EEIs_NOPR_comments_2-27

UNITED STATES OF AMERICA

BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION









New PURPA Section 210(m) Regulations )

Applicable to Small Power Production ) Docket No. RM06-10-000

and Cogeneration Facilities )









COMMENTS OF

THE EDISON ELECTRIC INSTITUTE









Edward H. Comer Randall E. Davis

General Counsel Stuntz, Davis & Staffier, P.C.

Edison Electric Institute 555 Eleventh Street, N.W.

701 Pennsylvania Avenue, N.W. Suite 550

Washington, D.C. 20004 Washington, D.C. 20004

(202) 508-5000 (202) 638-6588









February 27, 2006

TABLE OF CONTENTS









I. COMMUNICATIONS AND SERVICE .....................................................3



II. BACKGROUND .........................................................................................3



III. EEI‟S INTEREST ........................................................................................4



IV. COMMENTS ...............................................................................................5



A. Executive Summary .........................................................................5



B. Responses to Specific Questions ...................................................12



1. There is ample evidence to support the Commission‟s

preliminary conclusion that QFs interconnected with

utilities that are members of the Midwest ISO, PJM,

ISO-NE and NYISO have nondiscriminatory access to

independently administered, auction-based day ahead

and real time wholesale markets for the sale of electric

energy and access to wholesale markets for long-term

sales of capacity and energy, within the meaning of

section 210(m)(1)(A) ...............................................................12



a. Midwest ISO ......................................................................15



b. PJM ....................................................................................23



c. ISO-NE ..............................................................................29



d. NYISO ...............................................................................35



2. The Commission should make a generic finding that

QF access pursuant to a Commission-approved OATT

meets the “nondiscriminatory access” test of section 210(m)

for all markets, whether centrally organized and

administered or not ..................................................................39









i

3. The Commission should make generic findings

applicable to SPP and the CAISO that QFs operating

within these markets 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,” as required under

section 210(m)(1)(B)(i) ............................................................40



4. A number of factors are indicative of the ability

of QFs in a region without an RTO or ISO “Day 2” market

to participate in a competitive wholesale market .....................42



a. Evidence of bilateral transactions reflects

a competitive wholesale market ...........................................42



b. Opportunities to participate in competitive

procurements reflect a competitive wholesale

market ..................................................................................43



c. Access to trading hubs reflects a competitive

wholesale market ................................................................46



d. Actual QF sales are evidence of a competitive

wholesale market ................................................................47



5. The Commission should not make a generic

exemption for any QFs from the termination of

the mandatory purchase requirement .......................................48



6. The Commission should clarify its interpretation of

the application of the savings clause in section

210(m)(6) .................................................................................51



a. The term “obligation” refers to fully-defined

legal arrangements .............................................................51



b. The savings clause does not apply to a

generalized obligation under PURPA for the

purchase of power from QFs...............................................55



c. QFs having expiring contracts are not

entitled to “roll-over” contracts under

section 210(m) ....................................................................56







ii

d. The effective date of the termination of the

mandatory purchase requirement is the date

of enactment (August 8, 2005)............................................57



7. The Commission should clarify the procedures

for utilities requesting termination of the

mandatory purchase requirement on a

“service territory-wide” basis ..................................................58



8. The Commission should incorporate the

statutory cost recovery language in

section 210(m)(7) into its regulations ......................................59



V. CONCLUSION ..........................................................................................63





Exhibit A, Characteristics of “Day 2” RTOs



Exhibit B, Wholesale Power Purchases, 2004



Exhibit C, Bilateral Transactions









iii

UNITED STATES OF AMERICA

BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION





New PURPA Section 210(m) Regulations )

Applicable to Small Power Production ) Docket No. RM06-10-000

and Cogeneration Facilities )





COMMENTS OF

THE EDISON ELECTRIC INSTITUTE



The Edison Electric Institute (“EEI”) submits the following comments on the



Federal Energy Regulatory Commission‟s (“Commission” or “FERC”) January 19, 2006,



Notice of Proposed Rulemaking (“NOPR”) in this docket.1 The NOPR proposes to



amend the Commission‟s regulations governing the obligation of electric utilities to



purchase electricity from, or sell electricity to, qualifying facilities pursuant to section



210 of the Public Utility Regulatory Policies Act of 1978 (“PURPA”), as amended by



section 1253 of the Energy Policy Act of 2005 (“EPAct 2005”). EPAct 2005 added a



new subsection (m) to PURPA section 210. PURPA section 210(m) provides for



termination of an electric utility‟s obligation to purchase energy and capacity from



qualifying cogeneration facilities and qualifying small power production facilities



(collectively “qualifying facilities” or “QFs”) as of August 8, 2005, the date on which



EPAct 2005 was enacted, if the Commission finds that the QFs within the service



territory of a utility have nondiscriminatory access to competitive wholesale markets, the



indicia of which are prescribed in the statute. In general, the Commission‟s NOPR to



implement section 210(m) accurately interprets the statutory mandates of section 210(m)





1

New PURPA Section 210(m) Regulations Applicable to Small Power Production and Cogeneration

Facilities, 114 FERC ¶ 61,043 (2006).

and the congressional intent behind these provisions. EEI urges the Commission to



promulgate a final rule that:



1. finds that QFs interconnected with utilities that are members of the

Midwest Independent Transmission System Operator, Inc. (“Midwest ISO”),

PJM Interconnection, L.L.C. (“PJM”), ISO New England, Inc. (“ISO-NE”) and

the New York Independent Transmission System Operator, Inc. (“NYISO”) have

nondiscriminatory access to those markets and that those markets satisfy the

section 210(m)(1)(A) criteria for terminating the PURPA section 210 mandatory

purchase obligation;



2. finds that QFs have nondiscriminatory access to markets within the

meaning of section 210(m)(1) whenever transmission and interconnection

services are provided pursuant to a Commission-approved open access

transmission tariff (“OATT”);



3. finds specifically that QFs interconnected with utilities operating within

either the Southwest Power Pool, Inc. (“SPP”) or the California Independent

System Operator Corporation (“CAISO”) 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,” as required under section 210(m)(1)(B)(i);



4. provides that a demonstration that QFs have access to an organized power

procurement process is prima facie evidence that the QFs have access to

wholesale markets for long-term sales of capacity and electric energy;



5. clarifies that the term “contract or obligation” as used in section

210(m)(6) refers to a writing that completely memorializes all material terms

and conditions of a specific transaction for the purchase and sale of energy

and/or capacity between two or more counterparties;



6. does not categorically exempt any subset of QFs;



7. clarifies that the service territory of utilities requesting termination of the

mandatory purchase requirement may be identified as the applicant utility‟s

control area(s); and



8. incorporates the statutory language ensuring recovery of mandatory

PURPA costs, as required by section 210(m)(7).









2

I. COMMUNICATIONS AND SERVICE



All communications and correspondence with respect to this filing and proceeding



may be served upon the following individuals:



Edward H. Comer, General Counsel* Randall E. Davis*

Melissa Lauderdale, Director, Ellen S. Young

Industry Legal Affairs Stuntz, Davis & Staffier, P.C.

Edison Electric Institute 555 Eleventh Street, N.W.

701 Pennsylvania Avenue, N.W. Suite 550

Washington, D.C. 20004 Washington, D.C. 20004

(202) 508-5000 (202) 638-6588

ecomer@eei.org rdavis@sdsatty.com



Persons designated for inclusion on the official service list compiled by the Secretary in



this proceeding are indicated with an asterisk.



II. BACKGROUND



On August 8, 2005, President Bush signed EPAct 2005 into law.2 Title XII of



EPAct 2005, the Electricity Modernization Act of 2005, made numerous changes to the



nation‟s electricity laws, including fundamental changes to section 210 of PURPA, 16



U.S.C. § 824a-3. Section 1253(a) of EPAct 2005 added section 210(m) to PURPA,



which is intended to relieve an electric utility of the requirement to enter into a new



contract or obligation to purchase QF power upon a Commission finding that certain



market conditions exist. Section 210(m) provides for termination of a utility‟s obligation



to purchase electric energy from QFs and sell electric energy to QFs when the



Commission finds that QFs have nondiscriminatory access to one of three markets



described in section 210(m)(1)(A),(B) or (C). These are: (A) independently



administered, auction-based day-ahead and real-time wholesale markets for electric



energy and wholesale markets for long-term sales of capacity and electric energy; or (B)





2

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





3

transmission and interconnection services that are provided by a Commission-approved



regional transmission entity pursuant to an open access transmission tariff that affords



nondiscriminatory treatment to all customers, and competitive wholesale markets that



provide a meaningful opportunity to sell capacity and energy on a short-term and long-



term basis; or (C) wholesale markets for the sale of capacity and electric energy that are



at a minimum of comparable competitive quality as those described in (A) or (B).



EPAct 2005 does not require a rulemaking to implement section 210(m), which



provides for electric utilities to seek relief from the mandatory purchase requirement on a



“service territory-wide” basis. Nevertheless, the Commission has determined that it is



appropriate to address the termination of the mandatory purchase obligation through



rulemaking. (NOPR, ¶ 9). Thus, the Commission requested comments on its proposed



interpretations of the statutory criteria for terminating the mandatory purchase



requirement, along with preliminary generic findings that the mandatory purchase



requirement should be terminated in four markets: the Midwest ISO, PJM, ISO-NE, and



the NYISO.



III. EEI’S INTEREST



EEI is the association of the nation‟s shareholder-owned electric companies,



international affiliates, and industry associates worldwide. EEI‟s U.S. members serve 97



percent of the ultimate consumers served by the shareholder-owned segment of the



electric utility industry and 71 percent of all electric utility ultimate consumers in the



nation. They generate almost 60 percent of the electricity produced by U.S. electric



generators. As a result, the interests of EEI‟s members stand to be affected directly by









4

any Commission proceeding that involves the purchase obligations for cogeneration and



small power production facilities that may sell electricity to EEI‟s members.



IV. COMMENTS



A. Executive Summary



The fundamental changes Congress made to PURPA through new section 210(m)



reflect congressional recognition of the sweeping changes that have occurred in



wholesale electricity markets since PURPA was enacted in 1978. These changes include:



 The enactment of the Energy Policy Act of 1992, which encourages

exempt wholesale generators and requires nondiscriminatory transmission

of electricity for sale at wholesale;



 The Commission‟s adoption of Order No. 888 in 1996, which requires

open, non-discriminatory access to public utility-owned transmission, and

its promulgation of standard interconnection procedures and agreements

for large and small generators in Order 2003 and Order 2006;



 The development of ISOs and RTOs providing independent operation of

transmission and wholesale markets in accordance with Order No. 2000;

and



 The advent of large, competitive regional wholesale electric markets.



Today, QFs, like any other generators, are free to sell their power to the wholesale



buyer of their choice using open, nondiscriminatory access to the transmission system



and the right to interconnect to that system pursuant to tariffs filed with and approved by



the Commission. With the development of regional power markets, there are extensive



opportunities available for QFs to sell their output throughout large regions of the



country. Moreover, separate and apart from PURPA, several federal, state and even local



programs such as federal tax credits for renewable generation, state retail competition



policies, state renewable or resource portfolio standards, and state resource adequacy









5

requirements or requirements for competitive power procurement already exist to provide



strong economic and regulatory incentives to QF generators.



As Congress recognized by its adoption of a fundamentally new statutory



framework for QFs where competitive wholesale markets exist, there is no continuing



policy justification for favoring one particular class of electric generators over all others.



Under section 210(m), Congress determined that QFs should have access to competitive



wholesale markets OR the benefits of a mandatory purchase obligation, but NOT BOTH.



A QF that has the opportunity to sell its power into a competitive market, but is



dissatisfied with the options provided by the competitive marketplace, no longer has the



right to fall back on the section 210 mandatory purchase obligation.



EEI agrees that the issuance of regulations by the Commission should provide



greater certainty to industry – both electric utilities and QF developers – on the



continuing applicability of the mandatory purchase requirement in specific markets. EEI



generally supports the Commission‟s proposed rules, and for the most part, the



Commission has interpreted the legislative language of section 210(m) correctly and in a



manner consistent with congressional intent. In particular, EEI supports 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 mandatory purchase obligation. (NOPR, ¶ 27).



EEI also supports and encourages the Commission to make a generic finding that



QF access pursuant to any Commission-approved open access transmission tariff



(“OATT”) meets the “nondiscriminatory access” requirement of section 210(m) for all









6

markets, whether centrally organized and administered or not, as the Commission



tentatively has concluded (NOPR, ¶¶ 19, 31). It is difficult to envision any circumstance



in which a Commission-approved OATT should not be considered sufficient for purposes



of establishing a rebuttable presumption that a QF has “nondiscriminatory access” under



section 210(m) because every OATT requires such access. Any exceptions to this



requirement could result only from a case-by-case implementation of the open access



requirement, and not from the requirement itself, as the Commission tentatively has



concluded. (NOPR, ¶ 31). Thus the existence of a Commission-approved OATT should



establish a presumption that nondiscriminatory access exists within the meaning of



section 210(m) unless an affected QF can demonstrate conclusively that it does not



actually have such access.



EEI also encourages the Commission to make generic findings applicable to SPP



and CAISO that electric utilities operating within these markets provide



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,” as required under section 210(m)(1)(B)(i). The only case-specific



Commission finding that should be required with respect to utilities operating in these



areas is whether the markets available to QFs in these areas constitute “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-



times sales, to buyers other than the utility to which the qualifying facility is



interconnected” as required under section 210(m)(1)(b)(ii). EEI agrees that the types of









7

evidence proposed by the Commission, i.e., “actual sales data for (1) long-term and short-



term capacity and (2) long-term, short-term, and real-time electric energy as well as



evidence that the utility operates in a competitive wholesale market” (NOPR, ¶ 29) are



appropriate to demonstrate that the market test under 210(m)(1)(B)(i) has been met.



The Commission also has requested comments on whether, in regions without



“Day 2” markets, the requirement that QFs have access to wholesale markets for long-



term sales of capacity and electric energy is satisfied if an organized power procurement



process exists in which QFs can participate. (NOPR, ¶ 21). EEI submits that an



organized power procurement program, overseen by state regulators, in which QFs may



participate is ample evidence that QFs have access to the “competitive” wholesale energy



and capacity markets described in sections 210(m)(1)(B)(ii) and 210(m)(1)(C).3 It is



difficult to imagine how a more competitive wholesale market could be designed than



one that is open to all generators seeking to provide energy and capacity to a load serving



entity (“LSE”). The Commission should find that an organized power procurement



program that is open to QFs is prima facie evidence that QFs have access to



“competitive” wholesale energy and capacity markets under 210(m)(1)(B)(ii) and



210(m)(1)(C). This finding should be rebuttable only upon a showing that the organized



power procurement program somehow discriminates against QFs. Additionally, the



Commission should accept evidence of bilateral transactions, access to trading hubs, and



actual QF sales to demonstrate that such markets exist.









3

Indeed, such programs also are in place in states encompassed within RTO “Day 2” markets. For

example, Maryland‟s franchised electric utilities procure supplies to provide standard offer service to their

retail customers through acompetitive procurement process, as described in Allegheny Energy Supply

Company, LLC, 108 FERC ¶ 61,082 (2004).





8

EEI opposes any generic exemption for small renewable or other projects from



the termination of the mandatory purchase requirement. The requirements of Order 888



and the Commission‟s interconnection rules assure that generators selling at wholesale



will have open, nondiscriminatory access to the transmission system, regardless of



whether interconnection is accomplished at distribution or transmission voltage.4



Moreover, the statute does not provide for any exemptions for any class or category of



QFs. Had Congress intended that some QFs be exempt from the fundamental changes it



made to PURPA, it would have provided expressly for such special treatment. The



Commission tentatively has concluded that once a contract terminates by its terms, a



utility will not be required to enter into a new, successor contract with a QF if the



Commission has found that the QF has nondiscriminatory access to competitive markets



within the meaning of section 210(m). (NOPR, ¶ 32). EEI agrees with the Commission



that having QF status does not entitle a QF to the benefits of the mandatory purchase



obligation in perpetuity. Any other interpretation would negate the effectiveness of the



statutory provisions terminating the mandatory purchase requirement.



The Commission‟s proposal (NOPR, ¶ 32) to treat contracts that are entered into



between a QF and an electric utility after the date of enactment, but before the



Commission has determined that the utility is entitled to relief from the mandatory



purchase requirement, as “existing contracts” is problematic.5 As a legal matter, the







4

See Standardization of Generator Interconnection Agreements and Procedures, 68 Fed. Reg. 49845

(2003), FERC Stats & Regs ¶ 31,036 (2003)(“Order 2003”); Promoting Wholesale Competition Through

Open Access Non-Discriminatory Transmission Services by Public Utilities, FERC Stats & Regs,

Regulations Preambles January 1991-June 1996 ¶ 31,036, 61 Fed. Reg. 21540 (1996)(“Order 888”); FERC

Stats & Regs., Regulations Preambles July 1996-Dec. 2000 ¶ 31,048 (1997)(“Order 888A”), and as

discussed infra at section B 5.

