebut the NOPR's conclusions.

94. CIBO argue that placing the burden on industrial QFs is arbitrary, because industrial QFs generally lack the resources and Commission regulatory expertise to participate in litigation before the Commission. In addition, it argues that such a shifting of the burden of proof is contrary to 5 U.S.C. 556(d) and contrary to the structure of section 1253, which envisions that the Commission will act on applications submitted by the utility and supported by a demonstration made by the utility. Finally, the Council argues that it creates a disincentive for its members and other industrial QFs, who generally lack the resources and regulatory expertise to bear that burden.

95. Occidental adds that section 210(m)(3) provides the single mechanism by which an electric utility can eliminate its mandatory purchase requirement. It argues that the statute does not permit the Commission to relieve the applicants' burden to demonstrate the “factual basis” of their requested relief by rulemaking.

96. EEI states in its reply comments that it strongly believes the four RTO/ISOs provide nondiscriminatory access to all generators, operate competitive wholesale markets meeting the criteria in section 210(m)(1)(A)(i), and afford opportunities for long-term sales of capacity and energy within the meaning of section 210(m)(1)(A)(ii). EEI states that the Commission is correct to make generic findings regarding these markets. EEI states that to do otherwise would compel the Commission to re-litigate the same issues time and time again to reach the identical determination.

97. EEI states that only QFs will have the evidence necessary to demonstrate that they, in fact, lack access and thereby to rebut the presumption and that the Commission is not reversing the burden of proof, but placing it where it belongs. EEI states that the opportunity to rebut this presumption generally will be available to QFs in their comments to applications for relief filed pursuant to section 210(m)(3).

c. Commission Determination

98. Commenters, in response to the NOPR's proposal to find that the markets of the four RTO/ISOs satisfy section 210(m)(1)(A), raise essentially the same issue from two different perspectives: (1) The Commission's authority to make generic findings; and (2) section 210(m)(3) places the burden of proof on the electric utility, not the QF.

99. We have previously discussed the rebuttable presumptions being adopted herein—in favor of electric utilities with respect to “large” QFs in the four organized markets and in favor of “small” QFs in all markets. Several parties challenge our ability to make any such determinations on a generic basis in this rulemaking. We disagree. First, we have broad discretion to adopt generic policy or make generic findings through either rulemaking or adjudication.^[52] We believe doing so through this rulemaking provides all affected entities—including both utilities and QFs—a reasonable opportunity to be heard on common issues that arise in various market structures and for classes of QFs. It makes little sense to adopt such generic determinations in the first case to present them, thereby effectively denying the vast majority of utilities and QFs the ability to comment on those policies or findings before they are adopted for the first time. To some extent, generic findings about certain aspects of “Day 2” markets are inevitable, either by rulemaking or in the first utility specific filing in each “Day 2” market. Making generic findings by rulemaking provides affected QFs better notice.

100. Second, we are not persuaded that the issues relevant to the findings and rebuttable presumptions we adopt here vary so significantly in each case that they must be resolved only on a case-by-case basis. For example, the issue of whether the four “Day 2” markets satisfy section 210(m)(1)(A) is one that can be resolved generically. We find no merit in the contention that we should relitigate that issue hundreds of times for every QF located in “Day 2” organized markets. Our approach here is consistent with the language of the statute. Section 210(m)(1)(B) provides for the submission of “evidence of transactions within the relevant market.” Because this language is not included in section 210(m)(1)(A), our approach providing for findings and rebuttable presumptions is consistent with the statute. Finally, we note that, unlike the NOPR, we are only establishing rebuttable presumptions of access to markets, not final determinations. These rebuttable presumptions are not only reasonable because they address common, recurring issues, but also will permit better processing of applications under the compressed 90-day timeframe required by statute.^[53]

101. We also note that certain QFs recognize our authority to make generic findings. PIOs implicitly acknowledge the Commission's authority to make generic findings in supplemental comments filed on August 25, 2006. In those comments, PIOs urged the Commission to find that certain classes of QFs should retain the right to require electric utility purchases regardless of the state of the markets on the ground that certain classes of QFs lack access to markets.

102. As noted, while the Commission is making a finding in this rulemaking that four markets satisfy the market criteria of section 210(m)(1)(A) of PURPA, and is establishing a rebuttable presumption that QFs above 20 MWs have nondiscriminatory access to those markets, electric utilities within those markets will nevertheless have to file an application pursuant to our regulations implementing section 210(m)(3) of PURPA, that is pursuant to section 292.310 of the Commission's regulations, for relief from the requirement to enter into new contracts or obligations with QFs. An electric utility member of one of these four RTO/ISOs filing for relief from the obligation to purchase will need to refer to this finding in the Final Rule as part of its application. When it files for relief from the purchase obligation it must also submit information about transmission constraints within its service territory in order to give potentially affected QFs information that may be relevant to rebutting the presumption that they have access to all aspects of the applicable “Day 2” market. A QF 20 MW or smaller located within the Midwest ISO, PJM, ISO-NE, and NYISO will be presumed not to have nondiscriminatory access to these wholesale markets.^[54] A QF larger than 20 MW located within the Midwest ISO, PJM, ISO-NE, and NYISO will be presumed to have nondiscriminatory access to these wholesale markets. A QF larger than 20 MW may rebut that presumption by showing that it in fact lacks access.

103. A similar process will be used in cases for utilities located in “Day 1” or other markets. However, in those markets, other than ERCOT, there will be no presumption that a market that satisfies section 210(m)(1)(B) or (C) criteria for termination of the purchase obligation exists. The utility seeking relief will have to make that showing. In addition to providing evidence that such markets satisfy the criteria of subsections (B) and (C) generally, a utility will have to submit evidence sufficient to overcome the presumption that a QF of 20 MWs net capacity or below does not have nondiscriminatory access to those markets. Further, as indicated, there will be no presumption regarding QFs above 20 MWs for markets covered by sections 210(m)(1)(B) and (C).

104. The result of this procedural process is that, before the Commission relieves an electric utility of its requirement to enter into a new contract or obligation to purchase electric energy from any QF, the Commission will have made a facility-specific determination that the QF has nondiscriminatory access to a section 210(m)(1)(A), (B) or (C) market. It is true that the process utilizes certain rebuttable presumptions. But as discussed above, we believe that there is a reasonable basis for the presumptions we are establishing, and we stress that all of the presumptions being established are rebuttable. We also believe that the use of the presumptions will assist the parties—QFs as well as electric utilities—and the Commission to more readily process applications for termination of the purchase requirement consistent with the statute and within the 90-day timeframe required by section 210(m)(1)(3) of PURPA. Finally, we recognize concerns that QFs may not have access to the level of information that electric utilities have and that some QFs lack the resources and expertise to participate in Commission litigation. The creation of the rebuttable presumption in favor of small QFs, as well as the information requirements we are imposing on electric utilities as part of their applications, should help QFs in this regard. Thus, we believe that the procedures we are creating for processing applications to terminate the requirement that an electric utility purchase electric energy from a QF are consistent with the requirement in section 210(m)(3) of PURPA that: (1) QFs be given sufficient notice; (2) a utility set forth the factual basis on which relief is requested; and (3) a utility describe why the conditions set for in sections 210(m)(1)(A), (B) or (C) have been met.

105. As to the arguments that QFs do not have sufficient notice of the Commission's generic conclusions, we disagree. As indicated above, these parties have it backwards. We are providing greater, not lesser, notice of our conclusions regarding these issues by addressing them in a proposed rulemaking, rather than in individual adjudications. Moreover, every potentially affected QF will be given notice of the proceedings filed under § 292.310 of our regulations and will, in those proceedings, have the opportunity to rebut the generic findings made in this Final Rule.

B. Section 210(m)(1)(A) of PURPA

1. Midwest ISO, PJM, ISO-NE, and NYISO

a. NOPR

106. Section 210(m)(1)(A) of PURPA requires the Commission to terminate an electric utility's obligation to purchase from QFs if QFs have nondiscriminatory access to (i) independently administered, auction-based, day-ahead and real-time wholesale markets for the sale of electric energy; and (ii) wholesale markets for long-term sales of capacity and electric energy.

107. In the NOPR, the Commission interpreted section 210(m)(1)(A) to apply in regions in which ISOs and RTOs administer day-ahead and real-time markets, and bilateral long-term contracts for the sale of capacity and electric energy are available to participants/QFs in these markets. These are commonly known as “Day 2” RTO/ISOs. The Commission proposed to find that the Midwest ISO, PJM, ISO-NE, and NYISO satisfy the requirements of section 210(m)(1)(A).^[55] The Commission stated in the NOPR that these entities are Commission approved ISOs or RTOs that provide nondiscriminatory open access transmission services and independently administer auction-based wholesale markets for day-ahead and real-time energy sales. The Commission stated in the NOPR that additionally, with respect to subparagraph (A)(ii), the existence of bilateral long-term contracts for long-term sales of capacity and energy indicates that there is a market. The Commission stated that it is reasonable to conclude that the second prong of section 210(m)(1)(A) is met because bilateral long-term contracts are available to participants in the footprints of the Midwest ISO, PJM, ISO-NE, and NYISO. Therefore, the Commission proposed to find that electric utilities that are members of the Midwest ISO, PJM, ISO-NE, and NYISO would meet the requirements for relief from the mandatory purchase requirement.^[56]

b. Comments

108. The American Chemistry Council, American Energy, American Forest & Paper, CCC, and Midwest Transmission Customers disagree with the Commission's finding and argue that Midwest ISO, PJM, ISO-NE, and NYISO do not meet section 210(m)(1)(A). Several commenters argue that the Commission's proposed findings with respect to the Midwest ISO, PJM, ISO-NE, and NYISO markets are insufficiently supported by record evidence. In addition, the American Chemistry Council and CCC argue that these markets are premature.

109. Wisconsin Industrial Energy Group, Inc. argues that the Commission's proposed findings with respect to Midwest ISO are premature because a viable competive market does not exist in the Midwest ISO footprint and because QF owners and operators do not have nondiscriminatory access to the Midwest ISO market. Midwest Transmission Customers argue that Midwest ISO markets are still not sufficiently mature to justify the Commission terminating the PURPA purchase obligation in Midwest ISO. The American Chemistry Council and CCC argue that there is no evidentiary basis that shows bilateral contracts for long-term sales of capacity are available to QFs on a nondiscriminatory basis or that there is a “market” for such contracts. These commenters argue that the NOPR offers no qualitative analysis of the bilateral markets that are presumed to exist. ELCON argues that a QF-specific review would establish that, in many cases, QFs do not have nondiscriminatory access to long-term bilateral markets whether in RTOs or otherwise. ELCON states that considerable evidence establishes that markets either are in their infancy (e.g., Midwest ISO), or are not functioning vis-a-vis long-term sales of capacity or energy. ELCON states that it will be difficult for the Commission to sustain on judicial review a generic finding that ISOs and RTOs offer long-term markets for power when the Commission's own recent rulemaking announcing financial transmission rights (FTRs) is predicated on the need for FTRs to jump start long-term power markets specifically in regions with ISOs and RTOs. ELCON takes issue with the assertion that PJM operates an open, competitive market, citing the State of Delaware as an example. ELCON states that according to a recent report by the Delaware Cabinet Committee on Energy, competitive markets are not working in Delaware.^[57]

110. Deere & Company (Deere) states that open access transmission service presumes the existence of bilateral sale and purchase parties separate from the transmitting utility, with the transmitting utility providing the transmission service to either the seller or the buyer. Deere states that that does not mean that there is nondiscriminatory access to the long-term sale and purchase market. Deere states that one buyer for all long-term sellers in a market would mean that there is a monopsony, and through the exercise by the single buyer of its monopsony “market power,” manifested in the form of a refusal to deal, a new seller would not have any access to the long-term sale and purchase market.

111. Caithness argues that sections 210(m)(1)(A) and (B) both require that there be markets for long-term wholesale sales of energy and capacity before the must-purchase requirement can be terminated. The American Chemistry Council argues that in trying to make sense of the fact that section 210(m)(1)(B) contains a directive to “consider evidence of transactions in the relevant market,” while section 210(m)(1)(A) contains no such directive, the Commission's proposed interpretation effectively reads an essential element of section 210(m)(1)(A)—namely, the existence of “wholesale markets for long-term sales of capacity and electric energy”—out of the statute. The American Chemistry Council states that for this reason, the Commission's proposed interpretation contravenes the clear language of section 210(m)(1)(A).

112. American Forest & Paper states that bilateral contracts have always existed, but the Commission has never determined that the mere existence of bilateral contracts constituted a market, particularly, where those contracts are mostly between utilities and their affiliates.

113. The CCC states that the Commission must require an affirmative showing that buyers other than the utility are willing to purchase QF energy and capacity on a short-term and long-term basis, including through long-term purchases of capacity before the purchase obligation is lifted.

114. EEI, PJM, Constellation, Exelon, FirstEnergy, Montana-Dakota, National Grid, PJM Transmission Owners, and PPL support the Commission's preliminary finding that QFs interconnected with utilities that are members of the Midwest ISO, PJM, ISO-NE and NYISO have nondiscriminatory access to those markets and that those markets readily satisfy the section 210(m)(1)(A) criteria for removing the PURPA section 210 purchase obligation. EEI states that additional evidence of the scope of market opportunities for QFs is seen in the increasing number of QFs filing for authority to sell at market-based rates in response to the Commission's recent Order No. 671.^[58] EEI states that the QF's argument against the Commission's proposal in essence is that markets must assure QFs will receive the same amount of revenues that they would receive from mandatory utility sales at avoided cost rates before the mandatory purchase requirement may be lifted. Exelon believes that the PJM markets are effective and offer nondiscriminatory opportunities for QFs and small power producers to sell their output to entities other than the interconnecting utility. To facilitate these small generators participating in the RTO markets in the absence of a mandatory purchase requirement, Exelon suggests that the Commission encourage utilities to work with the QFs and small power producers that qualify under state renewable resource programs to develop and implement a voluntary standard offer contract.

115. EEI, PJM, Constellation, Exelon, FirstEnergy, Montana-Dakota, National Grid, PJM Transmission Owners, and PPL also support the NOPR's finding regarding bilateral contracts for long-term sales of energy and capacity. PJM states that the Commission reasonably concludes that the existence of organized and transparent competitive markets for capacity and energy provide a platform for the development of competitive bilateral contracts in satisfaction of section 210(m)(1)A(ii) of EPAct 2005. EEI states that the test of section 210(m)(1)(A)(ii) can be and is met by markets that provide opportunities for long term sales pursuant to bilateral transactions—markets which flourish in all the “Day 2” RTOs.

c. Commission Determination

116. Under section 210(m)(1)(A), the Commission must terminate the requirement that an electric utility enter a new contract or obligation to purchase electric energy from a QF if the QF has nondiscriminatory access to (i) independently administered, auction-based day-ahead and real-time wholesale markets for the sale of electric energy; and (ii) wholesale markets for long-term sales of capacity and electric energy.

117. We find that the Midwest ISO, PJM, ISO-NE, and NYISO satisfy section 210(m)(1)(A)(i) because the markets administered by these RTO/ISOs are, as required by subparagraph (A)(i), independently administered, auction-based day-ahead and real-time wholesale markets for the sale of electric energy. With respect to section 210(m)(1)(A)(ii) and the requirement for wholesale markets for long-term sales of capacity and electric energy, we find that, as proposed in the NOPR, the existence of bilateral long-term contracts for long-term sales of capacity and energy is a sufficient indication of a market. As the Commission explained in the NOPR, it is reasonable to conclude that subparagraph (A)(ii) is met because bilateral long-term contracts are available to participants in the footprints of the Midwest ISO, PJM, ISO-NE, and NYISO. Although there is no formalized market for such long-term contracts, nothing in the statute requires such an organized market. Rather, the only requirement for organized markets relates to subparagraph A(i), and the requirement that there be auction-based day-ahead and real-time markets.

