64342 Federal Register / Vol. 71, No. 211 / Wednesday, November 1, 2006 / Rules and Regulations 

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

2 16 U.S.C. 824a–3 (2000). 

3Attached as Appendix A is a list of all 

commenters and the abbreviations that are used 

throughout the order to refer to the commenters. 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 292 

[Docket No. RM06–10–000; Order No. 688] 

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, 

(202) 502–6113. Marka Shaw (Technical 

Information), Office of Energy Markets 

and Reliability, Federal Energy 

Regulatory Commission, 888 First 

Street, NE., Washington, DC 20426, 

(202) 502–8641. Samuel Higginbottom 

(Legal Information), Office of the 

General Counsel, Federal Energy 

Regulatory Commission, 888 First 

Street, NE., Washington, DC 20426, 

(202) 502–8561. Eric Winterbauer (Legal 

Information), Office of the General 

Counsel, Federal Energy Regulatory 

Commission, 888 First Street, NE., 

Washington, DC 20426, (202) 502–8329. 

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 


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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. 

5Reference 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. 

7To 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. 

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 longterm sales of capacity and electric energy; or 

(B)(i) Transmission and interconnection 

services that are provided by a Commissionapproved 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 longterm 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 nonjurisdictional 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 


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8Herein referred to as small QFs. 

9The 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. 

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 Commissionapproved 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 


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10 16 U.S.C. 824 et seq. 

11 Id. 796(18). 

12 Id. 796(17)(A)(i)–(ii). 

13Southern 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’’). 

14Energy 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. 

15Revised 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). 

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 


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16NOPR 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. 

22The Commission interprets the 90-day period 

to begin upon receipt of a completed application. 

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 longterm 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, auctionbased 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 Commissionapproved 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 longterm 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 longVerDate Aug<31>2005 17:43 Oct 31, 2006 Jkt 211001 PO 00000 Frm 00006 Fmt 4701 Sfmt 4700 E:\FR\FM\01NOR2.SGM 01NOR2

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23The 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. 

24ELCON Comments at 8. 

25 Id. 

26AWEA Comments at 2. 27EPSA Comments at 9. 

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 longterm 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 auctionbased 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 shortand 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 onsite 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 


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28Regional 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). 

29See supra note 15. 

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 Commissionapproved 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 


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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 

Continued 

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 Commissionapproved 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 Commissionapproved 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 


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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. 

32Promoting 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). 

33Standardization 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). 

34Standardization 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). 

35NOPR at P 20. 

36 Id. 

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 


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37EEI 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. 

38EEI 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. 

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 kickin. 

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 


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40As 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. 41A 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. 42Herein referred to as ‘‘small QF.’’

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 realtime 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 


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43Order 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. 

44An existing QF is one that is in existence as 

of the date the mandatory purchase obligation is 

terminated. 

45EEI 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. 

46EEI 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. 

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 dayahead, 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 processfollowing 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. 


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47Supra note 32. 

48Supra note 33. 

49Supra note 34. 

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 Commissiondetermined 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 


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50See, e.g., PJM Interconnection, LLC, 114 FERC 

¶ 61,191, order on reh’g, 116 FERC ¶ 61,102 (2006). 51The 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. 

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 relitigate 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 


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52See SEC v. Chenery, 332 U.S. 194, 202–03, 

reh’g denied, 332 U.S. 747 (1947). 

53We 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. 

54The 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. 

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 


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55 In the NOPR the Commission noted that while 

SPP and the CAISO, respectively are a Commissionapproved 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. 56NOPR at P 22. 

57ELCON’s August 25, 2006 Supplemental 

Comments at 8–9. 

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 realtime 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 longterm 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 longterm 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. 


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58Supra note 15. 

59See 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). 

60See 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. 

61We also know from electric quarterly report 

(EQR) filings by public utilities that there are longterm 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. 

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 longterm 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 marketbased 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 longterm 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, auctionbased 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, auctionbased 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 auctionbased 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 longterm 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 


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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 longterm 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 caseby-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, ISONE, 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 


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62NOPR at P 16. 

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 Commissionapproved ‘‘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-bycase 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 longterm 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 nonauction 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 


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63EEI Initial Comments at 44. 

64All 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. 

65The Commission would be particularly 

interested in whether QFs have participated in the 

solicitations and whether QFs have been selected as 

a winning bidder. 

66Solicitation characteristics refers to the contract 

term, type of service requested, dispatchability, the 

power terms and conditions, the non-power terms 

and conditions, etc. 

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 marketbased 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 marketbased 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 marketbased 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 


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67This 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. 

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, shortterm 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 nonRTO 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 caseby-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 Commissionapproved reciprocity tariff. 

2. Comments 

150. NRECA states that some nonpublic 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 nonpublic 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). 


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68The 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). 69Supra note 67. 70NOPR at P 16. 

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 longterm 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 


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71Southwest Power Pool, Inc., 116 FERC ¶ 61,289 

(September 26, 2006). 

72NOPR at P 16. 

210(m)(1). The Commission did 

recognize that the SPP is a Commissionapproved 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 realtime 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 marketbased day-ahead market for sales of 

electricity. The ERCOT ISO supports the 

scheduling of bilateral capacity and 

energy contracts (both short- and longterm) by qualified scheduling entities 


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73Texas 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). 

74QFs 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. 

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 marketplace 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 realtime 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 marketbased (as opposed to administrativelycreated) 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 


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

76See Alliant Energy Corporate Services, Inc., 113 

FERC ¶ 61,024 (2005) (Alliant); Montana-Dakota 

Utilities Co., 113 FERC ¶ 61,045 (2005) (MontanaDakota). 

77 18 CFR 385.207. 

78 18 CFR 385.204. 

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 


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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. 

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 caseby-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 


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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. 

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 wellestablished 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 noncontractual 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 


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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 


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84See 44 U.S.C. 3507(d). 85 5 CFR 1320.11. 

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 


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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. 

Data collection FERC–556 Number of 

respondents 

Number of 

responses 

Hours per 

response 

Total annual 

hours 

§ 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 (202)502–8415, fax: 

(202)273–0873, e-mail: 

michael.miller@ferc.gov] 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: (202) 395–4650, fax: (202) 395–

7285. 

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 


sroberts on PROD1PC70 with RULES
64372 Federal Register / Vol. 71, No. 211 / Wednesday, November 1, 2006 / Rules and Regulations 

normal business hours from our Help 

line at (202) 502–8222 or the Public 

Reference Room at (202) 502–8371 Press 

0, TTY (202) 502–8659. E-mail the 

Public Reference Room at 

public.referenceroom@ferc.gov. 

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: 

Sec. 

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 Commissionapproved 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). 


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(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 selfrecertification, 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 


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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 shortterm 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 nonjurisdictional 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 nonregulated 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) 


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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. (MontanaDakota) 

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) 

[FR Doc. 06–8928 Filed 10–31–06; 8:45 am] 

BILLING CODE 6717–01–P 


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