File No. 70-10294          

 

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM U-1/A

Exelon Corporation		Public Service
(and the Subsidiaries listed on the		Enterprise Group Incorporated
Signature Page hereto)		(on behalf of the Subsidiaries listed
10 South Dearborn Street		on the Signature Page hereto)
37th Floor		80 Park Plaza
Chicago, IL 60603		Newark, New Jersey 07102

(Name of companies filing this statement and address of principal executive office)

Exelon Corporation

(Name of top registered holding company)

Randall E. Mehrberg		R. Edwin Selover
Executive Vice President and		Senior Vice President and
General Counsel		General Counsel
Exelon Corporation		Public Service Enterprise
10 South Dearborn Street		Group Incorporated
37th Floor		80 Park Plaza
Chicago, IL 60603		Newark, New Jersey 07102

(Name and address of agent for service)

The Commission is requested to send copies of all notices, orders and communications in connection
with this Application-Declaration to:

Scott N. Peters		Tamara L. Linde
Constance W. Reinhard		Jason A. Lewis
Exelon Corporation		PSEG Services Corporation
10 South Dearborn Street, 35th Floor		80 Park Plaza
Chicago, Illinois 60603		Newark, New Jersey 07101
312-394-3604		973-430-8058
Joanne C. Rutkowski		Timothy M. Toy
Baker Botts L.L.P.		Bracewell & Giuliani LLP
1299 Pennsylvania Ave., NW		1177 Avenue of the Americas
Washington, DC 20004		New York, NY 10036-2714
202-639-7785		212-508-6118
William J. Harmon
Jones Day
77 West Wacker, Suite 3500
Chicago, Illinois 60601
312-782-3939

 

 

TABLE OF CONTENTS

Item 1. Description of Proposed Transaction									1
		A. Introduction							1
		B. Exelon Generation Restructuring							4
		C. Generation Transactions							5
				1. Generation Divestiture — Overview					5
				2. Generation Transactions — Background					6
				3. Exelon Generation Restructuring					6
				4. Divestiture Generation Restructuring					6
				5. Summary of Relevant Provisions of the Code					7
				6. Section 1081 Recitals					7
Item 2. Fees, Commissions And Expenses									9
Item 3. Applicable Statutory Provisions									9
		A. Applicable Provisions							9
		B. Analysis of Section 11(e) Plan							9
						(a) Necessity for Plan			10
						(b) Fairness			12
Item 4. Regulatory Approvals									13
Item 5. Procedure									16
Item 6. Exhibits And Financial Statements									16
		A. Exhibits							16
		B. Financial Statements							19
Item 7. Information as to Environmental Effects									19
Item 8. Implementation of Section 1271(c) of the Energy Policy Act of 2005									19
Order of the Federal Energy Regulatory Commission
Federal Energy Regulatory Commission Order on Rehearing

  i

      

     Applicants hereby incorporate by reference Amendment No. 2 to the application/declaration in File No. 70-10294 and provide the following supplemental information:

Item 1. Description of Proposed Transaction

     A. Introduction

     On December 29, 2005, the Securities and Exchange Commission (the “Commission” or “SEC”) issued a notice in File No. 70-10294 under the Public Utility Holding Company Act of 1935 (the “1935 Act” or “Act”), relating to the proposed merger (the “Merger”) of Exelon Corporation (“Exelon”) and Public Service Enterprise Group Incorporated (“PSEG” and, together with Exelon, the “Applicants”). The return date on the notice is January 23, 2006.

     Applicants are hereby asking the Commission to take such action as it may deem necessary to make findings under Section 11(b) of the Act in connection with the required asset divestiture (“Divestiture”) described more fully in Item 3(b) (“Section 11(e) Plan”). In the Commission’s discretion, such findings could be incorporated in an order approving the Merger and related transactions. In the alternative, the Commission could make the requested findings in an order approving the Applicants’ Section 11(e) Plan. Such findings are necessary to preserve for Applicants the ability to qualify for certain tax relief in connection with the Divestiture. Applicants believe that the net present value of the relief would exceed $100 million.

     Applicants understand that the Commission could choose not to act, given the pendency of repeal and the press of other business.¹   They believe, however, that the better course would be for the Commission to make the requested findings, which are consistent with the facts and the law, and leave to the Internal Revenue Service the application of tax law to those findings. In support of their request, Applicants note the following:

     The Commission Staff has indicated that it has no substantive problems with the Merger as such. The record in this matter is largely complete and Applicants believe that the Commission could properly issue an order at the completion of the notice period, approving the Merger and related transactions.²  Rather than press for the issuance of a comprehensive order, Applicants instead suggest that the Commission might focus on the one aspect of its authorization that will have continuing effect post-repeal, namely, findings in connection with the “very substantial divestiture of generation” that will form the predicate for tax relief under section 1081 of the Internal Revenue Code of 1986, as amended (“Code”).

§

Section 1081 is one of a series of tax provisions intended to mitigate the economic consequences of certain government-compelled actions.

	§		Of interest here, section 1081 permits a party to defer recognition of gain on transactions that have been found to be “necessary or appropriate to effectuate the provisions of Section 11(b)” of the 1935 Act.
	§		Further, a party’s ability to avail itself of the benefits of section 1081 survives repeal of the Act. See section 1271(c) of the Energy Policy Act of 2005, which expressly provides that: “Tax treatment under section 1081 of the [Code] as a result of transactions ordered in compliance with the [Act] shall not be affected in any manner due to the repeal of that Act and the enactment of the Public Utility Holding Company Act of 2005.”3

     The Commission can make the requested findings on the basis of the record before it, regardless of whether it ultimately passes on the Merger as a whole. The predicate for the Section 11(b) finding exists in the form of the approvals that have already been granted by the Federal Energy Regulatory Commission (“FERC”).

	§		In its July 1, 2005 order approving the Merger, the FERC determined that a “very substantial divestiture of generation,” including the divestiture by sale of 4,000 MW of generating capacity, was necessary to address potential anticompetitive consequences of the Merger.4
	§		In the ordinary course of its review, the Commission would “watchfully defer” to the FERC’s action, including the need for divestiture, for purposes of its findings under Section 10(b)(1) of the 1935 Act that the Merger not result in a “concentration of control of public-utility companies, of a kind or to an extent detrimental to the public interest or the interest of investors or consumers.”5

          In so doing, the Commission would incorporate by reference the conditions of the FERC order, including the divestiture requirement . Thus, even if the Commission did not expressly order divestiture, it would incorporate by reference the FERC requirement.

§

The findings and remedies under Section 10(b)(1) of the Act are intended to ensure, among other things, that the resulting electric utility system is “not so large as to impair . . . the effectiveness of regulation” under Section 11(b)(1) of the Act (by reference to Section 2(a)(29) of the Act).

     Further, the interrelation of the FERC and SEC findings, on the one hand, and Sections 10(b)(1) and 11(b)(1) of the 1935 Act, on the other, are well established.

	§		Concerning the FERC and SEC findings, the Federal Power Act and the 1935 Act are coordinate titles of the Public Utility Act of 1935. Responsibility, sometimes overlapping, was allocated between the two agencies with the goal of ensuring “effective public regulation” of the utility industry. See Sections 1(b) and 1(c) of the 1935 Act. The legislative history makes clear that the purpose of Section 11 of the Act “is simply to provide a mechanism to create conditions under which effective Federal and State regulation will be possible.” S. Rep. No. 621, 74th Cong., 1st Sess. 11 (1935) (Report of Senator Wheeler from the Committee on Interstate Commerce).
	§		Findings under Sections 10 and 11 of the 1935 Act are even more closely linked. Simply stated, “Sections 9 and 10 are preventive in purpose. Their essential function is to avoid recreating, by acquisition, what Section 11(b) was designed to undo or eliminate.” Public Service Company of Oklahoma, Holding Co. Act Release 19090 (July 17, 1975); see also American Electric Power Company, Inc., Holding Co. Act Release No. 20633 (July 21, 1978) (footnotes omitted) (noting that “Section 10, in particular was intended to prevent acquisitions which would be ‘attended by the evils which have featured the past growth of holding companies.’”).

     Finally, Section 11(e) of the Act provides a mechanism by which the Commission can address the Section 11(b) issues in isolation, reserving jurisdiction over Applicants’ other requests.

§

As the United States Supreme Court has explained: “Section 11(e) merely permits the holding companies to formulate their own programs for compliance with § 11(b)(1) or to submit plans in conformity with prior Commission orders under § 11(b), . . . .” American Power Co. v. SEC, 329 U.S. 90, 119 (1946).

     In this matter, the standards for approval of a plan, that it be both “necessary to effectuate the provisions of” Section 11(b), and “fair and equitable to the persons affected by such plan,” are met.

	§		The Commission has declared that “[a] plan is ‘necessary’ within the meaning of section 11(e), . . . if it accomplishes the objectives required by section 11(b) in an appropriate manner.” Midland Utilities, 24 S.E.C. 463, 475 (1946). “It thus seems clear that Section 11(e) permits a company to propose particular transactions which under our ordinary practice we would not, or perhaps could not, specifically require by order under Section 11(b).” See also Mission Oil Co., 35 S.E.C. 540 (1954) (in which the Commission authorized a Section 11(e) plan to enable applicant to obtain tax relief).
	§		Consistent with Commission precedent, Applicants’ Divestiture plan is “necessary” to ensure that the resulting electric-utility system is “not so large as to impair . . . the effectiveness of regulation” (Section 11(b)(1) by reference to Section 2(a)(29)).
	§		The Divestiture plan is also “fair and equitable” to the public interest and the interest of investors and consumers, the “protected interests” under the Act.

	°		If, for some reason, the Merger does not close, the order approving the Section 11(e) Plan will be of no effect, other than for tax relief purposes.6
	°		If, however, as Applicants anticipate, the Merger does close in the first half of 2006, the tax deferrals will contribute to the financial health of the merged company and so be in the “public interest” for purposes of the Act.
	°		Similarly, although the 1935 Act does not provide extra protection for shareholders of registered holding companies, the tax deferrals will clearly be beneficial to the interest of investors and, by bolstering the financial health of the merged company, similarly beneficial to the interests of consumers
	°		Moreoever, the 1935 Act is still effective through February 8, 2006 and the Applicants are requesting relief under the currently effective 1935 Act. While effective, the Commission should affirmatively act and should not, through procedural or other delays, disregard the Applicants’ rights to obtain a fair determination under the 1935 Act.

     Applicants submit that the circumstances — a major merger involving an unprecedented amount of divesture and legislation that offers significant potential relief in connection with that divestiture — clearly warrant Commission action. The sole operative effect of the requested order would be to enable Applicants to qualify for tax relief. Even with the Commission’s order, there is no guarantee that the Internal Revenue Service will agree that they are entitled to the relief. Absent such an order, however, Applicants will have no basis for seeking such relief and the potential tax savings — with net present value in excess of $100 million — will be irrevocably lost to the very interests the Act was intended to protect. Accordingly, Applicants urge the Commission to issue an order making the necessary findings prior to February 8, 2006, the effective date of repeal.

     B. Exelon Generation Restructuring

     After obtaining any appropriate third-party consents, including consents of certain PSEG Power debt holders to certain amendments of PSEG Power debt agreements, the Applicants will undertake the Exelon Generation Restructuring such that PSEG Power and its direct subsidiaries PSEG Nuclear, PSEG Fossil and PSEG ER&T will all cease to exist as separate entities and will become part of Exelon Generation. The business functions of these former PSEG entities will become a part of their respective Exelon Generation business unit. The subsidiaries owned by these PSEG entities will be retained as direct subsidiaries of Exelon Generation, which will continue to be an electric utility company for purposes of the Act. It is contemplated that the Exelon Generation Restructuring will take place contemporaneously with the closing of the Merger. See Exhibits G-1, G-2 and G-3 hereto for diagrams of the pre-Merger and post-Merger corporate structures.

     It is anticipated that the current subsidiaries of PSEG Fossil that own and/or operate electric generation facilities will remain subsidiaries of Exelon Generation as “exempt wholesale generators” (“EWG“s). The Exelon Generation Restructuring will not result in any new “public utility” subsidiary of Exelon Generation.

     Applicants seek such approval as may be required for the Exelon Generation Restructuring.⁷

     C. Generation Transactions

          1. Generation Divestiture — Overview

     The proposed Merger will increase the total capacity of generation resources owned or controlled by Exelon. To ensure that the combined company does not have market power in any relevant market, Exelon and PSEG have proposed the Mitigation Plan designed to address in full the FERC’s requirements for competitive markets. As part of the plan, the companies have proposed a divestiture as further described in this Item 1(C) (the “Generation Divestiture”) — to divest a number of coal, mid-merit, and peaking generating plants. The Mitigation Plan also provides for the transfer of control of the output of a portion of their baseload nuclear generating capacity.

     The final divestiture proposal made by Applicants and approved by the FERC in the FERC Merger Order will result in Applicants divesting 6,600 MW of electric generating capacity. Of this, 4,000 MW will be physically divested fossil generation. Under the FERC Merger Order, Applicants are required to make a compliance filing to the FERC within 30 days of the completion of their physical divestiture, providing an analysis of the Merger’s effect on competition in energy and capacity markets, given actual plants and assets divested and the actual acquirers of the divested assets. If the analysis shows that the Merger’s harm to competition has not been sufficiently mitigated, Applicants must propose additional mitigation at that time. The divestiture of the 4,000 MW contemplated in the FERC Merger Order plus any subsequent physical divestiture ordered by the FERC as necessary additional mitigation is referred to herein as the Generation Divestiture.

     Rather than divest their nuclear baseload units, the Applicants have proposed, and the FERC has accepted, a “virtual divestiture” whereby they will divest, through sales of long-term firm energy rights, 2,600 MW of nuclear generating capacity in PJM East. Such “virtual divestiture” will take the form of the FERC jurisdictional wholesale power transactions and will not constitute the disposition of “utility assets” within the meaning of the Act, therefore, no approval by the Commission is required for the virtual divestiture.