118. We disagree with those who argue that because these markets are premature or in their infancy, the Commission cannot relieve utilities of the purchase obligations. The relevant issue under the statute is whether these markets satisfy the requirements enumerated above, not whether they are “perfect” today or are undergoing reforms as they develop. Again, nothing in the statutory language suggests such a test, nor have its proponents provided us with any clear demarcation to determine when such a market is too “premature” to qualify under section 210(m)(A). Further, we note that the Midwest ISO has been an RTO since 2001 and began “Day 2” operations (i.e., auction-based, day-ahead markets) in 2005. PJM has been an RTO since 2001 and began “Day 2” operations in 2000. ISO-NE has been an RTO since 2004 and began “Day 2” operations in 2003. NYISO has been an ISO since 1998 and began “Day 2” operations in 1999. These RTOs and ISOs are established and operate “Day 2” wholesale markets, as required by subparagraph (A)(i), in their respective regions.

119. CCC and the American Chemistry Council argue that the Commission's proposed findings with respect to the Midwest ISO, PJM, ISO-NE, and NYISO markets are insufficiently supported by record evidence. We find this argument without merit. The day ahead and real time markets are precisely those contemplated by the words of section 210(m)(A)(i) and, indeed, there is no real dispute that they are Commission approved independently administered entities,^[59] and that they operate auction-based day-ahead and real-time wholesale markets for the sale of electric energy as represented pursuant to their respective, Commission approved, tariffs.^[60]

120. With respect to bilateral markets in these ISOs/RTOs, i.e., section 210(m)(A)(ii), no party argues that long-term contracts do not exist in these markets or that QFs are precluded from entering into them with willing buyers.^[61] The transmission access offered by RTOs allows suppliers (including QFs) the opportunity to enter into long-term bilateral contracts in a competitive wholesale market. RTOs have no incentive to favor one set of suppliers over others in providing transmission access. RTO footprints encompass many different wholesale buyers, thus proving significant opportunity for sellers to reach many different wholesale buyers. In addition, the organized markets operated by RTOs facilitate long-term bilateral contracts between sellers (including qualifying facilities) and wholesale buyers. First, organized markets provide transparent spot energy prices that can serve as a reference in negotiating longer term contract prices. Second, organized markets reduce the costs to suppliers of making long-term bilateral supply commitments. That is because whenever a supplier is unable to produce the energy required under the bilateral contract (for example, because of an outage), the supplier can easily acquire replacement energy from the organized market at a transparent and competitive price. Moreover, even when the supplier is physically capable of producing its contractually-required energy, the supplier can acquire the energy from the RTO's market whenever it is cheaper to do so. Both of these factors reduce the cost to a supplier of entering into a long-term bilateral contract. Furthermore, our approach is consistent with the language of section 210(m)(1)(A)(ii). As discussed above, section 210(m)(1)(B) provides for the submission of “evidence of transactions within the relevant market.” Because this language is not included in section 210(m)(1)(A), our finding with respect to section 210(m)(1)(A)(ii) is consistent with the statute. We, therefore, find it reasonable to conclude that Day 2 markets provide an opportunity to make long-term sales of capacity and electric energy and meet the criteria of section 210(m)(1)(A)(ii) as well as section 210(m)(1)(A)(i).

121. As to ELCON's citation to a study by the State of Delaware finding that competitive electric energy markets are not working well in Delaware, we find it inapposite. The issue under the statute is not whether these organized markets are perfect or, alternatively, could be improved. As we stated above, all that is required by section 210(m)(A)(ii) is the presence of “wholesale markets for long-term sales of capacity and electric energy.” The Delaware report does not demonstrate that such a market does not exist.

2. Whether Membership in an RTO/ISO Is Necessary To Invoke the Rebuttable Presumption of Access to “Day 2” Markets

a. NOPR

122. In the NOPR, the Commission concluded that QFs interconnected with electric utilities that are members of Midwest ISO, PJM, ISO-NE, and NYISO have nondiscriminatory access to markets described in section 210(m)(1)(A).

b. Comments

123. Missouri River Energy Services (MRES), a municipal, and the NRECA seek clarification as to which entities are eligible for the exemption from the mandatory purchase requirement. For example, MRES states that not all entities within the Midwest ISO footprint are transmission-owning electric utility members of Midwest ISO. MRES states that it is currently a market participant in the Midwest ISO, but not a member. MRES states that in addition, MRES has assumed the section 210 mandatory purchase requirement on behalf of its members, many of which are located within the Midwest ISO footprint.

124. Progress states that while a case-by-case analysis may be appropriate, it believes that utilities such as CP&L, that have Commission-approved OATTs and are adjacent to and directly connected with a “Day 2” RTO (such as PJM), should obtain a rebuttable presumption that the second prong of the test is met. Progress states that there is no difference between a QF located within PJM and a QF located within CP&L's service territory with respect to access to short-term and long-term capacity and energy wholesale markets.

c. Commission Determination

125. The statute is clear that the obligation to purchase and thus relief of the obligation resides with the electric utility. For purposes of establishing a rebuttable presumption that QFs interconnected with certain utilities have access to “Day 2” markets, we think that a reasonable line to draw is with the member utilities of the “Day 2” RTO/ISOs. These utilities have turned over the operation of their transmission facilities to an independent entity that has no stake in the marketplace and will ensure that all users of the transmission system are treated on a nondiscriminatory basis and are provided access to markets. We recognize that other electric utilities may provide nondiscriminatory access to the “Day 2” markets. But for purposes of applying a rebuttable presumption that QFs have nondiscriminatory access to the “Day 2” markets, we believe that it is reasonable to draw the line with members of the Midwest ISO, PJM, ISO-NE, or NYISO. Nevertheless, entities that are not members of the Midwest ISO, PJM, ISO-NE, or NYISO may seek relief from the purchase obligation pursuant to either section 210(m)(1)(B) or (C) pursuant to the procedures contained in § 292.310 of the Commission's regulations. Such applications will be reviewed on an electric utility-by-electric utility basis pursuant to the procedures contained in § 292.310 of the Commission's regulations. A utility making such an application will have the burden of showing that all elements necessary for granting relief exist.

3. Compliance Filing

a. NOPR

126. The Commission proposed that to claim relief from the purchase obligation, electric utilities that are members of Midwest ISO, PJM, ISO-NE, and NYISO will need to make compliance filings pursuant to section 210(m)(3).

b. Comments

127. AEP and PJM Transmission Owners argue that the Commission should remove the obligation to require a compliance filing for utilities located in one of the exempted RTO/ISOs. PJM Transmission Owners argue that it is not apparent that Congress intended the Commission only to grant relief from such mandatory purchase requirements upon receipt of an application. AEP and PJM Transmission Owners contend there is nothing prohibiting the Commission from granting blanket relief for all electric utilities in a particular RTO/ISO that meets the requirements of section 210(m). PJM Transmission Owners request, if compliance filings are ultimately required, to be allowed to make one filing on behalf of all the electric utilities in PJM.

128. EEI states that, instead of compliance filings by utilities located within the four “Day 2” markets, the Commission may wish to require utilities to apply for relief from the mandatory purchase requirement, in accordance with section 210(m)(3) of PURPA. EEI states that utilities applying for relief would be entitled to rely on generic Commission findings (as the Commission has proposed in the NOPR) that the four “Day 2” markets meet the tests established in section 210(m)(1)(A) and that a Commission-approved OATT is evidence of nondiscriminatory access to these markets under section 210(m)(1).

c. Commission Determination

129. In light of the comments filed, we conclude that utilities in “Day 2” RTO/ISO markets should file applications pursuant to section 210(m)(3), instead of the “compliance filings” proposed in the NOPR. We believe that this will be more consistent with the statute than the compliance filings proposed in the NOPR. In the section 210(m)(3) application, a utility within a “Day 2” RTO/ISO will be required to: (a) Show that it is a member of a “Day 2” RTO; (b) provide information to enable QFs larger than 20 MW to seek to rebut the presumption that they have nondiscriminatory access to the market; such information will be a description of transmission constraints not otherwise publicly available, and if publicly available, provide a specific link to such information; and (c) provide a list of affected interconnected QFs. With respect to the section 210(m)(A) “Day 2” RTO/ISO markets, these applications, in conjunction with the generic findings and rebuttable presumptions adopted in this Final Rule and discussed elsewhere, will allow us to timely and fairly process applications within the 90-day time period intended by Congress.

C. Section 210(m)(1)(B)

1. Definition of “Regional” for Purposes of Section 210(m)(1)(B)(i)

a. NOPR

130. Section 210(m)(1)(B) requires the Commission to make a finding, among other things, that a QF has nondiscriminatory access to transmission and interconnection services provided by a Commission-approved “regional transmission entity.” In the NOPR, the Commission noted that amended section 210 does not contain any express definition of “regional transmission entity.” The Commission therefore explained in the NOPR that we have discretion in interpreting section 210(m)(1)(B)(i) to deem an entity to be “regional.” The Commission listed factors, such as sufficient regional scope or configuration of the multiple discrete transmission systems the regional transmission entity controls, to be considered when determining a “regional transmission entity.” ^[62]

b. Comments

131. American Forest & Paper, LEUG, and NISCO offer suggestions as to how the Commission should define “regional” as it is used in section 210(m)(1)(B). LEUG suggests that the Commission should use a similar standard in defining the term “regional” as it's used in Order No. 2000. American Forest & Paper believes that the Commission should exercise the discretion it has under section 210 in conformance with its observations, concerns and findings regarding the scope and independence of RTOs and ISOs necessary to assure nondiscriminatory access and independence. American Forest & Paper states that the Commission has extensive jurisprudence regarding its concerns surrounding the scope and the level of independence necessary to assure nondiscriminatory and independent administration, and should rely on this existing body of precedent when making determinations pursuant to newly enacted section 210(m). Occidental argued that the NOPR incorrectly suggests that the Commission has discretion to deem an entity to be a “Commission-approved regional transmission entity” solely in the context of a determination that the QF is provided nondiscriminatory access in accordance with section 210(m)(1)(B)(i). It requests the Commission to clarify, at a minimum, that “Commission-approved regional transmission entity” does not include stand-alone electric utilities or Entergy's ICT.

c. Commission Determination

132. In determining whether a transmission entity is “regional,” we will not rely solely on the “scope and regional configuration” standard as discussed in Order No. 2000 as one commenter suggests. Section 210(m)(1)(B) does not tie “regional” to Order No. 2000 but rather leaves to the Commission's discretion whether to deem an entity “regional” and we will make that determination on a case-by-case basis in response to applications filed by electric utilities pursuant to § 292.310 of the Commission's regulations. Accordingly, we will not make a finding that Entergy's ICT or a stand-alone electric utility would not be deemed a “regional transmission entity” at this time. The NOPR laid out some of the factors the Commission may consider in its determination, such as sufficient regional scope or configuration or the multiple discrete transmission systems and electric utility controls. In this Final Rule, an electric utility claiming relief pursuant to section 210(m)(1)(B) must set forth the reasons that it meets the requirements of section 210(m)(1)(B)(i) in an application made pursuant to § 292.310 of the Commission's regulations.

2. Section 210(m)(1)(B)(ii)

a. NOPR

133. Section 210(m)(1)(B)(ii) requires QFs to have access to competitive wholesale markets that provide a meaningful opportunity to sell capacity and energy on both a short- and long-term basis and energy on a real-time basis to a buyer other than the utility to which the QF is interconnected. The Commission is to consider, among other factors, evidence of transactions within the relevant market in determining “meaningful opportunity.” The Commission stated that, taken together, the terms “competitive,” “meaningful opportunity,” and “evidence of transactions” suggest that Congress intended waiver to occur in a non-auction based market only if it could be established that QFs had the opportunity to sell their output into competitive wholesale markets to buyers other than the utility to which the QF is interconnected. In the NOPR, the Commission sought comment on ways that section 210(m)(1)(B)(ii) could be satisfied. The Commission asked if a demonstration that an organized power procurement process exists in which QFs can participate would satisfy.

b. Comments

134. AES Shady Point, Deere, Energy Producers of California, Utah Association of Energy Users (UAE), and Solid Waste of Palm Beach believe that the existence of an organized power procurement process does not indicate the presence of a competitive wholesale market. Occidental argues that the Commission's reference to a generic “organized procurement process” lacks the specificity required in order to analyze whether it would satisfy any element of section 210(m)(1)(B)(ii) and omits the statutory requirement that QFs have a meaningful opportunity to sell to “buyers other than the utility to which the qualifying facility is interconnected.” ELCON states that the critical question is whether potential suppliers have access to other potential buyers apart from the monopsony buyer holding the request for proposals (RFP). ELCON states that the Commission should seek a demonstration of contractual sales of capacity or energy to utilities other than the interconnected utility in response to RFPs. The UAE argues that an organized procurement process does not ensure fairness since utilities often control their own procurement processes and can affect the outcome. The lack of an independently administered market makes it easy for a utility to select its own resource or a resource that it prefers. UAE also states that QF resources are likely to be eliminated in early rounds of the procurement process by unreasonably stringent credit requirements.

135. Entergy and EEI contend that a procurement process should constitute ample evidence that QFs have access to competitive wholesale energy markets. EEI states that the Commission would be correct in finding that QFs with opportunities to participate in organized power procurement processes have access to short-term and long-term markets for the sale of energy and capacity. EEI states that roughly nineteen states already require some form of competitive power procurement process.^[63] EEI states that QF commenters have submitted no evidence to disprove their ability to participate in these state-overseen processes. EEI states that competitive procurements also are a feature of retail access programs and state renewable or resource portfolio programs.

136. Pacific Gas and Electric Company (PG&E) suggests the Commission should adopt a rebuttable presumption of a “competitive wholesale market” in which an organized power procurement process exists in which QFs can participate. PG&E notes that the California legislature established a comprehensive procurement process to be administered and overseen by the California Public Utilities Commission (CPUC). PG&E states that load serving entities must prepare a procurement plan which contains a process for utility procurement and CPUC approval of procurement strategies. PG&E claims that California's procurement process ensures QFs have fair access to this process. SCE argues that QFs have robust opportunities to compete in competitive solicitations issued by IOUs. SCE notes that its power procurement solicitations that are conducted pursuant to California's Renewable Portfolio Standard are open to generators as small as one megawatt.