5

The term “existing” contract, as used here, is a shorthand reference to contracts or obligations described in

section 210(m)(6), which provides that “nothing in [subsection 210(m)] affects the rights or remedies of





9

proposal is inconsistent with the language in section 210(m)(1) that establishes the date



of enactment as the cutoff date for the mandatory purchase requirement in markets that



the Commission finds meet the standards in subparagraphs (A), (B), or (C). The



determination of whether a contract to which the mandatory purchase requirement may



continue to apply exists must be made as of the date of enactment of section 210(m) –



August 8, 2005. As a practical matter, the Commission‟s proposed approach could



provoke a “gold rush” of QFs to state commissions to order utilities to enter into



contracts.



A related matter is the Commission‟s proposal (NOPR, ¶ 49) merely to adopt the



statutory language of section 210(m)(6) into its regulations for determining what



arrangements are “grandfathered” pursuant to that section. The Commission‟s approach



is likely to engender litigation and confusion. The scope of the “savings clause” has



already come before the Commission once and it is likely that the meaning of the



language “contract or obligation, in effect or pending approval . . . . on the date of



enactment,” will continue to result in disputes until it is established clearly by the



Commission. The Commission‟s final regulations should clarify that:



1. the term “obligation . . . in effect or pending approval before the

appropriate State regulatory authority or non-regulated electric utility on

the date of enactment” refers to a writing that completely memorializes

all material terms and conditions of a specific transaction for the

purchase and sale of energy and/or capacity between two or more

counterparties;



2. the certification, by the Commission or via a self-certification, that a

facility is a qualifying facility does not give rise to a “contract or

obligation” within the meaning of section 210(m)(6); and







any party under any contract or obligation, in effect or pending approval before the appropriate State

regulatory authority or non-regulated electric utility on the date of enactment of this subsection. . . .”





10

3. a state regulatory proceeding to determine the avoided cost rate or other

relevant and material terms of a generic or pro forma contract intended to

implement PURPA does not constitute a proceeding to approve a “contract

or obligation” as those terms are used in the statute.



The Commission should clarify the procedures to be used by utilities requesting



the termination of the mandatory purchase requirement. EEI agrees with the



Commission‟s proposal to require a “compliance” filing in the four RTO/ISO “Day 2”



markets. For other markets, the statute envisions that the mandatory purchase



requirement will be terminated on a “service territory-wide” basis. EEI anticipates that



generally the service territory of the applicant will be co-extensive with the utility‟s



control area. However, in the case of an applicant with multiple control areas in different



states, EEI recommends that the Commission clarify that the control area in which the



relief will be provided is to be identified in the application.



Finally, the Commission sought comment on whether there is a need at this time



for a regulation to ensure recovery of mandatory PURPA costs, as prescribed in section



210(m)(7). (NOPR, ¶ 52). Under established legal precedent, states are prohibited from



denying utilities the opportunity to recover Commission-approved wholesale costs,



including costs associated with contracts mandated by PURPA. The language in PURPA



section 210(m)(7) adds a congressional mandate to what EEI believes the law already



requires. EEI suggests that the Commission amend its rules to reflect the statutory



mandate requiring cost recovery. This could be accomplished by incorporating the



statutory language into the Commission‟s rules. Enforcement of the cost recovery



requirement would be through case-by-case enforcement actions, as already provided for



under PURPA.









11

B. Responses To Specific Questions



1. There is ample evidence to support the Commission’s

preliminary conclusion that QFs interconnected with utilities that are

members of the Midwest ISO, PJM, ISO-NE and NYISO have

nondiscriminatory access to independently administered, auction-

based day ahead and real time wholesale markets for the sale of

electric energy and access to wholesale markets for long-term sales of

capacity and energy, within the meaning of section 210(m)(1)(A).



Pursuant to PURPA § 210(m)(1)(A), a utility will be relieved of PURPA‟s



mandatory purchase obligation if the Commission determines that the QFs in its service



territory have access to both (1) independently administered, auction-based, day ahead



and real time wholesale markets for the sale of electric energy; and (2) wholesale markets



for long-term sales of capacity and electric energy. The Commission has concluded that



the most reasonable interpretation of section 210(m)(1)(A) is that “it was crafted to apply



in regions in which Independent System Operators (“ISO”) and Regional Transmission



Organizations (“RTO”) administer day-ahead and real-time markets, and bilateral long



term contracts for the sale of capacity and electric energy are available to



participants/QFs in these markets.” (NOPR, ¶ 14). The Commission‟s interpretation is



eminently reasonable and demonstrably correct.



The first element necessary for the termination of the mandatory purchase



requirement is that QFs have “nondiscriminatory access” to a “sufficiently competitive



market” in order to sell their power. (NOPR, ¶ 13.) As to this requirement, the



Commission concludes that QFs do have nondiscriminatory access if they have access to



utilities that provide service pursuant to an OATT, or a Commission-accepted reciprocity



tariff. (NOPR, ¶ 19). EEI agrees.









12

The Commission‟s proposed rules would establish a rebuttable presumption that



there is nondiscriminatory access to wholesale markets whenever a QF “is provided



transmission services pursuant to a Commission-approved open access transmission tariff



or reciprocity tariff, and interconnection services pursuant to Commission-approved



interconnection rules.” See proposed rules in section 292.309(c). The language of the



proposed regulation that the nondiscriminatory access requirement would be deemed met



when a QF “is provided” service could be read to suggest that the QF must already have



obtained service, rather than having the opportunity to obtain service as provided through



the OATT. In addition, the reference in the proposed regulations to the provision of



interconnection services pursuant to Commission-approved rules should be harmonized



with the fact that interconnections at the local distribution level will in some cases be



made pursuant to State regulations, even though the Commission will have jurisdiction



over the wholesale transaction.6 Therefore, EEI recommends that the Commission clarify



that the access requirement is met if the QF “has the opportunity to obtain transmission



services pursuant to a Commission-approved open access transmission tariff or



reciprocity tariff, and interconnection services pursuant to Commission-approved or



state-jurisdictional interconnection rules.”



Today, QFs, like any other generators, are free to sell their power to the wholesale



buyer of their choice using open, nondiscriminatory access to the transmission system



and the right to interconnect to that system pursuant to OATT filed with and approved by









6

The principle of Commission jurisdiction over delivery service associated with QF sales was recently

affirmed in PJM Interconnection, LLC, 114 FERC ¶ 61, 191 at P17 (2006). In that case, the Commission

acknowledged that in some circumstances, the state will have jurisdiction over the interconnection,

although the Commission will retain jurisdiction over wholesale sales and delivery.





13

the Commission.7 Open access is the “law of the land,” and therefore the Commission is



correct to presume its existence where OATTs are in effect, and to place the burden on a



QF to rebut the presumption though a showing of specific and credible evidence



demonstrating that it does not have nondiscriminatory access. (NOPR, ¶ 31). Questions



about the proper implementation of a specific OATT are most appropriately addressed in



complaint proceedings before the Commission, and should not have a bearing on whether



the QF is deemed to have nondiscriminatory access for purposes of section 210(m)(1).



The statute further requires that the wholesale markets to which QFs have



nondiscriminatory access must meet specific characteristics. The first prong of the



statutory market test requires the Commission to determine whether the organized market



to which the QF has access includes an independently administered, auction-based, day



ahead and real time wholesale market for the sale of electric energy. This test is



straightforward and requires no extensive analysis or interpretation. Four of the



Commission-approved ISOs/RTOs – Midwest ISO, PJM, ISO-NE and NYISO – clearly



meet this market test, as the Commission proposes to find. (NOPR, ¶ 22). The



characteristics of each of these markets are described in detail in the attached Exhibit A.8



The second aspect of the statutory market test requires that QFs have access to



“wholesale markets for long-term sales of capacity and electric energy.” PURPA §



210(m)(1)(A)(ii). The extent of wholesale power sales in each state is evidence of the



nationwide availability of competitive wholesale markets. Exhibit B presents data for







7

In the case of RTO/ISO markets, service is provided pursuant to the RTO/ISO‟s OATT. Outside these

markets, service is provided pursuant to a utility-specific OATT.

8

The Commission‟s 2004 State of the Markets Report presents an abbreviated description of the

characteristics of the Day 2 markets operational in PJM, ISO-NE and NYISO in 2004. See Federal Energy

Regulatory Commission 2004 State of the Markets Report, June 2005, at 51-2, Tables 1 and 2. This report

will hereinafter be referred to as “2004 Markets Report.”





14

wholesale power purchases in 2004, which indicate extensive and robust wholesale



markets exist throughout the country.



As the Commission correctly observed in the NOPR, there is no requirement in



the law that wholesale markets for long-term sales of capacity and energy must be



“independently administered,” that QFs must have access to an “organized” capacity



market, or that QFs must have access to separate markets for capacity and energy.



(NOPR, ¶ 15). If Congress had so intended, it would have drafted this requirement



differently. Certainly the statutory test is met when QFs have the opportunity to make



sales of capacity and energy through bilateral contracts. This opportunity is readily



available to QFs within the four enumerated ISOs/RTOs. Exhibit C documents the



extensive availability of bilateral transactions in these markets.



The Commission has asked for specific evidence to support its preliminary



finding that QFs interconnected with electric utilities that are members of the Midwest



ISO, PJM, ISO-NE and NYISO have nondiscriminatory access to those markets and



those markets meet the criteria of section 210(m)(1)(A) for removal of the mandatory



purchase requirement. The following discussion describes how the Midwest ISO, PJM,



ISO-NE and NYISO today satisfy the requirements of section 210(m)(1)(A).



a. Midwest ISO



The Midwest ISO is an independent, Commission-recognized RTO that



provides open access transmission service, administers an open access, same time



information system (“OASIS”) and operates day ahead and real time energy markets in









15

accordance with a tariff on file with the Commission.9 As reported in the Commission‟s



2004 Markets Report, market participants traded bilaterally at several trading points



within the Midwest ISO, including Cinergy Corp., Northern Illinois, and Northern



MAPP.10 The Midwest ISO “extends over a relatively broad area and is heavily



interconnected to adjacent regions.” 11 Joint Operating Agreements between the Midwest



ISO and PJM and between the Midwest ISO and SPP, the seams operating agreement



between the Midwest ISO and the Mid-Continent Area Power Pool, and the Joint



Reliability Coordination Agreement between the Midwest ISO, PJM and the Tennessee



Valley Authority, assure QFs, like any other generators in the Midwest ISO footprint, of



broad power sales flexibility.



Nondiscriminatory Access



In 2001, the Midwest ISO was the first Regional Transmission Organization to



receive Commission approval. The Commission‟s approval was based on its conclusion



that the Midwest ISO is independent of all market participants.12 When it began



operation in February 2002, the Midwest ISO‟s primary function was the implementation



of its OATT. 13 Today, the Midwest ISO retains responsibility for centrally dispatching



wholesale electricity and transmission service in many areas of the Midwest, utilizing



security constrained economic dispatch, in order to “ensure that every electric industry



9

See, e.g., Midwest ISO Open Access Transmission and Energy Markets Tariff (“Midwest ISO TEMT”);

Midwest Independent Transmission System Operator, Inc., 108 FERC ¶ 61,163 (2004) (Order Accepting

proposed sheets of Midwest ISO TEMT).

10

2004 State of the Markets Report at 77.

11

See Potomac Economics, Ltd., 2004 State of the Market Report Midwest ISO, at 6 (June

2005)(hereinafter “2004 Midwest ISO State of the Markets Report”). Midwest ISO is interconnected with

the Independent Electricity System Operator of Ontario, the Mid-Continent Area Power Pool, PJM, SPP,

and the TVA.

12

Midwest Independent Transmission System Operator, Inc., 97 FERC ¶ 61,326 at 62,505 (2001), reh’g

denied, 103 FERC ¶ 61,169 (2003).

13

Indeed, one of the primary missions of Midwest ISO is ensuring fair access to the grid. See, e.g.,

“Midwest ISO Launches Energy Markets,” Midwest ISO Press Release, April 1, 2005, at 3.





16

participant has access to the lines and that no entity has the ability to deny access to a



competitor.”14 Through the Midwest ISO Transmission and Energy Markets Tariff



(“Midwest ISO TEMT”), the Midwest ISO provides nondiscriminatory access to the



transmission system and to the day-ahead and real-time energy and other markets (e.g.,



financial transmission rights (“FTRs”)) that it administers.15



The Midwest ISO TEMT provides for the interconnection of generators, and



incorporates the Commission‟s standard generator interconnection procedures and



agreements, with certain regional variations as approved by the Commission.16 The



Midwest ISO processes requests for interconnection and coordinates the processing and



analysis of interconnection requests, and is a party to the resulting interconnection and



operating agreements that allow any qualified facility to interconnect and operate within



the Midwest ISO footprint. A QF may interconnect its facility with the Midwest ISO



administered transmission facilities on comparable terms and conditions as other



generators and is subject to the same process as other generators under the Midwest ISO



TEMT.17 Once interconnected and operating within the Midwest ISO, the QF can avail





14

See “About MISO,” at www.midwestmarket.org. The Commission has recognized that the Midwest ISO

is a single market that performs functions including central commitment and dispatch with Commission-

approved market monitoring and mitigation. See Detroit Edison Co., et al., 111 FERC ¶ 61,158 at P13

(2005).

15

Module B of the Midwest ISO TEMT deals with transmission service; Module C deals with transmission

provider energy markets, scheduling and congestion management, and also provides for the availability of

FTRs.

16

Attachment X to the TEMT contains standard large generator (>20 MW) interconnection procedures.

Attachment R to the TEMT contains standard small generator (<20 MW) interconnection procedures. In

July 2004, the Commission accepted in part and rejected in part certain revisions proposed by Midwest ISO

to the pro forma tariff sheets filed in compliance with Order Nos. 2003 and 2003-A. See Midwest

Independent Transmission System Operator, Inc., 108 FERC ¶ 61,027 (2004). In October 2004, the

Commission accepted a further compliance filing from the Midwest ISO, and ordered an additional

compliance filing. Midwest Independent Transmission System Operator, Inc, 109 FERC ¶ 61,085 (2004);

Midwest Independent Transmission System Operator, Inc., 111 FERC ¶ 61,052 (2005).

17

Module B of the Midwest ISO TEMT specifies the steps to be followed by a customer seeking

transmission service. For example, the Midwest ISO TEMT generally requires the transmission provider

(Midwest ISO) to provide firm and non-firm point to point service to any transmission customer meeting

the requirements of Section 16.1 of Module B. First, a determination of available transmission capacity is





17

itself of the markets described below, which are administered on a non-discriminatory



basis in accordance with the Midwest ISO TEMT.18



The Midwest ISO‟s Independent Market Monitor has found that the Midwest ISO



has made transmission service adequately available to market participants.19 The



Midwest ISO‟s transmission reservation and scheduling procedures “have improved the



coordination of transmission service in the Midwest.”20 The Independent Market



Monitor found high rates of approval of transmission requests in 2004, which it



concluded indicate that “transmission has generally been available for participants, which



contributes to efficient wholesale trading.”21



More than 150 entities, including investor-owned utilities, municipal utilities and



independent power producers, own generation resources in the Midwest ISO footprint.22



Under the Midwest ISO TEMT, any person generating electric energy for sale or resale is



an eligible customer.23









made. If sufficient ATC does not exist to accommodate a request, a system impact study is performed. If

the Transmission Provider and the Transmission Customer do not agree on a service agreement, the

Transmission Provider is required to begin providing the requested service, subject to the agreement of the

Transmission Customer to compensate the Transmission Provider at whatever rate the Commission

ultimately determines is applicable. If the request cannot be accommodated, section 15.4 of Module C

requires the Transmission Provider and the affected Transmission Owner to “use due diligence to expand or

modify the Transmission System” to provide the requested Transmission Service, provided that the

Transmission Customer agrees to compensate the Transmission Provider and the ITC. Section 16 of the

Module sets forth various requirements for Transmission Customers, including the completion of an

application for service; meeting creditworthiness criteria; having arrangements in place to affect the

delivery from the generating source to the Transmission Provider; agreeing to pay for facilities chargeable

to the Transmission Customer pursuant to the Midwest ISO TEMT; and executing a point-to-point service

agreement or agreed to receive service as provided in section 15.3 of Module B.

18

See Midwest ISO TEMT Module C.

19

See 2004 Midwest ISO State of the Markets Report at v.

20

Id., at 25.

21

Id., at 28.

22

Id., at 3.

23

See Module A of the Midwest ISO TEMT, section 1.79.





18

Markets: Day 2 Markets



The Midwest ISO “Day 2” or “Midwest Market” was implemented on April 1,



2005.24 Today, the Midwest ISO independently administers auction-based, day ahead



and real-time wholesale markets for the sale of energy within the meaning of PURPA



section 210(m)(1)(A). Any entity may qualify as a Market Participant,25 and any Market



Participant may participate in all market activities, including the submission of generation



offers and bids for FTRs.26



The Midwest ISO administers a two settlement system for energy.27 As part of



the first settlement, physical or financial bilaterals, virtual demand or supply offers,



generation supply offers and demands bids are accepted. The Midwest ISO clears a day-



ahead market through an auction process that minimizes the production cost of the bid in



load subject to the constraints of the transmission system and that calculates locational



based prices hourly. As discussed above, this market is available to QFs through the



Midwest ISO TEMT. The financially binding prices at which energy is cleared are posted



for each hour of the operating day by 5 p.m. EST the day before the operating day.