     Exhibit G-4 to the Application previously filed herein is a listing of generation facilities subject to divestiture as initially proposed by Exelon and PSEG (1,000 MW of peaking capacity and a total of 1,900 MW of mid-merit capacity of which 550 MW would be coal-fired). Subsequent to filing the Application, the proposed Generation Divestiture was expanded by an additional 1,100 MW for the total divestiture as approved in the FERC Merger Order of 6,600 MW as noted above and certain other generation facilities were added to the list subject to divestiture. See Exhibit G-4.1 for the final list of the facilities that may be subject to the Generation Divestiture.

     The FERC Merger Order requires Applicants to execute sales agreements and make appropriate filings at the FERC within twelve (12) months of the closing of the Merger in order to implement the Generation Divestiture. The Applicants intend to commence the divestiture process more quickly, but 12

months may be necessary to conduct a sales process, negotiate all necessary agreements and file for all necessary regulatory approvals.

     As explained more fully herein, the FERC has approved the Merger based upon, among other things, the Mitigation Plan and Applicants are asking the Commission to make the necessary findings to support relief pursuant to section 1081 of the Code with respect to the Generation Transactions. None of the proposed mitigation, including the Generation Divestiture, would adversely affect the integration of the combined electric utility operations for purposes of the Act.

     Applicants propose to effect the Generation Divestiture pursuant to a voluntary plan under Section 11(e) of the Act. The Commission has consistently held that a plan under Section 11(e) of the Act may be found “necessary” if it provides an appropriate means to achieving results required by Section 11(b) of the Act. See, e.g., Northeast Utilities, Holding Co. Act Release No. 24908 (June 22, 1989) (approving a Section 11(e) plan to dispose of gas distribution system assets via a spin-off of common stock of a newly constituted holding company system). Under Section 11(e) of the Act, the Commission shall approve a plan if it finds that:

	•		the plan is fair and equitable to persons affected by the plan; and
	•		the plan is necessary to carry out the provisions of Section 11(b) of the Act.

In this matter, the Generation Divestiture has been found by the FERC to be necessary and in the public interest as the fundamental underpinning of the FERC Merger Order. Generation Divestiture has or will be an essential aspect of the effective performance by the FERC, of its regulatory role. The reduction in the size of the combined company’s generation fleet to reduce market power and so provide for the effectiveness of regulation is at the core of the Act’s Section 11(b) “integrated public-utility system” mandate. Since the Generation Divestiture will be an essential aspect of the exercise of non-Commission regulatory oversight of the Merger, the Generation Divestiture has become an appropriate means of achieving the Act’s Section 11(b) mandate.

     2. Generation Transactions — Background

     Exelon Generation owns or controls all of the Exelon system’s generating assets including the electric generating units that are subject to being divested as part of the Generation Divestiture.

     PSEG Fossil is an EWG under Section 32 of the Act and a wholly-owned subsidiary of PSEG Power. PSEG Fossil owns directly the electric generating units that are subject to being divested as part of the Generation Divestiture.

     3. Exelon Generation Restructuring

     After obtaining necessary approvals and third party consents, PSEG Power and PSEG Fossil will cease to exist as separate entities and will become part of Exelon Generation. Accordingly, the Generation Transactions will be specified in this Application on the assumption that the Exelon Generation Restructuring will precede the Generation Divestiture Restructuring and the Generation Divestiture.

     4. Divestiture Generation Restructuring

     In order to maximize the amount a buyer would be willing to pay for the Subject Assets, defined below, the Applicants are considering alternative options for effecting the disposition by sale of the electric generating assets listed in Exhibit G-10 (the “Subject Assets”), as required by the Generation Divestiture.⁸ Subsequent to the Merger but prior to the implementation of any of the options set forth below, Exelon

would cause the assets listed in Exhibit G-11 owned by PSEG Fossil to be transferred to Exelon Generation, which currently owns the assets listed in Exhibit G-12 (the “Consolidating Transfers”). Pursuant to Option 2 described below, an internal restructuring would occur immediately prior to the disposition of the Subject Assets to the buyer that would change the ownership structure of the Subject Assets. The particular tax characteristics of the sale of a generating unit, including the buyer’s desired business and tax structures, would determine which option would be utilized. Because there are likely to be multiple buyers of the Subject Assets (each such buyer a “Third Party”), the Applicants may utilize either of the disposition options to effectuate the sale of the Subject Assets to each Third Party (the disposition to each such Third Party is referred to herein as a “Divestiture Transaction”). Each of the Subject Assets would be acquired pursuant to each Divestiture Transaction in exchange for cash and/or notes (the “Transfer Consideration”).

		Option 1: Exelon Generation would sell each of the assets listed in Exhibit G-13 to a Third Party pursuant to the Divestiture Transaction in exchange for the Transfer Consideration. Exelon Generation may distribute to Exelon (via Ventures) the Transfer Consideration received.
		Option 2: Exelon Generation would sell, in exchange for an amount of cash equal to the Transfer Consideration, each of the assets listed in Exhibit G-14 to the corporation wholly-owned by Ventures that is listed as the “Acquiring Sub” next to that asset in Exhibit G-14. Exelon Generation may distribute to Exelon (via Ventures) the cash received. Ventures would then sell all of the interests in the Acquiring Sub to the Third Party in exchange for the Transfer Consideration.

     The particulars of the option selected for each Divestiture Transaction would be specified in the applicable post-Merger FERC compliance filing. Each of the steps outlined in Option 2 above could occur simultaneously.

     5. Summary of Relevant Provisions of the Internal Revenue Code

     Code section 1081(b)(1) provides for the nonrecognition of gain or loss from a sale or exchange of property made in obedience to a Commission order; however, gain will not be recognized only to the extent that it can be (and is) applied to reduce the basis of the transferor’s remaining assets as provided in Code section 1082(a)(2). In the event that the transferor receives “nonexempt property” in the exchange,⁹ Code section 1081(b)(2) mandates that gain be recognized unless, within 24 months of the exchange, the transferor uses the nonexempt property to acquire property other than nonexempt property or invests the nonexempt property in accordance with that paragraph, and an order of the Commission recites that such expenditure or investment is necessary or appropriate to the integration or simplification of the transferor’s holding company system.

     Code section 1081(d) provides for the nonrecognition of gain or loss from certain intercompany transactions between members of the same system group if such transactions are made in obedience to a Commission order. System group is defined in Code section 1083(d) to include, as a general matter, corporations connected by common ownership with at least 90 percent of each class of stock of the corporations owned by other members of the system group.

     6. Section 1081 Recitals

     It is requested that the order of the Commission on this Application: (i) recite that the sale or disposition of generating units as part of the Generation Transactions is necessary or appropriate to the integration or simplification of the post-Merger Exelon holding company system and to effectuate the provisions of Section 11(b) of the Act; and (ii) require post-Merger Exelon to take appropriate actions to cause its direct and indirect subsidiaries, as the case may be, to complete the Generation Divestiture as required in order to comply with the FERC Merger Order.¹⁰

     In particular, the Applicants request that the Commission include the following in its order:

     The transfer of the assets listed in Exhibit G-11 from PSEG Fossil to PSEG Power, followed by the transfer of the interests in PSEG Power by Exelon to Ventures and then by Ventures to Exelon Generation, followed by the transfer of the assets listed in Exhibit G-11 by PSEG Power to Exelon Generation, are found to be necessary or appropriate to the integration or simplification of the post-Merger Exelon holding company system and to effectuate the provisions of Section 11(b) of the Act; and Exelon shall cause PSEG Fossil to transfer to PSEG Power the assets listed in Exhibit G-11, followed by the transfer of the interests in PSEG Power by Exelon to Ventures and then by Ventures to Exelon Generation, followed by the transfer of the assets listed in Exhibit G-11 from PSEG Power to Exelon Generation, in exchange for cash and/or notes (the notes referred to as the “Consolidation Notes”) in accordance with section 1081(d) of the Code.

     Each sale of the assets listed in Exhibit G-13 from Exelon Generation to a Third Party is found to be necessary or appropriate to the integration or simplification of the post-Merger Exelon holding company system and to effectuate the provisions of Section 11(b) of the Act; each sale of the assets listed in Exhibit G-13 by Exelon Generation shall be made to the Third Party in exchange for cash and/or notes in accordance with section 1081(b)(1) of the Code; and to the extent that the cash and/or notes received in such sale constitutes “nonexempt property,” Exelon shall cause such proceeds to be reinvested within 24 months of the divestiture date in a manner that complies with section 1081(b)(2) of the Code, which includes the satisfaction by Exelon Generation of the Consolidation Notes.

     Each sale of the assets listed in Exhibit G-14 from Exelon Generation to the corporation wholly-owned by Ventures that is listed as the “Acquiring Sub” next to that specific asset in Exhibit G-14, followed by each sale of such Acquiring Sub stock by Ventures to a Third Party, are found to be necessary or appropriate to the integration or simplification of the post-Merger Exelon holding company system and to effectuate the provisions of Section 11(b) of the Act; each sale of the assets listed in Exhibit G-14 by Exelon Generation shall be to the corporation wholly-owned by Ventures that is listed as the “Acquiring Sub” next to that specific asset in Exhibit G-14 in exchange for cash in accordance with section 1081(d) of the Code, and shall be followed by the sale of such Acquiring Sub stock by Ventures to a Third Party in exchange for cash and/or notes in accordance with section 1081(b) of the Code; and to the extent that the cash and/or notes received in the sale of the Acquiring Sub stock to the Third Party constitutes “nonexempt property,” Exelon shall cause such proceeds to be reinvested within 24 months of the divestiture date in a manner that complies with section 1081(b)(2) of the Code, which includes the satisfaction by Exelon Generation of the Consolidation Notes.

     Each distribution by Exelon Generation to Ventures, followed by each distribution by Ventures to Exelon, of the cash and/or notes received by Exelon Generation on the sale of the assets listed in Exhibit G-13 to a Third Party or the assets listed in Exhibit G-14 to an Acquiring Sub, and each distribution from

Ventures to Exelon of the cash and/or notes received on the sale of the stock of Acquiring Sub to a Third Party, are found to be necessary or appropriate to the integration or simplification of the post-Merger Exelon holding company system and to effectuate the provisions of Section 11(b) of the Act; and each distribution by Exelon Generation of the cash and/or notes received by Exelon Generation on the sale of the assets listed in Exhibit G-13 to a Third Party or the assets listed in Exhibit G-14 to an Acquiring Sub shall be made to Ventures in accordance with section 1081(d) of the Code, each distribution by Ventures of such cash and/or notes shall be made to Exelon in accordance with section 1081(d) of the Code, and each distribution by Ventures of the cash and/or notes received on the sale of the Acquiring Sub stock to a Third Party shall be made to Exelon in accordance with section 1081(d) of the Code.

     The foregoing request for Code section 1081 recitals is subject to possible modification (to be detailed in an amendment to this Application) so that the subject “Divestiture Transaction” encompasses all physical assets being disposed of by the Applicants in connection with obtaining Merger-related approvals.

Item 2. Fees, Commissions And Expenses.

     The fees, commissions and expenses to be paid or incurred, directly or indirectly, in connection with the Merger, including the solicitation of proxies, registration of securities of Exelon under the Securities Act of 1933, and other related matters, are estimated to be approximately $70 million.

Item 3. Applicable Statutory Provisions.

     A. Applicable Provisions.

     Sections 6(a), 7, 8, 9, 10, 11(b)(1), 11(e), 12, 13, 32 and 33 of the Act and the rules thereunder are considered applicable to the Merger and the proposed transactions. Sections 10 and 11 of the Act are applicable to the proposed Divestiture.

     To the extent that the proposed transactions are considered by the Commission to require authorizations, exemption or approval under any section of the Act or the rules and regulations thereunder other than those set forth above, request for such authorization, exemption or approval is hereby made.

     B. Analysis of Section 11(e) Plan

     Applicants propose to effect the Generation Divestiture pursuant to a voluntary plan under Section 11(e) of the Act. To approve a Section 11(e) plan, the Commission must determine, after notice and opportunity for hearing, that the plan is both “necessary to effectuate the provisions of” Section 11(b), and “fair and equitable to the persons affected by such plan.” Northeast Utilities, Holding Co. Act Release No. 24908 (June 22, 1989), citing Valley Gas Co., 40 S.E.C. 162, 167 (Aug. 10, 1960).

     Simply stated, Section 11(e) of the Act provides a voluntary means for complying with Section 11(b) of the Act. There is nothing novel about Applicants’ use of a Section 11(e) plan. Voluntary divestiture plans have long been used by public utility holding companies to identify and divest non-compliant interests. Joel Seligman, in The Transformation of Wall Street 252 (Third Edition), described the Commission’s historical reliance on voluntary plans under Section 11(e) as a means of achieving compliance with the policies and principles of the Act:

The essence of the Commission’s enforcement strategy after 1940 involved creating incentives (and removing disincentives) so that the utilities themselves would offer acceptable divestiture and simplification plans. This was known as the 11(e) strategy, since the Holding Company Act authorized enforcement under Subsection 11(b) under either Subsection 11(d), which empowered the SEC to seek a federal district court order requiring compliance with a Commission reorganization plan, or Subsection 11(e), which authorized the SEC to approve and, if necessary, seek court approval of a reorganization

plan offered by a utility. Although the threat of imposing the more draconian Subsection 11(d) was deemed “indispensable” to the enforcement of the Act by the Commission, it was employed only once in the 1940-1952 period.

Id. (footnotes omitted). Accord Hawes, Utility Holding Companies 2-20 (“Usually, . . . companies complied voluntarily by submitting a plan under Section 11(e).”). The submission of a Section 11(e) plan does not in any way limit or reduce the Commission’s authority. Rather, as explained below, the Commission must make a Section 11(b) determination in considering whether to approve a Section 11(e) plan.

     The United States Supreme Court, in American Power Co. v. SEC, 329 U.S. 90, 119 (1946), noted that: “Section 11(e) merely permits the holding companies to formulate their own programs for compliance with § 11(b)(1) or to submit plans in conformity with prior Commission orders under § 11(b), . . . .” In this regard, the Divestiture, which has been accepted by the FERC as an appropriate means of market power mitigation, fits squarely within the stated goals of Section 11(b) by ensuring that a utility system not be “so large as to impair . . . the effectiveness of regulation.”