137. SCE suggests the Commission should make a generic finding that if the Commission has authorized market-based rate authority for any seller in a market then that market should be competitive enough to satisfy subparagraph (B)(ii). Several commenters oppose SCE's market-based rate proposal and request that the Commission reject it. The CCC argues that SCE's arguments focus solely on the issue of whether sellers in a given market are able to exercise market power and fails to address the extent to which utilities are able to exercise monopsony buying power given their role as the only load serving entities (LSEs) with the ability and potential willingness to buy power on a long-term basis or in significant quantities. Deere contends that market-based rate authority is focused on the seller and its attributes, whereas section 210(m) is focused on the QF and its ability to access a market. Occidental adds that such a finding would render the distinction between “competitive wholesale markets,” as used in subparagraph (B)(ii), and “wholesale markets,” as used in subparagraphs (B) and (C), meaningless because the Commission has authorized market-based sales in every region of the continental United States.

c. Commission Determination

138. The Commission in the NOPR set forth its interpretation of the statute and sought comments on ways section 210(m)(1)(B)(ii) could be satisfied. Specifically, the Commission asked if an organized procurement process would meet the requirements of section 210(m)(1)(B)(ii). After reviewing the comments received, we have decided not to make any generic findings concerning whether procurement processes might satisfy section 210(m)(1(B)(ii). Reflecting on parties' comments and the Commission's own experience with utilities' procurement processes leads us to conclude that the processes are complex and not uniform. Thus, we cannot find that simply requiring an organized procurement process without elaboration would meet the requirements of the statute. Accordingly, we will not make a generic finding nor establish a rebuttable presumption, as PG&E and SCE suggest. As discussed in a later section, the Commission will entertain applications for relief of the mandatory purchase requirement pursuant to section 210(m)(1)(B) on a case-by-case basis pursuant to the procedures specified in section 292.310 of the Commission's regulations. The only rebuttable presumption that will apply in the context of applications under section 210(m)(1)(B) (as well as (C)) is the presumption that QFs 20 MWs or below do not have nondiscriminatory access to the relevant markets.

139. The Commission, however, will not rule out the possibility of an organized procurement process satisfying some or all of the requirements of section 210(m)(1)(B)(ii). Should an electric utility seek such a finding in its application, it is incumbent upon the utility to fully demonstrate that the procurement process satisfies one or all of the elements of section 210(m)(1)(B)(ii).^[64] The utility must support its application with a detailed description of how the procurement process is designed, how winning bids are selected, evidence of past solicitations and winning bids,^[65] solicitation characteristics,^[66] and any other information about the procurement process. This list is not meant to be exhaustive, but rather provides examples of the type of information the Commission needs in order to make a finding.

140. SCE argues that the “competitive” element of section 210(m)(1)(B)(ii) could be met if the Commission has authorized market-based rate authority to the utility seeking relief from the mandatory purchase requirement. We will not make a generic finding as suggested by SCE. When the Commission grants an applicant market-based rate authority, it examines an applicant's generation market power potential. The competitive element of section 210(m)(1)(B)(ii) is not concerned with how much generation a utility owns or its ability to exercise generation seller market power, but rather, whether the wholesale market provides a meaningful opportunity for a QF to sell its capacity and energy to a buyer other than the utility to which the QF is interconnected.

3. Case-by-Case Determinations for Subparagraphs (B) and (C)

a. NOPR

141. In the NOPR, the Commission proposed to determine on a case-by-case basis, rather than generically, whether a utility has met the requirements of sections 210(m)(1)(B) and 210(m)(1)(C) for relief from its mandatory purchase requirement. The Commission also proposed to allow joint applications to be filed by several utilities in a region if the applications for relief present common issue of law and fact. The NOPR concluded that utilities would be required to file such applications for relief with the Commission pursuant to section 210(m)(3), which the Commission proposed to implement in section 292.310 of its regulations.

b. Comments

142. No comments were filed opposing the NOPR's proposal. Constellation seeks clarification as to how the Commission will treat current Day 1 or non-RTO markets which may, in the future, become “Day 2” markets. Constellation wants any future “Day 2” market to be analyzed on a case-by-case basis pursuant to section 210(m)(3).

143. EPSA supports a case-by-case approach for subparagraphs (B) and (C) provided that an individual QF can rebut utility's application. EPSA also argues that utilities should be required to file specific contract information that would support the premise that there are “competitive wholesale markets that provide a meaningful opportunity to sell capacity, including long-term, short-term and real-time sales to buyers other than the utility to which the qualifying facility is interconnected.”

144. LEUG, NISCO, and Occidental seek clarification in the Final Rule that Entergy's ICT does not satisfy the requirements of section 210(m)(1)(B). These commenters state that access to section 210(m)(1)(B) markets does not exist in Louisiana today, and will not result from Entergy's ICT and weekly procurement process proposals. The commenters state that an ICT can not satisfy section 210(m)(1)(B)(i) because Entergy's ICT proposal calls for Entergy to remain the owner and operator of the transmission system and continue to have ultimate responsibility for providing transmission service.

c. Commission Determination

145. The Commission adopts the NOPR's proposal to determine on a case-by-case basis in response to applications filed pursuant to section 292.310 of the Commission's regulations whether an electric utility has met the requirements of sections 210(m)(1)(B) and 210(m)(1)(C) for relief from its mandatory purchase requirement. We clarify for EPSA that individual QFs may file comments opposing a utility's section 210(m)(3) application for relief pursuant to subparagraphs (B) and (C).^[67] We will also clarify for Constellation that any current “Day 1” market or non-RTO market that becomes a “Day 2” market after issuance of this Final Rule will not be addressed generically in a rulemaking but will be addressed on a case-by-case basis. This is consistent with what the Commission proposed in the NOPR. The Commission proposed, and we adopt here, that all issues relating to non-RTO/ISOs and RTO/ISOs that do not have both auction-based real-time and day-ahead markets will be addressed on a case-by-case basis, pursuant to section 210(m)(3) as implemented by the Commission in § 292.310 of the Commission's regulations. The only generic finding in this Final Rule that will apply to case-by-case determinations are the rebuttable presumptions that the OATT and interconnection rules provide nondiscriminatory access to markets, and that QFs 20 MWs or below do not have nondiscriminatory access to markets.

146. While we will not institute another rulemaking to address whether a new “Day 2” RTO/ISO satisfies the statutory criteria for a utility to claim relief from the requirement that it enter into new contracts or obligations with QFs within the markets, we note that the 90-day proceedings provided for in section 210(m)(3) of PURPA and § 292.310 of our regulations, provide a very compressed period for making the complex determinations that a regional market satisfies the statutory criteria. Accordingly, for utilities that wish to obtain a regional generic determination that a market satisfies the criteria of section 210(m)(1)(A), we will entertain declaratory orders to make such determinations. If a generic determination is made in a declaratory order context, the utility members of the market would then be obligated to file for relief from the requirement that they purchase from QFs on a utility specific basis pursuant to section 292.310 of our regulations before the Commission would terminate the requirement that the electric utility purchase electric energy from QFs.

147. For purposes of obtaining regulatory certainty earlier rather than later, it is also possible that a QF may want to seek a declaratory order that, based on its specific circumstances, it does not have nondiscriminatory access to markets. We will entertain such declaratory order requests. If a QF obtains such an advance declaratory order, it may file the order in response to a utility's application to be relieved of the mandatory purchase obligation under section 292.310 of the Commission's regulations.

148. We will not grant the three commenters' request that we clarify in the Final Rule that Entergy's ICT does not satisfy the requirements of section 210(m)(1)(B). Rather, consistent with the approach adopted herein, we will consider Entergy's ICT on a case-by-case basis should Entergy decide to file an application for relief pursuant to section 210(m)(3) and § 292.310 of the Commission's regulations.

D. Section 210(m)(1)(C)—Nonpublic Utilities

1. NOPR

149. The NOPR proposed that there be a rebuttable presumption that a utility provides nondiscriminatory access if it has an Order No. 888 OATT on file with the Commission or a Commission-approved reciprocity tariff.

2. Comments

150. NRECA states that some non-public utility cooperatives do not have reciprocity tariffs however, a number of these non-public electric utilities have adopted OATTs based on the Commission's pro forma OATT, and have provided nondiscriminatory access to third parties for years. NRECA states that they too should be deemed to provide nondiscriminatory access on a case-by-case basis, or they should at least be accorded a rebuttable presumption that they provide such service.

3. Commission Determination

151. We decline to establish a rebuttable presumption of nondiscriminatory access here for non-public utilities which may have adopted transmission tariffs that are based on the Commission's pro forma OATT but are not on file with the Commission. The statute clearly states that the Commission must find that the QF has nondiscriminatory access to specific markets before the purchase obligation may be lifted. While the Commission appreciates that some non-public cooperatives have adopted OATTs based on the Commission's pro forma OATT, the Commission has not had opportunity to review these nor has the public, including any affected QF. We therefore believe that it is more appropriate for the Commission to evaluate whether QFs interconnected with such utilities have nondiscriminatory access to a market defined by section 210(m)(1)(A), (B), or (C) on a case-by-case basis. Non-public utilities seeking relief from the mandatory purchase requirement may file an application pursuant to § 292.310 of the Commission's regulation and may include their tariffs in support of their applications.

E. California Independent System Operator Corporation

1. NOPR

152. In the NOPR, the Commission did not make a preliminary finding that the California region operated by the CAISO met the requirements of PURPA section 210(m)(1). The Commission did recognize that the CAISO is a Commission-approved ISO, but that the requirements of section 210(m)(1)(A) have not been satisfied because the CAISO does not have a day-ahead market. The Commission noted that any utility within the CAISO footprint may file an application with the Commission to seek relief from the mandatory purchase requirement pursuant to sections 210(m)(1)(B) or (C).

2. Comments

153. SCE and PG&E submitted comments requesting that the Commission find that the CAISO will meet the requirements of section 210(m)(1)(A) once the CAISO's Market Redesign and Technology Upgrade Tariff (MRTU Tariff) is effective.^[68] SCE and PG&E note that the MRTU Tariff filing demonstrates that the CAISO region will have the requisite features to satisfy section 210(m)(1)(A)(i), specifically a day-ahead market. SCE argues that the features described in the MRTU Tariff compare with those of other regions for which the Commission is prepared to make generic findings. SCE also states there are bilateral long-term contracts in the CAISO region today. Therefore, the CAISO region meets section 210(m)(1)(A)(ii). The California Public Utilities Commission (CPUC) and PG&E also request a finding that once the Commission has determined that CAISO has met the requirements of section 210(m)(1)(A), utilities participating in CAISO need only make a ministerial filing to be granted a waiver by the Commission.

154. PG&E, SCE and the EEI request a generic finding that the CAISO satisfies section 210(m)(1)(B)(i), and thus, a utility interconnected to the CAISO meets section 210(m)(1)(B)(i). EEI notes that the Commission has ruled that the CAISO Tariff provides nondiscriminatory access to the ISO controlled grid.

155. The CCC objects to the NOPR's suggestion that California could qualify for termination of the PURPA purchase obligation once a day-ahead market starts operating. It argues that such a suggestion ignores the realities of the California market. CCC contends that QFs continue to have difficulty finding meaningful opportunities to sell their output in California due to utilities' general reluctance to execute contracts with QFs and a lack of viable alternatives to the utility purchaser. It states that merely adding an organized day-ahead market will not resolve these problems. The CCC points to a California Energy Commission's 2005 Integration Energy Policy Report (Energy Report) as support for the position that QFs do not have meaningful opportunities to sell their power in California. According to CCC, the Energy Report finds that cogenerators have few opportunities to sell their power in the existing wholesale markets and a lack of a robust, functioning wholesale market in California discourages cogenerators from installing new generation. SCE disputes CCC's representation of the Energy Report.

156. Independent Energy Producers Association of California (Independent Energy Producers) states that the MRTU has yet to be implemented let alone analyzed to ensure it is operating as designed and in a manner that the CAISO itself has determined sufficient to remedy the market deficiencies it has identified. Independent Energy Producers also notes that the California market cannot provide the nondiscriminatory access required because projects smaller than 1 MW are excluded by rule from participation. Independent Energy Producers further notes CAISO's intent to subject existing QFs with existing interconnections to renewed interconnection studies.

3. Commission Determination

157. Certain commenters request that the Commission make a generic finding that the CAISO will meet the requirements of section 210(m)(1)(A) once the CAISO's MRTU Tariff filing becomes effective. According to the CAISO, the MRTU Tariff provides for operation of a day-ahead market, which is the missing element in meeting the requirements of section 210(m)(1)(A). It would be premature for the Commission to make such a generic finding in this rulemaking proceeding. The CAISO filed its proposed MRTU Tariff on February 9, 2006, in Docket No. ER06-615-000, and requested an effective date of November 1, 2007. While the Commission conditionally approved CAISO's MRTU Tariff on September 21, 2006,^[69] the tariff will not become effective until November 1, 2007, as requested. Until there is a functioning “Day 2” RTO/ISO in California, the Commission is unable to make the findings required by section 210(m)(1)(A) for termination of the mandatory purchase requirement. However, for utilities that wish to obtain a regional generic determination that a market satisfies the criteria of section 210(m)(1)(A), we will entertain requests for declaratory orders to make such determinations.

158. Certain commenters request that the Commission make a finding that the CAISO satisfies section 210(m)(1)(B)(i). Section 210(m)(1)(B)(i) requires a QF to have nondiscriminatory access to transmission and interconnection services that are provided by a Commission-approved regional transmission entity and administered pursuant to an open access transmission tariff that affords nondiscriminatory treatment to all customers. In the NOPR, the Commission interpreted section 210(m)(1)(B)(i) to mean that QFs must have access to transmission and interconnection service pursuant to a Commission-approved OATT and interconnection rules and provided by an entity that is regional in scope.^[70] The CAISO has a Commission-approved OATT that has been amended to incorporate the interconnection requirements of Order No. 2003. Thus, in order to make a finding that the CAISO satisfies section 210(m)(1)(B)(i), the Commission would have to find that the CAISO is a “regional transmission entity.” We noted in the NOPR that amended PURPA section 210 does not define “regional transmission entity,” and therefore, the Commission has discretion to deem an entity to be “regional” based on factors such as sufficient regional scope or configuration of the multiple discrete transmission systems it controls. The CAISO offers transmission and interconnection services throughout the state of California over the transmission systems of several electric utilities. We find that California is large enough in size and configures several discrete transmission systems for the CAISO to be considered a “regional transmission entity.” Accordingly, the Commission finds that the CAISO satisfies section 210(m)(1)(B)(i). A member electric utility of the CAISO may rely on this finding in its application to be relieved of the obligation to enter into new contracts to purchase QF electric energy. We will not, however, make any findings with regard to section 210(m)(1)(B)(ii). Thus, electric utilities that are members of the CAISO seeking relief from the mandatory purchase requirement will need to file an application pursuant to section 210(m)(3) and § 292.310 of the Commission's regulations with the Commission and make the showings required by section 210(m)(1)(B)(ii) in order to be relieved of the PURPA purchase obligation. The presumption that QFs 20 MWs or below do not have nondiscriminatory access to markets will apply.

F. Southwest Power Pool

1. NOPR

159. In the NOPR, the Commission did not make a preliminary finding that the region operated by the SPP meets the requirements of PURPA section 210(m)(1). The Commission did recognize that the SPP is a Commission-approved RTO, but that the requirements of section 210(m)(1)(A) have not been satisfied because the SPP does not operate a day-ahead market. The Commission noted that any utility within the SPP footprint may file an application with the Commission to seek relief from the mandatory purchase requirement pursuant to sections 210(m)(1)(B) or (C).

2. Comments

160. OG&E requests the Commission find that utilities located in the SPP satisfy section 210(m)(1)(A). OG&E notes that the SPP filed revisions to its OATT to implement a real-time imbalance market (EIS Market). The EIS Market will enable market participants to undertake both day-ahead and real-time transactions.