24

In August 2004, the Commission required the Midwest ISO to file a certificate of Operational Readiness

and a Certificate of Organizational Readiness to demonstrate that its energy markets were ready for startup.

The Midwest ISO filed its Readiness Certification in February 2005. In a March 16, 2005 order, the

Commission found the Readiness Certification to be in compliance with prior Commission orders and

found the Midwest ISO energy markets to be ready for start-up on April 1. Midwest Independent System

Operator, Inc.,110 FERC ¶ 61,289 (2005).

25

A “market participant” is defined in section 1.184 of Module A of the Midwest ISO TEMT as “An entity

that (i) has successfully completed the registration process with the Transmission Provider and is qualified

by the Transmission Provider as a Market Participant, (ii) is financially responsible to the Transmission

Provider for all of its Market Activities and obligations, and (iii) has demonstrated the capability to

participate in its relevant Market Activities.” See Midwest ISO TEMT, Substitute Second Revised Sheet

No. 95.

26

See Module C of the Midwest ISO TEMT at section 38.2. The Midwest ISO TEMT requires in section

38.3 that to be authorized to engage in market activities, generation owners and load serving entities must

be qualified as Market Participants. A generation owner that does not intend to qualify as a market

participant may still have the output of its generation available to the Transmission Provider [the Midwest

ISO] via an agreement with a Market Participant who would use the generator‟s output as part of its own

generation offers. See Midwest ISO TEMT, Second Revised Sheet No. 423.

27

The settlement system is described in Module C of the Midwest ISO TEMT at Second Revised Sheet No.

574.





19

The Midwest ISO also operates a second settlement or real time market. In this



market, generation bids and actual system conditions are inputs to a security constrained



economic dispatch market that calculates locational market clearing prices. That is, from



the resulting actual dispatch of generating facilities, market clearing locational based



prices are calculated ex post every five minutes and integrated over the hour to derive



hourly locational prices for each bus, node, zone or hub on the system. Generators



including QFs are paid the difference between what they delivered in the real time market



and what they committed to sell in the day-ahead market times the market clearing price



at the node or bus where they are located. All generators are compensated for the other



services they supply on comparable terms through the Midwest ISO TEMT (e.g.,



payments available for operating reserve and regulation). In addition, the Midwest ISO



has markets for FTRs which permit Market Participants to hedge the price differences



between locations on the grid.



The Midwest ISO also establishes resource adequacy requirements for the load



within the Midwest ISO that obligates the load to meet the requirement under the tariff



for designation of network resources. The Midwest ISO operates 5 trading hubs which



provide liquid trading locations in which market participants can exchange energy and



capacity. At these hubs the Midwest ISO facilitates trading by allowing transactions to



settle against a transparent index that is calculated by the Midwest ISO based upon the



day-ahead and real-time clearing prices of the nodes that comprise the hub.



Resources located outside the Midwest ISO region (“external resources”) also



may participate in the Day-Ahead and Real-Time energy markets through external









20

bilateral transaction schedules pursuant to Module C of the Midwest ISO TEMT.28 The



Midwest ISO TEMT expressly provides for the coordination of bilateral transactions,



both external (involving resources destined for or originating outside the Midwest ISO



footprint), and internal bilateral transactions.29



Markets: Wholesale Markets for Long-Term Sales of Capacity and Electric

Energy



The second aspect of the statutory test requires that QFs have access to



“wholesale markets for long-term sales of capacity and electric energy.” PURPA §



210(m)(1)(A)(ii). This statutory test is met when QFs have the opportunity to make sales



of capacity and energy at wholesale on a long-term basis through bilateral contracts. This



opportunity is readily available to QFs within the Midwest ISO footprint. Because the



Midwest ISO has executed a Joint Operating Agreement with SPP intended to facilitate



interregional electricity trade, and is directly interconnected with PJM (and the



Commission has eliminated the transmission charge for through and out service from



PJM), the size of the potential market for QF suppliers of electricity is larger than just the



Midwest ISO footprint.



Because of its design, the Midwest ISO provides a platform for market



participants to enter into longer term transactions for energy and capacity. The



combination of transparent day ahead and real time prices, financial transmission rights,



trading hubs and access to the system provides all the necessary elements to facilitate



longer term financial and physical bilateral transactions between willing buyers and



sellers.







28

Module C of the Midwest ISO TEMT at Section 38.2.5.f.

29

Module C of the Midwest ISO TEMT at Section 38.2.5.g.





21

An incentive for long term bilateral sales of capacity and energy results from



regional resource adequacy requirements. Module E of the Midwest ISO TEMT sets



requirements and standards to be met by the Midwest ISO and Market Participants to



assure that there is access to sufficient generation resources in order to meet demand on



the transmission system. Under the Midwest ISO TEMT, Market Participants are to



identify at least annually resources relied upon to comply with reliability and resource



adequacy standards, including operating and planning reserve requirements.30 This



process creates an incentive for LSEs to enter into longer term transactions with QFs and



other entities.



To further facilitate such transactions the Intercontinental Exchange, Inc. (“ICE”)



uses trading hubs in Midwest ISO as liquid trading points for physical and financially



settling power contracts for longer durations than the day-ahead market. In addition, over



the counter markets and bilateral transactions between Market Participants are facilitated



by the Midwest ISO transparent day-ahead and real time markets and the liquid trading



hubs such as Cinergy. For example, prices are quoted for standard products for up to



three years forward on both NYMEX and ICE. In addition, Megawatt Daily reports both



long-term and day-ahead transactions (see Exhibit C). These longer term markets



collectively provide any buyers and sellers, including QFs, the opportunity to enter into a



variety of long-term financial and physical contracts for energy and capacity.



A review of selected annual FERC Form 1 filings for 2004 shows that at least 12



Midwest ISO utilities procure long-term capacity and energy from third party suppliers:





30

The Midwest ISO resource adequacy requirements currently are based upon the pre-existing reliability

mechanisms of the states within the Midwest ISO region and within the applicable regional reliability

organizations. The requirements under Module E of the Midwest ISO TEMT are scheduled to terminate

when the Midwest ISO implements a long-term resource adequacy plan.





22

Minnesota Power, CILCO, Illinois Power, Interstate Power & Light, Madison Gas &



Electric, MDU Resources, MidAmerican Energy, Otter Tail Power, Wisconsin Electric



Power, Wisconsin Power & Light, Wisconsin Public Service and Wolverine Power



Supply Coop. This is only a sample of Form 1 filings; other Midwest ISO utilities also



procure long-term capacity and energy resources from third party suppliers. Since 2002,



LSEs in the Midwest ISO region conducted at least 14 competitive RFPs soliciting long-



term generation supplies, some of which were targeted specifically to renewable



generation. These long-term purchases demonstrate the existence of long-term bilateral



capacity and energy markets in the region.31



b. PJM



PJM is an independent entity recognized as an RTO by the Commission in 2001.32



PJM provides open access transmission service, administers the OASIS and operates the



PJM markets including the day ahead and real time energy markets. As the Commission



found in the 2004 Markets Report, there also is active bilateral electricity trading, through



brokers and ICE, in PJM.33



Pursuant to the Operating Agreement, PJM membership is open to end users, load



serving entities, transmission owners, generation owners (including QFs) and marketers.



There are currently over 390 members of PJM who transact in the PJM markets and with



whom a QF can enter into contracts. The number and diversity of membership illustrates





31

Alliant Energy buys approximately 350 MW of power, and has about another 200 MW of future

capacity under contract, from a number of wind projects that are recognized by the Commission as Exempt

Wholesale Generators, but that could also qualify as QFs. This demonstrates the market viability of

economic renewable energy and the willingness of utilities to voluntarily buy economic power from QF-

eligible generation in the Midwest ISO region.

32

The Commission recognized PJM‟s RTO status on a provisional basis in PJM Interconnection, L.L.C.,

96 FERC ¶ 61,061 (2001). In PJM Interconnection, L.L.C., 101 FERC ¶ 61,345 (2002), the Commission

granted full RTO status to PJM.

33

2004 Markets Report at 105.





23

the potential diverse purchasers of a QF‟s energy and capacity. A QF, like other



independently owned generating facilities (EWG, IPPs), is eligible to become a PJM



member and can take service under the PJM OATT.



Nondiscriminatory Access



PJM provides non-discriminatory access to the transmission system and to the



energy and other markets it administers. The PJM Tariff contains the rules for



interconnection with PJM.34 A QF may interconnect with the PJM administered



transmission facilities on comparable terms and conditions as other generators and is



subject to the same process as other generators under the PJM OATT. PJM receives



requests for interconnection and performs any necessary analysis (in conjunction as



appropriate with the local transmission owner), determines the necessary upgrades and



prepares the response to the request. PJM also develops a transmission expansion plan



pursuant to schedule 6 of the Operating Agreement that is submitted to the PJM Board of



Managers for approval.35 Thus, the PJM OATT and the Operating Agreement including



the sections on interconnection provide a cogeneration facility with the ability to



interconnect and operate within the PJM on comparable terms to other generators. Once



interconnected and operating within PJM, a cogeneration facility can avail itself of the



PJM markets which are administered on a non-discriminatory basis in accordance with



the PJM OATT.









34

PJM Tariff Section IV, Attachment K, Subpart A, Generation Interconnection Procedures.

35

See PJM Interconnection, L.L.C., Amended and Restated Operating Agreement, Third Revised Rate

Schedule, FERC No. 24.





24

Markets: Day 2 Markets



PJM operates day ahead and real time energy markets.36 PJM introduced nodal



energy pricing with market-clearing prices based on offers at cost on April



1, 1998, and nodal market-clearing prices based on competitive offers on April 1, 1999. 37



PJM implemented the day ahead energy market on June 1, 2000.38 The 2004 State of the



Market Report (“2004 PJM Market Report”) concluded that the PJM energy markets



were competitive in 2004.39



The 2004 PJM Market Report described the options available to generators that



are Market Participants in the PJM Market:40



In PJM, market participants wishing to buy and sell energy have multiple

options. Market participants decide whether to meet their energy needs

through self-supply, bilateral purchases from generation owners or market

intermediaries, through the Day-Ahead Energy Market or the Real-Time

Energy Market. Energy purchases can be made over any timeframe from

instantaneous Real-Time Energy Market purchases to long-term bilateral

contracts. Purchases may be made from generation located within or

outside PJM. Market participants also decide whether and how to sell the

output of their generation assets. Generation owners can sell their output

within PJM or externally and can use generation to meet their own loads,

to sell into the spot market or to sell bilaterally. Generation owners can

sell their output over any timeframe from instantaneous Real-Time Energy

Market sales to long-term bilateral arrangements. Market participants can

use increment and decrement bids in the Day-Ahead Energy Market to

hedge positions or to arbitrage expected price differences between

markets. The PJM Energy Market comprises all types of energy

transactions, including the sale or purchase of energy in PJM‟s Day-Ahead

and Real-Time Energy Markets, bilateral and forward markets and self-

supply.







36

PJM also operates certain capacity markets (Daily Capacity Market, the Interval, Monthly and

Multimonthly Capacity Markets, as well as the Regulation Market, the Spinning Reserve Market, and the

Annual and Monthly Auction Markets in FTRs).

37

See 2004 State of the Market Report of the Market Monitoring Unit at 19 (March 8, 2005) (hereinafter

2004 PJM Market Report).

38

2004 PJM Market Report at 19.

39

Id. at 20.

40

Id. at 22.





25

PJM administers a two settlement system for energy. As part of the first



settlement self schedules, virtual demand or supply offers, generation supply offers and



demands bids are accepted. PJM clears a day-ahead market through an auction process



that minimizes the production cost of the bid in load subject to the constraints of the



transmission system and that calculates locational based prices for each hour of the



operating day. As discussed above, this market is available to QFs through the Operating



Agreement41 and the PJM Tariff. The financially binding prices at which energy is



cleared are posted for each hour of the operating day by 4 P.M. the day before the



operating day.



PJM also operates a second settlement or real time market. In this market,



generation bids, self scheduled generation and actual system conditions are inputs to a



security constrained economic dispatch that calculates locational market clearing prices.



From the resulting actual dispatch of generating facilities, market clearing locational



based prices are calculated ex post every five minutes and integrated over the hour to



derive hourly locational prices for each bus, node, zone or hub on the system. Generators



including cogeneration facilities are paid the difference between what they delivered in



the real time market and what they committed to sell in the day-ahead market times the



market clearing price at the node or bus where they are located.



Generators also are compensated for the other services they supply on



comparable terms through payments or markets for ancillary services including operating



reserves, spinning reserves and regulation service. In addition, there are markets for



financial transmission rights which permit market participants to hedge the price





41

A QF does not need to sign the Operating Agreement. It may have an agent who has signed the

Operating Agreement transact on its behalf.





26

differences between locations on the grid.42 PJM also establishes resource adequacy



requirements for the load within PJM that obligates the load to meet the requirement.



PJM posts prices for 5 trading hubs, 10 zones and a PJM wide price which provide liquid



trading locations at which market participants can exchange energy. At these locations,



PJM facilitates trading by allowing transactions to settle against a transparent index that



is calculated by PJM based upon the day-ahead and real-time clearing prices of the nodes



that comprise the location.



PJM has established QFs as nodes in the PJM pricing model, offering specific



evidence of the ability of QFs to sell their output into the wholesale market. Day-ahead



and real-time prices can be viewed for each facility through the PJM website.43



Markets: Wholesale Markets for Long-Term Sales of Capacity and Electric

Energy



While a centrally-administered, auction based market for long term sales of



capacity and electric energy is not required in PURPA section 210(m)(1)(A), PJM does



administer daily, monthly and multi-month capacity markets in which capacity may be



sold. Within PJM, all the arrangements by which LSEs acquire capacity are known



generally as the “Capacity Market.”44 Any entity serving PJM load is required to own or



acquire capacity resources to meet its capacity obligations. LSEs may obtain the



necessary resources through bilateral agreements, by constructing generation, or through





42

See e.g. 2004 PJM Market Report at 39.

43

Examples of the this capability within the Commonwealth Edison territory are:



Generator Equipment Market Entry Date

Mendota Hills MENDOTWF August 1, 2005

Crescent Ridge CRIDGEWF August 1, 2005

Mallard Lake MALR-1 October 19, 2005

Hillside HILL-1 October 19, 2005

Pontiac LIVG-1 October 19, 2005

44

2004 PJM Market Report at 26.





27

participation in the PJM-operated Capacity Credit Market. The objective of these



markets is to offer a transparent, market-based mechanism for competitive retail LSEs to



meet their capacity obligations. Capacity of different durations is available through the



Capacity Credit Market. For example, the PJM Daily Capacity Credit Market offers a



mechanism to match capacity with short term changes in retail load. The PJM Interval,



Monthly, and Multi-Monthly Capacity Credit Markets are available to match longer term



obligations with capacity resources.45



PJM members can and do enter into longer term bilateral contracts that become



part of meeting the needs of the PJM Energy Markets. The 2004 PJM Market Report



found that a “significant proportion of the spot market activity represents such underlying



bilateral contracts.”46 The 2004 PJM Market Report also shows that PJM market



participants continuously export and import energy from external regions, in fulfillment



of long-term or short-term bilateral contracts and/or to take advantage of price



differentials.47 PJM is directly interconnected with other RTO markets (Midwest ISO



and NYSIO) and the Commission has eliminated the transmission charge for through and



out service from the Midwest ISO which means that the size of the potential market is



larger than the PJM footprint. Thus, a QF interconnected to a utility within the PJM



footprint has access to a large energy market that extends beyond the boundaries of the



PJM region itself.



The PJM markets provide indices at the locations as well as a large market in



which QFs can sell day-ahead and real time energy and can enter into long term contracts



with other market participants. The various facets of the PJM market – transparent day



45

Id.

46

Id. at 23.

47

2004 PJM Market Report at 26.





28

ahead and real time prices, financial transmission rights, capacity markets, trading hubs



and access to the system – provide all the necessary elements to facilitate long term



financial and physical bilateral transactions for energy and capacity between willing



buyers and sellers. To further facilitate such transactions the ICE uses trading hubs in



PJM as liquid trading points for physical and financially settling power contracts for



longer durations than the day-ahead market.48 In addition, over-the-counter markets and



bilateral transactions between market participants are facilitated by the PJM transparent



day-ahead and real time markets and the liquid trading hubs such as PJM Western Hub.



For example, prices are quoted for standard products for up to three years forward on



NYMEX and ICE (see Exhibit C). In addition, as shown in Exhibit C, Megawatt Daily



reports both long-term and day-ahead transactions. These longer term markets



collectively provide buyers and sellers the opportunity to enter into a variety of long-term



financial and physical contracts for energy and capacity, and therefore satisfy the



statutory requirements.



c. ISO-NE



ISO-NE began operations as an RTO in February 2005. At that time, ISO-NE



assumed broader operational responsibility for the day-to-day operation of the regional



grid. ISO-NE‟s assumption of RTO status was based on the Commission‟s finding that it



satisfies the independence requirements of Order No. 2000.49 ISO-NE has operated day-



ahead and real-time markets since March 1, 2003. As reported in the 2004 Markets









48

See Exhibit C, which summarizes the NYMEX and ICE products available within PJM.

49

ISO-NE received approval from the Commission as an independent RTO in 2004. ISO New England,

Inc., 106 FERC ¶ 61,280 (2004).