     Applicants’ suggestion that the Commission consider the Section 11(e) Plan on a stand-alone basis is dictated by the exigencies of the circumstances, namely, that the Act is repealed effective February 8, 2006. If the Act had not been repealed, Applicants would have asked the Commission to make the Divestiture findings as part of a comprehensive order approving the Merger. As noted previously, Applicants believe the Commission could, in fact, issue such an order. Nonetheless, they recognize that a Section 11(e) plan may be the preferred approach because the Section 10(f) of the Act concerns that may prevent the Commission from issuing a Merger Order prior to the effective date of repeal do not apply to the proposed Section 11(e) Plan.

     Applicants acknowledge that the proposed Section 11(e) Plan is forward-looking and contingent on events that may take place, if at all, only after the effective date of repeal They believe, however, that there are two important points in this regard: (i) Section 1271(c) of the Energy Policy Act of 2005 expressly contemplates that parties will be able to rely post-repeal on Commission orders that have been issued prior to the effective date of repeal; and (ii) the Commission routinely issues forward-looking orders; financing orders, for example, routinely authorize a wide range of transactions that may or may not occur in the future.

     As noted above, Applicants believe the circumstances of this matter — a major merger involving an unprecedented amount of divesture and legislation that offers significant potential relief in connection with that divestiture — warrant Commission action. Applicants are asking the Commission to issue an order approving the Section 11(e) Divestiture plan before February 8, 2006. Commission inaction in this matter means that these benefits are irreparably lost.

     (a) Necessity for Plan

     As noted above, the proposed Divestiture is intended to address market power concerns under both the Federal Power Act and the 1935 Act and so, to enable the electric utility company operations of Exelon post-Merger to meet the standards of an integrated electric public-utility system.

     There does not appear to be any serious dispute that, but for repeal, the Commission would have “watchfully deferred” to the FERC’s findings concerning market power when reviewing the Merger under the standards of Section 10(b)(1) of the Act. Regardless of whether the Commission determines to issue a comprehensive Merger Order or instead focus on the Section 11(e) Plan and reserve jurisdiction over Applicants’ other requests, there is already a sufficient basis in the record to enable the Commission to conclude that the proposed Divestiture is “necessary” for purposes of mitigating market power concerns that might otherwise be associated with the Merger.

     Based on the FERC’s determinations, the Commission can similarly conclude that the Divestiture is “necessary” to ensure that the post-Merger electric-utility system is “not so large as to impair... the effectiveness of regulation.” As explained previously, the determination in this regard requires expertise in operational issues. The Commission has long recognized, and the courts have agreed, that it is appropriate for the Commission to “look to” or “watchfully” defer to the expertise of the FERC in matters such as these, involving the operation and regulation of competitive energy markets. See Madison Gas & Electric Co. v. SEC, 168 F.3d 1337, 1341-42 (D.C. 1999) (“when the SEC and another regulatory agency both have jurisdiction over a particular transaction, the SEC may ‘watchfully defer[]’ to the proceedings held before — and the result reached by — that other agency”), citing City of Holyoke Gas & Electric Department v. SEC, 972 F.2d 358 (D.C. Cir. 1992). Consistent with its precedent, the Commission therefore can properly rely on the FERC Merger Order in concluding that the proposed Divestiture is “necessary or appropriate to effectuate the provisions of Section 11(b)” of the 1935 Act.

     The Commission’s ability to rely on the FERC’s findings for purposes of anticompetitive concerns under Section 10(b)(1) is also relevant to its determinations under Section 11(b)(1). The relationship between the standards of Section 10 and 11 has been summarized in the Commission’s long-standing position that a company “cannot acquire what it cannot retain.” As the Commission, in Public Service Company of Oklahoma, Holding Co. Act Release 19090 (July 17, 1975), explained, the requirements of the two sections are integrally linked and, indeed, the purpose of Section 10 review is to avoid acquisition that would create issues for purposes of Section 11:

Sections 9 and 10 are preventive in purpose. Their essential function is to avoid recreating, by acquisition, what Section 11(b) was designed to undo or eliminate, and this statutory link is explicitly recognized in Section 10(c)(1) which prescribes that we not approve an acquisition that “is detrimental to the carrying out of the provisions of Section 11.” These reticulated provisions should be applied so as to effect their common purpose.

Although Public Service of Oklahoma involved nonutility interests, the principle applies to utility holdings as well. The Commission, in a 1978 decision, discussed this interplay at length:

The Act . . . focused on the elimination of the perceived abuses and excesses against which it was directed.

The key provision is Section 11(b) which requires the Commission, with narrow exceptions, to limit each holding company system to a single “integrated public-utility system” as defined in Section 2(a)(29). This provision has been referred to by the Supreme Court as the “heart of the Act,” and its implementation was a principal activity of the Commission during the early years of the Act’s history.

Various other provisions of the Act were designed . . . to prevent a recurrence of the practices which gave rise to the Act. * * * * * Section 10, in particular was intended to prevent acquisitions which would be “attended by the evils which have featured the past growth of holding companies.”

American Electric Power Company, Inc., Holding Co. Act Release No. 20633 (July 21, 1978) (footnotes omitted) (the “1978 Decision”).

     The 1978 Decision highlights the interrelation of the “size” standards of Sections 10(b)(1) and 11(b)(1) as means to a common end:

In the 1946 proceeding, AEP had applied for permission to acquire the stock of CSOE. There our predecessors, in a 2-1 decision, rejected AEP’s application on the basis that it did not satisfy the acquisition standards of the Act. The majority’s rationale was that “the

substantially enlarged group of properties that would result from the acquisition . . . cannot be found to be ‘not so large as to impair. . . the advantages of localized management and the effectiveness of regulation.’” The opinion . . . emphasized that an essential part of the spirit of the Act was the desire to avert the process of concentration of power which had characterized the growth of holding companies.

Emphasis added. While the Commission in the 1978 Decision did approve the CSOE acquisition, it did not abandon its long-standing position that a company cannot acquire what it cannot retain. Rather, the Commission focused on changed circumstances, including changes in the state of the art.¹¹ So, too, in this matter, would changes in the state of the art, in particular, the development of competitive wholesale energy markets under the stewardship of the FERC represent an important reason why market power — as well as geographic expanse — is an important factor in determining whether an electric-utility system is, in fact, so “large” as to impair the effectiveness of regulation. In this regard, the Divestiture that is necessary and appropriate to “avert the process of concentration of power” for purposes of Section 10(b)(1) is similarly necessary and appropriate to ensure that the acquisition that is the subject of the Section 10 review does not result in a system that is “so large . . . as to impair the effectiveness of regulation” for purposes of Section 11(b).

     The Commission has declared that “[a] plan is ‘necessary’ within the meaning of section 11(e), . . . if it accomplishes the objectives required by section 11(b) in an appropriate manner.” Midland Utilities, 24 S.E.C. 463, 475 (1946). “It thus seems clear that section 11(e) permits a company to propose particular transactions which under our ordinary practice we would not, or perhaps could not, specifically require by order under Section 11(b).” See also Mission Oil Co., 35 S.E.C. 540 (1954) (in which the Commission authorized a Section 11(e) plan to enable applicant to obtain tax relief). As explained in Northeast Utilities, supra, “The Commission has consistently held that a plan under Section 11(e) of the Act may be found “necessary” if it provides an appropriate means for achieving results required by Section 11(b) of the Act, although a different method may have been chosen, or though further action may be required to effectuate compliance with the standards of section 11(b).” Id. (footnotes omitted). The Applicants submit that the proposed Plan is a suitable means of accomplishing the required objective of assuring that the resulting system is not so large as to impair the effectiveness of regulation, and thus it meets the necessity standard of Section 11(e) of the Act.

     (b) Fairness

     Finally, there is no harm to the protected interests in the requested relief. If, for some reason, the Merger does not close, the order approving the Section 11(e) Plan will be of no effect. If, however, as Applicants anticipate, the Merger does close in the first half of 2006, the tax deferrals will contribute to the financial health of the merged company and so be in the “public interest” for purposes of the Act. Similarly, although the 1935 Act does not provide extra protection for shareholders of registered holding companies, the tax deferrals will clearly be beneficial to the interest of investors and, by bolstering the financial health of the merged company, similarly beneficial to the interests of consumers.

          American Electric Power, supra, n. 26.

Item 4. Regulatory Approvals

     New Jersey Board of Public Utilities (NJBPU)

     As a utility in the State of New Jersey, PSE&G is subject to the jurisdiction of the NJBPU. Under Section 48:2-51.1 of New Jersey’s public utility law, the NJBPU’s approval is required in connection with the indirect transfer of the capital stock of PSE&G resulting from the Merger. In considering the Merger, the NJBPU is required to evaluate the impact of the Merger in four areas: competition, the rates of ratepayers affected by the Merger, the employees of the affected public utility, and the provision of safe and adequate utility service at just and reasonable rates.

     On February 4, 2005, Exelon and PSE&G made the initial filing of their joint application with the NJBPU for approval of the indirect transfer of the capital stock of PSE&G resulting from the Merger. While New Jersey law does not specify a timetable for completion of the NJBPU’s review, Exelon and PSE&G expect the proceeding to be concluded in the first half of 2006.

     In addition, while not required by law to complete the Merger, Exelon and PSEG have made it a condition to the Merger that PSE&G receive an order from the NJBPU allowing PSE&G to defer certain pension and other post-retirement benefit expenses that will be recognized in connection with the purchase accounting treatment of the Merger, and providing that PSE&G’s rate recovery of pension and other post-retirement benefits will be calculated consistently with recovery of such amounts in the absence of the Merger.¹² On February 4, 2005, Exelon and PSE&G made the initial filing of their joint application with the NJBPU to obtain the order.¹³

     New Jersey Department of Environmental Protection (NJDEP)

     Subsidiaries of PSEG own facilities in New Jersey that are industrial establishments as defined in ISRA. The parties have already filed their application with NJDEP and have received a letter of non-applicability under ISRA with respect to the Merger, the Generation Restructuring and Merger related corporate restructurings during the first quarter of 2005.¹⁴

     New York Public Service Commission (NYPSC)

     As an owner of generation facilities in the State of New York, a subsidiary of PSEG Power is subject to the jurisdiction of the NYPSC. Under Section 70 of the New York Public Service Law, the NYPSC’s written consent is required in connection with the indirect transfer of ownership interests in such subsidiary of PSEG Power in connection with the Merger. Under Section 70 of the New York Public Service Law, the NYPSC must determine whether the Merger is in the public interest. The parties have already filed their application and have received approval with the NYPSC.¹⁵

     Pennsylvania Public Utility Commission (PAPUC)

     PECO and PSE&G are subject to the jurisdiction of the PAPUC. The issuance to each of PECO and PSE&G of a certificate of public convenience and necessity by the PAPUC may be required as a result of the indirect transfer of the capital stock of PSE&G in connection with the Merger under Chapters 11, 22 and 28 of the Public Utility Code of Pennsylvania. The standard for approval is whether the transaction is necessary and proper for the service, accommodation, convenience or safety of the public. This standard has been applied by the PAPUC to require that applicants demonstrate that the transaction will affirmatively promote the service, accommodation, convenience or safety of the public in some substantial way. In addition, under provisions enacted as part of Pennsylvania’s electric and natural gas restructuring legislation, the PAPUC must consider:

	•		whether a proposed transaction is likely to result in anticompetitive or discriminatory conduct, including the unlawful exercise of market power, which would prevent retail electric or natural gas customers in Pennsylvania from obtaining the benefits of a properly functioning and workable competitive retail electric or natural gas market; and
	•		the effect of the proposed transaction on the natural gas distribution company employees and authorized collective bargaining agreement.

     On February 4, 2005, PECO and PSE&G made the initial filing of their joint application for approval by the PAPUC under the Public Utility Code of Pennsylvania or a determination that Chapters 11, 22 and 28 are not applicable to the Merger.¹⁶

     On September 13, 2005, PECO announced that it had filed with the PAPUC a settlement of most issues raised in Pennsylvania’s review of the Merger.¹⁷  If the settlement is approved, PECO would provide $120 million over four years in rate discounts for customers and cap its rates through the end of 2010. The settlement also provides substantial funding for alternative energy and environmental projects, economic development, expanded outreach and assistance for low-income customers, and various corporate safeguards. The PAPUS administrative law judge has approved the settlement, and the matter is currently on the PAPUC agenda for January 27, 2006.

     Illinois Commerce Commission (ICC) ComEd has filed a notice with respect to the Merger with the ICC. Formal approval of the Merger by the ICC is not required.¹⁸

     Connecticut As the owner of generation stations in the State of Connecticut, PSEG Power Connecticut LLC, an indirect subsidiary of PSEG Power, is subject to the jurisdiction of the Connecticut Siting Council (“CSC”) under Connecticut public utility laws and the Connecticut Department of Environmental Protection (“CDEP”) under Connecticut environmental law. The indirect transfer of the ownership interests in these entities may require the approval of the CDEP and will require the approval of the CSC. The parties filed their application with the CSC on March 3, 2005 and received their approval. The parties intend to file their application for approval with the CDEP during the first quarter of 2005.¹⁹

     Nuclear Regulatory Commission (NRC)

     PSEG Power holds a NRC operating license for its Salem and Hope Creek nuclear generating facilities. This license authorizes PSEG Power to own and/or operate its nuclear generating facilities. The

Atomic Energy Act provides that a license may not be transferred or, in any manner disposed of, directly or indirectly, through transfer of control of any license unless the NRC finds that the transfer complies with the Atomic Energy Act and consents to the transfer. Therefore, the consent of the NRC is required for the transfer of control pursuant to the Merger of the license held by PSEG Power. The NRC will consent to the transfer if it determines that:

	•		the proposed transferee is qualified to be the holder of the license; and
	•		the transfer of the license is otherwise consistent with applicable provisions of laws, regulations and orders of the NRC.