161. OG&E and AEP also request the Commission find that SPP utilities satisfy section 210(m)(1)(B). The SPP is a Commission-approved RTO and the SPP OATT affords all customers with nondiscriminatory treatment and complies with all currently-effective Commission policies and regulations as they apply to the development of an OATT. Therefore, OG&E and AEP ask the Commission to find that the SPP OATT satisfies the criteria of section 210(m)(1)(B)(i). OG&E states that section 210(m)(1)(B)(ii) is satisfied because load serving entities in SPP actively solicit power supplies using competitive bidding procedures. OG&E notes that the Oklahoma Corporation Commission requires electric public utilities providing retail service in Oklahoma to procure long-term electric generation through competitive bidding. AEP notes that Louisiana established competitive bidding rules that require a utility to follow a formal RFP process for the acquisition of generation resources and for purchases of capacity and/or energy of more than one year in duration. Based on these aspects, OG&E and AEP argue that the SPP region satisfies section 210(m)(1)(B).

162. Deere disagrees with OG&E and AEP and argues that the SPP market has not yet satisfied the criteria for relief from the PURPA mandatory purchase requirement. Deere notes that SPP's EIS Market implementation has been delayed until at least October 2006, and therefore, it has not been “road tested.”

3. Commission Determination

163. Similar to the determination we made for the CAISO, the Commission will not make the findings required by section 210(m)(1)(A) for termination until there is a functioning “Day 2” market. The Commission, on September 26, 2006, acted on rehearing requests concerning SPP's proposed tariff revisions to implement an imbalance market,^[71] which will not be functional until December 1, 2006, at the earliest. Thus, it would be premature for the Commission to make such a finding in this rulemaking proceeding. Once SPP's market is operational, electric utilities who are members of SPP may file, individually or jointly, an application for relief of the PURPA purchase obligation pursuant to section 210(m)(3) and section 292.310 of the Commission's regulations.

164. OG&E and AEP also request the Commission to make a determination that electric utilities operating in the SPP satisfy section 210(m)(1)(B). These commenters also request a finding that the SPP OATT satisfies the requirements of section 210(m)(1)(B)(i). With regard to the latter request, section 210(m)(1)(B)(i) requires a QF to have nondiscriminatory access to transmission and interconnection services that are provided by a Commission-approved regional transmission entity and administered pursuant to an OATT that affords nondiscriminatory treatment to all customers. In the NOPR, the Commission interpreted section 210(m)(1)(B)(i) to mean that QFs must have access to transmission and interconnection service pursuant to a Commission-approved OATT and interconnection rules provided by an entity that is regional in scope.^[72] SPP provides transmission and interconnection service pursuant to a Commission-approved OATT that has been amended to incorporate the interconnection requirements of Order No. 2003. As noted above, SPP is a Commission-approved RTO, and, therefore, SPP satisfies the “regional transmission entity” requirement of section 210(m)(1)(B)(i). Accordingly, the Commission finds that SPP meets the criteria of section 210(m)(1)(B)(i). A member electric utility of the SPP may rely on this finding in its application to be relieved of the obligation to enter into new contracts to purchase QF electric energy.

165. Turning our attention to whether electric utilities operating in the SPP market satisfy section 210(m)(1)(B), we decline to make such a finding in this rulemaking proceeding. As an initial matter, the Commission does not have the evidence of transactions, as required by the statute, to make the requisite finding that QFs in the SPP market have nondiscriminatory access to “competitive” wholesale markets that provide a “meaningful opportunity” to make sales to buyers other than the electric utility to which the QFs are interconnected.

166. Moreover, as discussed above, the Commission will make determinations on a case-by-case basis, rather than generically, for utilities seeking relief from the mandatory purchase requirement pursuant to sections 210(m)(1)(B) and (C). Accordingly, OG&E, AEP, or any other electric utility may file with the Commission an application for relief pursuant to section 210(m)(3) of PURPA and § 292.310 of the Commission's regulations and make the showings required by section 210(m)(1)(B)(ii) in order to be relieved of the PURPA purchase obligation. The rebuttable presumption that QFs 20MW or below do not have nondiscriminatory access to markets will apply.

G. ERCOT

1. Comments

167. Reliant, TXU Energy, Power and Wholesale Companies (TXU) and the Public Utility Commission of Texas (PUCT) request that the Commission extend its preliminary finding regarding approved RTO/ISOs to include ERCOT through a generic finding under section 210(m)(1)(C) of section 210(m) rather than requiring case-by-case review. Direct Energy filed reply comments in support of this request.

168. Reliant explains that, while the ERCOT ISO does not meet all the criteria under section 210(m)(1)(A), the region is competitive in compliance with Texas law under the Public Utility Regulatory Act (PURA) and was certified as an ISO by the Public Utilities Commission of Texas. PURA provided for the creation of a regional independent organization to perform key functions to facilitate wholesale and retail competition similar to those the Commission prescribed for RTOs in Order No. 2000.

169. Reliant describes the features of the ERCOT market without explicitly suggesting that it meets the criteria of section 210(m)(1)(A). Reliant notes that ERCOT is independently administered. While it does not administer a centralized day-ahead market or forward market, ERCOT has a real-time market sufficient to support a robust market-based day-ahead market for sales of electricity. The ERCOT ISO supports the scheduling of bilateral capacity and energy contracts (both short- and long-term) by qualified scheduling entities and conducts day-ahead auctions for ancillary services.

170. Reliant asserts that the ERCOT region meets the criteria for electric utility relief from the purchase obligation under 210(m)(1)(C) because access to a sufficiently competitive market for QFs to sell their power currently exists in ERCOT and has been affirmed by the PUCT. Reliant contends that this access parallels the nondiscriminatory access to competitive markets in Commission-approved RTOs and ISOs. It believes that the PUCT's certification of ERCOT as a competitive market and the “operational reality” of a robust wholesale and retail market in ERCOT further support this conclusion.

171. Reliant argues that the most administratively efficient application of section 210(m)(1) would be to extend the Commission's preliminary finding regarding its approved RTOs or ISOs to the ERCOT region through a generic finding under section 210(m)(1)(C). This would allow ERCOT entities to submit ministerial applications under this section and to have the application treated as a compliance filing under § 292.310(a) of the proposed rule. It would allow the Commission to avoid the filing of separate applications from electric utilities located in a region that has robust wholesale and retail competition. Reliant states that extension of the Commission's finding is appropriately based on the demonstrated competitive market conditions existing in the ERCOT region, in which QFs have the opportunity to sell energy and capacity to buyers other than the utilities to which they are interconnected. TXU supports Reliant's positions for the same reasons.

172. The PUCT adds that wholesale competition has been in effect in ERCOT under open-access rules prescribed by the PUCT since 1996. It states that, on January 1, 2002, retail competition in the electric market began for all customers of investor-owned utilities in the ERCOT region. The PUCT also states that, as of October 2004, there were 85 retail electric providers certified by the PUCT, with 55 of those actively serving customers.

2. Commission Determination

173. The information Reliant provides with regard to ERCOT supports a finding that QFs have access to the transmission and distribution systems so that they have access to markets in ERCOT; the information also supports a finding that the markets in ERCOT satisfy the criteria of section 210(m)(1)(C) in that they are of comparable competitive quality as the markets described in section 210(m)(1)(A).

174. The PUCT states that wholesale competition has been in effect in ERCOT under open-access rules prescribed by the PUCT since 1996. According to the PUCT, these open access rules ensure access to the transmission and distribution systems for all buyers and sellers of electricity on nondiscriminatory terms. PUCT states that the ERCOT system is administered independently of any individual market participant. Utility and non-utility sellers have nondiscriminatory access to wholesale transmission service. Scheduling protocols afford non-discriminatory access to all customers. In ERCOT, there is no “native load preference,” and thus QFs receive the same quality of access to ERCOT markets as all other market participants. In addition, ERCOT uses a market-based congestion management system. ERCOT's zonal model uplifts local congestion costs system-wide, while directly assigning the cost of relieving inter-zonal congestion. ERCOT conducts auctions that allow market participants to hedge their risk by buying financial transmission rights on commercially significant flowgates.

175. On January 1, 2002, retail competition in the electric market began for all customers of investor-owned utilities (IOU) in the ERCOT region. As of October 2004, there were 85 retail electric providers (REPs) certified by the PUCT. The PUCT states that with the numerous REPs in the ERCOT market-place QFs have ample opportunity, equal to that of all other generators in the marketplace, to competitively procure contracts for the output of their facilities.

176. According to the PUCT, QFs in ERCOT have ample opportunity to sell both firm and non-firm power. Power is sold to REPs in the ERCOT market primarily through bilateral contracts of varying lengths of time. While ERCOT operates a real-time balancing energy market, bilateral transactions permit a buyer and seller to come to mutually agreed to terms with a greater degree of price certainty than in the balancing market and the majority of transactions in ERCOT take place pursuant to bilateral transactions.

177. In ERCOT, QFs have the opportunity to sell in an organized energy market. ERCOT's balancing energy market is an independently administered, aution-based, real time market and provides cogeneration QFs an opportunity to sell in the electric market while fulfilling contractual obligations to provide steam to their thermal hosts. QFs, as well as others, may use the balancing energy market to sell energy in the real-time at the market clearing price of energy. In addition, ERCOT operates a day-ahead and real-time market for ancillary services. ERCOT does not administer a centralized day-ahead market for energy, but Reliant submitted testimony that ERCOT's real-time market has been sufficient to support a robust market-based (as opposed to administratively-created) day-ahead market for sale of electricity.

178. As part of its filing, Reliant submitted the ERCOT protocols to support its claim that QFs have nondiscminatory access to markets that are of equal competitive quality to section 210(m)(1)(A) markets. These protocols are not a FERC tariff. They are, however, approved by the PUCT.^[73] In its comments, the PUCT states that the market that has developed in ERCOT is sufficiently robust that QFs operating within ERCOT now rely on the market to make sales and no longer rely on the PURPA purchase obligation to make sales.

179. As noted above, Reliant, TXU and the PUCT have asked that the Commission make a generic finding that QFs in ERCOT have nondiscriminatory access to markets that satisfy section 210(m)(1)(C). No commenters have opposed this request. Based on our review of the ERCOT protocols, the support of the PUCT for termination of the purchase obligation in ERCOT, and the lack of opposition to our making a generic finding, the Commission finds that: (1) there is a rebuttable presumption that QFs larger than 20 MW operating in ERCOT have nondiscriminatory access to markets,^[74] and (2) the markets in ERCOT satisfy the criteria of section 210(m)(1)(C) in that they are markets of comparative competitive quality to markets described in section 210(m)(1)(A).

180. Electric utilities operating within ERCOT may make a filing to be relieved of the purchase obligation pursuant to section 292.310 of the regulations. The rebuttable presumption that QFs 20 MW or smaller lack nondiscriminatory access shall be applicable to QFs in ERCOT. Electric utilities may rebut that presumption on the same grounds as electric utilities in other markets rebut the presumption.

H. Section 210(m)(2)—Revised Purchase and Sale Obligation for New Cogeneration Facilities

181. Section 210(m)(2)(A) reads:

REVISED PURCHASE AND SALE OBLIGATIONS FOR NEW FACILITIES—(A) After the date of enactment of this subsection, no electric utility shall be required pursuant to this section to enter into a new contract or obligation to purchase from or sell electric energy to a facility that is not an existing qualifying cogeneration facility unless the facility meets the criteria for qualifying cogeneration facilities established by the Commission pursuant to the rulemaking required by subsection (n).

182. In the NOPR the Commission stated that this provision reinforces the requirement that new qualifying cogeneration facilities must satisfy the section 210(n) criteria for new qualifying cogeneration facilities. The Commission proposed to include this language in § 292.309(d) of the proposed regulations. There were no comments objecting to this proposal, and the Commission will adopt the NOPR's proposal. The language proposed by the Commission is adopted in this Final Rule as § 292.309(h) of the Commission's regulations.

183. Section 210(m)(1)(B) defines the term “existing qualifying cogeneration facility.” The Commission proposed a definition of “existing qualifying cogeneration” in § 292.309(b)(1) of the proposed regulations. There were no comments objecting to the proposal. The proposed language is adopted in this Final Rule as § 292.309(i).

I. Section 210(m)(3)—Commission Review

1. Sufficient Notice

a. NOPR

184. Section 210(m)(3) states, in relevant part, that “after notice, including sufficient notice to potentially affected [QFs], and an opportunity for comment, the Commission shall make a final determination within 90 days of such application regarding whether the conditions set forth in subparagraph (A), (B), or (C) of paragraph (1) have been met.” ^[75] Prior to the issuance of the NOPR, the Commission dealt with two section 210(m)(3) applications.^[76] In Alliant, the Commission explained its interpretation and application of “notice, including sufficient notice to potentially affected [QFs].” The Commission clarified that an applicant would be required to identify all potentially affected QFs in any section 210(m)(3) application. The Commission also listed five categories of facilities that would constitute “all potentially affected QFs.” In the NOPR, the Commission proposed to incorporate this interpretation of “sufficient notice” and “all potentially affected QFs” in new § 292.310(b) and (c) of the Commission's regulation.

b. Comments

185. PSNM is concerned with requiring notice by applicants seeking relief from the purchase obligation to developers of facilities that have pending state avoided cost proceedings and any other QFs that the applicant reasonably believes to be affected by its petition. Specifically, it states that the applicant seeking relief may not necessarily be aware of all of the entities falling within these classifications. PSNM recommends that the Commission revise the proposed § 292.310(c)(4) to state: “developers of facilities that have pending state avoided cost proceedings involving the applicant.”

186. SCE is concerned with proposed § 292.310(b), (c)(2) and (c)(5). It states that these categories may capture too broad a category of entities and thus lead to needless debates over the scope of notice provided. It states that in any case uncertified QFs and certified QFs not in the service territory of the applicant, as well as all other interested parties, will receive sufficient notice through the Federal Register notice process. SCE argues that the relevant statute requires sufficient notice, not actual notice.

c. Commission Determination

187. The Commission will adopt the NOPR's proposal to incorporate its interpretation of “sufficient notice” and “all potentially affected QFs” as described in Alliant with one modification. PSNM points out that an applicant may not be aware of state avoided cost proceedings that do not involve the applicant and recommends adding “involving the applicant” to proposed § 292.310(c)(4). We agree that an applicant would not necessarily know about QF developers that have initiated state avoided cost proceedings that do not involve the applicant. Nor did we intend for applicants in this situation to identify such QF developers. We find PSNM's proposed revision adds clarity to § 292.310(c)(4) and it is consistent with the Commission's interpretation of “all potentially affected QFs.” Accordingly, we will modify § 292.310(c)(4) to state: “(4) The developers of facilities that have pending state avoided cost proceedings involving the applicant; and”.

188. We disagree with SCE's notion that “all potentially affected QFs” will receive sufficient notice through the Federal Register notice process. While the statutory language does not explicitly state that the “notice, including sufficient notice” shall be actual notice, the Commission nonetheless believes its statutory requirement is best met by providing all potentially affected QFs, many of which are small entities that do not regularly read the Federal Register, with actual notice.

2. Filing Fee

a. NOPR

189. Section 210(m)(3) states, in relevant part, that any electric utility may file an application for relief from the mandatory purchase requirement. In the NOPR, the Commission proposed that utilities seeking relief from the mandatory purchase requirement would need to file an application pursuant to section 210(m)(3).

b. Comments

190. SCE seeks confirmation that an application filed pursuant to section 210(m)(3) is not subject to Rule 207.^[77] SCE argues that the statute indicates that the filing is an “application” and thus should be subject to Rule 204,^[78] which does not require the payment of a fee.

c. Commission Determination

191. SCE is the only commenter to seek clarification on whether or not a filing fee is associated with a section 210(m)(3) application. We find that no filing fee shall apply to section 210(m)(3) applications.