29

Report, market participants “actively trade electricity bilaterally, often using the ISO-NE



Internal Hub as the pricing point.”50



Nondiscriminatory Access



The ISO-NE Transmission, Markets and Services Tariff (“ISO-NE OATT”)



provides the rates, terms and conditions for transmission, market and other services



provided by the ISO within the New England Control Area. The ISO-NE OATT is



contained in Section II of the Tariff. The Tariff states that one of the objectives of ISO-



NE is to provide access to competitive markets within the New England Control Area and



to neighboring regions.51



Any entity that is engaged, or proposes to engage, in the wholesale or retail



electric power business is an Eligible Customer under the ISO-NE OATT. Any entity



generating electricity for sale also is an Eligible Customer.52 The ISO-NE OATT



provides the terms and conditions under which nondiscriminatory open access



transmission service is provided over the New England transmission system, and “is



intended to provide for comparable, non-discriminatory treatment of all similarly situated



Transmission Owners and all Transmission Customers, and it shall be construed in the



manner which best achieves this objective.”53 ISO-NE also provides an OASIS



consistent with Order 889. A reciprocity requirement under section II.7 obligates



transmission customers receiving transmission service under the OATT to provide



comparable transmission service to market participants on similar terms and conditions.









50

2004 Markets Report at 83.

51

ISO-NE OATT at Section I.1.3(f).

52

Id. at Section II.1.21.

53

Id. at Section II.2.





30

QFs may be Market Participants in the ISO-NE Market.54 QFs also are eligible to



be transmission customers in ISO-NE.55 The ISO-NE Tariff contains the rules for



interconnection with ISO-NE.56 A QF may interconnect its facility with ISO-NE



administered transmission facilities on comparable terms and conditions to other



generators and is subject to the same process as other generators under the ISO-NE



OATT. ISO-NE receives requests for interconnection and with the assistance of the



local transmission owner performs the analysis that determines the upgrades necessary to



interconnect with the grid and prepares the response to the request. ISO-NE also



develops a transmission expansion plan that is submitted to the ISO-NE Board for



approval. Once interconnected and operating within ISO-NE, the cogeneration facility



can avail itself of the New England markets which are administered on a non-



discriminatory basis in accordance with the ISO-NE OATT and Market Rule 1.



Markets: Day 2



As provided for in Market Rule 1, ISO-NE features Day-Ahead and Real-Time



energy markets that produce separate financial settlements; locational marginal pricing;



and risk management tools to hedge against congestion costs.57 The New England



wholesale market was implemented in 1999. The 2004 Annual Markets Report of ISO-



NE concluded that in 2004, the first full year of operation under Market Rule 1, the ISO-







54

A market participant generally is a participant in the New England Markets that has executed a Market

Participant Service Agreement (MPSA),with accompanying financial assurances, or on whose behalf a

non-executed Market Participant Service Agreement has been filed at the Commission. Through the

MPSA, Market Participants agree to accept service under the Tariff as participants in the New England

Markets and agree to be bound by the terms of ISO-NE operating documents and to make timely payments

55

A Transmission customer is defined as any eligible customer that execute appropriate agreements, either

a Market Participant Service Agreement or a Transmission Service Agreement (which is for customers

seeking transmission service only that do not intend to participate in the markets).

56

See ISO-NE OATT, Section II, Schedule 22.

57

See e.g. ISO New England, Inc., 91 FERC ¶ 61,311 (2000).





31

NE market was competitive.58 The 2004 ISO-NE Markets Report found that since that



time, the New England system has become more efficient, as evidenced in part by the



addition of 9,450 MW of new generation capacity by competitive suppliers.59 Among the



changes implemented in the ISO-NE market in 2004 was the implementation of a



Forward Reserve Market, which is intended to provide an incentive for the installation



and maintenance of quick start generation needed for reliability purposes.60



ISO-NE administers a two settlement system for energy. As part of the first



settlement self schedules, virtual demand or supply offers, generation supply offers and



demands bids are accepted. ISO-NE clears a day-ahead market through an auction



process that minimizes the production cost of the bid in load subject to the constraints of



the transmission system and that calculates locational based prices for each hour of the



operating day. As discussed above, this market is available to cogeneration facilities



through the various agreements and ISO-NE Tariff and Market Rule 1. The financially



binding prices at which energy is cleared are posted for each hour of the operating day by



4 p.m. the day before the operating day. Thus, ISO-NE operates a day-ahead auction



clearing market for energy that is accessible on a non-discriminatory basis to all



generation whether it is cogeneration, utility owned generation or independently owned



generation.



ISO-NE also operates a second settlement or real time market. In this market,



generation bids, self scheduled generation and actual system conditions are inputs to a



security constrained economic dispatch that calculates locational market clearing prices.



58

See 2004 Annual Markets Report (2005) at 2 (hereinafter “2004 ISO-NE Markets Report”).

59

Id. at 3.

60

The Forward Market Reserve (“FRM”) became operational on January 1, 2004. The FRM compensates

generators that can supply electricity to the system within 10 or 30 minutes in response to a contingency,

even if they are not generating prior to the contingency. See 2004 ISO-NE Markets Report at 7.





32

That is, from the resulting actual dispatch of generating facilities, market clearing



locational based prices are calculated ex post every five minutes and integrated over the



hour to derive hourly locational prices for each bus, node, zone or hub on the system.



Generators including cogeneration facilities are paid the difference between what they



delivered in the real time market and what they committed to sell in the day-ahead market



times the market clearing price at the node or bus where they are located. Thus, ISO-NE



operates a real time auction market that is available to all generation (IPPS, EWGs, QFs,



etc.) on comparable terms and conditions in accordance with a FERC filed tariff.



Generators are also compensated for the other services they supply on comparable



terms through payments or markets for ancillary services including operating reserves,



spinning reserves and regulation service. As noted above, ISO-NE also administers a



forward reserve auction market that generators can bid into to sell reserves to ISO-NE on



a longer term basis. In addition, there are markets for FTRs which permit market



participants to hedge the price differences between locations on the grid. ISO-NE also



establishes resource adequacy requirements for the load within ISO-NE that obligates the



load to meet the requirement, and therefore providing an incentive for acquiring energy



and capacity from various suppliers.



Markets: Wholesale Markets for Long-Term Sales of Capacity and Electric

Energy



ISO-NE administers a monthly capacity market in which capacity may be sold.



According to the 2004 ISO-NE Markets Report, on average during 2004, 6% of the



system capacity requirement was met through supply auctions and deficiency auctions



(allowing load serving entities to make up any deficiency in their required capacity after









33

the supply auction) through the capacity market.61 The rest of the required capacity was



either self-supplied or acquired through bilateral contracts.



ISO-NE posts day ahead and real-time prices at a trading hub, 8 zones and a New



England zone which provide liquid trading locations in which market participants can



exchange energy. At these locations, ISO-NE facilitates trading by allowing transactions



to settle against a transparent index that is calculated by ISO-NE based upon the day-



ahead and real-time clearing prices of the nodes that comprise the location.



The ISO-NE markets provide indices at the locations as well as a large market in



which QFs can sell day-ahead and real time energy and can enter into long term contracts



with other market participants. For the periods January through December 2004,



approximately 73% of total real-time load obligations was either forward contracted or



covered by a physical hedge.62 Moreover, ISO-NE is directly interconnected with the



NYISO which provides a larger market for participants.



The ISO-NE market is designed to provide a platform for market participants to



enter into longer term transactions for energy and capacity. The combination of



transparent day ahead and real time prices, financial transmission rights, forward reserve



market, capacity markets, a trading hub, zones and access to the system provides all the



necessary elements to facilitate longer term financial and physical bilateral transactions



between willing buyers and sellers. To further facilitate such transactions the ICE uses



the trading hubs in ISO-NE as liquid trading points for physical and financially settling



power contracts for longer durations than the day-ahead market. In addition, over the



counter markets and bilateral transactions between Market Participants are facilitated by





61

2004 ISO-NE Markets Report at 7.

62

Id. at 101.





34

the ISO-NE transparent day-ahead and real time markets and the trading hub. For



example, prices are quoted for standard products for up to three years forward on ICE



and NYMEX. Additionally, long-term and day-ahead transactions are reported by



Megawatt Daily. (See Exhibit C.) These longer term markets collectively provide



buyers and sellers the opportunity to enter into a variety of long-term financial and



physical contracts for energy and capacity.



d. NYISO



NYISO was found by the Commission to be independent of market participants,



and thus authorized to operate as an independent transmission operator in 1998. 63



The NYISO provides open access transmission service, administers an OASIS and



operates the NYISO markets including the day ahead and real time energy markets. As



found in the 2004 Markets Report, NYISO market participants also trade electricity



bilaterally through brokers, ICE and the NYMEX ClearPort.64



Nondiscriminatory Access



A QF may participate in the NYISO markets and can take service under the



NYSIO OATT and the Services Tariff. The NYISO provides non-discriminatory access



to the transmission system and to the energy and other markets it administers pursuant to



its OATT. Section 1.11 of the NYISO OATT provides that any electric utility or any



person generating energy for sale for resale is an eligible customer. The NYISO Tariff



contains the rules for interconnection with NYISO.65 A QF may interconnect its facility



with the NYISO administered transmission facilities on comparable terms and conditions





63

Central Hudson Gas & Electric Co., 83 FERC ¶ 61,352 (1998), order on reh’g, 87 FERC ¶ 61,135

(1999).

64

2004 Markets Report at 91.

65

NYISO OATT Attachment S.





35

to other generators and is subject to the same process as other generators under the



NYISO OATT. The NYISO receives requests for interconnection and has primary



responsibility for studies which determine system reliability impact and determination of



the grid modifications necessary to complete the interconnection. The transmission



owner is a party to the grid modification study. Thus, the NYISO OATT including the



sections on interconnection provides a QF with the ability to interconnect and operate



within the NYISO on comparable terms to other generators. Once interconnected and



operating within NYISO, the QF can avail itself of the NYISO markets which are



administered on a non-discriminatory basis in accordance with the NYISO OATT.



Markets: Day 2 Market



The NYISO market is operated pursuant to the NYISO Market Administration



and Control Area Services Tariff (“NYISO Tariff”). The NYISO Tariff contains



provisions related to the NYISO‟s administration of competitive markets for the sale and



purchase of energy and capacity. Market participants under the NYISO Tariff include



entities purchasing, transmitting, selling or purchasing for resale capacity, energy or



ancillary services in the wholesale market.66 Transmission customers under the OATT



are market participants, as are suppliers and their designated agents.



NYISO administers multi-settlement energy markets, which consist of a



financially binding day-ahead market and a real-time market. As part of the first



settlement virtual demand or supply offers, generation supply offers and demands bids



are accepted. NYISO clears a day-ahead market through a security constrained unit



commitment which is an auction process that minimizes the production cost of the bid in



load subject to the constraints of the transmission system and that calculates locational

66

Id. at Section 2.103.





36

based prices for each hour of the operating day. The financially binding prices at which



energy is cleared are posted for each hour of the operating day by 11 A.M. the day before



the operating day. Thus, the NYISO operates a day-ahead auction clearing market for



energy that is accessible on a non-discriminatory basis to all generation whether it is



cogeneration, utility owned generation or independently owned generation.



The NYISO also operates a second settlement or real time market. In this market,



generation bids, self scheduled generation and actual system conditions are inputs to a



real time security constrained economic dispatch that calculates locational market



clearing prices. Based on the resulting actual dispatch of generating facilities, market



clearing locational based prices are calculated ex ante every five minutes and integrated



over the hour to derive hourly locational prices for each bus, node, or zone on the system.



Generators, including cogeneration facilities, are paid the difference between what they



delivered in the real time market and what they committed to sell in the day-ahead market



times the market clearing price at the node or bus where they are located. Thus, NYISO



operates a real time auction market that is available to all generation (IPPs, EWGs, QFs,



aggregators of generation, etc.) on comparable terms and conditions in accordance with a



FERC filed tariff.



Generators are also compensated for the other services they supply on comparable



terms through payments or markets for ancillary services including operating reserves



and regulation service. The NYISO operates a two settlement system or market for



operating reserves and regulation. In addition, there are markets for FTRs which permit



market participants to hedge the price differences between locations on the grid.









37

Markets: Wholesale Markets for Long-Term Sales of Capacity and Electric

Energy



The NYISO also establishes resource adequacy requirements for the load within



NYSIO that obligates the load to meet the requirement. Annually the NYISO administers



26 auctions for capacity which consists of three types of auctions. The auctions consist of



2 strip auctions for six months, 12 monthly auctions and 12 spot market auctions for



capacity. NYISO posts day-ahead and real-time prices for 11 zones which provide liquid



trading locations in which market participants can exchange energy and capacity. At



these locations, NYISO facilitates trading by allowing transactions to settle against a



transparent index that is calculated by NYSIO based upon the day-ahead and real-time



clearing prices of the nodes that comprise the zone.



The NYISO markets provide indices at the locations as well as a large market in



which QFs can sell day-ahead and real time energy and can enter into long term contracts



with other market participants. There are currently over 80 market participants of



NYISO which illustrate the entities that a QF has access to in the NYISO markets.67



These participants and the NYISO markets form a platform for long term contracts.



Because NYISO is directly interconnected with two other organized markets (PJM and



ISO-NE), the size of the potential market is larger than NYISO.68



The combination of transparent day ahead and real time prices, financial



transmission rights, capacity markets, zones and access to the system provides all the



necessary elements to facilitate longer term financial and/or physical transactions



67

See the RTO Table attached as Exhibit A for a description of these customers.

68

NYISO continues to work with ISO-NE to develop external scheduling provisions to enable the two

markets to realize the benefits that would follow from a larger control area. See 2004 NYISO State of the

Market Report at 66. The Report states further that the Joint Operating Agreement between the Midwest

ISO and PJM could serve in the future as a model for further coordination between the NYISO and

adjacent markets.





38

between willing buyers and sellers. To further facilitate such transactions, the ICE uses



zones in the NYISO as liquid trading points for physical and financially settling power



contracts for longer durations than the day-ahead market. In addition, over the counter



markets and bilateral transactions between Market Participants are facilitated by the



NYSIO transparent day-ahead and real time markets. For example, prices are quoted for



standard products for up to three years forward on NYMEX and ICE (see Exhibit C).



Megawatt Daily‟s reports regarding both long-term and day-ahead transactions in the



NYISO also are shown in Exhibit C. These longer term markets collectively provide



buyers and sellers the opportunity to voluntarily enter into long-term third party financial



and physical contracts for energy and capacity, should they want price certainty, which is



beyond the PURPA requirements.



2. The Commission should make a generic finding that QF access

pursuant to a Commission-approved OATT meets the

“nondiscriminatory access” test of section 210(m) for all markets,

whether centrally organized and administered or not.



EEI agrees with the Commission‟s proposal to establish a rebuttable presumption



that a utility provides nondiscriminatory access if such utility has on file a tariff that



meets the open access requirements of Order 888, regardless of whether the utility



operates in an organized market or not. In the past ten years, the Commission and the



electric industry have made improvements in providing access to the transmission grid.



The OATT established in Order 888 and its progeny have been effective in preventing



discrimination. Order 889 established OASIS requirements to facilitate access to the



transmission system by providing real time information about transmission availability.



The Commission‟s Standards of Conduct for transmission providers require functional



separation of transmission and wholesale merchant functions. More recently, in Order







39

2004, the Commission extended Standards of Conduct safeguards to all relationships



between transmission providers and all of their marketing and energy affiliates. In Order



2003 and Order 2006, the Commission established standardized interconnection



procedures and agreements for both large and small generators to protect against the



possibility that transmission providers would favor their own generation while hindering



market entry for competing generators. EEI believes that this regime of regulation has



been effective in promoting open access to the nation‟s transmission system and



preventing affiliate abuse.



EEI notes that the Commission has recently received comments on the sufficiency



of the pro forma tariff in Docket No. RM05-25. To the extent that revisions in the OATT



ultimately are deemed necessary as the result of this Order 888 reform initiative, any such



modifications will only serve to further enhance the ability of QFs to access competitive



wholesale markets. And as is the case under the current OATT, any QF will continue to



have the right to file a complaint regarding the administration of any individual OATT, or



present evidence to rebut the presumption that nondiscriminatory access is available.



3. The Commission should make generic findings applicable to

SPP and the CAISO that QFs operating within these markets 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” as required under section 210(m)(1)(B)(i).



EEI agrees with the Commission‟s interpretation that the nondiscriminatory



access requirement of section 210(m)(1)(B) will be met for QFs where access is available



pursuant to an OATT and interconnection rules approved by the Commission and



provided by an entity that is regional in scope. (NOPR, ¶ 16.) The Commission has









40

considered an entity to be sufficiently regional because of its scope or configuration, or



because of its control of multiple discrete transmission systems. Applying these criteria,



both the SPP and CAISO, a Commission approved RTO and ISO,69 respectively, should



be deemed to satisfy the nondiscriminatory access requirement.70



Transmission and interconnection services are provided by SPP and administered



pursuant to the SPP OATT. The SPP OATT affords nondiscriminatory treatment to all



customers. Within the SPP, the External Market Monitor continues to monitor and report



on transmission access issues.71 The SPP OATT complies with all currently-effective



Commission policies and regulations as they apply to the provision of nondiscriminatory



access to transmission.