     The parties have filed applications with the NRC,²⁰ and currently expect approval in the first quarter of 2006.

     Federal Energy Regulatory Commission

     On July 1, 2005, the FERC issued the FERC Merger Order.²¹ The changed merger review provision implemented by the Energy Policy Act of 2005 are not applicable to the Merger. In December of 2005, the FERC issued its order on rehearing, reaffirming approval of the Transaction, as described in Item 1. Certain parties have filed notices of appeal.

     In addition Exelon and PSEG are required by the FERC order to make appropriate filings under Section 205 of the Federal Power Act to implement the transaction.

     Antitrust

     Under the provisions of the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, (the “H-S-R Act”), the Merger cannot be completed until both Exelon and PSEG file a notification of the proposed transaction with the Antitrust Division of the United States Department of Justice (the “Antitrust Division”) and the Federal Trade Commission (“FTC”) and the specified waiting periods have expired or been terminated. The parties have been informed that the Antitrust Division will review the case and the FTC will not.

     The parties received a second request for information from the Antitrust Division and have certified substantial compliance with such request. The waiting period mandated by the H-S-R Act expired September 1, 2005. The Antitrust Division review continues notwithstanding such expiration but the parties do not expect a delay in closing will result.

     At any time before the Merger is completed, the Antitrust Division could challenge or seek to block the Merger under the antitrust laws, as it deems necessary or desirable in the public interest. Other competition promoting agencies with jurisdiction over the Merger could also initiate action to challenge or block the Merger. In addition, in some jurisdictions, a competitor, customer or other third party could initiate a private action under the antitrust laws challenging or seeking to enjoin the Merger, before or after it is completed. Based upon an examination of information available relating to the businesses in which the companies are engaged, Exelon and PSEG believe, with the market concentration mitigation plan they have proposed, that completion of the Merger will not violate United States or applicable foreign antitrust laws.

     The Merger may also be subject to review by the governmental authorities of various other jurisdictions under the antitrust laws of those jurisdictions.

     Federal Communications Commission

     The Federal Communications Commission (“FCC”) must approve the transfer of control of telecommunications permits or licenses. The Communications Act of 1934 prohibits the transfer, assignment or disposal in any manner of any license, or any rights thereunder, to any person without authorization from the FCC. PSEG’s subsidiaries hold telecommunications licenses and, together with the appropriate subsidiaries of Exelon, will seek the necessary approvals from the FCC for the assignment of or transfer of control over such licenses in connection with the Merger. Under the Communications Act, the FCC will approve a transfer of control if it serves the public interest, convenience, and necessity.

     Private Letter Ruling of the Internal Revenue Service

     Exelon and PSEG have received a ruling from the Internal Revenue Service (“IRS”) confirming that no gain or loss will be recognized for United States federal income tax purposes with respect to the transfer of PSEG’s nuclear decommissioning trust funds as a result of the Merger.

     Exelon will request that the IRS issue a private letter ruling confirming section 1081 tax treatment in respect of the Generation Transactions as and to the extent that Exelon will seek to utilize such tax treatment in respect of the divestiture of a particular generating unit. It is possible that the IRS may require Exelon to modify aspects of the structure of the Generation Transactions to obtain the private letter ruling. The Generation Transactions are deemed to include any such modifications to the extent such modifications allow Exelon to comply with the order of the Commission on the Applications and is otherwise acceptable to Exelon.

     Except as stated above, no state or federal regulatory agency other than the Commission under the Act has jurisdiction over the proposed Merger.

     NJBPU Approval Regarding PSE&G Securities Issuances

     The NJBPU has authority under N.J.S.A. 48:3-7, N.J.S.A. 48:3-9 and N.J.S.A. 14:1-5,9 to approve the issuance of securities by PSE&G. PSE&G, a New Jersey corporation, obtains approval from the NJBPU for all of its securities issuances, including both long-term and short-term debt securities. Its existing approvals include authority to issue up to $750 million of short-term debt through January 2, 2007 (Order of Approval, Docket No. EF04101117 (December 2, 2004)). Further, PSE&G has authority to issue various long-term debt securities in an amount not to exceed $525 million through December 31, 2005. (Order of Approval, Docket No. EF03121003 (April 28, 2004)). Accordingly, PSE&G is not seeking any approval from the Commission for the issuance of exempt securities, but will rely on Rule 52(a).

Item 5. Procedure.

     The Applicants request that the Commission’s order be issued as soon as the rules allow, and that there should not be a 30-day waiting period between issuance of the Commission’s order and the date on which the order is to become effective. The Applicants hereby waive a recommended decision by a hearing officer or any other responsible officer of the Commission and consent that the Division of Investment Management may assist in the preparation of the Commission’s decision and/or order, unless the Division opposes the matters proposed herein.

Item 6. Exhibits And Financial Statements.

		A.		Exhibits.
		A-1		Amended and Restated Articles of Incorporation of Exelon (incorporated by

				reference to Exhibit 3.1 to Exelon’s Registration Statement on Form S-4, filed May 15, 2000 (File No. 333-37082))
		A-2		Amendment to Amended and Restated Articles of Incorporation of Exelon (incorporated by reference to Exhibit 3.1 to Exelon’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, filed July 28, 2004 (File No. 001-16169))
		A-3		Form of Amendment to Amended and Restated Articles of Incorporation of Exelon, (incorporated by reference to Exhibit 4.1 to Exelon’s Registration Statement on Form S-4, filed February 10, 2005 (File No. 333-122074))
		B-1		Agreement and Plan of Merger between Exelon and PSEG, dated as of December 20, 2004 (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K, filed December 21, 2004 (File No. 001-16169))
		B-2		Exelon Indenture (incorporated by reference to Exhibit 4.1 to Exelon’s Registration Statement on Form S-3, filed March 27, 2001 (File No. 333-57540))
		B-3		Exelon Generation Indenture (incorporated by reference to Exhibit 4.1 to Exelon’s Registration Statement on Form S-4, filed April 4, 2002 (File No. 333-85496))
		B-4		Form of PSEG Mutual Services Agreement (to be filed by amendment)
		B-5		Description of Exelon Service Providers and existing agreements under State approved affiliated interest requirements (incorporated by reference to Exhibit B-3.3 to Exelon’s Application on Form U-1, filed October 18, 2000 (File No. 70-09645))
		C		Definitive joint proxy statement/prospectus, filed pursuant to rule 424(b)(3) on June 3, 2005 (File No. 333-122074) (incorporated by reference)
		D-1		Joint Application of Exelon and PSEG to the FERC regarding Merger, filed February 4, 2005 (excluding exhibits and testimony, which Applicant will supply upon request of the Commission.) (to be filed by amendment)
		D-2		Joint Petition of Exelon and PSE&G to the NJBPU for Approval of a Change in Control of PSE&G, and Related Authorizations, filed February 4, 2005 (excluding exhibits and testimony, which Applicants will supply upon request of the Commission) (to be filed by amendment)
		D-3		ComEd’s Notice of Holding Company Merger to the ICC, filed February 4, 2005 (excluding exhibits and attachments, which Applicants will supply upon request of the Commission) (to be filed by amendment)
		D-4		Joint Application of PECO and PSE&G to PAPUC for Approval of the Merger of PSEG with and into Exelon, filed February 4, 2005 (excluding exhibits and testimony, which Applicants will supply upon request of the Commission) (to be filed by amendment)
		D-5		Joint Application of Exelon and PSEG with NJDEP for Letter of Non-Applicability under ISRA (to be filed by amendment)
		D-6		Joint Application of Exelon and PSEG to NYPSC for Approval of Indirect Transfer of Ownership Interests (to be filed by amendment)

		D-7		Joint Request of PSEG Power Connecticut, LLC and Exelon Corporation to CSC for Approval of Transfer of Certificate of Environmental Compatibility and Public Need, filed March 3, 2005 (excluding exhibits and testimony, which Applicants will supply upon request of the Commission) (to be filed by amendment)
		D-8		Application of PSEG Nuclear LLC to NRC for Proposed License Transfer and Conforming License Amendments Relating to the Merger of PSEG and Exelon (excluding exhibits and testimony, which Applicants will supply upon request of the Commission) (to be filed by amendment)
		D-9		Application of Exelon Generation to NRC for Approval of License Transfers (excluding exhibits and testimony, which Applicants will supply upon request of the Commission) (to be filed by amendment)
		D-10		Application of AmerGen to NRC for Approval of Indirect License Transfers (excluding exhibits and testimony, which Applicants will supply upon request of the Commission) (to be filed by amendment)
		D-11		Order of the Federal Energy Regulatory Commission of July 1, 2005, “Order Authorizing Merger Under Section 203 of the Federal Power Act.”
		D-11.1		Federal Energy Regulatory Commission Order on Rehearing
		D-12		Joint Petition for Settlement (PAPUC) (to be filed by amendment)
		E-1		Map of combined transmission systems of Exelon and PSEG (to be filed by amendment)
		E-2		Map of combined gas service territory of Exelon and PSEG (to be filed by amendment)
		F		Opinions of counsel (to be filed by amendment)
		G-1		Diagram of Exelon’s Post-Merger Corporate Structure (to be filed by amendment)
		G-2		Diagram of Existing Corporate Structure of Exelon System (to be filed by amendment)
		G-3		Diagram of Existing Corporate Structure of PSEG System (to be filed by amendment)
		G-4		List of Generation Facilities Subject to Divestiture (to be filed by amendment)
		G-4-1		Subject Assets: Divestiture via Sale (previously filed)
		G-5		Description of all outstanding indebtedness and obligations of PSEG (to be filed by amendment)
		G-6		Description of all inter-company guaranties in PSEG system (to be filed by amendment)
		G-7		Analysis of Non-Utility Interests of PSEG (previously filed)
		G-8		Analysis of the Economic Impact of a Divestiture of the Gas Operations of PECO Energy Company (incorporated by reference to Exhibit J-1 to Exelon’s

				Application on Form U-1, filed March 16, 2000 (File No. 70-09645))
		G-9		Analysis of the Economic Impact of a Divestiture of the Gas Operations of PECO and PSE&G
		G-10		Additional information in connection with proposed Generational Divestiture (previously filed)
		G-11		Additional information in connection with proposed Generational Divestiture (previously filed)
		G-12		Additional information in connection with proposed Generational Divestiture (previously filed)
		G-13		Additional information in connection with proposed Generational Divestiture (previously filed)
		G-14		Additional information in connection with proposed Generational Divestiture (previously filed)
		H		Proposed Form of Notice (to be filed by amendment)

        B. Financial Statements.

		FS-1		Consolidated Balance Sheet of Exelon as of December 31, 2004 (incorporated by reference to Exelon’s Annual Report on Form 10-K for the year ended December 31, 2004, filed February 23, 2005 (File No. 1-16169))
		FS-2		Consolidated Statement of Income of Exelon for the year ended December 31, 2004 (incorporated by reference to Exelon’s Annual Report on Form 10-K for the year ended December 31, 2004, filed February 23, 2005 (File No. 1-16169))
		FS-3		Consolidated Balance Sheet of PSEG as of December 31, 2004 (incorporated by reference to PSEG’s Annual Report on Form 10-K for the year ended December 31, 2004, filed February 28, 2005 (File No. 1-09120))
		FS-4		Consolidated Statement of Operations of PSEG for the year ended December 31, 2004 (incorporated by reference to PSEG’s Annual Report on Form 10-K for the year ended December 31, 2004, filed February 28, 2005 (File No. 1-09120))

Item 7. Information as to Environmental Effects

     The proposed transaction involves neither a “major federal action” nor “significantly affects the quality of the human environment” as those terms are used in Section 102(2)(C) of the National Environmental Policy Act, 42 U.S.C. Sec. 4321 et seq. No federal agency is preparing an environmental impact statement with respect to this matter.

Item 8. Implementation of Section 1271(c) of the Energy Policy Act of 2005

     Repeal of the Act will become effective on the “Effective Date”. Notwithstanding such effectiveness, Section 1271(c) of the Energy Policy Act of 2005 provides that tax treatment under section 1081 of the Code as a result of transactions ordered in compliance with the Act shall not be affected in any manner due to repeal of the Act or enactment of PUHCA 2005.

     In order more fully to secure for the Applicants and their subsidiaries the benefits of tax treatment under section 1081, the Applicants undertake the following:

(i) notwithstanding the effectiveness of repeal of the Act, from and after the Effective Date, to comply with the Commission’s order to divest control, securities or other assets and for other

action by a company and/or subsidiary company thereof for the purpose of enabling the company or any subsidiary company thereof to comply with the provisions of subsections (b) and (e) of Section 11 of the Act (an “Implementation Order”) as to each and every condition ordered in the Implementation Order to the extent, but only to the extent, that such conditions also remain required pursuant to an order of the FERC or an order of any State or other Federal commission or an order of any State or Federal court; and

(ii) to submit to the authority of the FERC, from and after the Effective Date, in respect of such aspects of the Implementation Order that remain in force and effect (including, but without limitation, full power and authority to amend or change the surviving provisions of the Implementation Order as the FERC may deem necessary or appropriate in the circumstances).

     The Applicants consent and agree that consummation by them of the Merger shall constitute their acceptance of the survival of the Implementation Order as contemplated in this Item 8 notwithstanding the effectiveness of the repeal of the Act.

SIGNATURES

     Pursuant to the requirements of the Public Utility Holding Company Act of 1935, each of the undersigned companies has duly caused this amended Application/Declaration to be signed on its behalf by the undersigned thereunto duly authorized.