J. Section 210(m)(4)—Reinstatement of Obligation to Purchase

192. In the NOPR, the Commission proposed § 292.311 to the Commission's regulations which is identical to statutory language of section 210(m)(4). The Commission viewed section 210(m)(4) as an opportunity for a QF, a state agency, or any affected person to seek to reinstate the purchase obligation should there be a material change in the circumstances under which the Commission granted relief. The Commission noted that the applicant bears the burden to “set forth the factual basis” upon which the application is based. The Commission further stated that the requirement for a “factual basis” indicates that allegations of a change in the conditions upon which relief was granted must be supported with evidence. The Commission proposed to consider these applications on a case-by-case basis.^[79]

193. No adverse comments were filed in response to the Commission's proposal. Therefore, the Commission will adopt § 292.311 to the Commission's regulations, as proposed.

K. Section 210(m)(5)—Obligation to Sell

1. NOPR

194. Section 210(m)(5) of PURPA removes the requirement that an electric utility sell electric energy to any QF if the Commission finds that: “competing retail electric suppliers are willing and able to sell and deliver electric energy to the qualifying cogeneration facility or qualifying small power production facility; and the electric utility is not required by State law to sell electric energy in its service territory.” In the NOPR, the Commission proposed to incorporate the statutory language into its regulations.

2. Comments

195. ACC, American Iron and Steel Institute, ELCON and Midwest ISO Transmission Customers argue that by simply importing into its regulations the statutory standard in section 210(m)(5), the Commission provides no assurance that it will continue to protect the rights of QFs to receive standby and backup power at just, reasonable, and nondiscriminatory rates. They argue that no such finding can be made unless the Commission conducts an investigation to assure itself that there is sufficient competition among suppliers that market power will not be exercised in the sale of power. For instance, ELCON and American Forest & Paper suggest that the Commission require QFs have available at least two competing suppliers who are not affiliated with the utility before relieving the utility of its sales obligations under section 210(m)(5). They assert that this is required by the statutory language referring to “competing retail electric providers” in the plural. Moreover, the Coalition of CIBO argue that the utility be required to demonstrate that all of the services are competitively available.

196. In addition, CCC, EPSA, Florida Industrial, Energy Consumers, Solid Waste Authority request that the Commission clarify that lifting of the PURPA obligation to purchase QF electricity for a particular utility does not relieve such utility of its obligation to sell supplemental, backup, standby and maintenance power to the QF at fair, reasonable and nondiscriminatory rates.

197. Also, the CCC argues that the statute requires that the competing supplier must be able to “deliver” as well as “sell” the backup and standby power and that the Commission must make certain that the utility cannot use its monopoly over retail delivery (i.e., distribution) service to impede the development of QF projects.

198. Further, the CCC states that the Commission should recognize that in addition to a showing of an alternative retail supplier of electricity, the statute requires a second showing that the utility no longer has any state law obligation to serve retail customers in its service territory. ELCON and American Forest & Paper add that the Commission should interpret this second prong to require any utility that has an obligation to provide Standard Offer or Default service is “required by state law to sell electric energy in its service territory.” They state that typically the state has imposed such obligations where necessary to achieve just and reasonable rates or adequate, reliable service. ELCON and American Forest & Paper state that QFs should not be deprived of any benefit that the state has determined to be appropriate for retail customers.

199. In response to the arguments for the Commission to retain a utility obligation to supply backup power at just and reasonable rates, EEI argues that as backup power is a retail electric service, it is beyond the Commission's jurisdiction to determine the justness and reasonableness of such retail rates. It argues that the most the Commission can find, as the statute makes clear, is that competing retail suppliers are willing and able to sell to the QF, and that there is no applicable state obligation to serve.

3. Commission Determination

200. We clarify that lifting of the PURPA obligation to purchase QF electricity for a particular utility does not relieve such utility of its obligation to sell supplemental, backup, standby and maintenance power to the QF. Any finding under section 210(m)(5) which would relieve the utility from selling to a QF would be made under a separate standard and in a separate proceeding pursuant to § 292.312 of the Commission's regulations. We agree, with EEI, however, that it is beyond the Commission's jurisdiction to determine the justness and reasonableness of retail rates.

201. Also, we agree with ELCON and American Forest & Paper that the language in section 210(m)(5), “competing retail electric providers,” requires that QFs have available at least two competing suppliers who are not affiliated with the utility before relieving the utility of its sales obligations under section 210(m)(5). We emphasize that during a section 210(m)(5) proceeding, the Commission will strictly interpret the statutory language. We note that the Commission's regulations provide that a utility must interconnect with a QF, and nothing in section 210(m) of PURPA terminates that obligation.

202. As to the CCC's argument that section 210(m)(5) has an additional state law prong that has to be met, we agree. Whether a utility that has an obligation to provide Standard Offer or Default service is “required by state law to sell electric energy in its service territory” is an issue that invokes consideration of particular state laws or state regulatory authority actions. Accordingly, the Commission believes that the issue is more appropriately addressed on a case-by-case basis in proceedings under § 292.312 of the Commission's regulations rather than generically in this rulemaking.

L. Section 210(m)(6)—No Effect on Existing Rights and Remedies

1. NOPR

203. Section 210(m)(6) protects the right and remedies under a contract or obligation in effect or pending approval before the state regulatory authority. In the NOPR, the Commission clarified that the protections provided for in section 210(m)(6) are triggered regardless of the stage of construction of a facility that may be the subject of the contract or obligation. The Commission proposed to adopt the language of the statute and solicited comments on whether further or different language and/or clarifications other than those proposed should be incorporated into our regulations.

2. Comments

204. Most of the comments received regarding the Commission's interpretation of section 210(m)(6) were focused on the terms “contract” and “obligation.” EEI and PG&E argue that the terms “contract” and “obligation” are synonymous and that an “obligation” within the meaning of PURPA section 210(m)(6) thus refers to a specific legal arrangement between specific parties that establishes all the relevant and material rates, terms and conditions under which power will be bought and sold. They contend that “obligation” must provide the same level of certainty as a contract, even though a contract per se may not actually be formed until regulatory approval is obtained. They further argue that the only obligations that were preserved under the savings clause were those obligations that (1) contain the mutual commitments of specific buyers and sellers of QF-generated electricity; (2) define all the relevant and material rates, terms and conditions of the sales; and (3) were in effect or pending regulatory approval on August 8, 2005.

205. SCE supports EEI and argues that “obligation” should refer only to mutual arrangements that were sufficiently developed to include all relevant terms and mutual commitments of the parties and were in effect, or awaiting state commission approval, as of August 8, 2005.

206. Midwest Renewable Energy Products argues that the Commission should clarify that any QF that was certified under 18 CFR 292.206 and made a filing with the relevant state regulatory authority before August 8, 2005 (to implement the mandatory purchase requirement) falls under the protection of the savings clause in section 210(m)(6), as having an “obligation” in effect as of August 8, 2005.

207. Deere argues that EEI and SCE ignore that there can be non-contractual legally enforceable obligations, created pursuant to a state's PURPA implementing scheme, which do not necessarily involve a single writing completely containing all material terms. Deere also argues that they ignore the new act's express mention of “contracts” separate from “obligations,” using the disjunctive “or.” It states that equating “obligations” to contracts would make it superfluous, contrary to the rules of statutory construction. Deere also states that Congress recognized that PURPA's purchase obligation is effectuated not only through contracts, but through obligations created by non-contractual mechanisms, such as a state regulatory process.

208. ELCON and American Forest & Paper state that the Commission should emphasize that even where mandatory purchase requirements are terminated as to new contracts, existing contracts and obligations may not be reopened.

3. Commission Determination

209. The Commission will adopt the statutory language of section 210(m)(6) into its regulations. Based on the comments received, it is evident that the term “obligation” as it is used in section 210(m)(6) and section 210(m)(1) needs to be clarified. Section 210(m)(6) reads, in relevant part, that “Nothing in this subsection affects the rights and remedies of any party under any contract or obligation, in effect or pending approval before the appropriate State regulatory authority * * *.” ^[80] Section 210(m)(1) states, in relevant part, that “no electric utility shall be required to enter into a new contract or obligation to purchase electric energy * * *.” ^[81] Because the term “obligation” appears in two distinct subsections of amended section 210(m), we believe it necessary to clarify how the Commission will interpret the term “obligation.”

210. The Commission has previously addressed the meaning of section 210(m)(6) in Midwest Renewable Energy Projects, LLC.^[82] In Midwest Renewable, we rejected the notion offered here by EEI and PG&E that “contract” and “obligation” are synonymous terms. We stated that such an interpretation would render the term “obligation” superfluous because then section 210(m)(6) would only apply to existing contracts. Had Congress intended section 210(m)(6) to apply to only existing contracts, it would not have included the term “obligation.” Thus, we found Congress intended there to be a distinction between “contract” and “obligation.”

211. In Midwest Renewable, we also disagreed with the theory offered by EEI and PG&E in this proceeding that an “obligation” within the meaning of PURPA section 210(m)(6) refers to a specific legal arrangement between specific parties that establishes all the relevant and material rates, terms and conditions under which power will be bought and sold. As we stated in Midwest Renewable:

While there appears to be some ambiguity surrounding the term “obligation” in 210(m)(6), we find that the reading favored by protestors would eliminate the term “or pending approval” from the statutory language, and would be contrary to the well-established rule of statutory construction that every clause and word of a statute be given effect and that no clause or word be interpreted so as to render it superfluous, redundant, void or insignificant. To the contrary, we find the phrase “or pending approval” to be quite significant, as it ensures that contracts or obligations that had not yet been entered into but were being pursued in the context of the state commission proceedings that were pending on the date of enactment of EPAct 2005 will fall within savings clause.^[83]

212. When a utility refuses to enter into a contract with a QF and the QF seeks state regulatory authority help to enforce its PURPA regulations, a non-contractual legally enforceable obligation may be created pursuant to the state's implementation of PURPA. Such obligations do not necessarily involve a single writing completely containing all material terms. How QFs initiate the PURPA process varies from state to state. Thus, to narrowly define “obligation” to encompasses only a specific legal arrangement with all the relevant and material rates, terms and conditions established may be at odds with a state's implementation of PURPA. Accordingly, the Commission views the term “obligation” as a “legally enforceable obligation” which is established through a state's implementation of PURPA. A QF that had initiated, prior to August 8, 2005, a state PURPA proceeding that may result in a contract or legally enforceable obligation would be considered to have triggered an “obligation” with the electric utility regarding section 210(m)(6).

213. With regard to section 210(m)(1), “obligation” will be viewed as a “legally enforceable obligation” and a QF that has initiated a state's PURPA proceeding that may result in a legally enforceable contract or obligation prior to the applicable electric utility filing its petition for relief pursuant to § 292.310 of the Commission's regulations will be considered to have triggered an “obligation” with the electric utility. Whether or not the utility's date of filing a petition for relief pursuant to § 292.310 of the Commission's regulations becomes the end date for the mandatory purchase requirement depends on whether the Commission makes a final determination that the criteria for granting relief have been satisfied, and the Commission terminates the mandatory purchase requirement.

M. Section 210(m)(7)—Recovery of Costs

1. NOPR

214. In the NOPR the Commission stated that it did not believe that regulations are necessary at this time to ensure that an electric utility that purchases electric energy or capacity from a QF recovers all prudently incurred costs associated with the purchase as described in section 210(m)(7). Nonetheless, the Commission requested comments on whether there is a need for the Commission to consider such a regulation.

2. Comments

215. EEI, Allegheny, Alliant, Montana-Dakota, PSNM and TNMP state that the Commission should adopt the statutory language in section 210(m)(7) into its regulations and provide for case-by-case relief where required. Central Vermont and Progress Energy argue that the Commission should establish wholesale and retail riders to permit consistent, complete and timely recovery of the utility's prudently-incurred QF purchase costs. They state that the states and the Commission often use different methodologies for allocating costs between the jurisdictions and the fact that utilities do not traditionally have general rate cases before the Commission and the state commissions every year. Therefore, when a QF purchase is made in a year without a general rate case at wholesale and retail, those costs are not recovered via the utility's retail or wholesale rates.

3. Commission Determination

216. We adopt our proposal in the NOPR. We do not find Central Vermont and Progress Energy's argument persuasive. No evidence has been presented that utilities will not be able to recover costs associated with purchases of electric energy or capacity from a QF. Until such time, we are reluctant to review an issue that should be handled by the states in the first instance. Therefore, we see no reason to act now.

N. Other Issues

1. Contract Termination

a. NOPR

217. In the NOPR, the Commission proposed to find that when a contract terminates by its own accord, an electric utility is not compelled to enter into a new, successor contract with the QF if the Commission has made a finding that section 210(m)(1) has been satisfied. The Commission further clarified that QF status does not mean that an electric utility has an “obligation” to purchase from the QF in perpetuity, or that a QF has the right to demand that the utility purchase at avoided-cost rates in perpetuity.

b. Comments

218. AEP, Deere, EEI, Entergy, Occidental, PPL, and PSNM agree with the NOPR's position. AEP and Occidental seek clarification or expansion of the NOPR's position. AEP believes that “terminates by its own accord” should also include the fact that a contract may terminate mutually between the parties and the electric utility would not be compelled to enter into another contract with that QF. Occidental seeks clarification that the proposed rules do not abrogate existing contracts. As such, Occidental wants the terms “terminates by its own accord” clarified to mean “expires by its own terms.”

c. Commission Determination

219. The Commission will adopt the NOPR's proposal regarding contract termination in the context of finding made pursuant to section 210(m)(1). Two commenters, AEP and Occidental, seek clarification of the phrase “terminates by its own accord.” AEP points out that some contracts may be terminated by mutual agreement between the parties to the contract and believes this type of contract termination should also be included in the Commission's interpretation of “terminates by its own accord.” As long as there is mutual agreement between a QF and the electric utility to terminate a contract, then the Commission finds that the electric utility is not compelled to enter into a new, successor contract with the QF. Occidental requests clarification that the NOPR does not abrogate existing contracts and thus wants the phrase “terminates by its own accord” to be clarified to mean “expires by its own terms.” We will also clarify that the proposed rules adopted in this Final Rule do not abrogate existing contracts. Thus, under the Final Rule, a QF contract is to remain in effect until it terminates by mutual agreement or by its own terms. We note, however, that there may be contracts that contain provisions that legislation, such as EPAct 2005, or a Final Rule, such as this one, trigger a termination clause in the contract. To the extent that the parties to a contract cannot agree whether a termination clause has been triggered, the issue will be best determined in an individual case-specific proceeding in which the particulars of the contract can be examined.

2. Effective Date of Contracts

a. NOPR

220. In the NOPR, the Commission proposed to find that if a contract is entered into after August 8, 2005, the date of EPAct 2005 enactment, but before the Commission has determined that an electric utility is entitled to relief from the mandatory purchase requirement, the contract already entered into will be treated as though it was in effect on August 8, 2005 for purposes of section 210(m)(1).

b. Comments

221. EEI, SCE, and PG&E disagree with the Commission's proposed statutory construction. They argue that once a utility is granted relief from the PURPA purchase obligation, it should not be required to honor any QF contracts entered into after August 8, 2005. EEI, SCE, and PG&E argue that this is the only determination that is consistent with the clear intent and express language of EPAct 2005, setting August 8, 2005 as the end date of the PURPA purchase obligation for utilities in appropriate markets. They state that this finding is also critical to preventing a QF “gold rush,” i.e., QFs with expiring contracts and/or new QFs may seek to obtain a contract prior to the Commission making the requisite finding under section 210(m)(1) that would relieve electric utilities like SCE and PG&E from the mandatory purchase requirement.