The Commission has ruled that under the CAISO Tariff “all transmission



customers will have access to the ISO Controlled Grid and all ancillary services provided



by the ISO under the ISO Tariff on a non-discriminatory basis.”72 The CAISO has since



abided by the requirements of Orders 2003 and 2006, amending its OATT in compliance









69

Southwest Power Pool, Inc., 106 FERC ¶ 61,110 (2004); Pacific Gas & Electric Co., San Diego Gas &

Electric Co., and Southern California Edison Co., 81 FERC ¶ 61,122 (1997).

70

On January 4, 2006, in Docket No. ER06-451-000, the SPP filed revisions to its open access transmission

tariff (“OATT”) to implement a real-time energy imbalance market (“EIS Market”). The filing was

composed of three parts: (1) tariff provisions to implement least cost security constrained economic

dispatch, including provisions related to bidding, scheduling and dispatch of generating units; (2) tariff

provisions detailing how locational prices will be developed and charged; and (3) detailed market

monitoring procedures, including market mitigation, monitoring and reporting requirements. The SPP

asked that the tariff sheets implementing the EIS Market go into effect on May 1, 2006. The SPP EIS

Market will be independently administered by the SPP, and will be monitored by the SPP‟s independent

Market Monitor. The SPP EIS Market relies on an auction process to select the wining bidder(s). The SPP

EIS Market will enable market participants to undertake both day-ahead and real-time transactions

When these markets become operational, the Commission should consider issuing a generic finding that the

SPP market meets the requirements of section 210(m)(1)(A).

71

See, e.g., Second Draft of the Initial Assessment of Remaining Compliance and Market Power Issues

Related to the Provisions of Transmissions Service, issued January 18, 2006 by Boston Pacific, Inc.

72

Pacific Gas and Elec. Co., 81 FERC ¶ 61,122 at 61,455-61,456 (1997).





41

with both rules.73 For customers located on distribution-level facilities that are seeking



access to the CAISO markets, each investor-owned utility in California has on file a



Wholesale Distribution Access Tariff (“WDAT”).74 These WDATs have been amended



to reflect Orders 2003 and 2006, as necessary.75



4. A number of factors are indicative of the ability of QFs in a

region without an RTO or ISO “Day 2” market to participate in a

competitive wholesale market.



The Commission requested comments on what tests it should use to ascertain



whether the standards in section 210 (m) (1) (B) and (C) have been met outside RTO/ISO



(“Day 2”) markets. EEI understands that the Commission is not proposing to require any



specific showing to be made, but rather, is seeking input on the indicia of competitive



markets that meet the statutory standards. EEI believes that evidence of bilateral



transactions, opportunities to participate in competitive procurements, access to trading



hubs and actual QF sales all can attest to the presence of a competitive wholesale market



satisfying the statutory requirements. This list is not exclusive, but represents features



likely to be present in many markets across the nation.



a. Evidence of bilateral transactions reflects a competitive

wholesale market.



The presence of a robust bilateral market for energy trades should be prima facie



evidence that a competitive market within the meaning of the statute exists. As





73

E.g., California Indep. Sys. Oper. Corp., 112 FERC ¶ 61,009 (2005) (addressing Order No. 2003

compliance). The CAISO filed its Order No. 2006 compliance filing on February 20, 2006 in Docket No.

ER06-629.

74

Pacific Gas and Electric Co., 100 FERC ¶ 61,156 (2002) (approving terms and conditions of WDATs),

subsequent history omitted.

75

E.g., Southern California Edison Co., 113 FERC ¶ 61,334 (2005) (addressing SCE‟s Order No. 2003

compliance); Southern California Edison Co., 114 FERC ¶ 63,016 (2006) (addressing all three utilities‟

compliance with Order No. 2006 regarding their WDATs). Note that Large Generators typically only

interconnect to SCE‟s distribution system; thus, only SCE has been required to amend its WDAT to reflect

Order No. 2003.





42

illustrated on Table 1 of the 2004 Markets Report, day ahead bilateral markets exist in all



regions of the country.76 For example, in the Southwest and Pacific Northwest, bilateral



markets have existed for many years, and large volumes of energy are traded. Fairly



deep and liquid bilateral spot markets exist at 10 to 12 locations, both inside and outside



California.77 There are liquid trading points in both the Northwest (mid-Columbia for



physical trades and California-Oregon Border for both physical and financial trades) and



the Southwest (Palo Verde, Four Corners, and Mead), with the most liquid points being



mid-Columbia and Palo Verde.78 NP-15 and SP-15 in California are among the most



heavily traded bilateral markets in the country.79 Confidence in Western bilateral



markets is reflected in the length of contract terms available, in some cases as long as 12



years.80



b. Opportunities to participate in competitive procurements

reflect a competitive wholesale market.



The Commission asks (NOPR, ¶ 21) whether the requirement of section



210(m)(B)(ii) should be deemed met if an organized power procurement process exists.



EEI submits that power procurement through a competitive solicitation process in which



a QF can participate directly or indirectly, such as through an aggregator, and where



transactions result via arms-length negotiations should be treated by the Commission as



one means to meet the requirements of the statute. 81 To the extent that a competitive



solicitation process results in acquisition of power from affiliates of the soliciting entity,



EEI believes that the process would meet the statutory requirements as long as the

76

2004 Markets Report at 51. See also Exhibit C.

77

Id. at 51.

78

Id. at 7, 53.

79

Id. at 52.

80

Id. at 53.

81

Fundamentally, if there are a variety of potential buyers in a given market, that market should be deemed

competitive.





43

Edgar82 standards are met. If there are solicitations for power to be delivered over short-



term and long-term periods, EEI believes that the Commission should conclude that a



market exists for both short-term and long-term sales under section 210(m)(1)(B)(ii).



A growing number of states authorize or require different types of competitive



power procurement programs.83 For example, electric public utilities in Oregon,



Washington and Utah are required to participate in competitive bidding processes for



resource procurement.84 QFs in each of these states are eligible to participate in Requests



for Proposals that these utilities issue to secure supply-side resources. In January 2006,



Oklahoma became the latest state to promulgate rules requiring electric public utilities



providing retail service in the state to procure long-term electric generation through



competitive bidding.85 By establishing specific requirements to ensure their electric



utilities utilize a fair, open and transparent bidding process, such states have clearly,



opened the marketplace to all participants, including QFs, and provided a meaningful



opportunity for potential QFs to sell their output on both a long-term and short-term



basis.







82

Boston Edison Co. Re: Edgar Electric Energy Co., 55 FERC ¶ 61,382 at 62,167 (1991) (Edgar). The

Edgar standards require generally that: (1) a competitive solicitation process was designed and

implemented without undue preference for an affiliate; (2) the analysis of bids did not favor affiliates,

particularly with respect to nonprice factors; and (3) the affiliate was selected based on some reasonable

combination of price and non-price factors.

83

According to the Electric Power Supply Association, the following states have either legislated or

regulatorily-required competitive procurement mandates: Arizona, California, Colorado, Connecticut,

District of Columbia, Georgia, Illinois, Maine, Maryland, Massachusetts, New Jersey, Ohio, Oklahoma,

Oregon, Pennsylvania, Rhode Island, Utah, Virginia and Washington.

84

Oregon Order No. 91-1383; Washington WAC 480-107,

http://www.wutc.wa.gov/webdocs.nsf/0/575e2bdaf5fb7a958825647600003b3c?OpenDocumentand; and

Utah Energy Resource Procurement Act, Utah Code Ann. 54-17-101,

http://www.le.state.ut.us/~2005/htmdoc/sbillhtm/SB0026S01.htm.

85

See Oklahoma Administrative Code (“OAC”) 165:35-34-1 et seq. (“Competitive Procurement Rules”).

The intent of the Oklahoma Corporation Commission in promulgating the rules was “to create an open,

transparent, fair and nondiscriminatory competitive bidding process for the utility to meet its needs.” The

Rules establish specific requirements to ensure that bidders affiliated with the utility are given no

competitive advantage in the bidding and evaluation process.





44

Each such state-sanctioned process that is open to QFs should be recognized as



prima facie evidence that QFs have access to “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 term sales…” within



the meaning of section 210(m)(1)(B)(ii) and within the meaning of section 210(m)(1)(C).



Given the nature and number of competitive power procurements, it is evident



that there are vibrant, robust wholesale markets for energy and capacity throughout the



country. For example, within the CAISO, the number of RFPs, the variety of resources



sought, and the varying durations of contracts offered demonstrate that a robust bilateral



market exists for both short-term and long-term sales of electricity and capacity.



Moreover, as in many other states, utilities in California are under a statutory mandate –



the Renewables Portfolio Standard (“RPS”) statute – to procure renewable power.



Accordingly, even in the absence of PURPA‟s mandatory purchase obligation, California



utilities will remain obligated under state law to buy power from facilities that would for



the most part qualify as QFs under PURPA.



Substantial opportunities for QFs in California have been seen in practice. Since



August, 2002, Southern California Edison (“SCE”) has issued numerous RFPs that



included provisions for QF resources. For example, SCE issued an RFP in 2005 that



specifically requested offers from interested parties for dispatchable and non-dispatchable



QF resources. SCE also issued three RFPs pursuant to the state RPS statute between



2002 and 2005 that sought only renewable resources. The delivery periods sought in



these various RFPs ranged from 56 to 240 months.









45

LSEs in the SPP also actively solicit power supplies using competitive bidding



procedures. Oklahoma Gas and Electric Company (“OG&E”) is aware of 21



solicitations, issued in the last two years by Entergy and LSEs within the SPP, seeking



more than 5,000 MW of long-term energy and capacity products. This is not an



exhaustive list of recent solicitations in the SPP. Because many load serving entities



solicit power suppliers through private requests for bids, there are many more



opportunities for a potential QF to sell its output than are captured by the 21 solicitations



of which OG&E is aware. In addition, there is a significant volume of short-term



transactions within the SPP. This is confirmed by the Electronic Quarterly Reports of



independent power producers located in the SPP.



c. Access to trading hubs reflects a competitive wholesale

market.



Where a utility can provide a QF with OATT transmission access to a market that



meets the standard in 210(m)(1)(A), or to another transmission provider that can



subsequently provide access to such a market, that QF should be considered to have



access to a market of “comparable quality” pursuant to section 210(m)(1)(C).



Consequently, being able to reach such a market with an open access tariff should suffice,



since reaching that actual “Day 2” market is clearly “comparable” within the meaning of



section 210(m)(1)(C). EEI recommends that the Commission consider establishing a



rebuttable presumption that in the case of any utility directly interconnected with a Day 2



market or a market that the Commission has found to be of comparable quality to a Day 2



market, if that utility has an OATT on file with the Commission, a QF within the utility‟s



service territory would have access to a market meeting the requirement of section



210(m)(1)(C).







46

In a similar vein, if the QF has OATT transmission access to a liquid trading



location and day-ahead as well as long-term sales of financial and physical energy are



available, then the Commission should conclude that a market exists for short-term and



long-term sales of capacity and energy. Using the West region as an example, QFs that



are able to reach established trading hubs such as the California-Oregon Border, Mid-



Columbia, Palo Verde, Mona, Four Corners, South of Path 15, North of Path 15, Mead,



or Marketplace, should be deemed to have access to the statutorily required markets.



d. Actual QF sales are evidence of a competitive wholesale

market.



Where QFs have made or are making wholesale sales into the market, the



Commission should terminate the mandatory purchase requirement. Over the past



several years and up to the present, QFs in the West with PURPA mandated short-term



power purchase agreements also have made wholesale market transactions either at the



point of interconnection or at a number of market hubs in the Western Electricity



Coordinating Council ("WECC"). These include QFs that have represented they have,



currently are, or could sell into the Mid-Columbia, California Oregon Border and Mona



hubs. In many cases, because of the WECC requirements for wholesale market



transactions, the QF will schedule the entire amount of its generation to market or



schedule a fixed block to market and sell any excess over the market sale to its PURPA-



mandated utility purchaser on a non-firm basis.86









86

Non-firm utility purchases occur because while the electric utility is obligated to purchase pursuant to

PURPA, the QF is not obligated to schedule or deliver. The net effect of this imbalance is that the utility

recipient of this non-firm energy gains only limited value because the QF output cannot be forecasted and

included in utility resource planning, while the utility is obligated to incur the additional expense of

integrating the QF energy into its system.





47

Similarly, QFs in service territories adjacent to Day 2 RTO markets, like Carolina



Power & Light (“CP&L”), already are taking advantage of access to competitive short-



term and long-term energy and capacity wholesale markets. CP&L is adjacent to and



directly interconnected with PJM. As noted in Progress Energy‟s comments in this



proceeding, a wood-burning QF (Craven County, LLC) that is interconnected with



CP&L recently notified CP&L that it will no longer sell its capacity and energy to CP&L



as a QF.87 Instead, the QF has requested transmission and interconnection service



pursuant to CP&L‟s OATT in order to sell its capacity and energy into the PJM market.



In cases such as these, where there is clear evidence of the ability of QFs to sell



their power at wholesale on the open market, there is no justification for continuing the



mandatory purchase requirement.



5. The Commission should not make a generic exemption for any

QFs from the termination of the mandatory purchase requirement.



The Commission requested comments on whether the purchase obligation should



be retained for small renewable projects (or other categories of QFs) because they



interconnect at the distribution level and thus may not be deemed to have



“nondiscriminatory access” to the transmission system. (NOPR, ¶ 20.) The



Commission‟s concern over whether QFs interconnecting at the distribution level have



“nondiscriminatory access” to transmission services is misplaced. QFs have the same



right to request FERC jurisdictional transmission service regardless of whether they



interconnect at the transmission or distribution level. In addition, QFs may take



advantage of the interconnection provisions of section 210 of the Federal Power Act, 16



U.S.C. § 824i.





87

See Comments of Progress Energy, Inc., filed in Docket No. RM06-10, at 6.





48

The Commission has long required utilities to provide FERC-jurisdictional



transmission service over local distribution facilities. In Tex-La Electric Cooperative of



Texas, Inc., the Commission rejected an argument that the Commission lacked authority



to order the transmission services requested by Tex-La because some of the delivery



points included facilities that the utility regarded as local distribution facilities.88 The



Commission found that it had the authority to order transmission services regardless of



any local distribution (as opposed to transmission) function of the facilities involved.



The Commission concluded that “[t]he fact . . . that transmission services may encompass



the use of facilities that in other contexts would be classified as distribution facilities has



no effect on the Commission‟s authority to order transmission services under 211.”89 In



line with Tex-La, in Order 888, FERC decided that facilities used for wholesale sales,



whether labeled “transmission,” “distribution,” or “local distribution” are subject to the



OATT.90 On appeal, the D.C. Circuit agreed with FERC as to the scope of its jurisdiction



over facilities used for wholesale “transmissions.” The court concluded that “FERC‟s



assertion of jurisdiction over all wholesale transmissions, regardless of the nature of the



facility, is clearly within the scope of its statutory authority. Moreover, various cases



support the proposition that FERC regulates all aspects of wholesale transactions.”91 The



D.C. Circuit, in Detroit Edison Co.v. FERC, 334 F.3d 48, 51 (D.C. Cir. 2003) further



explained that “when a local distribution facility is used in a wholesale transaction, FERC







88

Tex-La Electric Cooperative of Texas, Inc., 69 FERC ¶ 61,269 (1994)(“Tex-La Electric Cooperative of

Texas, Inc.”).

89

69 FERC ¶ 61,269 at 62,206, citing Tex-La Electric Cooperative of Texas, Inc., 67 FERC ¶ 61,019

(1994).

90

Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by

Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888,

61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ¶ 31,036 at 31,969 (1996).

91

Transmission Access Policy Study Group v. FERC, 225 F. 3rd 667, 696 (D.C. Cir. 2000).





49

has jurisdiction over that transaction pursuant to its wholesale jurisdiction under FPA §



201(b)(1).”92



In sum, the Commission has jurisdiction over all interstate transmission service



and over all wholesale sales service and over all transactions relating thereto, regardless



of the classification of the facilities used for these services. This determination is



reflected in section 1.11 of the pro forma OATT, which makes it clear that a generator



interconnected at the distribution level is entitled to request transmission service under



the OATT.



Because all QFs are eligible to receive transmission service under the pro forma



OATT, regardless of the level at which they are interconnected, there is no legal,



technical or policy justification for making any generic exemption from the mandatory



purchase termination provisions of PURPA section 210(m).



Moreover, as a matter of statutory construction, Congress has not given the



Commission the authority to exempt QFs from the provisions of section 210(m).93 If



relief for certain categories of QFs is to be provided, it must be provided on a case-by-



case basis as the result of a specific finding that these QFs lack “nondiscriminatory



access” to markets otherwise meeting the statutory tests under Section 210(m)(1).









92

See also, Soyland Power Cooperative, Inc., 102 FERC ¶ 61,244 (2003), where FERC confirmed that

Order No. 888 covers all facilities used for wholesale transactions, ruling that Soyland was required to file

an OATT that covers transmission over its distribution facilities.

93

Other provisions of EPAct 2005 demonstrate that Congress was well aware of how to direct that certain

entities be exempt from statutory requirements. See, e.g., the provisions of new FPA section 211A

exempting certain municipal utilities from the open access requirements.