Date: January 20, 2006

Public Service Enterprise Group Incorporated		Exelon Corporation
Public Service Electric and Gas Company*		Exelon Energy Delivery Company, LLC*
PSEG Power LLC*		Exelon Business Services Company*
PSEG Energy Holdings L.L.C.*		Exelon Ventures, LLC*
PSEG Service Corporation				10 South Dearborn Street
80 Park Plaza				37th Floor
Newark, New Jersey 07102				Chicago, Illinois 60603
		PECO Energy Company*
* Including one or more subsidiaries				2301 Market Street
				Philadelphia, Pennsylvania 19101
		Exelon Generation Company, LLC*
				300 Exelon Way
				Kennett Square, Pennsylvania 19348
		* Including one or more subsidiaries

By Public Service Enterprise Group Incorporated				By Exelon Corporation
By:		/s/ R. Edwin Selover		By:		/s/ Elizabeth A. Moler
Name:		R. Edwin Selover		Name:		Elizabeth A. Moler
Title:		Senior Vice President and General		Title:		Executive Vice President
		Counsel				Government and Environmental Affairs
		Public Service Enterprise Group				and Public Policy
		Incorporated				Exelon Corporation
		80 Park Plaza				101 Constitution Avenue, NW
		Newark, New Jersey 07102				Suite 400 East
						Washington, DC 20001

Commonwealth Edison Company*
10 South Dearborn Street
37th Floor
Chicago, Illinois 60603

By Commonwealth Edison Company
By:		/s/ J. Barry Mitchell
Name:		J. Barry Mitchell
Title:		President
		One Financial Place
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EXHIBIT D-11

112 FERC ¶ 61,011
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners:		Pat Wood, III, Chairman;
		Nora Mead Brownell, Joseph T. Kelliher,
		and Suedeen G. Kelly.

Exelon Corporation		Docket No. EC05-43-000
Public Service Enterprise Corporation, Inc.

ORDER AUTHORIZING MERGER UNDER SECTION 203 OF THE FEDERAL POWER ACT

(Issued July 1, 2005)

1. In this order, the Commission authorizes the merger of Exelon Corporation (Exelon) and Public Service Enterprise Group Incorporated (PSEG Holdings) (collectively, Applicants) to form Exelon Electric & Gas Corporation (EE&G). This order benefits customers because it ensures that the transaction, which includes mitigation of market effects through very substantial divestiture of generation, is consistent with the public interest, as required by section 203 of the Federal Power Act¹ (FPA).

Background

     A. The Parties

2. Exelon is a registered holding company, under the Public Utility Holding Company Act of 1935 (PUHCA)² that distributes electricity to approximately 5.1 million customers in Illinois and Pennsylvania through its subsidiaries, mainly Commonwealth Edison (ComEd) and PECO Energy (PECO). Through ComEd and PECO, it is the Provider of Last Resort (POLR) for customers who do not or cannot exercise retail choice for their electricity needs in Illinois and Pennsylvania, respectively. Exelon is also involved in gas distribution through PECO. The PECO gas facilities are local distribution facilities that are not interstate facilities and, therefore, are not subject to the

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Commission’s jurisdiction under the Natural Gas Act.³ Exelon Generation Company, LLC (Exelon Generation) conducts Exelon’s generation business. Exelon Generation owns or controls generation assets throughout the country with a net capacity of approximately 33,000 MWs, including ownership interests in 11 nuclear generating stations.

3. PSEG Holdings is an exempt public utility holding company, under PUHCA, with four major subsidiaries, including Public Service Electric and Gas Company (PSE&G), which is a public utility company engaged in the transmission and distribution of electric energy and gas service to approximately 3.6 million customers, primarily in New Jersey. PSEG Holdings’ subsidiaries also include PSEG Power LLC, the parent company of most of PSEG’s United States power production business, PSEG Services Corporation, and PSEG Energy Holdings LLC, the parent company of PSEG’s other businesses.

4. Both Exelon and PSEG Holdings have transferred control of their transmission systems to the PJM Interconnection, LLC (PJM), a Commission approved Regional Transmission Organization (RTO). Both entities sell power under market-based rate authority.⁴

B. The Proposed Transaction

5. On February 4, 2005,⁵ Exelon and PSEG Holdings filed, under section 203 of the FPA and Part 33 of the Commission’s Regulations,⁶ an application for Commission approval of a transaction that includes: (1) Exelon’s acquisition of PSEG Holdings and the resulting indirect merger of Exelon’s and PSEG Holdings’ jurisdictional facilities; and (2) the internal restructuring and consolidation of Exelon’s and PSEG Holdings’ subsidiaries to establish an efficient corporate structure for EE&G.

6. PSEG Holdings would no longer have a separate corporate existence and would merge into Exelon, forming EE&G. PSEG Holdings’ shareholders would each receive 1.225 shares of Exelon common stock for each PSEG Holdings share held and cash in

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lieu of any fraction of an Exelon share that a PSEG shareholder would have otherwise been entitled to receive. EE&G will remain the ultimate corporate parent of PECO and ComEd and other Exelon subsidiaries and will become the corporate parent of PSE&G and all other PSEG subsidiaries. EE&G will assume all of PSEG Holdings’ outstanding indebtedness.

7. EE&G will be a registered public utility holding company under PUHCA. ComEd, PECO and PSE&G will continue to operate franchised public utility companies.

8. In addition to merging jurisdictional assets, Applicants intend to revise their corporate structure. They plan to make PSE&G a direct subsidiary of Exelon Energy Delivery Company LLC and keep the subsidiaries of PSE&G intact. PSEG Energy Holdings LLC will become a direct subsidiary of EE&G and the subsidiaries of PSEG Holdings LLC will remain intact. The PSEG Services Corporation will sell all of its assets to Exelon Business Services Company, making Exelon Business Services Company the sole “service company” of EE&G. PSEG Power and its direct subsidiaries, PSEG Nuclear, PSEG Fossil and PSEG Energy Resources and Trade, would all become part of Exelon Generation, and their business functions would become part of their respective Exelon Generation business units. The subsidiaries owned by PSEG Power, PSEG Nuclear, PSEG Fossil and PSEG Energy Resources and Trade, will either be merged into Exelon Generation or kept as direct subsidiaries of Exelon Generation. The reorganization will not result in merchant affiliates that have market-based rate authority being moved back into the regulated companies of EE&G.

9. Applicants state that the proposed merger will benefit the public interest by providing an increased scale and scope of both energy delivery and generation, improved service and reliability, and a more balanced generation portfolio to serve over seven million electric customers and two million gas customers. Applicants’ further state that the proposed merger will lead to improved stability, higher capacity utilization rates and lower costs from combining the nuclear operations under Exelon’s experienced management.

C. Standard of Review under Section 203

10. Section 203(a) provides that the Commission must approve a merger if it finds that the consolidation “will be consistent with the public interest.”⁷ The Commission’s analysis under the Merger Policy Statement of whether a consolidation is consistent with the public interest generally involves consideration of three factors: (1) the effect on

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competition; (2) the effect on rates; and (3) the effect on regulation.⁸ As discussed below, we will approve the proposed merger as consistent with the public interest and find that it will not adversely affect competition, rates, or regulation.

1. Effect on Competition

a. Applicants’ Analysis of Horizontal Competitive Issues

11. Exelon retained Dr. William Hieronymus and PSEG Holdings retained Mr. Rodney Frame to analyze the effect of the merger on competition. Both witnesses identify three relevant products: non-firm energy, capacity, and ancillary services, across the geographic markets affected by the merger. Both witnesses conclude that, as mitigated, the merger will not harm competition.

i. Energy Markets

12. Dr. Hieronymus identifies four relevant geographic markets using the approach described by Appendix A of the Merger Policy Statement: Expanded PJM, PJM Pre-2004, PJM East, and Northern PSEG.⁹ In his analysis of non-firm energy markets, Dr. Hieronymus uses economic capacity and Available Economic Capacity, as defined in the Merger Policy Statement, as proxies to represent a supplier’s ability to participate in the

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market.¹⁰ He uses the Delivered Price Test to evaluate the effect on competition in the relevant markets over 10 separate time periods: Super Peak, Peak and Off-Peak periods for Summer, Winter and Shoulder seasons, along with an extreme Summer Super Peak. Dr. Hieronymus uses a range of prices from $20 per megawatt hour (MWh) in the Shoulder Off-Peak to $250 per MWh in the extreme Summer Super Peak. He considers actual prices in the PJM markets during 2004, fuel prices in 2004, and forecast fuel prices for 2006, the test year for his analysis.¹¹

13. In his analysis, Dr. Hieronymus presumes simultaneous import limits for imports into each geographic market based on a study conducted by PSE&G’s transmission engineering group. The simultaneous import limits in his analysis are 7,300 MW for PJM-East; 4,600 MW for PJM Pre-2004; and 7,500 MW for Expanded PJM. Dr. Hieronymus allocates scarce transmission availability on a pro rata basis.

14. Dr. Hieronymus states that Exelon has several long-term contracts that are relevant to the analysis. Exelon has long-term contracts to purchase the output of two coal-fired generating plants and approximately 3,600 MW of supply from peaking facilities, all in the ComEd service territory. Dr. Hieronymus assigns control of that capacity to Exelon. Exelon sells 400 MW of the output of the Clinton nuclear unit under a long-term contract, and Dr. Hieronymus assigns control of that capacity to the buyer. He states that PSE&G has sold a substantial amount of energy and capacity in the New Jersey Basic Generation Service auction. He assigns control of that capacity to PSE&G. He does, however, consider those commitments as part of PSE&G’s native load deduction in his analysis of Available Economic Capacity.

15. Without mitigation, Dr. Hieronymus reports failures of the Competitive Analysis Screen¹² for economic capacity in all season/load conditions in PJM East, PJM Pre-2004, and Expanded PJM. For PJM-East, the screen failures are most severe, with post-merger market concentrations ranging from 2,057 to 2,492 on the Herfindahl-Hirschman Index (HHI) (indicating a highly concentrated market) and merger-related changes in HHI ranging from 848 to 1,067 HHI, all well above the 50 HHI screening threshold for highly

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concentrated markets. As stated in the Merger Policy Statement, for moderately concentrated markets (1000 = HHI < 1800), the screening threshold for the change in HHI is 100. For the PJM Pre-2004 and Expanded PJM markets, the post-merger HHIs indicate moderately concentrated markets, with merger-related increases in HHI ranging from 172 to 668 HHI, all above the 100 HHI screening threshold for moderately concentrated markets.

16. For the other markets that could be affected by the merger, Northern PSEG, Electric Reliability Counsel of Texas (ERCOT) and ISO New England, Inc. (ISO-NE), Dr. Hieronymus does not perform a complete competitive screen analysis, but explains why he thinks such an analysis is not necessary and why the merger will not harm competition in those markets.

17. For Northern PSEG, Dr. Hieronymus argues that because Exelon does not own any generation in that market, the merger will not harm competition. He states that when there are not binding transmission constraints for imports into Northern PSEG, the geographic boundaries of the market are at least as broad as PJM-East, and he states that Applicants’ proposed mitigation will offset any increase in market concentration in that market.¹³ He argues that when there are import constraints for Northern PSEG, it should be considered a separate market from PJM East. However, in that case, the merger will not increase the amount of capacity controlled by the merged firm or its incentive to withhold generation to raise prices, because Exelon does not own any capacity in Northern New Jersey, so there is no overlap between the Exelon and PSE&G’s generation capacity in that market. Despite his argument, Dr. Hieronymus does analyze Northern PSEG and shows screen failures due to some of Exelon’s capacity being included in the pro rata allocation of transmission availability. His analysis shows post-merger concentrations ranging from 2,750 to 7,288 HHI, with merger-related increases in concentration ranging from 99 to 204 HHI. He finds that divesting 100 MW of generating capacity in Northern PSEG would return market concentration levels to approximately the pre-merger levels, with the concentration increasing by less than 50 HHI for some load levels and falling in others. He states that if the Commission decides it is necessary to mitigate the screen failures, Applicants would divest sufficient generation in the Northern PSEG market as part of their overall divestiture plan.

18. Dr. Hieronymus argues that there is little overlap between Exelon and PSE&G’s generation assets in the ERCOT market. He states that Exelon owns or controls 3,651 MW of generation capacity, mostly in the North zone of ERCOT, while PSE&G owns 2,026 MW of affiliated generation capacity in the West and South zones. He argues that because Applicants’ capacity is in different zones within ERCOT, the only market that

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could be affected by the merger is ERCOT as a whole. He states that Exelon and PSE&G’s capacity in ERCOT is less than five percent and 2.5 percent respectively, so the merger-related change in HHI would only be approximately 20 HHI, well under Commission’s screening threshold.¹⁴

19. For the ISO-NE market, Dr. Hieronymus also argues that, because Exelon’s and PSE&G’s generation is in different constrained regions, the smallest relevant market in which both Applicants’ generation would compete would be ISO-NE as a whole. He concludes that because Exelon and PSE&G control only two and three percent of the generation capacity in ISO-NE, combining such small market shares would not harm competition.¹⁵

20. PSE&G’s witness, Mr. Frame, also analyzes non-firm energy markets, using economic capacity and Available Economic Capacity to represent a supplier’s ability to participate in the market. Mr. Frame analyzes three geographic markets using the approach described by Appendix A of the Merger Policy Statement: Expanded PJM, PJM Pre-2004, PJM East. He uses the Delivered Price Test to analyze the effect of the merger on market concentration. Like Dr. Hieronymus, Mr. Frame uses ten season/load conditions. He uses a range of prices from $30 to $150 per MWh based on prevailing market-clearing prices in PJM over the last two years for the relevant season/load conditions. He allocates scarce transmission availability on a pro rata basis and imposes simultaneous imports limitations in his analysis. Mr. Frame states that he follows the Commission’s procedures by assigning control of generation under contract to the party that has operational control of the facility.

21. Mr. Frame’s results are consistent with those of Dr. Hieronymus. He reports screen failures in PJM-East and Pre-2004 PJM for all season/load conditions, and in Expanded PJM for most season/load conditions. For PJM-East, he reports post-merger

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concentrations ranging from 1,688 to 2,816 HHI, with merger-related changes in HHI ranging from 695 to 1,252 HHI, all well above the Commission’s screening thresholds. For Pre-2004 PJM, he reports post-merger concentrations ranging from 1,133 to 1,509 HHI, with merger-related changes in HHI ranging from 336 to 443 HHI, all well above the Commission’s screening thresholds. For Expanded PJM, he reports post-merger concentrations ranging from 919 to 1,197 HHI, with merger related changes in HHI ranging from 178 to 236 HHI, with six of the ten season/load conditions above the Commission’s screening thresholds.