222. In the alternative, SCE and PG&E state that if the Commission believes that some contracts entered into after August 8, 2005 must be honored, it should adopt a rule that ensures that electric utilities either: (1) are not compelled by their state commissions to enter into new contracts or extend existing contracts after a petition for relief is filed pursuant to section 210(m) (PURPA Petition) until and unless the PURPA Petition is denied; or (2) are not required to honor contracts (or contract extensions) entered into after a PURPA Petition is filed, if the PURPA Petition is subsequently granted. Under this approach, contracts entered into between August 8, 2005, and the filing of a PURPA Petition would be honored, but there would be no “gold rush” incentive created by the filing of the utility's PURPA Petition.

223. OG&E proposes that when a QF attempts to establish a contract or obligation after August 8, 2005, a utility should have a reasonable opportunity to demonstrate in a filing at the Commission that the utility satisfies one of the tests set forth in section 210(m)(1). A QF attempting to establish a new obligation would be required to provide the utility with formal notice. Within 60 days of such notice, the utility could file a PURPA Petition if it believed the requisite market conditions existed.

224. The CCC, and the APPA and LPPC argue that the language is clear that the ability of a utility to have its mandatory purchase requirement terminated is dependent on a Commission determination that a nondiscriminatory market satisfying the statutory conditions exists. Until this determination is made, the mandatory purchase requirement remains in effect. Deere adds that generation project financing is long-term in nature, and contractual and non-contractual legally enforceable obligations are typically for up to 20 years or longer so as to support the long-term financing. The possibility of a new QF contract or obligation being negated, either ab initio or at the time of a section 210(m) order, would leave the remaining term of the financing arrangements unsupported.

225. The CPUC states that should the Commission adopt a rule as suggested by SCE and PG&E, the rule should affirm that state commissions retain oversight of such terminable contracts to ensure utilities afford equal treatment of all QF contracts.

c. Commission Determination

226. Section 210(m)(1) states, in relevant part, that, after August 8, 2005, no electric utility shall be required to enter into a new contract or obligation to purchase electric energy from QFs if the Commission finds that the QF has nondiscriminatory access to either section 210(m)(1)(A), (B), or (C). The Commission's interpretation of this statutory language, as expressed in the NOPR, was to treat new contracts or obligations entered into after August 8, 2006, but before the Commission makes a finding, as contracts or obligations in effect prior to August 8, 2005. This interpretation is consistent with the Commission's policy of not abrogating contracts. Moreover, this is consistent with the statute. Under the statue, the purchase obligation is not terminated on August 8, 2005, but only when the Commission terminates the obligation, after an electric utility filing. Until an electric utility makes a filing pursuant to the regulations, and the Commission makes the required findings, the purchase obligations remains in effect. A different statutory interpretation, such as the one advocated by EEI, would lead to QF contracts being abrogated potentially several years after execution. We believe Congress did not intend for this after-the-fact abrogation of contracts to occur. Thus, we believe the NOPR's interpretation of this statutory language is reasonable.

227. Nonetheless, some of EEI, SCE, and PG&E's arguments are compelling. The Commission's interpretation could potentially lead to what these commenters describe as a “gold rush” of QFs seeking contracts once an electric utility files for relief. Since the Commission has 90 days in which to render a finding, QFs would be able to seek new contracts or obligations from the electric utility upon learning of the electric utility's relief application until the Commission makes a finding, and the electric utility would be subject to the mandatory purchase requirement even if the Commission eventually made a finding removing the mandatory purchase requirement. We believe this possibility would undermine and circumvent the intent of section 210(m)(1).

228. In order to prevent the possibility of a “gold rush,” the Commission will modify its proposed interpretation. Rather than treat new contracts and obligations entered into after a PURPA petition is filed but before the Commission renders a finding as in effect prior to August 8, 2005, the Commission will temporarily suspend an electric utility's obligation to enter into new contracts and obligations upon the filing of its PURPA petition. When an electric utility files its PURPA petition, that electric utility will not be obligated to enter into new contracts or obligations with QFs as of the date its PURPA petition is filed. If the Commission finds that section 210(m)(1) has been met, then the mandatory purchase requirement for that electric utility ends as of the date of the PURPA petition. However, if the Commission finds that the requirements of section 210(m)(1) have not been met, then the electric utility's obligation to enter into new contracts or obligations is reinstated as of the date of a Commission order and a QF seeking a new contract or obligation shall not be denied. As such, a new contract or obligation in this situation will be treated as in effect prior to August 8, 2005. We believe this modification will remove any “gold rush” incentive QFs may have and preserves the integrity of the mandatory purchase requirement and contracts entered into between QFs and electric utilities. We note, however, that to the extent that a QF had a contract or obligation pending approval before an appropriate state regulatory authority, or non-regulated utility on August 8, 2005, a finding by that state regulatory authority or non-regulated utility that an electric utility has an obligation to purchase or must enter into a contract is binding.

229. The Commission recognizes that there is a possibility of electric utilities filing PURPA Petitions one right after another in order to invoke the temporary suspension period of the mandatory purchase requirement. Repeated section 210(m)(3) applications by utilities intended will not be tolerated and the Commission will take appropriate action if utilities abuse the process.

V. Information Collection Statement

The following collections of information referenced in this Final Rule have been submitted to the Office of Management and Budget (OMB) for review under section 3507(d) of the Paperwork Reduction Act of 1995.^[84] OMB's regulations require OMB to approve certain information collection requirements imposed by agency rule.^[85] Upon approval of a collection of information, OMB will assign an OMB control number and expiration date. Respondents subject to the filing requirements of this Final 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 or the Commission had provided a justification as why the control number should be displayed.

In the NOPR the Commission provided the following burden estimates for complying with the rule as follows:

Data collection FERC-556	Number of respondents	Number of responses	Hours per response	Total annual hours
§ 292.310	230	1	2	460
§ 292.312	230	1	2	460
§ 292.313	630	1	3	1,890
Totals	860	1		2,810

Information Collection Costs: Because of the regional differences and the various staffing levels that have been involved in preparing the documentation (legal, technical and support) the Commission is using the hourly rate of $150 to estimate the costs for filing and other administrative processes (reviewing instructions, searching data sources, completing and transmitting the collection of information). The estimated cost is anticipated to be $421,500.

In response to the NOPR, the Commission received no comments concerning its estimates for burden and costs and will use those estimates here in the final rule. Where commenters believed that a disproportionate amount of burden had been placed on certain entities in order to meet statutory criteria, the Commission has addressed this issue elsewhere in the rule and will not repeat its responses here. The actions taken in the Final Rule should ameliorate their concerns of a significant shift in the burden.

Title: FERC-556 “Small Power Production and Cogeneration Facilities”.

Action: Proposed collections.

OMB Control Nos.: 1902-0075.

Respondents: Businesses or other for profit.

Frequency of responses: Annually and on occasion.

Necessity of the Information: The Commission amends its regulations to implement Section 210(m) of PURPA which was enacted in Section 1253 of the EPACT 2005 to implement a process by which electric utilities may apply for removal of the requirement that they enter into new contracts or obligations for the purchase of electric energy from qualifying facilities (QFs) after August 8, 2005. The Final Rule is in response to a Congressional mandate that addresses complaints of electric utilities of having to pay contractually high prices for power they did not need. In adding Section 210, Congress described a standard of relief for the requirement that electric utilities enter into new obligations to purchase electric power from QFs.

Interested persons may obtain information on the reporting requirements by contacting the following: Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426 [Attention: Michael Miller, Office of the Executive Director, Phone [phone], fax: [phone], e-mail: [e-mail]] For submitting comments concerning the collection of information(s) and the associated burden estimates, please send your comments to the contact listed above and to the Office of Management and Budget, Office of Information and Regulatory Affairs, Washington, DC 20503, Attention: Desk Officer for the Federal Energy Regulatory Commission; Phone: [phone], fax: [phone].

VI. Environmental Analysis

230. 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. The Commission has categorically excluded certain actions from this requirement as not having a significant effect on the human environment. As explained above, this rule is clarifying in nature. It interprets several amendments made to PURPA by EPAct 2005, and clarifies the applicability of these amendments to electric utilities and QFs; it does not substantially change the effect of the legislation. Accordingly, no environmental consideration is necessary.

VII. Regulatory Flexibility Act Certification

231. The Regulatory Flexibility Act of 1980 (RFA) ^[86] generally requires a description and analysis of rules that will have significant economic impact on a substantial number of small entities and where notice and comment rulemaking is required. Certain rules are exempt from notice and comment from the RFA requirements; exempt rules include interpretative rules, general statements of policy, or rules of agency organization procedure or practice.^[87] Interpretative rules “generally interpret the intent expressed by Congress, where an agency does not insert its own judgments or interpretations in implementing a rule and simply regurgitates statutory language.” ^[88] The rule we are proposing in this docket is mostly an interpretative rule and thus, does not require a regulatory flexibility analysis. The exception, however, is the Commission's establishment of a rebuttable presumption that small QFs, with a net capacity no greater than 20 MW, do not have nondiscriminatory access to wholesale markets described in section 210(m)(1)(A), (B), or (C). Unless an electric utility seeking the right to terminate its requirement to purchase small QF power specifically rebuts this small QF presumption, and that electric utility's request is granted by the Commission, a small QF would continue to be eligible to require the electric utility to purchase its electric energy. With this 20 MW rebuttable presumption the Commission reduces the burden, i.e., the cost of participating in termination proceedings, of small QFs to participate in the section 210(m)(3) proceedings. In fact, the Commission is being generous in allowing small QFs up to 20 MWs to have a rebuttable presumption given that the Small Business Administration considers “small” to mean 4 MW or less.

VIII. Document Availability

232. 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 FERC's Home Page (http://www.ferc.gov) and in FERC's Public Reference Room during normal business hours (8:30 a.m. to 5 p.m. Eastern time) at 888 First Street, NE., Room 2A, Washington DC 20426.

233. From FERC's Home Page on the Internet, this information is available on 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.

234. User assistance is available for eLibrary and the FERC's Web site during normal business hours from our Help line at [phone] or the Public Reference Room at [phone] Press 0, TTY [phone]. E-mail the Public Reference Room at [e-mail].

IX. Effective Date

235. These regulations are effective January 2, 2007. 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 251 of the Small Business Regulatory Enforcement Fairness Act of 1996. The Commission will submit the Final Rule to both houses of Congress and the General Accounting Office.

List of Subjects in 18 CFR Part 292

• Electric power
• Electric power plants
• Electric utilities

By the Commission.

Magalie R. Salas,

Secretary.

In consideration of the foregoing, the Commission amends part 292, chapter I, title 18, Code of Federal Regulations, as follows.

PART 292—REGULATIONS UNDER SECTIONS 201 AND 210 OF THE PUBLIC UTILITY REGULATORY POLICIES ACT OF 1978 WITH REGARD TO SMALL POWER PRODUCTION AND COGENERATION

1. The authority citation for part 292 continues to read as follows:

Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352.

2. Section 292.303 is revised to read as follows:

§ 292.303

Electric utility obligations under this subpart.

(a) Obligation to purchase from qualifying facilities. Each electric utility shall purchase, in accordance with § 292.304, unless exempted by § 292.309 and § 292.310, any energy and capacity which is made available from a qualifying facility:

(1) Directly to the electric utility; or

(2) Indirectly to the electric utility in accordance with paragraph (d) of this section.

(b) Obligation to sell to qualifying facilities. Each electric utility shall sell to any qualifying facility, in accordance with § 292.305, unless exempted by § 292.312, energy and capacity requested by the qualifying facility.

(c) Obligation to interconnect. (1) Subject to paragraph (c)(2) of this section, any electric utility shall make such interconnections with any qualifying facility as may be necessary to accomplish purchases or sales under this subpart. The obligation to pay for any interconnection shall be determined in accordance with § 292.306.

(2) No electric utility is required to interconnect with any qualifying facility if, solely by reason of purchases or sales over the interconnection, the electric utility would become subject to regulation as a public utility under part II of the Federal Power Act.

(d) Transmission to other electric utilities. If a qualifying facility agrees, an electric utility which would otherwise be obligated to purchase energy and capacity from such qualifying facility may transmit the energy or capacity to any other electric utility. Any electric utility to which such energy or capacity is transmitted shall purchase such energy or capacity under this subpart as if the qualifying facility were supplying energy or capacity directly to such electric utility. The rate for purchase by the electric utility to which such energy is transmitted shall be adjusted up or down to reflect line losses pursuant to § 292.304(e)(4) and shall not include any charges for transmission.

(e) Parallel operation. Each electric utility shall offer to operate in parallel with a qualifying facility, provided that the qualifying facility complies with any applicable standards established in accordance with § 292.308.

3. Sections 292.309 through 292.314 are added to read as follows:

292.309

Termination of obligation to purchase from qualifying facilities.

292.310

Procedures for utilities requesting termination of obligation to purchase from qualifying facilities.

292.311

Reinstatement of obligation to purchase.

292.312

Termination of obligation to sell to qualifying facilities.

292.313

Reinstatement of obligation to sell.

292.314

Existing rights and remedies.

§ 292.309

Termination of obligation to purchase from qualifying facilities.

(a) After August 8, 2005, an electric utility shall not be required, under this part, to enter into a new contract or obligation to purchase electric energy from a qualifying cogeneration facility or a qualifying small power production facility if the Commission finds that the qualifying cogeneration facility or qualifying small power facility production has nondiscriminatory access to:

(1)(i) Independently administered, auction-based day ahead and real time wholesale markets for the sale of electric energy; and

(ii) Wholesale markets for long-term sales of capacity and electric energy; or

(2)(i) Transmission and interconnection services that are provided by a Commission-approved regional transmission entity and administered pursuant to an open access transmission tariff that affords nondiscriminatory treatment to all customers; and

(ii) Competitive wholesale markets that provide a meaningful opportunity to sell capacity, including long-term and short-term sales, and electric energy, including long-term, short-term and real-time sales, to buyers other than the utility to which the qualifying facility is interconnected. In determining whether a meaningful opportunity to sell exists, the Commission shall consider, among other factors, evidence of transactions within the relevant market; or

(3) Wholesale markets for the sale of capacity and electric energy that are, at a minimum, of comparable competitive quality as markets described in paragraphs (a)(1) and (a)(2) of this section.

(b) For purposes of § 292.309(a), a renewal of a contract that expires by its own terms is a “new contract or obligation” without a continuing obligation to purchase under an expired contract.

(c) For purposes of § 292.309(a)(1), (2) and (3), with the exception of paragraph (d) of this section, there is a rebuttable presumption that a qualifying facility has nondiscriminatory access to the market if it is eligible for service under a Commission-approved open access transmission tariff or Commission-filed reciprocity tariff, and Commission-approved interconnection rules. If the Commission determines that a market meets the criteria of § 292.309(a)(1), (2) or (3), and if a qualifying facility in the relevant market is eligible for service under a Commission-approved open access transmission tariff or Commission-filed reciprocity tariff, a qualifying facility may seek to rebut the presumption of access to the market by demonstrating, inter alia, that it does not have access to the market because of operational characteristics or transmission constraints.

(d)(1) For purposes of § 292.309(a)(1), (2), and (3), there is a rebuttable presumption that a qualifying facility with a capacity at or below 20 megawatts does not have nondiscriminatory access to the market.