50

6. The Commission should clarify its interpretation of the

application of the savings clause in section 210(m)(6).



a. The term “obligation” refers to fully-defined legal

arrangements.



Section 210(m)(1) provides, in part, that “[a]fter the date of enactment …, no



electric utility shall be required to enter into a new contract or obligation to purchase



electric energy from a [QF]” if certain conditions have been met. (Emphasis supplied.)



The terms “new contract or obligation” are used in section 210(m)(1) to distinguish



power purchase arrangements arising after the date of enactment from existing contracts



or obligations which, under the savings clause in PURPA section 210(m)(6), are not



affected by the termination of the mandatory purchase requirement. This savings clause



applies by its terms to preserve the “rights or remedies of any party under any contract



or obligation, in effect or pending approval before the appropriate State regulatory



authority or non-regulated electric utility on the date of enactment of this subsection, to



purchase electric energy or capacity … under this Act ….” (Emphasis supplied.)



In the NOPR, the Commission tentatively has concluded that QF status alone does



not create an existing obligation protected under section 210(m)(6) and that a “contract”



either has to have been in effect as of the date of enactment or pending approval before a



state regulatory authority as of the date of enactment in order to be protected. The



Commission has requested comments on whether further or different language and/or



clarification should be incorporated into the final regulations (NOPR, ¶ 49.)



The Commission‟s tentative conclusion is correct as far as it goes but EEI urges



the Commission to clarify further the meaning of the term “obligation” in order to avoid



confusion and dispute over the correct meaning of this key term.









51

It is clear from the plain meaning of the language Congress used, the legislative



history and generally used canons of statutory construction that the terms “contract” and



“obligation” contained in sections 210(m)(1) and 210(m)(6) are used to describe a



writing that completely memorializes all material terms and conditions of a specific



transaction for the purchase and sale of energy and/or capacity between two or



more counterparties. The savings clause provisions thus operate to preserve fully



defined legal arrangements that establish the rights and responsibilities of named parties,



not an inchoate bundle of rights that may or may not eventually ripen into a “contract” or



“obligation” as those terms are generally understood.



As the legislative history demonstrates, Congress viewed the terms “contract” and



“obligation” as essentially synonymous when used in the PURPA section 210(m)(6)



savings clause. The proposal to terminate the mandatory purchase and sale requirements



under PURPA section 210 was under consideration by Congress for a number of years.



In virtually every legislative formulation, the termination of the mandatory purchase



requirement was coupled with legislative language to preserve existing contracts.94



The “contract or obligation” language in the savings clause as enacted was



contained in substantively the same form in the version of the energy legislation reported



by the House Energy and Commerce Committee on April 8, 2003.95 The Committee



Report describes the provisions of the legislation to prospectively terminate the









94

See, e.g., Section 3 of H.R. 381, 107th Cong. (2001); Section 4 of S. 552, 107 th Cong. (2001); Section

132 of H.R. 3406, 107th Cong. (2001); section 244 of H.R. 4, 107 th Cong. (2002); Section 3 of H.R. 1341,

108th Cong. (2003); Section 4 of S. 688, 108 th Cong.; Section 215 of S. 475, 108th Cong. (2003).

95

See H. Rep. No. 108-65, Part I, Report of the Committee on Energy and Commerce to Accompany H.R.

1644 , (“2003 House Report”)., at 85 (April 8, 2003).





52

mandatory purchase and sale requirements, and states that the legislation “protects



existing contracts or certain pending contracts.”96



After the passage of the energy legislation in the House in 2003, negotiations



continued on the PURPA mandatory purchase repeal provision and other PURPA reform



language. The resulting compromise language was contained in an amendment offered to



the Senate energy bill in July 2003.97 The amendment contained the identical savings



clause language ultimately enacted into law, describing a contract or obligation in effect



or pending approval before a State regulatory body. This formulation of the savings



clause and PURPA reform language was carried forward into the Conference Report on



the energy legislation in 2003.98 It was also included in the energy policy legislation



adopted by the House of Representatives in 2004.99



The Energy and Commerce Committee‟s 2005 report on the legislation that



ultimately became EPAct 2005 uses the identical language to describe coverage of the



savings clause ultimately enacted. The Report states that section 1253, inter alia,



“protects existing contracts or certain pending contracts.”100



The intent of Congress throughout the PURPA reform legislative process was to



protect existing contracts. The “contract or obligation” language of the savings clause



has been used consistently and interpreted consistently to refer to existing contracts. At a



minimum, then, an “obligation” within the meaning of the savings clause must mean a



requirement already existing on the date of enactment which expressly identifies the





96

2003 House Report at 174.

97

See Remarks of Senator Thomas discussing the compromise PURPA reform provisions contained in

Senate Amendment 1412 to S. 14, the Energy Policy Act of 2003, 149 Cong. Rec. S9995-6 (July 28, 2003).

98

See Section 1253 of the Conference Report on H.R. 6, H.Rep. No. 108-375 (November 18, 2003).

99

See Section 1253 of H.R. 4503, the Energy Policy Act of 2004, as passed by the House on June 15, 2004.

100

H. Rep. 109-215, Part 1, Report of the Committee on Energy and Commerce to Accompany H.R. 1640,

(“2005 House Report”) at 264 (July 29, 2005).





53

specific terms, rates and conditions for an electric utility to purchase electricity from a



QF.



Further support for this reading that an obligation is essentially synonymous with



a contract is found in the Commission‟s existing PURPA regulations. The regulations in



18 C.F.R. § 292.304(b)(5) address rates over the specific term of a “contract or legally



enforceable obligation.” 18 C.F.R. § 292.304(d) applies to purchases that are made “as



available” or pursuant to a “legally enforceable obligation.” An “as available” purchase



is one made without a legal obligation, i.e., in most instances, without a contract.



Alternatively, the “use of the term „legally enforceable obligation‟ is intended to prevent



a utility from circumventing the requirement that provides capacity credit for an eligible



qualifying facility merely by refusing to enter into a contract with the qualifying



facility.”101 In this context, a “legally enforceable obligation” clearly is intended to



substitute for a contract.



Congress was aware of this background when it used the term “obligation” in the



savings clause. 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. 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.



In sum, if an executed contract for the sale of QF power was already approved by



the state regulatory authority or was pending approval by the state regulatory authority on





101

Small Power Production and Cogeneration Facilities; Regulations Implementing Section 210 of the

Public Utility Regulatory Policies Act of 1978, Reg-Preamble, FERC Stat. & Regs. 1977-1981 ¶ 30,128

(April 9, 1980) at 30,880.







54

the date of enactment, that specific contract is subject to the savings clause. Similarly, an



obligation to purchase QF power that fully defines the commitments undertaken by each



party and sets forth all of the relevant rates, terms and conditions upon which sales are to



be made, but which will not result in a contract until final regulatory approval is given,



should be treated as an “obligation” within the meaning of the savings clause if the



proceeding to obtain regulatory approval was pending on the date of enactment.



b. The savings clause does not apply to a generalized obligation

under PURPA for the purchase of power from QFs.



Prior to its amendment, PURPA section 210 generally imposed an obligation on



all electric utilities to purchase the power generated by QFs at avoided cost rates.



PURPA section 210(m)(1), as added by EPAct 2005, expressly terminates this



“obligation to purchase” electricity from a QF if the QF has access to markets described



in the statute in which to sell its power.



An existing obligation that is preserved under the savings clause cannot mean the



obligation all utilities had to purchase power from QFs under PURPA before it was



amended. Such an interpretation would render the amendment to PURPA section



210(m)(1) terminating the mandatory purchase requirement meaningless. Nor does the



mere fact that a QF has self-certified its status before August 8, 2005, automatically



create an obligation that was in effect prior to the termination of the mandatory purchase



requirement. Had Congress wanted to make any QF that self-certified before the date of



enactment eligible to take advantage of the “grandfather” clause, it could have done so.102







102

Congress did make QF self-certification the triggering event for the application of the grandfather clause

contained in PURPA section 210(n)(2). That section grandfathers any cogeneration QF that “(A) was a

qualifying cogeneration facility on the date of enactment [of EPAct 05], or (B) had filed with the

Commission a notice of self-certification, self-recertification or an application for Commission certification





55

It did not, and the language that Congress did use makes it clear that any self-certified QF



must be a party to a contract or obligation existing on the date of enactment, or pending



regulatory approval, or the savings clause will not apply.



As discussed above, 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; that 2) define all the relevant and material rates,



terms and conditions of the sales; and that 3) were in effect or pending regulatory



approval on August 8, 2005. Any other interpretation would frustrate the intent of



Congress in adopting the mandatory purchase termination provisions of EPAct 2005.



c. QFs having expiring contracts are not entitled to “roll-

over” contracts under section 210(m).



As the Commission tentatively has concluded, QF status alone is not



determinative under 210(m)(1) or the grandfather clause contained in section 210(m)(6).



(NOPR, ¶ 49). The language contained in these sections refers to existing contracts or



obligations, not existing QFs. As noted above and by the Commission, had Congress



intended to grandfather existing QFs, which it did with respect to the new cogeneration



criteria required under section 210(n), it knew what language to adopt in order to



accomplish this objective, but it chose not to do so in section 210(m).



When an existing contract expires or is terminated pursuant to its terms, it is no



longer a contract within the meaning of sections 210(m)(1) and 210(m)(6). Because QF



status alone confers no special privileges under the language Congress used, an existing



QF, without a contract or binding obligation in effect or pending state regulatory approval





under 18 C.F.R. 292.207 prior to the date on which the Commission issues the final rule required by

paragraph (1) [establishing criteria applicable to new qualifying cogenerators.]”







56

as of August 8, 2005, is not entitled to the mandatory purchase obligation under section



210 in those markets meeting the standards for relief. EEI urges the Commission to



clarify this point further in its final regulations.



d. The effective date of the termination of the mandatory

purchase requirement is the date of enactment (August 8,

2005).



The Commission has proposed to find that “if a contract is entered into after



August 8, 2005, the date of enactment, but before the Commission has determined that an



electric utility is entitled to relief from the obligation to purchase from a QF, 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).” (NOPR, ¶ 32). The NOPR cites no statutory authority



supporting this sweeping interpretation. In fact, the statute by its terms makes it clear



that contracts signed after August 8, 2005, the date of enactment, are not entitled to be



grandfathered from the provisions of 210(m)(1).



Section 210(m)(6) in part provides that “[n]othing in this subsection affects the



rights or remedies of any party under any contract or obligation, in effect or pending



approval before the appropriate State regulatory authority or non-regulated electric



utility on the date of enactment of this subsection. . . .” (Emphasis supplied.) Thus,



contracts that were in effect on August 8, 2005, or were pending before the appropriate



State regulatory body on that date for approval, are protected from the lifting of the



mandatory purchase obligation in section 210(m)(1). Contracts that were not in effect or



pending approval on that date clearly are not.



EEI appreciates that some QFs will argue that the statute is harsh or unfair.



However, the statutory language that Congress ultimately adopted was publicly under









57

consideration as early as July 2003, and passed both houses of Congress in its current



form several times. Industry participants were well aware of the language in the statute



and had ample opportunity to try to modify it. In addition, it is not unusual for Congress



to choose to grandfather only those projects that have reached a certain stage as of the



date of enactment of a statute to avoid precipitating a “gold rush” of new contracts or



projects trying to beat a delayed deadline. Because the language of the statute is clear



and unambiguous, EEI urges the Commission to incorporate this statutory language into



its regulations, rather than the proposal in the NOPR which is contrary to the text of



section 210(m).



7. The Commission should clarify the procedures for

utilities requesting termination of the mandatory purchase

requirement on a “service territory-wide” basis.



Section 210(m)(3) of PURPA provides that an electric utility may file an



application with the Commission for relief from the mandatory purchase obligation on a



“service territory-wide” basis. The Commission‟s NOPR to implement section



210(m)(3) adopts the statutory provision verbatim. However, the term “service territory-



wide” is not defined in PURPA or in the Commission‟s proposed implementing



regulations. “Service territory-wide” will generally be synonymous with the control area



operated by the applicant. However, in the limited circumstances where the electric



utility applicant operates multiple control areas spanning multiple states, EEI seeks



clarification that the Commission will interpret “service territory” to be the particular



control area identified in the application itself. EEI believes the above interpretation is



consistent with Congressional intent that an electric utility be relieved of the mandatory



purchase obligation upon a Commission finding that certain market conditions exist. The









58

factual determination of whether potentially affected QFs have sufficient



nondiscriminatory access to off-system markets is best applied at the local control area



level where the QFs are interconnected.



8. The Commission should incorporate the statutory cost

recovery language in section 210(m)(7) into its regulations.



Under established legal precedent, states are prohibited from denying utilities the



opportunity to recover Commission-approved wholesale costs, including costs associated



with contracts mandated by PURPA. Congress largely ratified and codified established



legal precedent requiring recovery of costs associated with PURPA mandated contracts.



The Commission should adopt the statutory language into its regulations and provide for



case-by-case relief where required.



The Supremacy Clause of the U.S. Constitution makes federal law the “supreme



law of the land.” 103 This supremacy extends not only to federal statutes themselves but



also to the actions of a federal agency acting within the scope of its congressionally



delegated authority. Such an agency has the power to preempt state regulation and render



unenforceable state or local laws which are otherwise not consistent with federal law.104



The Supremacy Clause requires that a state agency‟s “efforts to regulate



commerce must fall when they conflict with or interfere with federal authority over the



same activity.”105 In Mississippi Power, the Supreme Court held that “[t]he Supremacy



Clause compels the [state commission] to permit [appellant] to recover as a reasonable









103

U.S. Const. Art. VI, Cl. 2.

104

Louisiana Public Service Comm. v. FCC, 476 U.S. 355, 368-69 (1986).

105

Chicago & North Western Transportation. Co. v. Kalo Brick & Tile Co., 450 U.S. 311, 318-319 (1981).





59

operating expense costs incurred as a result of paying a FERC-determined wholesale rate



for a FERC-mandated allocation of power.”106



FERC has authority over the “transmission of electric energy in interstate



commerce and the sale of such energy at wholesale in interstate commerce….”107 The



term “sale of electric energy at wholesale” means a sale of electric energy to any person



for resale.108 The sales of electricity from QFs to the purchasing utility are sales for



resale within FERC‟s exclusive jurisdiction to regulate. While the states implement some



provisions of PURPA, FERC has retained its jurisdiction over PURPA wholesale sales



and has the ability to enforce PURPA and its regulations against the states.109



Section 210(b) of PURPA requires that the rates for purchases from QFs be “just



and reasonable to the electric consumers of the electric utility and in the public



interest.”110 FERC‟s implementing regulations provide that the rates an electric utility



pays a QF shall be just, reasonable, in the public interest and not discriminatory.111 They



also provide that an electric utility is not obligated to pay more than its “avoided costs”



for purchases from a QF and that an avoided cost rate for QF purchases will be



considered to be just, reasonable, in the public interest and not discriminatory.112 The



regulations further require that purchases shall be at the utility‟s avoided cost rate. 113



Thus, as a matter of law, FERC has found QF rates to be “just and reasonable and in the









106

Mississippi Power & Light Co.v. Mississippi Ex Rel. Moore, 487 U.S. 354, 373 (1988)(“Mississippi

Power”).

107

Section 201(b) of the Federal Power Act, 16 U.S.C. 824(b)(1).

108

16 U.S.C. § 824(d).

109

16 U.S.C. § 824a-3(h).

110

16 U.S.C. § 824a-3(b).

111

18 C.F.R. § 292.304(a)(1).

112

18 C.F.R. §§ 292.304(a)(2) and 292.304(b)(2). .

113

18 C.F.R. § 292.304(b)(4).





60

public interest” if they equal a utility‟s avoided costs and it has required purchasing



utilities to pay QFs this avoided cost rate.



Any effort by a state to reduce a rate deemed just and reasonable by FERC, by



restricting a utility‟s ability to recover these costs and thus “trapping” them would



conflict with FERC‟s just and reasonable rate determination. Therefore, such state action



cannot stand.114 To conclude otherwise would allow states to undermine FERC‟s



exclusive jurisdiction over wholesale transactions.



FERC has delegated to the states the ability to define avoided costs for utilities



within the State, 115 but states may not exercise utility-type regulation of QF rates,



including taking any action that effectively would alter the avoided cost rate that FERC



has determined to be just and reasonable or would deny utilities the opportunity to



recover PURPA costs.



In the leading decision on this point, the U.S. Court of Appeals for the Third



Circuit ruled that a state could not modify a long-term contract between a QF and an



electric utility, nor could it deny a utility the opportunity to recover PURPA costs.116



Freehold Cogeneration Associates, L.P. (“Freehold”) sought a declaratory judgment from



the District Court of New Jersey that the Board of Regulatory Commissioners of the State



of New Jersey (“BRC”) was preempted by PURPA from modifying the terms of a



previously-approved power purchase agreement between Freehold and Jersey Central



Power and Light Company (“JCP&L”), the electric utility. The court denied Freehold‟s



motion for summary judgment and granted the motion to dismiss by the electric utility



114

See, e.g., Nantahala Power & Light Co., et al. v. Thornburg, 476 U.S. 953 (1986) and Mississippi

Power & Light Co. v. Mississippi Ex Rel. Moore, 487 U.S. 354 (1988).