22. Dr. Hieronymus also performs a Competitive Analysis Screen for Available Economic Capacity in Expanded PJM, PJM Pre-2004, PJM East, and Northern PSEG. However, he argues that Available Economic Capacity is not an accurate measure in PJM because utilities have been largely released from their native load obligations in states with retail choice programs; or serve as providers of last resort through power purchase agreements, or, in the case of New Jersey, through the Basic Generation Service auction. He reports screen failures in eight of the 10 season/load conditions in PJM East,¹⁶ all season/load conditions in PJM Pre-2004, and none of the season/load levels for Expanded PJM.

23. Mr. Frame also performs a Competitive Analysis Screen for Available Economic Capacity in Expanded PJM, PJM Pre-2004, and PJM East. He states that Available Economic Capacity is difficult to measure in PJM because native load obligations have changed in states with retail choice programs, standard offer services and Basic Generation Service auctions. He states that the purpose of his Available Economic Capacity analysis is to show that the mitigation offered to address the screen failures in the Economic Capacity analysis will mitigate any Available Economic Capacity screen violation. He states that he uses conservative assumptions for his Available Economic Capacity analysis and reports screen failures for most season/load conditions for those markets, all of which are eliminated by the mitigation.

24. Like Dr. Hieronymus, Mr. Frame argues that it is not necessary to analyze the effect of the merger on competition in the Northern New Jersey market because Exelon does not own any generation in that market. He does, however, analyze Northern New Jersey by starting with his analysis of the PJM East market, removing suppliers located in

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Northern New Jersey, and then allocating the import capability into Northern New Jersey among the PJM East suppliers.¹⁷ He states that based on his analysis, divesting approximately 100 MW of generation capacity, including at least 80 MW of coal-fired capacity within Northern New Jersey, would eliminate any screen violations in the Northern New Jersey Market.

ii. Mitigation for identified screen failures

25. Applicants propose mitigation to address the harm to competition indicated by the screen failures. First, they propose divesting 2,900 MW of generation capacity in PJM-East in order to eliminate the peak and super-peak screen failures described above. The 2,900 MW would consist of 1,000 MW of peaking generation and 1,900 MW of mid-merit generation, of which at least 550 MW would be coal-fired capacity. They state that no more than half of the 2,900 MW would be sold to a single buyer and that no capacity would be sold to a market participant with a greater than five percent market share in PJM-East or Expanded PJM (original Buyer Restrictions).¹⁸ Applicants note that they have not yet identified the specific generation units that they intend to divest. They do, however, list those generating units that will be considered for divestiture.¹⁹ Applicants also state they will make a compliance filing showing the effect on market concentration given the actual divestitures.

26. Applicants originally committed to complete the divestiture within 18 months after the date of merger consummation, but later committed to complete the divestiture within 12 months.²⁰ They recognize that the Commission requires that interim mitigation for any merger-related harm to competition be in place at the time of merger consummation. Accordingly, they propose that within 30 days following the end of the month in which the merger closes, they will sell the rights to 2,900 MW of energy and capacity from

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designated coal, mid-merit and peaking facilities in PJM—East. ²¹ As with the permanent mitigation, they state that no more than half of the 2,900 MW would be sold to a single buyer and that no capacity would be sold to a market participant with a greater than five percent market share in PJM-East of Expanded PJM. The interim contracts will have a minimum term of one month and will be in effect for no longer than 18 months after merger consummation. Applicants explain that the purchasers of the interim capacity and energy will acquire all of the Unforced Capacity associated with the units, and full dispatch unit and offering rights, including the right to call for market-based ancillary services, thus enabling the purchaser to offer the units into the PJM capacity, energy and ancillary services markets.²²

27. Applicants propose a “virtual divestiture” to address the Appendix A screen failures for the off-peak periods. They will sell long-term energy rights from nuclear baseload units.²³ They state that the virtual divestiture will remove any merger-related increase in Applicants’ ability or incentive to withhold baseload energy in order to exercise market power. Applicants propose virtually divesting 2,250 MW of energy from nuclear units located in PJM-East in order to address the screen failures in that market.²⁴ They note that Dr. Hieronymus’ analysis shows that an additional divestiture of 200 MW of capacity in the larger Pre-2004 PJM market is also required and, accordingly, they will virtually divest another 200 MW of baseload nuclear energy in the larger, Pre-2004 PJM market.

28. Applicants state that the virtual divestiture will take one of two forms: (1) a firm sales contract expiring no earlier than 15 years after the date of the merger consummation (Long-Term Contract Option); or (2) an annual auction of 3-year entitlements to baseload energy, in 25 MW blocks. Applicants state that the auction process will be administered

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by an independent auction manager in order to ensure a transparent and objective auction process.²⁵ The sum of the baseload energy entitlements sold under the two options will be 2,450 MW (Baseload Mitigation Amount), unless, as described below, the Baseload Mitigation Amount needed to mitigate harm is reduced by other structural mitigation measures. In addition, no single purchaser will be allowed to purchase more than 50 percent of the Baseload Mitigation Amount.

29. Applicants state that under the Long-Term Contract Option, they will sell entitlements to PJM East baseload nuclear energy for terms of at least 15 years in return for cash or similar rights to energy taken for delivery outside of PJM (Energy Swap). Applicants originally committed to the divestiture restrictions regarding the potential purchasers under the Long-Term Contract Option, and, additionally, committed that they will not sell more that 25 percent of the Baseload Mitigation Amount to market participants owning three to five percent of the installed generation capacity in Expanded PJM or PJM East.²⁶

30. Applicants state that, under the auction option, the auctions will be held to coincide with the New Jersey Basic Generation Service auctions. The product to be auctioned will be a three-year obligation to take 25 MW of “7 x 24” energy. In the first year, the auction will be phased in by selling one third of the capacity for a one-year term, one third of the capacity for a two-year term, and one third of the capacity for a three-year term. In subsequent years, one third of the capacity will be sold for a three-year term.²⁷

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31. Dr. Hieronymus analyzes the effect of the merger, given Applicants’ proposed mitigation, and finds that the merger would not harm competition. For PJM-East, the merger-related changes in concentration range from falling by 101 HHI in the Winter Peak period to rising by 63 HHI in the Winter Super Peak period. The post-merger and mitigation markets are moderately concentrated for all season/load conditions, with the change in market concentration falling within the Commission’s tolerance for all periods. For PJM Pre-2004 and PJM Expanded, with mitigation, the markets are moderately concentrated in 14 of the 20 total season/load conditions and unconcentrated in the other 6 season/load conditions. With exception of one season/load condition in each market, all of the changes in concentration are within the Commission’s tolerances. Dr. Hieronymus concludes that Applicants’ proposed mitigation eliminates any harm to competition indicated by the screen failures in his analysis of economic capacity. In addition, the proposed mitigation would reduce market concentration below the pre-merger level in the three PJM markets in all season/load conditions for Available Economic Capacity. Therefore, he also concludes that the proposed mitigation eliminates any harm to competition indicated by the screen failures in his analysis of Available Economic Capacity.

32. Mr. Frame also finds that the proposed mitigation would eliminate the harm to competition in energy markets indicated by the screen failures in economic and Available Economic Capacity. Mr. Frame finds that the proposed mitigation would reduce market concentration below the pre-merger level in the three PJM markets in virtually all season/load condition for Available Economic Capacity. For economic capacity, he finds that the post-merger and mitigation markets will be moderately concentrated for 15 of the 30 season/load condition in the three PJM market scenarios and unconcentrated for the other 15 season/load conditions, with all changes in HHI falling within the Commission’s tolerance levels.

Notice of Filing and Pleadings

33. Notice of Applicants’ filing was published in the Federal Register,²⁸ with interventions and protests due on or before April 11, 2005. Numerous parties filed motions to intervene.²⁹ The Pennsylvania Public Utility Commission, the New Jersey

(continued...)

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Board of Public Utilities and the Illinois Commerce Commission filed notices of intervention. Additionally, several parties filed motions to intervene and protests and some parties file motions to intervene and comments³⁰. Allegheny Electric Cooperative,

Power Associates, LP (LS Power); Constellation Energy Commodities Group, Inc. (CCG), together with Constellation Generation Group, LLC (CGG), and Constellation NewEnergy, Inc. (CNE) (collectively, Constellation); American Electric Power Service Corporation (AEP); Wisconsin Electric Power Company (Wisconsin Electric); East Coast Power LLC (ECP); New Jersey Large Energy Users Coalition (NJLUPC); Mid-Atlantic Power Supply Association (MAPSA); UGI Development Company (UGID); and TXU Portfolio Management Company (d/b/a TXU Wholesale Markets) (TXU).

(continued...)

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Inc. (Allegheny Electric), Indiana Utility Regulatory Commission, and H-P Energy Resources LLC each filed motions to intervene out-of-time.

34. Three individuals³¹ filed comments in this proceeding expressing concerns about the proposed merger and the effect it would have on individual consumers and the future energy markets. We find that the issues raised by the individual commentors are outside the scope of this proceeding.

A. Protests

35. Protestors state claims of factual errors in Applicants’ analyses: (1) Hoosier contends that Dr. Hieronymus understated the amount of generation controlled by Applicants when developing the Competitive Analysis Screen because he failed to include a 200 MW power purchase agreement between PECO and Hoosier in 2006; (2) the PHI Companies state that Conectiv Energy Services, Inc. only controls 2,595 MW of generating capacity in PJM East rather than the 4,800 MW used in Applicants’ analyses; (3) the analyses should have included the PPL Companies recently-completed 600 MW Lower Mount Bethel combined cycle facility; and (4) the analyses failed to account for Dominion’s native load obligation in the calculation of Available Economic Capacity. Some protestors, including the PHI Companies, argue that given the material issues of fact raised by inaccuracies in Applicants’ analysis, a hearing is necessary.

36. A number of protestors argue that Applicants have not analyzed all of the geographic markets that will be affected by the merger. The POCA argues that Dr. Hieronymus and Mr. Frame understated the extent of market concentration resulting from the proposed merger and that it is unclear whether Applicants analyzed all relevant load pockets and geographic markets, especially the Northern New Jersey load pocket.

37. Protestors argue that Dr. Hieronymus failed to analyze the merger’s effect on markets in PJM other than PJM- East, PJM Pre-2004, and PJM-Expanded.

the City of Philadelphia (collectively, City of Philadelphia); and H-P Energy Resources, LLC (H-P Energy). Comments were filed by the American Antitrust Institute (AAI); Williams Power Company (Williams); and the New Jersey Board of Public Utilities (NJBPU).

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38. Environmental Law and Policy Center is concerned about the effects that the proposed merger would have on market power in the Midwest ISO markets and its effect on the interconnection between the Midwest ISO and the PJM markets.

39. FirstEnergy, through its expert, Ms. Julia Frayer, argues that Applicants’ Appendix A analysis underestimates the Applicants’ combined post-merger market power, understates the ` levels in the relevant PJM markets and leads to Applicants’ proposal of inadequate mitigation. Ms. Frayer specifically questions Dr. Hieronymus’ fuel price and market price assumptions. She performs an alternative analysis showing higher concentration levels and merger-related changes in concentration, and, thus, higher amounts of capacity needing to be divested. Other protestors, including the New Jersey Advocate, question assumptions in Dr. Hieronymus’ analysis and argue that he should have performed tests of sensitivity of his results to changes in the underlying assumptions. They conclude that a hearing is necessary to determine the accuracy of his assumptions and any effects on his results.

40. FirstEnergy argues that Applicants overestimate the entry of new generation and underestimate the retirement of old generation, thus overstating the degree of competition in PJM and understating the merger’s effect on competition. Ms. Frayer argues that when Dr. Hieronymus’s erroneous assumptions regarding entry and exit (along with other assumptions she questions) are corrected, post-merger concentration levels are as high as 2,818 HHI, calling for up to 900 MW more capacity to be divested in order to mitigate the harm to competition.

41. Hoosier also raises questions regarding the model that Applicants used to perform the Competitive Analysis Screen. It states that Applicants should be required to submit studies regarding the effect the increased consolidation of suppliers as a result of the proposed merger would have on market power concentration in PJM and other affected markets. Hoosier specifically questions Dr. Hieronymus’ use of a pro-rata allocation of scarce transmission availability rather than an economic allocation, which it asserts is more accurate and which would result in greater merger-related changes in market concentration and thus a need for a larger amount of generation divestiture. Hoosier argues that if the Commission does not reject the application outright, then the Commission should establish an evidentiary hearing to address the issues of fact raised by the proposed merger. The PPL Companies also protest the lack of support for Applicants’ use of the ‘squeeze down’³² method to allocate imports into the relevant PJM

(continued...)

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markets and the failure to address the effect of Applicants’ Financial Transmission Rights on transmission capacity in the affected markets.

42. The PHI Companies question the value of Applicants’ Available Economic Capacity analysis because state-level restructuring is at different stages in the various PJM states. Thus, the deduction for native load obligations used in Available Economic Capacity analysis does not accurately reflect competitive conditions in the various PJM geographic markets analyzed by Dr. Hieronymus. The PHI Companies also argue that the native load deduction in Dr. Hieronymus’s Available Economic Capacity analysis is incorrect because it imputes PECO’s provider of last resort obligations to PECO’s affiliated generating companies, which violates the Commission’s policy requiring regulated, load-serving companies to stand at arm’s length from their marketing affiliates. In addition, PPL’s witness, Dr. Kalt, argues that although Available Economic Capacity analysis in PJM East is “not straightforward,” there is sufficient data on buyer and seller transactions in New Jersey to develop a more refined analysis that would ensure that Applicants’ proposed divestitures will pass the Competitive Analysis Screen for Available Economic Capacity. He concludes that by failing to satisfy the Commission’s requirements and not properly analyzing Available Economic Capacity, Applicants may have substantially underestimated post-merger concentration levels in both PJM East and PJM Pre-2004.³³

43. Some intervenors argue that the merger will increase Applicants’ ability to exercise market power through strategic bidding and that Applicants have not sufficiently analyzed the merger’s effect on strategic bidding in the relevant markets. Furthermore, the New Jersey Division of the Ratepayer Advocate (Division of the Ratepayer Advocate) states that the Competitive Screen Analysis submitted by Applicants raises several questions. It argues that data published by PJM shows that the PJM East markets are substantially more concentrated than Applicants’ analysis suggests and that the Applicants’ methodologies might not detect certain market power problems, such as strategic bidding concerns. The Division of the Ratepayer Advocate also argues that the mitigation measures proposed by Applicants do not adequately address the market power problems created by the proposed merger. In addition, POCA argues that Applicants have not analyzed the potential for strategic bidding or other actions that could increase prices in the PJM market.

to the amount of economic capacity each supplier has outside of the interface. Application, Exhibit J-4 at 10-11.