(2) For purposes of implementing paragraph (d)(1) of this section, the Commission will not be bound by the one-mile standard set forth in § 292.204(a)(2).

(e) Midwest Independent Transmission System Operator (Midwest ISO), PJM Interconnection, L.L.C. (PJM), ISO New England, Inc. (ISO-NE), and New York Independent System Operator (NYISO) qualify as markets described in § 292.309(a)(1)(i) and (ii), and there is a rebuttable presumption that qualifying facilities with a capacity greater than 20 megawatts have nondiscriminatory access to those markets through Commission-approved open access transmission tariffs and interconnection rules, and that electric utilities that are members of such regional transmission organizations or independent system operators (RTO/ISOs) should be relieved of the obligation to purchase electric energy from the qualifying facilities. A qualifying facility may seek to rebut this presumption by demonstrating, inter alia, that:

(1) The qualifying facility has certain operational characteristics that effectively prevent the qualifying facility's participation in a market; or

(2) The qualifying facility lacks access to markets due to transmission constraints. The qualifying facility may show that it is located in an area where persistent transmission constraints in effect cause the qualifying facility not to have access to markets outside a persistently congested area to sell the qualifying facility output or capacity.

(f) The Electric Reliability Council of Texas (ERCOT) qualifies as a market described in § 292.309(a)(3), and there is a rebuttable presumption that qualifying facilities with a capacity greater than 20 megawatts have nondiscriminatory access to that market through Public Utility Commission of Texas (PUCT) approved open access protocols, and that electric utilities that operate within ERCOT should be relieved of the obligation to purchase electric energy from the qualifying facilities. A qualifying facility may seek to rebut this presumption by demonstrating, inter alia, that:

(1) The qualifying facility has certain operational characteristics that effectively prevent the qualifying facility's participation in a market; or

(2) The qualifying facility lacks access to markets due to transmission constraints. The qualifying facility may show that it is located in an area where persistent transmission constraints in effect cause the qualifying facility not to have access to markets outside a persistently congested area to sell the qualifying facility output or

(g) The California Independent System Operator and Southwest Power Pool, Inc. satisfy the criteria of § 292.309(a)(2)(i).

(h) No electric utility shall be required, under this part, to enter into a new contract or obligation to purchase from or sell electric energy to a facility that is not an existing qualifying cogeneration facility unless the facility meets the criteria for new qualifying cogeneration facilities established by the Commission in § 292.205.

(i) For purposes of § 292.309(h), an “existing qualifying cogeneration facility” is a facility that:

(1) Was a qualifying cogeneration facility on or before August 8, 2005; or

(2) Had filed with the Commission a notice of self-certification or self-recertification, or an application for Commission certification, under § 292.207 prior to February 2, 2006.

(j) For purposes of § 292.309(h), a “new qualifying cogeneration facility” is a facility that satisfies the criteria for qualifying cogeneration facilities pursuant to § 292.205.

§ 292.310

Procedures for utilities requesting termination of obligation to purchase from qualifying facilities.

(a) An electric utility may file an application with the Commission for relief from the mandatory purchase requirement under § 292.303(a) pursuant to this section on a service territory-wide basis. Such application shall set forth the factual basis upon which relief is requested and describe why the conditions set forth in § 292.309(a)(1), (2) or (3) have been met. After notice, including sufficient notice to potentially affected qualifying cogeneration facilities and qualifying small power production facilities, and an opportunity for comment, the Commission shall make a final determination within 90 days of such application regarding whether the conditions set forth in § 292.309(a)(1), (2) or (3) have been met.

(b) Sufficient notice shall mean that an electric utility must identify with names and addresses all potentially affected qualifying facilities in an application filed pursuant to paragraph (a).

(c) All potentially affected qualifying facilities shall include:

(1) Those qualifying facilities that have existing power purchase contracts with the applicant;

(2) Other qualifying facilities that sell their output to the applicant or that have pending self-certification or Commission certification with the Commission for qualifying facility status whereby the applicant will be the purchaser of the qualifying facility's output;

(3) Any developer of generating facilities with whom the applicant has agreed to enter into power purchase contracts, as of the date of the application filed pursuant to this section, or are in discussion, as of the date of the application filed pursuant to this section, with regard to power purchase contacts;

(4) The developers of facilities that have pending state avoided cost proceedings, as of the date of the application filed pursuant to this section; and

(5) Any other qualifying facilities that the applicant reasonably believes to be affected by its application filed pursuant to paragraph (a) of this section.

(d) The following information must be filed with an application:

(1) Identify whether applicant seeks a finding under the provisions of § 292.309(a)(1), (2), or (3).

(2) A narrative setting forth the factual basis upon which relief is requested and describing why the conditions set forth in § 292.309(a)(1), (2), or (3) have been met. Applicant should also state in its application whether it is relying on the findings or rebuttable presumptions contained in § 292.309(e), (f) or (g). To the extent applicant seeks relief from the purchase obligation with respect to a qualifying facility 20 megawatts or smaller, and thus seeks to rebut the presumption in § 292.309(d), applicant must also set forth, and submit evidence of, the factual basis supporting its contention that the qualifying facility has nondiscriminatory access to the wholesale markets which are the basis for the applicant's filing.

(3) Studies, including the applicant's long-term transmission plan, conducted by applicant, or the RTO, ISO or other relevant entity, that show:

(i) Transmission constraints by path, element or other level of comparable detail that have occurred and/or are known and expected to occur, and any proposed mitigation including transmission construction plans;

(ii) Levels of congestion, if available;

(iii) Relevant system impact studies for the generation interconnections, already completed;

(iv) Other information pertinent to showing whether transfer capability is available; and

(v) The appropriate link to applicant's OASIS, if any, from which a qualifying facility may obtain applicant's available transmission capacity (ATC) information.

(4) Describe the process, procedures and practices that qualifying facilities interconnected to the applicant's system must follow to arrange for the transmission service to transfer power to purchasers other than the applicant. This description must include the process, procedures and practices of all distribution, transmission and regional transmission facilities necessary for qualifying facility access to the market.

(5) If qualifying facilities will be required to execute new interconnection agreements, or renegotiate existing agreements so that they can effectuate wholesale sales to third-party purchasers, explain the requirements, charges and the process to be followed. Also, explain any differences in these requirements as they apply to qualifying facilities compared to other generators, or to applicant-owned generation.

(6) Applicants seeking a Commission finding pursuant to § 292.309(a)(2) or (3), except those applicants located in ERCOT, also must provide evidence of competitive wholesale markets that provide a meaningful opportunity to sell capacity, including long-term and short-term sales, and electric energy, including long-term, short-term and real-time sales, to buyers other than the utility to which the qualifying facility is interconnected. In demonstrating that a meaningful opportunity to sell exists, provide evidence of transactions within the relevant market. Applicants must include a list of known or potential purchasers, e.g., jurisdictional and non-jurisdictional utilities as well as retail energy service providers.

(7) Signature of authorized individual evidencing the accuracy and authenticity of information provided by applicant.

(8) Person(s) to whom communications regarding the filed information may be addressed, including name, title, telephone number, and mailing address.

§ 292.311

Reinstatement of obligation to purchase.

At any time after the Commission makes a finding under §§ 292.309 and 292.310 relieving an electric utility of its obligation to purchase electric energy, a qualifying cogeneration facility, a qualifying small power production facility, a State agency, or any other affected person may apply to the Commission for an order reinstating the electric utility's obligation to purchase electric energy under this section. Such application shall set forth the factual basis upon which the application is based and describe why the conditions set forth in § 292.309(a), (b) or (c) are no longer met. After notice, including sufficient notice to potentially affected electric utilities, and opportunity for comment, the Commission shall issue an order within 90 days of such application reinstating the electric utility's obligation to purchase electric energy under this section if the Commission finds that the conditions set forth in § 292.309(a), (b), or (c) which relieved the obligation to purchase, are no longer met.

§ 292.312

Termination of obligation to sell to qualifying facilities.

(a) Any electric utility may file an application with the Commission for relief from the mandatory obligation to sell under this section on a service territory-wide basis or a single qualifying facility basis. Such application shall set forth the factual basis upon which relief is requested and describe why the conditions set forth in paragraphs (b)(1) and (b)(2) of this section have been met. After notice, including sufficient notice to potentially affected qualifying facilities, and an opportunity for comment, the Commission shall make a final determination within 90 days of such application regarding whether the conditions set forth in paragraphs (b)(1) and (b)(2) of this section have been met.

(b) After August 8, 2005, an electric utility shall not be required to enter into a new contract or obligation to sell electric energy to a qualifying small power production facility, an existing qualifying cogeneration qualifying facility, or a new qualifying cogeneration facility if the Commission has found that;

(1) Competing retail electric suppliers are willing and able to sell and deliver electric energy to the qualifying cogeneration facility or qualifying small power production facility; and

(2) The electric utility is not required by State law to sell electric energy in its service territory.

§ 292.313

Reinstatement of obligation to sell.

At any time after the Commission makes a finding under § 292.312 relieving an electric utility of its obligation to sell electric energy, a qualifying cogeneration facility, a qualifying small power production facility, a State agency, or any other affected person may apply to the Commission for an order reinstating the electric utility's obligation to purchase electric energy under this section. Such application shall set forth the factual basis upon which the application is based and describe why the conditions set forth in Paragraph (b)(1) and (b)(2) of this section are no longer met. After notice, including sufficient notice to potentially affected utilities, and opportunity for comment, the Commission shall issue an order within 90 days of such application reinstating the electric utility's obligation to sell electric energy under this section if the Commission finds that the conditions set forth in paragraphs (b)(1) and (b)(2) of this section are no longer met.

§ 292.314

Existing rights and remedies.

Nothing in this section affects the rights or remedies of any party under any contract or obligation, in effect or pending approval before the appropriate State regulatory authority or non-regulated electric utility on or before August 8, 2005, to purchase electric energy or capacity from or to sell electric energy or capacity to a qualifying cogeneration facility or qualifying small power production facility under this Act (including the right to recover costs of purchasing electric energy or capacity).

Note:

The following appendix will not be published in the Code of Federal Regulations.

Appendix A: List of Petitioners Requesting Clarification or Submitting Comments

AES Shady Point, LLC (AES Shady Point)

Albers, John D. (Mr. Albers)

Allegheny Power (Allegheny)

Alliant Energy Corporate Services, Inc. (Alliant)

American Chemistry Council

American Electric Power Service Corporation (AEP)

American Energy Company

American Forest and Paper Association (American Forest & Paper)

American Iron and Steel Institute

American Petroleum Institute

American Public Power Association and Large Public Power Council (APPA)

American Wind Energy Association (AWEA)

Caithness Energy, LLC (Caithness)

California Cogeneration Council (CCC)

California Independent System Operator Corporation (CAISO)

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

Central Vermont Public Service Corporation and Green Mountain Power Corporation (Central Vermont)

Coalition of Midwest Transmission Customers (Midwest Transmission Customers)

Cogeneration Association of California and Energy Producers and Users Coalition (Cogeneration Association of California)

Cogeneration Coalition of Washington

Congressmen Boucher, Brown and Pickering

Consolidated Edison Company of New York, Inc. (ConEd)

Constellation Energy Group, Inc. (Constellation)

Council of Industrial Boiler Owners (CIBO)

Deere & Company (Deere)

Direct Energy Services, LLC (Direct Energy)

Dow Chemical Company (Dow)

Edison Electric Institute (EEI)

Electricity Consumers Resource Council (ELCON)

Electric Power Supply Association (EPSA)

Entergy Services, Inc. (Entergy)

Environmental Law and Policy Center

Exelon Corporation (Exelon)

The Fertilizer Institute

FirstEnergy Corp. (FirstEnergy)

Florida Industrial Cogeneration Association (Florida Industrial Cogeneration)

Granite State Hydropower Association, Inc. and Vermont Independent Power Producers Association (Granite State)

Independent Energy Producers Association of California (Independent Energy Producers)

Industrial Energy Consumers of America (Industrial Energy Consumers)

Landfill Gas Coalition

Louisiana Energy Users Group (LEUG)

Midwest Renewable Energy Projects, LLC (Midwest Renewable Energy Projects)

Missouri River Energy Services (Missouri River)

Midwest Transmission Customers

Modesto Irrigation District (Modesto Irrigation)

Montana-Dakota Utilities Co. (Montana-Dakota)

National Grid USA (National Grid)

National Petrochemical & Refiners Association (NPRA)

National Rural Electric Cooperative Association (NRECA)

Nelson Industrial Steam Company's Industrial Participants (NISCO)

New York Independent System Operator, Inc. (NYISO)

NSTAR Electric & Gas Corporation (NSTAR)

Occidental Chemical Corporation (Occidental)

Oklahoma Corporation Commission

Oklahoma Gas and Electric Company (OG&E)

Ottinger, Richard L. (Mr. Ottinger)

Pacific Gas and Electric Company (PG&E)

PacifiCorp

PJM Interconnection, LLC (PJM)

PJM Transmission Owners

PPL Electric Utilities Corporation (PPL)

Progress Energy, Inc. (Progress Energy)

Public Interest Organizations (PIOs) (Center for Energy Efficiency & Renewable Technologies, Delaware Division of the Public Advocate, Environmental Law & Policy Center, Interwest Energy Alliance, Izaak Walton League of America, Natural Resources Defense Council, Northwest Energy Coalition, Office of the Ohio Consumers' Counsel, Pace Energy Project, Project for Sustainable FERC Energy Policy, West Wind Wires, and Western Resource Advocates)

Public Interest and Renewable Energy Organizations

Public Power Council

Public Service Company of New Mexico (PSNM) jointly with Texas-New Mexico Power Company (TNP)

Public Utilities Commission of the State of California (CPUC)

Public Utility Commission of Texas (PUCT)

Reliant Energy, Inc. (Reliant)

Senators Alexander, Carper and Collins

Solid Waste Authority of Palm Beach, Florida (Solid Waste Authority)

Southeast Electricity Consumers Association (SeECA)

Southern California Edison Company (SCE)

Swecker, Gregory (Mr. Swecker)

Transmission Agency of Northern California (TANC)

TXU Energy, Power and Wholesale Companies (TXU)

U.S. Combined Heat & Power Association (USCHPA)

Utah Association of Energy Users (UAE)

Wisconsin Industrial Energy Group, Inc.

Xcel Energy Services Inc. (Xcel)

Footnotes

1.  Pub. L. 109-58, 1253, 119 Stat. 594 (2005).

2.  16 U.S.C. 824a-3 (2000).

3.  Attached as Appendix A is a list of all commenters and the abbreviations that are used throughout the order to refer to the commenters.

4.  18 CFR part 292, subpart C, Arrangements Between Electric Utilities and Qualifying Cogeneration and Small Power Production Facilities Under section 210 of the Public Utility Regulatory Policies Act of 1978.

5.  Reference to “Day 2” and “Day 1 ” and the corresponding parenthetical are meant to be descriptive and thus are not a recitation of the elements of section 210(m)(1)(A) or (B).

6.  18 CFR 35.28(e). An OATT provides interconnection as well as transmission services on a nondiscriminatory basis.

7.  To the extent that a QF raises issues about the adequacy of an electric utility's implementation of an OATT, such issues are more properly addressed in a complaint proceeding and will not be considered in the context of petitions for the termination of mandatory purchase requirements. However, a QF may raise other issues, such as operational characteristics and transmission limitations, to attempt to rebut the presumption of market access when it files a response to an application submitted pursuant to section 210(m)(3) of PURPA and section 292.310 of our regulations.