115

18 C.F.R. § 292.304.

116

Freehold Cogeneration Associates v. Board. Regulatory Commissioners of NJ, 44 F.3d 1178, 1194 (3rd

Cir. 1995), cert. denied, 116 S. Ct. 68 (1995).





61

and the BRC. The Third Circuit held that the district court erred in dismissing Freehold‟s



complaint and ruled that PURPA preempted the BRC order. The Court found that „[a]



state law may not only be preempted expressly by Congress, but whenever it conflicts



with federal law.”117 The court further held that “[u]nder the Supremacy Clause of the



United State Constitution, a federal agency acting within the scope of its congressionally



delegated authority has the power to preempt state regulation and render unenforceable



state or local laws which are otherwise not inconsistent with federal law.”118 The court



concluded that “[b]ased on the overall scheme of PURPA … we hold that Congress



attempted to exempt qualified cogenerators from state and federal utility rate



regulations”119 and that “once the BRC approved the power purchase agreement between



Freehold and JCP&L on the ground that the rates were consistent with avoided cost, just,



reasonably, and prudentially incurred, any action or order by the BRC to reconsider its



approval or to deny the passage of those rates to JCP&L’s consumers under



purported state authority was preempted by federal law.”120



A State‟s failure to provide for full utility recovery of QF costs would constitute



the same “after the fact” utility regulation of QF contracts preempted by PURPA. We



urge the Commission to adopt in its regulations the explicit language Congress has used



to ensure recovery of PURPA costs and to provide for case-by-case enforcement actions



if necessary to implement Congress‟ intent to require full cost recovery.









117

Id. at 1190.

118

Id.

119

Id. at 1192.

120

Id. at 1194 (Emphasis supplied).





62

V. CONCLUSION



Congress adopted legislation that provides for the termination of an electric



utility‟s obligation to purchase electricity from QFs after August 8, 2005 if certain



conditions are met. The Commission has proposed to find that those conditions are met



in the four RTO/ISOs currently operating “Day 2” markets – Midwest ISO, PJM, ISO-



NE and NYISO. The evidence amply supports the Commission‟s proposal.



Similarly, the Commission proposes to conclude that nondiscriminatory access to



markets is available through open access transmission tariffs that comply with the



requirements of Order 888. This, too, is a fully justified position, and should be applied



to all ISOs, RTOs, and public utilities with OATT on file with and approved by the



Commission. To the extent that a QF believes that it is not afforded access under such an



OATT, it will appropriately be up to the QF to demonstrate that it lacks



nondiscriminatory access.



Finally, the Commission has correctly looked to evidence of competitive power



procurement as an appropriate indicator of the availability of wholesale markets in which



QFs may sell electricity and capacity on a long-term basis. The nature and number of



competitive procurements throughout the country, and the trend of more and more states



to require power procurement through competitive processes, fully supports the use of



this measure to identify markets in which QFs have the ability to sell their power. The



Commission also should consider other indicia of such competitive wholesale markets,









63

including evidence of bilateral transactions, access to trading hubs, and actual QF sales



that already are occurring in markets around the nation.



Respectfully submitted,





/s/: Randall E. Davis

Randall E. Davis

Stuntz, Davis & Staffier, P.C

555 Eleventh Street, N.W.

Suite 550

Washington, D.C. 20004

rdavis@sdsatty.com



Counsel to the Edison Electric Institute









February 27, 2006









64

EXHIBIT A





CHARACTERISTICS OF “DAY 2” RTOs

(PJM; NYISO; ISO-NE; MIDWEST ISO)

PJM RTO



PJM RTO FERC Tariff Reference Other Reference

1. Transmission Access

- Open Access Tariff PJM OATT

administered by RTO

- Regional transmission PJM OATT - Attachment K PJM Manual M-10 – Pre-

scheduling Scheduling Operations

PJM OATT - Attachment Q PJM Manual M-11 –

Scheduling Operations

PJM Manual M-12–

Dispatching Operations

PJM Manual M-04 - OASIS

Operation

PJM Operating Agreement –

Schedule 1

PJM Manual M-02 –

Transmission Service

Request, Section 1

- Regional transmission PJM OATT: Part IV PJM M-14B – Manual for

planning Generation and Transmission

Interconnection Planning

PJM OATT: Attachment U PJM M-14C – Manual for

Generation and Transmission

Interconnection Facility

Construction

PJM Transmission Owners

Agreement, Article 7.1

PJM Operating Agreement,

Schedule 6

Interstate Strategies for

Transmission Planning and

Expansion

Memorandum of

Understanding between PJM

Interconnection, LLC and Mid-

Atlantic Conference of

Regulatory Utility

Commissions

Interstate Strategies for

Transmission Planning and

Expansion

Expansions and

enhancements as parts of the

Regional Transmission

Expansion Plan PJM

(Transmission Owners

Agreement, Article 7.1)

- Regional interconnection PJM OATT, Section 1.14F: PJM M-14A – Manual for

process Interconnection Queue Generation and Transmission

Interconnection Process

PJM OATT, Subpart G – Small PJM M-14B – Manual for

Generation Interconnection Generation and Transmission

Procedure Manual Interconnection Planning







1

PJM Operating Agreement –

Schedule 6



- Independence

- Independent Board PJM OATT – Attachment M PJM Bylaws

PJM Operating Agreement

PJM Members Handbook

PJM Committee Handbook

PJM Committees



- RTO Services Tariff Only PJM OATT N/A

- Market Tariff administered Only PJM OATT N/A

by RTO

2. RTO Markets

- Day Ahead market with PJM OATT - Attachment K, PJM Manual M-28 – Operating

transparent hourly energy and Section 1.10.1A Agreement Accounting,

congestion price Section 16

PJM Operating Agreement –

Schedule 1

- Real time market with PJM OATT - Attachment K, PJM Manual M-28 – Operating

transparent hourly energy and Section 1.3.30A & B, Section 2 Agreement Accounting,

congestion price Section 16

PJM Operating Agreement –

Schedule 1

PJM Manual M-11 –

Scheduling Operations

- Ancillary Service market PJM OATT, Section 3 – PJM Operating Agreement,

Ancillary Services Section 9.5 – Ancillary

Services

PJM OATT - Attachment M PJM Manual M-11 –

(PJM Market Monitoring Plan) Scheduling Operations,

Section 2

PJM Manual M-10 – Pre-

Scheduling Operations,

Section 4

PJM Manual M-12 –

Dispatching Operations,

Section 4

PJM Manual M-28 – Operating

Agreement Accounting,

Section 3

- Operating reserve market PJM OATT, Section 3 – PJM Manual M-11 –

Ancillary Services Scheduling Operations,

Section 2

PJM OATT - Attachment M PJM Manual M-12 –

(PJM Market Monitoring Plan) Dispatching Operations,

Section 4

PJM Operating Agreement,

Section 9.5 – Ancillary

Services



- Regulation Service market PJM OATT, Section 3 – PJM Manual M-11 –

Ancillary Services Scheduling Operations,

Section 2

PJM Manual M-10 – Pre-





2

Scheduling Operations,

Section

PJM Manual M-12 –

Dispatching Operations,

Section 4



- Financial transmission rights PJM OATT – Attachment K PJM Manual M-06 – Financial

Transmission Rights

PJM OATT – Attachment Q PJM Operating Agreement –

Schedule 1

PJM OATT – Annex 1 PJM Manuals M-11 –

Scheduling Operations,

Section 2

PJM Manuals M-12 –

Dispatching Operations,

Attachment B

PJM Manual M-02 –

Transmission Service

Requests, Sections 1 and 2





- Capacity or resource PJM OATT - Section I, 1.3D Reliability Assurance

obligations & market Agreement - Article 7 and

Schedules 4-8

PJM Manual M-20 – Reserve

Requirements

PJM Manual M-17 – Capacity

Obligations: Section 4 –

Updating Capacity Data

PJM Operating Agreement -

Schedule 11

PJM Manual M-21 – Rules

and Procedures for

Determining of Generating

Capacity – Section 1 and

Appendix A



3. Longer term trading &

contracting facilitated by

RTO markets

- Bilateral online physical and PJM OATT – Attachment K See Table 2

financial trading of power

Appendix, Section 1.10



- 5 PJM HUBs (liquid trading PJM OATT – Attachment K

points)

Appendix, Section 7

- 5 MISO hubs PJM OATT – Attachment K

- Many market participants PJM Member List



28 Electric Distributors Electricity Distributors Sector

List (01.18.2006)

31 End Use Customers End-Use Customer Sector List

(01.18.2006)

44 Generation Owners Generation Owners Sector List





3

(12.14.2005)

128 Other Suppliers Other Suppliers Sector List

(01.18.2006)

12 Transmission Transmission Owners Sector

Owners List (01.04.2006)

- 2 RTO markets directly NYISO, MISO

interconnected with PJM



New York ISO



Characteristic FERC Tariff Reference Other Reference

1. Transmission Access

- Open Access Tariff New York Independent N/A

administered by RTO System Operator, Inc. FERC

Electric Tariff

- Regional transmission NYISO Services Tariff – Manual for Transmission

scheduling Articles 4, 5, 13 Services – Sections 7

NYISO Outage Scheduling

Manual – Sections 1 & 2

NYISO Transmission Owners

Agreement – Article 3

NYISO/NYSRC Agreement –

Article 2

NYISO Control Center

Requirements Manual –

Section 3

- Regional transmission OATT Sections 32A, 15 NYISO Transmission

planning Expansion and

Interconnection Manual

Sections 2, 3

NYISO/Transmission Owner

Agreement – Section 3.10 d

New York State Public Service

Law Articles VII, X



- Regional interconnection OATT Attachment S – Section NYISO Transmission

process 1A Expansion and

Interconnection Manual

Sections 3, 4

NYISO/Transmission Owner

Agreement – Section 3.10 d



- Independence See below See below

- Independent Board N/A ISO Agreement – Articles 2, 5,

7, 8, 9 & 19

ISO/Transmission Owner’s

Agreement – Section 3

NYISO – Committee

Organizational Chart

- RTO Services Tariff NYISO Services Tariff N/A

- Market Tariff administered NYISO OATT N/A

by RTO

NYISO Services Tariff

2. RTO Markets See below See below







4

- Day Ahead market with NYISO Services Tariff – Article NYISO Market Participant’s

transparent hourly energy and 4, Attachment B User Guide - Sections 3, 7

congestion price

OATT Schedule 1 OATT NYISO Technical Bulletin #

Attachment J 74, # 83, # 58, # 40

NYISO Day Ahead Scheduling

Manual – Section 1

NYISO Transmission and

Dispatching Operations

Manual – Section 4

- Real time market with NYISO Services Tariff – Article NYISO Market Participant’s

transparent hourly energy and 4, Attachment B User Guide - Sections 3, 7

congestion price

OATT Schedule 1 NYISO Technical Bulletin #

74, # 83, # 58, # 40

OATT Attachment J NYISO Transmission and

Dispatching Operations

Manual – Section 4

- Ancillary Service market OATT Section 3 NYISO Ancillary Services

Manual – Sections 1, 2, 4;

OATT Schedules 3, 4, 5 SMD2 Redline Sections 4, 5,

6; Attachment D

Market Services Tariff Rate

Schedule 3 - Sections 4.1 &

5.1

- Operating reserve market NYISO Services Tariff Articles

2, 4, 5

- Regulation Service market NYISO Services Tariff Articles NYISO Market Participant’s

2, 4, 5 User Guide - Section 3

- Transmission Congestion OATT – Attachment J NYISO Market Participant’s

Contracts User Guide – Section 2

OATT – Attachment M NYISO Transmission Services

Manual – Sections 4, 5, 7

OATT – Attachment N

OATT Section 13

- Capacity requirement or NYISO Services Tariff Article 5 NYISO Installed Capacity

resource obligation & markets Manual – Sections 3, 4

NYISO Installed Capacity

Manual Attachment B

Order Accepting ICAP

Demand Curves, as Modified,

Removing Refund Condition,

and Dismissing Motion and

Request for Rehearing, April

21st, 2005

3. Longer term trading & See below

contracting facilitated by

RTO markets

- Bilateral online physical and NYISO Agreement – Article 17 See Table 2

financial trading of power

- Zones (liquid trading points) OATT Section 1.18f Market Data Exchange Zone

Maps (on NYISO website)



- Many market participants NYISO Market Services Tariff NYISO ISO Agreement –

Articles 2, 4, 5, 6, 12 Sections 1, 2





5

NYISO Approved Customers

List

14 Generation Owners Committee Membership

37 Other Suppliers

6 Transmission Owners NYISO Committee

Membership (11/22/2005)

6 End Use - Large Consumers NYISO Committee

Membership (11/22/2005)

1 End Use - Large Consumer NYISO Committee

Govt. Membership (11/22/2005)

8 End Use - Small Consumers NYISO Committee

Membership (11/22/2005)

1 End Use - State Agency NYISO Committee

Membership (11/22/2005)

2 End Use - Govt. NYISO Committee

Agency/Aggr. Membership (11/22/2005)

2 Public Power - Authorities NYISO Committee

Membership (11/22/2005)

11 Public Power - Munis & Co- NYISO Committee

ops Membership (11/22/2005)

5 Public Power - NYISO Committee

Environmental Membership (11/22/2005)

14 Other NYISO Committee

Membership (11/22/2005)

- 2 RTO markets directly PJM, ISO-NE

interconnected with NYISO



ISO – New England



Characteristic FERC Tariff Reference Other Reference

1. Transmission Access

- Open Access Tariff ISO New England OATT ISO OATT Business Practices

administered by RTO

- Regional transmission ISO New England OATT ISO OATT Business Practices

scheduling

- Regional transmission ISO New England OATT Transmission Operating

planning Sections I & II Agreement - Schedule 3

- Regional interconnection ISO New England OATT ISO New England Planning

process Section II Procedure No. 5-6

General Transmission System

Design Requirements for the

Interconnection of New

Generators (Resources) to the

System

- Independence

- Independent Board ISO New England OATT ISO-NE Participants

Section II Agreement

- RTO Services Tariff ISO New England OATT

- Market Tariff administered ISO New England OATT

by RTO

2. RTO Markets

- Day Ahead market with ISO New England OATT ISO New England Market

transparent hourly energy and Section II.1.16 Operations Manual

congestion price







6

ISO New England Market Rule

1 – Section 1

ISO Market Rule 1 Accounting

– Sections 1.1 & 3.2



ISO New England Information

Policy – Section 3

ISO New England Financial

Transmission Rights

ISO New England Operating

Procedure 9 – Scheduling and

Dispatch of External

Transactions

- Real time market with ISO New England OATT , ISO New England Market

transparent hourly energy and Section II.1.114, II.1.115, Operations Manual

congestion price

II.44 ISO New England Market Rule

1 – Section 1

ISO Market Rule 1 Accounting

– Sections 1.1 & 3.2

ISO New England Information

Policy – Section 3

ISO New England Financial

Transmission Rights

ISO New England Operating

Procedure 9 – Scheduling and

Dispatch of External

Transactions

- Ancillary Service market ISO New England OATT – ISO New England Market Rule

Section II 1 – Section 3.2.2 & 3.2.3 & 9

ISO New England OATT – ISO New England Manual for

Schedules 3, 4, 5, & 6 Forward Reserve – Section

1.1

Second Restated NEPOOL

Agreement - Section 5

Transmission Operating

Agreement – Section 3

Participants Agreement –

Section 8

ISO New England Market Rule

1 – Section 1.10.1



- Operating reserve market ISO New England OATT – ISO New England Market Rule

Section II.1.2 1 – Section 3

ISO New England OATT – ISO New England Manual for

Schedules 3, 4, 5, 6 Forward Reserve



- Regulation Service market ISO New England OATT – ISO New England Market Rule

Schedules 3, 4, 5, & 6 1 – Section 3

Manual for FWD. Reserve

- Financial transmission rights ISO New England OATT, ISO New England Market Rule

Section II.42 1 – Section 7.2

ISO New England Financial

Transmission Rights

ISO Market Rule 1 Accounting





7

Manual – Section 7

ISO New England Market

Operations Manual – Section

5

ISO New England Operating

Procedure 9 – Scheduling and

Dispatch of External

Transactions

ISO Market Operations

Manual – Section 6



- Capacity or resource ISO New England OATT, ISO New England Market Rule

obligation & market Section II.1.127 1 – Section 8

ISO New England Manual for

Installed Capacity



3. Longer term trading &

contracting facilitated by

RTO markets

- Bilateral online physical and ISO New England OATT See Table 2

financial trading of power Section II, Schedules 4, 5, 6,

18; ISO New England Market

Rule 1 Accounting Manual





- 1 ISO-NE Hub, x Zones

(liquid trading points)

Many market participants ISO New England OATT

Section II

14 Generation NEPOOL Participants (9/2005)

Participants

7 Transmission NEPOOL Participants (9/2005)

Participants

60 Suppliers NEPOOL Participants (9/2005)

11 AR Participants NEPOOL Participants (9/2005)

45 Publicly Owned NEPOOL Participants (9/2005)

Participants

43 End Users NEPOOL Participants (9/2005)

- NYISO directly ISO New England OATT

interconnected with ISO-NE Section II.1.139, II.24, II.25,

Schedule 18, Attachments G-

2, G3







Midwest ISO



Characteristic FERC Tariff Reference Other Reference

1. Transmission Access

- Open Access Tariff MISO Open Access

administered by RTO Transmission and Energy

Markets Tariff (EMT)

- Regional transmission EMT – Schedule C Business Practices Manual for

scheduling Coordinated Reliability,

Dispatch, & Control, Manual







8

No. 006, Section 2

Business Practices Manual for

Energy Markets, Manual No.