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44. Direct Energy argues that Applicants’ market power analysis significantly understates Applicants’ potential market power after the merger. Direct Energy’s expert witness, Dr. Andrew Kleit, argues that the merger significantly enhances the merged firms’ ability to unilaterally exercise market power by withholding output of key generation resources along the market supply curve. Dr. Kleit compares Applicants’ post-merger costs of withholding output (foregone revenue) to the benefits (higher prices), and finds that the benefits of withholding the output of peaking facilities are significantly enhanced by the merger. Dr. Kleit concludes that the merger enhances the incentive of the merged firm to exercise market power through withholding of output from peaking facilities. He recommends that the Commission analyze the costs and benefits of withholding from each of the merged firm’s peaking facilities.

45. Some parties argue that the Commission does not apply the Competitive Analysis Screen as a bright line test and that the Applicants, by proposing mitigation specifically designed to restore the concentration level to within the screens’ tolerances, have misinterpreted the Commission’s merger policy. For example, the PPL Companies argue that tools such as market share and HHI screens “provide only the starting point” for assessing the competitive implications of a merger.³⁴ They argue that the issue is whether the divesture will result in a market structure that is sufficiently competitive, not whether a particular HHI level is achieved.

46. A number of parties protest Applicants’ proposed Buyer Restrictions. The PPL Companies’ witness, Dr. Kalt, argues that market forces should determine who acquires the divested assets and at what price. He further argues that the restrictions may harm market efficiency by not allowing those buyers that could most efficiently use the generation resources to participate in the auction.³⁵ The AAI argues that giving Applicants control of the divesture process is “akin to the fox guarding the henhouse.”³⁶ It notes that a Federal Trade Commission (FTC) Staff Study showed that when the FTC

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determined the assets that were to be divested, merging companies urged the FTC to divest assets to weak buyers; proposed packages of assets that were too narrow to ensure fully viable competition; and took actions that diminished the viability of the business acquired by the buyer.³⁷

47. Midwest Generation states that the Commission should consider whether Applicants’ proposed Buyer Restrictions are reasonable; it says that they could undermine Applicants’ ability to fully divest the assets necessary to mitigate the market power problem. Therefore, the Commission should consider requiring Applicants to eliminate the restrictions or, in the alternative, require Applicants to identify an alternative should their restrictive divestiture plan fail.

48. Protestors argue that Applicants’ proposed virtual divestiture is not as effective as physical divestiture for a number of reasons. Hoosier requests that the Commission reject Applicants’ virtual divestiture proposal and require absolute and permanent divestiture of ownership. The APPA and NRECA state that the proposal is inadequate to remedy the potential market power abuses that will result from the proposed merger. Additionally, POCA argues that virtual divestiture has never before been relied upon by the Commission as a mitigation tool and that it is not a permanent structural change.

49. Regarding the virtual divestiture proposal, FirstEnergy argues that Applicants must submit the terms and conditions of the long-term contracts; specify the auction protocols; include the long-term rights to capacity as well as energy so that there is sufficient capacity-related mitigation; and enter into long-term, firm contracts for nuclear energy and capacity, or impose bid caps for the non-nuclear assets that are more likely to set prices. It also states that the PJM Market Monitoring Unit (MMU) must monitor the implementation of the interim mitigation measures. FirstEnergy also questions the practical effects of virtual divestiture, such as how the Applicants’ market power will be held in check after the long-term contracts expire, and what Applicants will do if there are not enough purchasers in the auction process or those buyers default. In addition, FirstEnergy states that Applicants will obtain a market price for their energy, and questions whether the energy sales are actually mitigation if Applicants are able to receive the same price (i.e., post-merger, post-mitigation) for the energy that they would have received without mitigation.³⁸

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50. FirstEnergy argues that the Commission rejected partial divestiture in the AEP/CSW merger³⁹ for the reasons stated above. It states that, in that case, the Commission rejected applicants’ proposal to divest a minority interest in a generating facility while retaining operational control over the output of the facility, and required applicants to divest their entire ownership interest in the generating facilities at issue.⁴⁰ Finally, FirstEnergy argues that the Commission rejected a proposal similar to Applicants’ baseload auction in Allegheny/DQE⁴¹, where the Commission expressed concern that the entire output of the facility in question would not be sold under the proposed RFP, and stated:

Divestiture would permanently eliminate the opportunity for the merged company to exercise the market power (by withholding output to raise electricity prices) conferred on them by the merger.⁴²

51. AAI also finds flaws in Applicants’ proposed divestiture plan, arguing that it does not provide sufficient information to satisfy concerns such as the need to create viable, independent competitors in the markets. Specifically, AAI argues that Applicants’ proposed virtual divestiture would allow Applicants to keep ownership and control of the capacity while they sell or swap the energy to third-party purchasers and that this would not adequately address the market power concerns raised by the proposed merger or create a viable competitor in the market. Another problem is that with Applicants controlling the virtual (and actual) divestiture process, the Commission could not modify or oversee the divestiture plans; and Applicants would have little incentive to divest and mitigate in a way that would create viable competitors and markets. AAI also argues that Applicants have not demonstrated the claimed efficiencies or other benefits that would allegedly result from the merger, particularly Applicants’ nuclear assets. Finally, AAI notes that the antitrust agencies prefer structural mitigation, such as divestiture, to conduct-based remedies, which are often difficult to design, cumbersome and costly to administer, and easier to circumvent than structural remedies.⁴³

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52. The City of Philadelphia also protests Applicants’ use of virtual divestiture. The Office of the People’s Counsel claims that Applicants do not sufficiently explain how virtual divestiture will effectively mitigate market power. Therefore, they state that the Commission should establish hearing procedures to address the validity of the proposed mitigation and to explore how the mitigation, including the proposed virtual divestiture, will remedy the market power problems and screen failures resulting from the proposed merger.

53. Amtrak argues that the Applicants fail to set forth the legal basis for using the virtual divestiture as permanent mitigation and fail to demonstrate its effectiveness. Furthermore, Amtrak argues that the proposed virtual divestiture is not a permanent mitigation measure, since control of all generation will return to the merged entity after a fixed time period. Amtrak also argues that the PJM Market Monitoring Unit (MMU) is unable to compensate and adequately administer the unduly complicated and administratively burdensome proposed virtual divestiture.

54. The PHI Companies state that virtual divestiture is unacceptable because it fails to transfer control over the units’ operation, including the scheduling and duration of maintenance outages, and because the actual merged entity, and its market power, will outlast the virtual divestiture. The PHI Companies argue that the three year baseload auction energy sales might not continue over the proposed 15-year period, and urge the Commission to evaluate the actual mitigating effects of the virtual divestiture and impose certain conditions on the virtual divestiture. The PHI Companies’ economic witness, Dr. Cichetti, argues that the three-year and 15-year contracts do not adequately mitigate Applicants’ market power because the nuclear units would not be divested and would still be controlled by EE&G, which will be able to affect market prices in the Basic Generation Service auction. He concludes that the virtually divested MWs should be considered to be controlled by EE&G in Dr. Hieronymus’ Appendix A analysis. Therefore, in order to fully evaluate the effect on the PJM markets and the validity of Applicants’ mitigation plan, the PHI Companies request that the Commission establish an evidentiary hearing.

55. The NJBPU states that it is concerned about the creation of significant market power in the PJM markets involved in the state’s Basic Generation Service auctions and the effect that that market power would have on the Basic Generation Service auction process. The NJBPU asked the PJM MMU to study the effects of the proposed merger on competition in all relevant PJM markets. It also raises several concerns regarding Applicants’ proposed mitigation plan and the effect the mitigation would have competition in the relevant PJM markets. Therefore, the NJBPU requests that the Commission establish an evidentiary hearing to fully evaluate all aspects of Applicants’ proposed merger.

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56. The Illinois Attorney General states that the merger would exacerbate already existing market power problems in the PJM markets that influence the prices paid for electricity by Illinois customers. It states that the Illinois Commerce Commission is in the process of approving an auction similar to the Basic Generation Service auctions that take place in the New Jersey markets, and argues that the proposed merger could undermine the ability of the proposed auction to secure electricity at competitive prices for Illinois consumers. Therefore, the Illinois Attorney General requests that the Commission set this matter for hearing.

57. AAI argues that Applicants’ failure to specify which units will be divested allows Applicants to divest the units that are least likely to compete with the assets kept by Applicants. Similarly, numerous parties, including Hoosier, AAI, the PHI Companies, FirstEnergy, the PPL Companies and the Division of the Ratepayer Advocate, argue that Applicants’ mitigation plan fails to comply with the Commission’s requirements by failing to specify which of Applicants’ facilities would be divested.⁴⁴

58. FirstEnergy’s witness, Ms. Frayer, raises a number of concerns regarding Applicants’ interim mitigation proposal. Specifically, she argues that: (1) Applicants have not provided sufficient detail about the interim mitigation;⁴⁵ (2) there must be a credible and transparent means of oversight over Applicants’ enforcement of the interim auctions, as the Commission recognized in OG&E;⁴⁶ and (3) Applicants’ proposal to bid the nuclear capacity into the PJM markets at a $0 price does not mitigate market power because the nuclear plants do not set the market-clearing price.

59. Protestors also point out that transmission expansion is a form of market power mitigation. FirstEnergy argues that the Commission should consider what studies the PJM MMU might perform to identify the specific transmission enhancements Applicants could be required to construct to relieve congestion in PJM East as a condition of merger approval. The PHI Companies argue that Applicants may have positions in the PJM queue for generation interconnection projects and that they should be required to

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relinquish these positions in order to enable other parties to construct generation in the affected markets, thus limiting the merged company from re-establishing its pre-mitigation market power.⁴⁷

60. The PHI Companies argue that the sheer size of the merged company (nearly 40,000 MW of generation in PJM) creates market power problems that the Commission’s Competitive Analysis Screen does not address. POCA also argues that the size and scope of this proposed merger will present opportunities for the merged entity to wield market power, even after the proposed mitigation and divestiture. POCA points out that Applicants would still own 37,100 MW of generation in PJM, including 14,400 MW, or 36 percent of the capacity in PJM East, the most constrained market in PJM.

61. Protestors question how the proposed merger will affect Applicants’ authorization to sell power at market-based rates. First Energy’s witness, Ms. Frayer, performed an analysis which she characterized as being required for Applicants to be able to continue to sell power at market-based rates, and concluded that Applicants would fail the 20 percent market share screen.⁴⁸ While acknowledging that this case is under section 203 of the FPA, not section 205, FirstEnergy concludes that the Commission will have to address the issue of the merged firm’s market-based rate authorization, and that the Commission should make a decision in the 203 proceeding that will “pass muster” in the related section 205 market-based rate proceedings.⁴⁹ FirstEnergy argues that when the 20 percent market share threshold is violated, which Ms. Frayer shows will occur even when Applicants’ proposed mitigation plan is imposed, the Commission then requires a delivered price test — which is exactly what the Applicants performed in this section 203 proceeding. Dominion’s witness, Mr. Frank Graves, also finds that, even with mitigation, Applicants will have a greater than 20 percent market share in Expanded PJM, and that Applicants would need to divest an additional 1,200 MW in order to pass the Commission’s market share screen for market-based rate authorization.

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62. Dominion argues that the market-share screen failure indicates that Applicants will have market power in PJM and urges the Commission to reject any argument that the PJM MMU can address market power issues in the PJM market. Amtrak, the Coalition and the Energy Users Group also argue that the Commission should not rely on the PJM MMU to identify and prevent exercises of market power.

63. FirstEnergy states that Applicants have not provided any details regarding their planned reorganization of the “unregulated” entities owned by Exelon and PSE&G, and argues that the Commission cannot find that the reorganization will be consistent with the public interest until Applicants provide details. FirstEnergy states that in Ameren Energy, the Commission recognized that some types of internal reorganizations can harm competition, and asserts that the Commission cannot act on Applicants’ proposed internal restructuring based on the limited information provided in the application.⁵⁰

64. NiSource states that it does not oppose the merger, but it requests that the Commission condition approval on the resolution of NiSource’s increased parallel path flow, or “loop flow,” problems, which will be exacerbated by the proposed merger. Therefore, NiSource requests that the Commission require Applicants to further study how the proposed merger will affect loop flow and take certain remedial actions, such as requiring Applicants to mitigate their loop flow if the Applicants’ proposed merger is approved.

B. Applicants’ Answer to the Protests

65. On May 10, 2005, Applicants filed an answer and amendment to their original filing. Notice of the answer and amendment to the filing was published in the Federal Register,⁵¹ with comments due on or before May 27, 2005.

66. Applicants acknowledge that protestors have raised some good points regarding errors in Dr. Hieronymus’s original analysis, but argue that, even with the appropriate revisions to the inputs in their analysis, Applicants have shown that the proposed divestiture fully mitigates the merger-related harm to competition. Applicants cite four specific examples of factual errors in the original analysis: (1) the analysis should have included a 200 MW power purchase agreement between PECO and Hoosier in 2006;

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(2) the analysis should have included PPL’s recently completed 600 MW Lower Mount Bethel combined cycle facility; (3) the analysis should have used 2,595 MW, rather than 4,800 MW, of generating capacity for Conectiv Energy Services, Inc. in PJM East; and (4) the analysis failed to account for Dominion’s native load obligation in the calculation of Available Economic Capacity. Applicants state that Dr. Hieronymus has made those changes in his analysis and that the resulting changes are minor and do not affect the mitigation required to repair the merger’s harm to competition.