8.  Herein referred to as small QFs.

9.  The electric utility would have to make additional showings if it wished to rebut the presumption that small QFs do not have nondiscriminatory access to its region's “Day 2” wholesale markets.

10.  16 U.S.C. 824 et seq.

11.  Id. 796(18).

12.  Id. 796(17)(A)(i)-(ii).

13.  Southern California Edison Company and San Diego Gas & Electric Company, 70 FERC ¶ 61,215 at 61,677-78, reconsideration denied, 71 FERC ¶ 61,269 at 62,078 (1995) (finding that the determination of avoided cost must take into account “all sources”).

14.  Energy Policy Act of 1992, Pub. L. No. 102-486, 106 Stat. 2776, (1993) (EPAct 1992). EPAct 1992 added a new section 32 to the Public Utility Holding Company Act of 1935 (PUHCA) to permit a category of sellers called EWGs to be exempt from PUHCA.

15.  Revised Regulations Governing Small Power Production and Cogeneration Facilities, Order No. 671, 71 FR 7852 (Feb. 15, 2006), FERC Stats. & Regs. ¶ 31,203 (2006), order on reh'g, Order No. 671-A, 71 FR 30585 (May 30, 2006), FERC Stats. & Regs. ¶ 31,219 (2006).

16.  NOPR at P 14.

17.  Id. at P 22-28.

18.  Id. at P 40. We note that, since the time comments were filed in this proceeding, the Commission has issued a NOPR proposing amendments to the OATT. Preventing Undue Discrimination and Preference in Transmission Service, 71 FR 32636 (2006), FERC Stats. & Regs. ¶ 32,603 (2006).

19.  Id. at P 20.

20.  Id. at P 31.

21.  Id. at P 29-30.

22.  The Commission interprets the 90-day period to begin upon receipt of a completed application.

23.  The PIOs filing these comments are the Center for Energy Efficiency & Renewable Technologies, Delaware Division of the Public Advocate, Environmental Law & Policy Center, Interwest Energy Alliance, Izaak Walton League of America, Natural Resources Defense Council, Northwest Energy Coalition, Office of the Ohio Consumers' Counsel, Pace Energy Project, Project for Sustainable FERC Energy Policy, West Wind Wires, and Western Resource Advocates.

24.  ELCON Comments at 8.

25.  Id.

26.  AWEA Comments at 2.

27.  EPSA Comments at 9.

28.  Regional Transmission Organizations, Order No. 2000, 65 FR 809 (Jan. 6, 2000), FERC Stats. & Regs. P 31,089 (1999), order on reh'g, Order No. 2000-A, 65 FR. 12,088 (Mar. 8, 2000), FERC Stats. & Regs. P 31,092 (2000), aff'd sub nom. Pub. Util. Dist. No. 1 of Snohomish County, Washington v. FERC, 272_F.3d_607 (D.C. Cir. 2001).

29.  See supra note 15.

30.  In this regard we note that the rulemaking to reform the OATT is intended to remedy the “opportunity” for undue discrimination; the Commission did not base its institution of the rulemaking in Docket No. RM05-25-000 on any finding that the OATT allows actual discrimination. To the extent that ELCON argues that, through the NOPR process, the Commission has recognized “the continuation of patterns of abuse,” ELCON mischaracterizes the basis of the OATT rulemaking.

31.  In fact, PURPA section 210(m) provides a compressed 90-day time frame in which the Commission, after notice and opportunity for comment, must act on applications. This provides a clear indication that Congress did not intend hearing or lengthy proceedings in order to make a determination of whether the electric utility must be relieved of the mandatory purchase requirement. A QF may, of course, file a complaint with the Commission at any time, including a separate complaint in conjunction with its comments on an electric utility's application for relief from the mandatory purchase requirement.

32.  Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by Public Utilities and Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, 61 FR 21540 (1996), FERC Stats. & Regs. ¶ 31,036 (1996), Order No. 888-A, 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).

33.  Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003, 68 FR 49845 (Aug. 19, 2003), FERC Stats. & Regs. ¶ 31,146 (2003), order on reh'g, Order No. 2003-A, 69 FR 15932 (Mar. 26, 2004), FERC Stats. & Regs. ¶ 31,160 (2004), order on reh'g, Order No. 2003-B, 70 FR265 (Jan. 4, 2005), FERC Stats. & Regs. ¶ 31,171 (2004), order on reh'g, Order No. 2003-C, 70 FR 37661 (June 30, 2005), FERC Stats. & Regs. ¶ 31,190 (2005).

34.  Standardization of Small Generator Interconnection Agreements and Procedures, Order No. 2006, 70 Fed. Reg. 34,100 (Jun. 13, 2005), FERC Stats. & Regs. ¶ 31,180 at 31,406-31,551 (2005), order on reh'g, Order No. 2006-A, 70 Fed. Reg. 71,760 (Nov. 30, 2005), FERC Stats. & Regs. ¶ 31,196 (2005).

35.  NOPR at P 20.

36.  Id.

37.  EEI does not expect that the Commission would extend the opportunity to demonstrate lack of access under this proposal to wind generators. EEI states that while electricity production from wind power is variable, wind generation is predictable in its variability, and the Commission has accommodated this variability through interconnection rules and other policies. EEI asserts that wind generators differ as well from small industrial cogenerators, whose primary purpose, in accordance with PURPA, is not intended to be the production of electricity, while wind generators are exclusively electricity producers.

38.  EEI states that the size of a “very small” QF for purposes of its proposed exception to the termination of the mandatory purchase obligation is likely to vary among RTO/ISOs, based on factors such as operational requirements of the particular RTO, any threshold level for transactions that may be required in an RTO, any minimum size requirements for participation in the RTO market, or other factors specific to the RTO/ISO market involved. For example, EEI notes a “very small” QF for the NYISO market could be a QF less than 1 MW that has not been able to aggregate supply in order to participate at the 1 MW minimum transaction level established in the NYISO tariff. See NYISO FERC Electric Tariff, Original Volume No. 2 (“Services Tariff”), Sections 4.1.4, 4.2.2(c)(1) and 5.12.

39.  Industrial Boilers proposed 80 MW, UAE proposed 30 MW, AWEA and ELCON proposed 20, and EEI proposed 1 MW for cogeneration and 5 MW for small production.

40.  As we noted above in P 57, no class of QFs has been shown to uniformly lack nondiscriminatory access based on a single factor. Thus, we are not making a finding here but are establishing a rebuttable presumption.

41.  A QF, when it seeks certification, states what size it is. The size it is required to state is its “net capacity” which is its gross capacity, less station power. In the case of Commission-certified facilities, the Commission certifies the QF at its net capacity; self-certified facilities self-certify at net capacity. The Commission has been consistent over the years in requiring QFs to state their net capacity in the Form 556 which is the basis of both applications for Commission certification, and notices of self-certification. A QF's Commission certified (or self-certified) net capacity would determine whether the QF qualifies for the “small size” rebuttable presumption in this Final Rule.

42.  Herein referred to as “small QF.”

43.  Order No. 2006 defined a “Small Generating Facility” as a device used for the production of electricity having a capacity of no more than 20 MW. The Commission concluded in Order No. 2006 that general consistency between the Commission's interconnection procedures document and interconnection agreement adopted in that final rule and those of the states will be helpful to removing roadblocks to the interconnection of Small Generating Facilities. See Order No. 2006 at P 4.

44.  An existing QF is one that is in existence as of the date the mandatory purchase obligation is terminated.

45.  EEI suggests that for purposes of this exception, a QF is prevented from having “physical access” outside its congested area when the QF is located in a “generation pocket.” EEI believes this means that during annual system peak conditions, the QF is unable (because of transmission congestion) to deliver the power it generates that is not consumed by local loads to the remainder of the relevant ISO's or RTO's control area, or to other areas if the QF is not located in an ISO or RTO control area. EEI concludes the geographic area that should be evaluated as a potential “generation pocket” is the area containing the QF and other generators that sufficiently contribute to the congestion on the transmission line, as defined by the ISO or RTO in its applicable resource adequacy deliverability analysis, if the QF is located in an ISO or RTO control area. See, e.g., CAISO Preliminary Deliverability Baseline Analysis Study Report, May 3, 2005, Appendix I. In addition, a given QF's lack of physical access should be subject to annual review in order to determine whether the mandatory purchase obligation should continue.

46.  EEI states that existing “Day 2” organized markets rely on LMP and financial transmission rights rather than physical transmission rights. Where a financial right exists, a generator enjoys access to markets, regardless of whether a physical right exists.

47.  Supra note 32.

48.  Supra note 33.

49.  Supra note 34.

50.  See, e.g., PJM Interconnection, LLC, 114 FERC ¶ 61,191, order on reh'g, 116 FERC ¶ 61,102 (2006).

51.  The Small Generator Interconnection Procedures (SGIP) and the Small Generator Interconnection Agreement (SGIA) outlined in Orders Nos. 2006 and 2006-A, include separate definitions for “Transmission System” and “Distribution System” to account for the distinct engineering and cost allocation implications of an interconnection with a Distribution System. Order No. 2006 states that use of the term “Distribution System” has nothing to do with whether the facility is under this Commission's jurisdiction; some “distribution” facilities are under our jurisdiction and others are “local distribution facilities” subject to state jurisdiction. Further Order No. 2006 applies only to interconnections to facilities that are already subject to a jurisdictional OATT at the time the interconnection request is made and that will be used for purposes of jurisdictional wholesale sales. Order No. 2006 explains that because of this limited applicability, and because the majority of small generators interconnect with facilities that are not subject to an OATT, Order No. 2006 will not apply to most small generator interconnections. See Order No. 2006 at P 6, 7 and 8.

52.  See SEC v. Chenery, 332 U.S. 194, 202-03, reh'g denied, 332 U.S. 747 (1947).

53.  We note in this regard that section 210(m) of PURPA requires the Commission to act on an application, within 90 days of such application, “after notice * * * and an opportunity for comment.” This contrasts with the requirement of sections 205 and 206 of the FPA that the Commission act after a “hearing,” not just after an opportunity to comment. See 16 U.S.C. 824d, e.

54.  The electric utility would have to make additional showings if it wished to rebut the presumption that small QFs do not have nondiscriminatory access to its region's Day 2 wholesale markets, and to long term capacity and energy markets.

55.  In the NOPR the Commission noted that while SPP and the CAISO, respectively are a Commission-approved RTO and ISO, they do not satisfy the requirements of section 210(m)(1)(A) because neither has day-ahead markets. The Commission stated, however, that any utility within SPP and CAISO may file an application with the Commission to seek relief from the mandatory purchase requirement under section 210(m)(1)(B) or (C), on a case-by-case basis.

56.  NOPR at P 22.

57.  ELCON's August 25, 2006 Supplemental Comments at 8-9.

58.  Supra note 15.

59.  See Midwest Independent Transmission System Operator, Inc., 97 FERC ¶ 61,326 (2001) order on reh'g, 103 FERC ¶ 61,169 (2003); PJM Interconnection, L.L.C., 96 FERC ¶ 61,061 (2001). On December 20, 2002, in PJM Interconnection, L.L.C., 101 FERC ¶ 61,345 (2002), PJM was granted full, rather than provisional, RTO status. Independence was one of the matters considered in the 2002 Order; ISO New England, Inc., 106 FERC ¶ 61,280 (2004); Central Hudson Gas & Electric Co., 83 FERC ¶ 61,352 (1998), order on reh'g, 87 FERC ¶ 61,135 (1999).

60.  See Midwest Independent Transmission System Operator, Inc., 108 FERC ¶ 61,163 (Midwest ISO, FERC Electric Tariff, Third Revised Volume No. 1, Module C), order on reh'g, 109 FERC ¶ 61,157 (2004), order on reh'g, 111 FERC ¶ 61,043 (2005), PJM Interconnection, L.L.C., FERC Electric Tariff, Sixth Revised Volume No. 1; New York Independent System Operator, Inc., FERC Electric Tariff Original Volume No. 2.

61.  We also know from electric quarterly report (EQR) filings by public utilities that there are long-term contracts for long-term sales of capacity and energy in each of the markets; those data are available on the Commissions Web site. http://www.ferc.gov/​docs-filing/​eqr/​data.asp.

62.  NOPR at P 16.

63.  EEI Initial Comments at 44.

64.  All the elements of section 210(m)(1)(B)(ii) must be satisfied whether it is through an organized procurement process or by some other means or a combination.

65.  The Commission would be particularly interested in whether QFs have participated in the solicitations and whether QFs have been selected as a winning bidder.

66.  Solicitation characteristics refers to the contract term, type of service requested, dispatchability, the power terms and conditions, the non-power terms and conditions, etc.

67.  This also applies to section 210(m)(3) applications for relief pursuant to section 210(m)(1)(A), which is discussed in another part of the Final Rule.

68.  The CAISO filed its proposed MRTU Tariff on February 9, 2006, in Docket No. ER06-615-000, and requested an effective date of November 1, 2007. The Commission conditionally accepted MRTU on September 21, 2006. California Independent System Operator Corporation, 116 FERC ¶ 61,274 (2006).

69.  Supra note 67.

70.  NOPR at P 16.

71.  Southwest Power Pool, Inc., 116 FERC ¶ 61,289 (September 26, 2006).

72.  NOPR at P 16.

73.  Texas State law requires states: “The commission shall ensure that an electric utility or transmission and distribution utility provides nondiscriminatory access to wholesale transmission service for qualifying facilities, exempt wholesale generators, power marketers, power generation companies, retail electric providers, and other utilities or transmission and distribution utilities.” Public Utility Regulatory Act, TEX. UTIL. CODE ANN. 35.0004 (PURA).

74.  QFs may rebut this presumption by making a demonstration by making a demonstration that: (i) The QF has certain operational characteristics that effectively prevent the QF's participation in a market; or (ii) a QF lacks access to markets due to transmission constraints. An existing QF can show that it is located in an area where persistent transmission constraints in effect cause the QF to have neither physical nor financial access to markets outside a persistently congested area and there is not a sufficient opportunity to redispatch around the constraint or to sell the QF output or capacity within the area on a short-term and/or long-term basis because of the constraint.

75.  16 U.S.C. 824a-3(m)(3) (emphasis added).

76.  See Alliant Energy Corporate Services, Inc., 113 FERC ¶ 61,024 (2005) (Alliant); Montana-Dakota Utilities Co., 113 FERC ¶ 61,045 (2005) (Montana-Dakota).

77.  18 CFR 385.207.

78.  18 CFR 385.204.

79.  In the NOPR, the Commission also stated that, consistent with our interpretation of “notice” under section 210(m)(3), the Commission will require an applicant to identify all potentially affected utilities in the application so that the Commission will be able to meet its statutory requirement to provide sufficient notice and an opportunity for comment.

80.  16 U.S.C. 824a-3(m)(3) (emphasis added).

81.  16 U.S.C. 824a-3(m)(6) (emphasis added).

82.  Midwest Renewable Energy Projects, LLC, 116 FERC ¶ 61,017 (2006) (Midwest Renewable).

83.  Midwest Renewable at P 14.

84.  See 44 U.S.C. 3507(d).

85.  5 CFR 1320.11.

86.  5 U.S.C. 601-12.

87.  5 U.S.C. 553(b)(A).

88.  “How to Comply with the Regulatory Flexibility Act: A Guide for Government Agencies”, Small Business Administration, Office of Advocacy, P.5, May 2003.