002, Section 3

Business Practices Manual for

Outage Operations, Manual

No. 008, Section 4

Midwest Market Initiative

Protocols, Version 2.0, Section

7

Business Practices Manual for

Market Settlements, Manual

No. 005, Section 2

- Regional transmission EMT – Attachment A, Section Agreement of Transmission

planning 5 Facilities Owners to Organize

the Midwest Independent

Transmission System

Operator, Inc., a Delaware

Non-Stock Corporation, As

Accepted by the Federal

Energy Regulatory

Commission on November 23,

2004, Appendix B

EMT – Attachment N Midwest ISO Transmission

Expansion Plan 2003,

Approved by the Midwest ISO

Board of Directors June 19,

2003, Section 1

EMT – Attachment X Appendix 6 to LGIP Standard

Large Generator

Interconnection Agreement,

Section 9

- Regional interconnection EMT Attachment X Agreement of Transmission

process Facilities Owners to Organize

MISO, As Accepted by the

FERC on 11/23/04, Appendix

B, Section II and Section VII

EMT Attachment R FERC Order No. 2003-A

EMT Attachment N

- Independence

- Independent Board EMT – Module A, Module D Agreement of Transmission

Facilities Owners to Organize

the MISO, As Accepted by the

Federal Energy Regulatory

Commission on November 23,

2004, Article Two, Section III

- RTO Services Tariff

- Market Tariff administered MISO Open Access

by RTO Transmission and Energy

Markets Tariff (EMT)

2. RTO Markets

- Day Ahead market with EMT – Module C, Section IV Business Practices Manual for

transparent hourly energy and Energy Markets, Manual No.

congestion price 002, Sections 2, 4, 5, 25

Business Practices Manual for







9

Energy Market Instruments,

Manual 003, Sections 5, 6

Business Practices Manual for

Coordinated Reliability,

Dispatch, & Control, Manual

No. 006, Section 3

Business Practices Manual for

Scheduling, Manual No. 007,

Section 3

- Real time market with EMT – Module C, Section IV Business Practices Manual for

transparent hourly energy and Energy Markets, Manual 002,

congestion price Sections 2, 4, 5

Business Practices Manual for

Energy Market Instruments,

Manual 003, Sections 5, 6

Business Practices Manual for

Coordinated Reliability,

Dispatch, & Control, Manual

No. 006, Section 3 and

Manual 007, Section 3

- Ancillary Service market MISO Open Access Business Practices Manual for

Transmission and Energy Coordinated Reliability,

Markets Tariff (EMT), Module Dispatch, & Control, Manual

A, Section 1, Section 3, No. 006, Section 5

Module B.III. Section 28 and

Section 34, & Section III,

Module C, Section 38.6.3

Business Practices Manual for

Energy Markets Instruments,

Manual No. 003, Section 4.

Business Practices Manual for

Energy Markets, Manual No.

002, Section 5

- Operating reserve market EMT Module A, Section 1, Business Practices Manual for

Section 3, Module B.III. Coordinated Reliability,

Section 28 and Section 34, & Dispatch, & Control, Manual

Section III, Module C, Section No. 006, Section 5, Section 5

38.6.3

Business Practices Manual for

Energy Markets Instruments,

Manual No. 003, Section 4.

Business Practices Manual for

Energy Markets, Manual No.

002, Section 5

- Regulation Service market EMT Module A, Section 1, Business Practices Manual for

Section 3, Module B.III. Coordinated Reliability,

Section 28 and Section 34, & Dispatch, & Control, Manual

Section III, Module C, Section No. 006, Section 5, Section 5

38.6.3

Business Practices Manual for

Energy Markets Instruments,

Manual No. 003, Section 4.

Business Practices Manual for

Energy Markets, Manual No.

002, Section 5







10

- Financial transmission rights EMT Module B – Section III Business Practices Manual for

Financial Transmission Rights,

Manual No. 004, Section 2,

Section 4

EMT Module C – Section III, Business Practices Manual for

Section IV Market Settlements, Manual

005, Section 2

EMT Attachment P Business Practices Manual for

Scheduling, Manual No. 007,

Section A

Business Practices Manual for

Coordinated Reliability,

Dispatch & Control, Manual

No. 006, Section 3

Joint Operating Agreement

between the Midwest

Independent Transmission

System Operator, Inc. and

PJM Interconnection, L.L.C.,

Section on Long-Term ATC

(For Monthly Requests),

- Capacity or resource EMT Module B –Transmission Business Practices Manual for

requirements obligations for Service, Section 31.6 Resource Adequacy, Manual

LSEs No. 011, Section 2, Section 3

and Section 4

3. Longer term trading &

contracting facilitated by

RTO markets

- Bilateral online physical and EMT Module A, Section 7, See Table 2

financial trading of power Section 10 and Module C,

Section 38



- 5 MISO HUBs (liquid trading

points)

- 2 PJM Midwest hubs

- Many market participants

30 VITOs/MSATs Midwest ISO Advisory

Committee Member Groups

(Feb. 2006)

15 State Regulatory Midwest ISO Advisory

Authorities Committee Member Groups

(Feb. 2006)

11 IPPs/EWGs Midwest ISO Advisory

Committee Member Groups

(Feb. 2006)

14 Munis/Coops/TDUs Midwest ISO Advisory

Committee Member Groups

(Feb. 2006)

34 Power Midwest ISO Advisory

Marketers/Brokers Committee Member Groups

(Feb. 2006)

11 Public Consumer Midwest ISO Advisory

Groups Committee Member Groups

(Feb. 2006)

4 Environmental Midwest ISO Advisory







11

Advocates Committee Member Groups

(Feb. 2006)

4 Eligible End-Use Midwest ISO Advisory

Customers Committee Member Groups

(Feb. 2006)

1 Coordinating Member Midwest ISO Advisory

Committee Member Groups

(Feb. 2006)

PJM directly interconnected

with MISO PJM









12

Comments of the Edison Electric Institute

Docket No. RM06-10

Exhibit B

Wholesale Power Purchases, 2004









EXHIBIT B



WHOLESALE POWER PURCHASES BY STATE, 2004

Comments of the Edison Electric Institute

Docket No. RM06-10

Exhibit B

Wholesale Power Purchases, 2004





Wholesale Power Purchases 2004 (MWh)



State Long Term Short Term Non Firm Other Unknown Total

(1) (2)

AK

844,552 - 6,665 - 780,812 1,632,029

AL

4,619,574 - 5,792,345 - 11,873,226 22,285,145

AR

2,553,232 126,984 11,340,367 - 9,424,089 23,444,672

AZ

6,145,828 33,328,147 2,000,633 - 1,780,319 43,254,927

CA

30,157,168 6,947,255 35,930,567 - 6,942,669 79,977,659

CO

15,930,731 11,996,055 927,224 - 8,531,192 37,385,202

CT

9,024,905 - 27,639,596 18,375 - 36,682,876

DE

3,903,783 - 8,637,077 - 1,143,067 13,683,927

FL

25,587,331 73,779 13,505,372 60,665 10,307,875 49,535,022

GA

12,303,335 - 18,778,698 - 35,473,510 66,555,543

HI

3,299,045 - 3,767 - 35,749 3,338,561

IA

2,945,842 600,019 8,836,467 - 3,772,378 16,154,706

ID

1,075,140 2,973,972 485,665 - 1,116,470 5,651,247

IL

15,607,021 1,190,545 85,373,044 - 16,617,022 118,787,632

IN

6,166,259 3,066,797 32,138,652 - 8,987,181 50,358,889

KS

1,444,760 1,135,364 412,696 - 4,594,584 7,587,404

KY

17,937,756 8,164 8,019,347 - 26,066,886 52,032,153

LA

5,890,587 914,252 21,810,771 2,904 7,287,888 35,906,402

MA

19,995,278 21,450,130 3,969,175 37,749 72,120 45,524,452

MD

16,071,687 - 1,544 - 3,428,016 19,501,247

ME

2,633,616 - 76,640 - 32,568 2,742,824

MI

16,620,227 1,401,952 5,764,465 9,398 2,778,503 26,574,545

MN

4,647,700 116,152 21,648,212 - 7,099,169 33,511,233

MO

9,888,828 - 13,822,130 - 21,782,673 45,493,631

MS

4,947,850 - 11,051,878 - 11,532,896 27,532,624

MT

1,411,990 - - - 1,813,871 3,225,861







1

Comments of the Edison Electric Institute

Docket No. RM06-10

Exhibit B

Wholesale Power Purchases, 2004

NC

13,020,237 1,090,589 3,802,620 205,228 14,752,547 32,871,221

ND

2,600,007 - 518,446 - 7,416,376 10,534,829

NE

- - - - 4,689,104 4,689,104

NH

2,938,084 671,113 1,735,300 49 - 5,344,546

NJ

82,171,261 - 114,992,367 - 2,049,447 199,213,075

NM

1,953,188 - 7,924,743 264 4,495,313 14,373,508

NV

9,450,754 8,555,359 391,479 (8,942) 694,663 19,083,313

NY

37,494,285 7,907,355 22,895,604 163 23,237,432 91,534,839

OH

3,578,127 - 326,173,765 - 7,019,737 336,771,629

OK

9,997,148 2,471,392 4,545,104 (42,877) 5,581,101 22,551,868

OR

17,390,072 17,632,876 729,485 1,446 1,891,604 37,645,483

PA

57,962,871 1,265,858 69,568,011 - 1,864,350 130,661,090

RI

6,962,719 - - - 169 6,962,888

SC

18,915,437 - 876,392 - 13,597,595 33,389,424

SD

7,171,195 149,722 1,127,058 - 2,988,147 11,436,122

TN

2,080,910 - - - 22,562,703 24,643,613

TX

22,461,728 1,366,218 37,356,792 47,255 16,417,116 77,649,109

UT

1,047,257 305,676 - - 424,186 1,777,119

VA

12,350,512 - 31,586,863 (119,223) 9,957,195 53,775,347

VT

8,063,512 176,250 905,055 - 71,327 9,216,144

WA

13,012,073 2,144,927 7,570,641 560 1,264,126 23,992,327

WI

3,987,855 1,084,719 10,803,756 - 7,497,755 23,374,085

WV

2,668,851 2,007,061 10,096 - 67,760 4,753,768

WY

100,628 - - - 3,782,117 3,882,745

Total

579,032,736 132,158,682 981,486,574 213,014 355,596,603 2,048,487,609



Source: Global Energy Intelligence's EV Power Database (Federal Energy Regulatory

Commission (FERC Form 1), Energy Information Administration (DOE/EIA) Form 412, Rural

Utility Service (RUS) Form 7 and Form 12).



(1) Transactions longer than 1 year

(2) Transactions shorter than 1 year









2

Comments of the Edison Electric Institute

Docket No. RM06-10

Exhibit C

Bilateral Transactions









EXHIBIT C



BILATERAL TRANSACTIONS

Comments of the Edison Electric Institute

Docket No. RM06-10

Exhibit C

Bilateral Transactions

NYMEX Long-term Forward Markets

Hub Maximum December Month Term

Forward [Years]

Financially Settled Futures

PJM Interconnection, LLC, Futures

Peak

AEP-Dayton Hub Monthly Electricity Futures – Peak 3

Northern Illinois Hub Monthly Electricity Futures – Peak 3

PJM Financially Settled Monthly Futures – Peak 3

Off-Peak

AEP-Dayton Hub Monthly Electricity Futures – Off-Peak 3

Northern Illinois Hub Monthly Electricity Futures – Off-Peak 3

PJM Financially Settled Monthly Electricity Futures – Off-Peak 3

Western Power Contracts

Dow Jones Mid-Columbia Electricity Price Index Futures 3

Dow Jones North Path-15 Electricity Price Index Futures 3

Dow Jones Palo Verde Electricity Price Index Futures 3

Dow Jones South Path-15 Electricity Price Index Futures 3

New York Independent System Operator (NYISO) Futures

Peak

NYISO Zone A LBMP Swap – Peak 3

NYISO Zone G LBMP Swap – Peak 3

NYISO Zone J LBMP Sway – Peak 3

Off-Peak

NYISO Zone A LBMP Swap – Off-Peak 3

NYISO Zone G LBMP Swap - Off-Peak 3

NYISO Zone J LBMP Swap - Off-Peak 3

Midwest Independent Transmission System Operator (MISO) Futures

Peak

Cinergy Hub LMP Swap - Peak 3

Michigan Hub LMP Swap - Peak 3

MISO Illinois LMP Swap - Peak 3

Minnesota Hub LMP Swap - Peak 3

Off-Peak

Cinergy Hub Off-Peak LMP Swap 3

Michigan Hub Off-Peak LMP Swap 3

MISO Illinois Off-Peak LMP Swap 3

Minnesota Hub Off-Peak LMP Swap 3

ISO New England Futures

Peak

ISO New England Internal Hub Location Marginal Pricing Swap

Futures - Peak 3

Off-Peak

ISO New England Internal Hub Location Marginal Pricing Swap

Futures - Off-Peak 3





1

Comments of the Edison Electric Institute

Docket No. RM06-10

Exhibit C

Bilateral Transactions

Electricity Options

PJM Monthly Financially Settled Electricity Options 3



Source: New York Mercantile Exchange









2

Comments of the Edison Electric Institute

Docket No. RM06-10

Exhibit C

Bilateral Transactions

IntercontinentalExchange Long-term Forward Markets

Hub Maximum December Month Term

Forward [Years]

AD Hub Real Time 2

Cin Hub Real Time 3

Mid C 3

Nepool MH Day-Ahead 4

Nepool MH Day-Ahead Off-Peak 3

NI Hub Real Time 2

NP-15 3

NYISO A 3

NYISO G 2

NYISO J 2

NYISO A Off-Peak 3

Palo 3

PJM WH Real Time 4

PJM WH Real Time Off-Peak 3

SP-15 3



Source: IntercontinentalExchange









3

Comments of the Edison Electric Institute

Docket No. RM06-10

Exhibit C

Bilateral Transactions

Megawatt Daily Long-term Forward Markets

Hub Maximum Calendar Year Term Forward

[Years]

East

Mass Hub 2

PJM West 2

N.Y. Zone-G 1

N.Y. Zone-J 1

N.Y. Zone-A 1

Ontario 1

TVA, into 1

Central

Cinergy Hub 2

NI Hub 2

Entergy, into 2

ERCOT 2

West

Mid-C 3

Palo Verde 3

NP15 3

SP15 3



Source: Megawatt Daily Friday, December 16, 2005









4

Comments of the Edison Electric Institute

Docket No. RM06-10

Exhibit C

Bilateral Transactions

IntercontinentalExchange Day-ahead Markets

Hub Hub

AD Hub Real Time Peak Mid C Peak

AEP Dayton Hub Off-Peak Mona Off-Peak

Cin Hub Peak Mona Peak

Cin Hub Real Time Peak NOB N-S Peak

COB Off-Peak NP-15 Off-Peak

COB Peak NP-15 Peak

Entergy Peak Palo Verde Off-Peak

Ercot Off-Peak Palo Verde Peak

Ercot Peak Pinnacle 230 Peak

Ercot-Houston Peak PJM WH Real Time Off-Peak

Ercot-North Peak PJM WH Real Time Peak

Four Corners Off-Peak PJM-W Off-Peak

Four Corners Peak PJM-West Peak

Mead Off-Peak SP-15 Off-Peak

Mead Peak SP-15 Peak

Mid C Off-Peak West Wing Off-Peak



Source: IntercontinentalExchange









5

Comments of the Edison Electric Institute

Docket No. RM06-10

Exhibit C

Bilateral Transactions

Megawatt Daily Day-ahead Markets

Hub Hub

East Central

On-Peak Off-Peak

Mass Hub Michigan Hub

N.Y. Zone-G AD Hub

N.Y. Zone-J Cinergy Hub

N.Y. Zone-A Illinois Hub

Ontario NI Hub

PJM West Minnesota Hub

Dominion Hub MAPP, South

VACAR SPP, North

Southern, into Entergy, into

Florida ERCOT

TVA, into ERCOT, North

Off-Peak ERCOT, Houston

Mass Hub ERCOT, West

PJM West ERCOT, South

Dominion Hub West

VACAR On-Peak

Southern, into COB

Florida Mid-C

TVA, into Palo Verde

Central Mead

On-Peak Mona

Michigan Hub Four Corners

AD Hub NP15

Cinergy Hub SP15

Illinois Hub Off-Peak

NI Hub COB

Minnesota Hub Mid-C

MAPP, South Palo Verde

SPP, North Mead

Entergy, into Mona

ERCOT Four Corners

ERCOT, North NP15

ERCOT, Houston SP15

ERCOT, West

ERCOT, South



Source: Megawatt Daily Friday December 16, 2005







6

Comments of the Edison Electric Institute

Docket No. RM06-10

Exhibit C

Bilateral Transactions









7