67. Applicants respond to protestors’ arguments regarding the relevant geographic markets that would be affected by the merger. Answering the PPL Companies and the PHI Companies’ argument regarding the Northern New Jersey market, Applicants state that, because there was no overlap between Exelon’s and PSE&G’s generation in Northern New Jersey, Dr. Hieronymus analyzed the effect of the merger on that market and found that the mitigation for the PJM East market, along with an additional 100 MW divestiture of generation located in Northern New Jersey, would mitigate the harm to competition.

68. The PPL Companies argue that due to prevailing transmission constraints, the “PJM Classic” market, consisting of PJM Classic and the Allegheny Power system (Allegheny), should be analyzed as a separate market within the larger PJM Pre-2004 market. In response, Applicants assert that although PJM’s western interface once created a transmission constraint separating Allegheny from PJM Classic that constraint no longer exists, because PJM now redispatches the system when the constraint threatens to limit the west-to-east flows within PJM.⁵² Applicants cite the PJM Market Monitor’s 2004 State of the Market Report, which explains how the system operator redispatches higher-cost generating units in order to maintain the prevailing west-to-east flows from Allegheny into PJM Classic.

69. Applicants also address Protestors’ assertion that they should have analyzed PJM West and the “Rest of PJM Pre-2004” market (PJM Pre-2004 minus PJM West). They argue that the prevailing power flows are east-to-west, so the resulting transmission constraints can make PJM East a load pocket and, thus, a separate geographic market. However, Applicants argue that east-to-west flows are unconstrained, so there is no reason to consider PJM West as a separate market, because suppliers in PJM East can compete in the PJM West Market. Applicants contend that Protestors’ rationale for defining the relevant geographic market based on sellers’ opportunity costs is inconsistent with Commission precedent and Appendix A of the Merger Policy Statement. They state that Appendix A instructs applicants to consider those suppliers

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with low enough variable costs that they could compete (subject to transmission constraints) in a geographic market, not whether potential suppliers would consider the opportunity cost of selling into a particular geographic market.

70. Applicants address protestors’ questions about the fuel cost and assumed wholesale market prices in their analysis. While acknowledging that the assumed market prices are important parameters in the model, they argue that consistency between fuel cost assumptions and the prevailing market prices is most critical, and that Dr. Hieronymus’s and Mr. Frame’s testimonies are each internally consistent in their fuel cost and market price assumptions. That is, fuel cost assumptions on the low end of the range of observed or projected costs should correspond to market price assumptions on the low end of the range of observed or projected prices; likewise for high prices. They state that the protestors, including FirstEnergy’s witness, Ms. Frayer, have been able to show different results by changing one or the other of Dr. Hieronymus’ assumptions about fuel costs or market prices, but that those results are meaningless without a corresponding change in the other assumption. Moreover, Applicants assert that Ms. Frayer’s arguments about the accuracy of the fuel cost inputs are overstated because they do not change the merit order of the plants that would be dispatched under various market conditions; thus, they do not materially affect the results of Applicants’ analysis.⁵³ Applicants point out that Dr. Hieronymus and Mr. Frame used different fuel cost and market price assumptions, but arrived at very similar results, thus showing that the results are not sensitive to changes in fuel cost and market price assumptions. Finally, Applicants argue that some of the fuel costs and market prices assumed by protestors’ witnesses are wrong.⁵⁴

71. Applicants address claims that they should have performed more tests on the sensitivity of their results to changes in the assumed market prices. First, they argue that by using a range of prices from $20/MWh to $80/MWH and arriving at similar results throughout the range, Dr. Hieronymus has shown that changes in the assumed market price will not materially change his results. Second, as noted above, they argue that Mr. Frame’s analysis serves as a sensitivity test of Dr. Hieronymus’ analysis and confirms that the results are not sensitive to changes in fuel cost and market price assumptions.

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72. Regarding FirstEnergy’s assertion that Dr. Hieronymus overestimated the amount of new generation coming on line and underestimated the amount of old generation being retired in PJM, Applicants state that FirstEnergy’s claims are erroneous and are based on statements Dr. Hieronymus used in a different context, not in his analysis of energy markets. They state that in his analysis of energy markets, Dr. Hieronymus relied on PJM reports as to which plants would be coming on line and which would be retired in 2006, the test year, and that his comments about entry that FirstEnergy cites were more general and in the context of the competitiveness of long-term capacity markets. They also note that FirstEnergy’s witness, Ms. Frayer, used the same assumptions regarding generation entry and exit in her analysis of the relevant energy markets as did Dr. Hieronymus.

73. Applicants also address protests regarding Dr. Hieronymus’ allocation of available transmission in his analysis. Applicants challenge Hoosier’s and the PPL Companies’ claims that using a pro rata, rather than economic, allocation of available transmission skews the results of the analysis by understating the allocation of import capability for Applicants’ low-cost generation and systematically reducing the HHI. They say that the Commission has accepted the use of pro rata transmission allocation in numerous DPT analyses. They further state that, despite claims of an “opportunistic” use of the pro rata allocation by Dr. Hieronymus, he has always used that method in his many DPT analyses before the Commission.

74. Regarding their analysis of Available Economic Capacity, Applicants reiterate their argument that in retail choice states such as those affected by the merger, Available Economic Capacity is difficult to measure and does not accurately portray competitive conditions. They state that protestors largely agree with that assertion and that protestors’ attacks on Dr. Hieronymus’ analysis of Available Economic Capacity miss the fundamental point. While other suppliers’ native load data are not available, they do have data on their own native load obligation, so they are able to model their own Available Economic Capacity and conclude that the divestiture will bring that total below the pre-merger level.

75. Applicants address the numerous protests regarding the possibility of the merger creating or enhancing the merged firm’s incentive and/or ability to engage in strategic bidding, thus increasing its unilateral market power. First, they argue that the Commission’s Merger Policy Statement does not require an analysis of strategic bidding, nor is there case precedent requiring such an analysis. Rather, the Commission relies on the analysis described in Appendix A of the Merger Policy Statement, which is based on the Merger Guidelines, a well-established and court-affirmed analytical methodology. They further state that HHI screens are useful for analyzing the effect of a merger on the unilateral exercise of market power and cite the Merger Guidelines, which state that “[o]ther things being equal, market concentration affects the likelihood that one firm, or a

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small group of firms, could successfully exercise market power.”⁵⁵ Finally, they state that the analysis by Direct Energy’s witness, Dr. Kleit, of the cost and benefits of withholding and strategic bidding, is filled with errors and questionable assumptions.

76. Applicants characterize the protests regarding their proposed mitigation as falling into two major categories: (1) the Applicants proposed an inadequate amount of divestiture; and (2) virtual divestiture does not adequately mitigate market power. They further state that the questions raised by protestors are not issues of material fact that would require a hearing to explore, but legal and policy issues that can be decided by the Commission without a hearing.

77. Applicants respond to the PHI Companies, the PPL Companies and FirstEnergy’s argument that Applicants have misinterpreted the HHI screen as an absolute standard for Commission approval of a merger or acquisition. They assert that it is the PHI Companies, PPL Companies and FirstEnergy who have misinterpreted the Commission’s reliance on the HHI screen. Citing the Merger Policy Statement and the Merger Filings Requirements Rule, Applicants state that the Commission uses the screen to identify those mergers or acquisitions that will not require a hearing or additional mitigation in order to be authorized by the Commission, absent compelling evidence otherwise raised by intervenors. They conclude that because their proposed mitigation returns market concentration to levels that would pass the Competitive Analysis Screen, and no intervenor has made a showing that the merger has anticompetitive effects despite passing the screens, they have met the Commission’s standard for showing a lack of harm to competition.

78. Applicants argue that FirstEnergy’s assertion that an additional 890 MW of divestiture is required to avoid screen failures in the “summer rest of peak” and “shoulder rest of peak” periods is based on a miscalculation of Applicants’ proposed divestiture. They argue that Ms. Frayer undercounted the amount of the proposed divesture that would be relevant for the “summer rest of peak” and “shoulder rest of peak” periods by 1200 MW, because she was inconsistent between the types of units that would be considered economic capacity given her assumed price levels and the types of units that Applicants have committed to divest.⁵⁶

79. While Applicants disagree with the argument raised by numerous protestors regarding Applicants’ proposed Buyer Restrictions to purchase the divested plants and virtually divested energy, they offer to withdraw most of the proposed restrictions. They

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are willing to withdraw the restrictions that: (1) no more than half of the fossil generation would be sold to a single buyer and; (2) none would be sold to a market participant with a greater than five percent market share in PJM-East or Expanded PJM. Additionally, they withdraw the restriction that they will not sell more than 25 percent of the Baseload Mitigation Amount to market participants owning three to five percent of the installed generation capacity in Expanded PJM or PJM East. They continue to propose, however, the 50 percent limit on the total purchase of the virtually divested nuclear capacity.⁵⁷

80. In order to allow suppliers with larger pre-existing market shares in PJM to purchase the divested capacity, Applicants propose divesting an additional 1,100 MW of generating capacity (900 MW of fossil generating capacity and 200 MW of virtual nuclear capacity) in the PJM Pre-2004 market. Dr. Hieronymus analyzes the effect of the merger on competition with the increased divestiture and the assumption that equal shares of the entire divestiture amount were purchased by the four largest owners of capacity in PJM-East: PPL, Reliant, Conectiv and FirstEnergy. Under that scenario, for PJM-East, he finds that the post-merger-and-mitigation concentration levels range from 1,218 to 1,465 HHI, with changes in concentration ranging from negative 88 to 95 HHI, all within the Commission’s screening threshold for moderately concentrated markets. For PJM Pre-2004, he finds that the post-merger-and-mitigation concentration levels range from 996 to 1,292 HHI, with changes in concentration ranging from 48 to 105 HHI, with one period (shoulder peak, a moderately concentrated market with a change in concentration of 100 HHI) failing the Commission’s screening threshold for moderately concentrated and unconcentrated markets.⁵⁸

81. Applicants acknowledge that the additional mitigation does not necessarily cure all possible screen failures for all possible combinations of sales to companies with large market shares. They state that they will, therefore, make a compliance filing showing the effect on market concentration given the actual divestitures and the same data and assumptions used in Applicants’ revised Appendix A analysis, in order to show that no material screen failures will have resulted.

82. Applicants characterize the protests regarding their proposed virtual divestiture as falling into two major categories: (1) virtual divestiture is not as effective as physical divestiture in mitigating market power; and (2) compliance with the virtual divestiture commitment will be difficult to monitor, giving Applicants the ability to avoid the commitments they have made to the Commission.

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83. Applicants argue that the virtual divestiture is as effective as physical divestiture. They argue that the fact that the Commission has never approved sales of capacity, such as the virtual divesture proposal, as long-term mitigation, does not preclude the virtual divesture plan from being effective long-term mitigation. They state that, in the Merger Policy Statement, the Commission contemplated a possible alternative to physical divestiture that is similar to their proposed virtual divestiture:

[O]ne alternative might be to divest the ownership rights to energy and capacity to a number of owners. The unit could then be operated as a competitive joint venture and parts of its output could be bid or sold independently.⁵⁹

Applicants argue that their virtual divestiture plan, while not a joint venture, does divest the ownership rights to energy to a number of owners that can independently sell that energy or bid it into the PJM market.

84. Applicants argue that the Commission did not, in the Merger Policy Statement, establish physical divestiture as the only plausible mitigation for harm to competition; rather it recognized that “there are numerous mitigation measures that can be effective” and stated that it would consider the adequacy of various mitigation measures on a case-by-case basis.⁶⁰ Applicants assert that they have provided the analysis necessary for the Commission to determine the adequacy of virtual divestiture, and cite the testimony of Mr. Cassidy and Mr. Sabitino, explaining that the rights to the energy are firm rights and that the Applicants would have to pay liquidated damages if they failed to deliver. They further argue that, because the liquidated damages are based on the cost of covering any shortfall, they would have no incentive to withhold the energy subject to the virtual divestiture in order to profit from increased energy prices, because they would have to pay the cost of any such increase.

85. Applicants state that, under the virtual divestiture plan, the obligation to deliver energy is not tied to any specific unit and that they will guarantee the delivery of a specific amount of “24/7” energy under both the Auction Plan and the Long-Term

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Contract Plan, regardless of which units are operating.⁶¹ They assert that this guarantee eliminates the ability to profit by withholding output from the units that are under the virtual divestiture plan. Finally, Applicants note that the Commission has recognized in a number of cases that the operating characteristics of nuclear units reduce the danger of withholding output in order to raise prices.⁶²

86. In response to FirstEnergy’s assertion that the Commission rejected the sale of long-term power as mitigation in Allegheny, Applicants argue that FirstEnergy omitted the reasoning behind the Commission’s decision and that the circumstances are different here. They state that, in Allegheny, the Commission was concerned that “the merged company reserve[s] the right to reject any and all bids,” and that the merged company would thus retain control over the generation facility. Here, they argue, Applicants have committed to sell all of the energy that is offered, regardless of the price of the bids, and an independent auction monitor will oversee Applicants’ compliance with that commitment.

87. Applicants dispute FirstEnergy’s assertion that they will receive the same price for the virtually divested energy as they would have in the absence of mitigation. They state that, under the virtual divestiture plan, they will receive the price determined in the auction for the three-year life of each contract, whereas if they retained control of the output of the nuclear units, they would be able to benefit from any market price increases during the same three-year period. They conclude that, because of the three-year contracts, they will have no economic incentive to increase the market price in order to increase profit from the virtually divested capacity.

88. Applicants challenge Dr. Cichetti’s assertion that they will retain control of both the three-year and the 15-year products offered in the virtual divestiture plan because the purchasers of those products will likely resell the power in the Basic Generation Service auction. They state that, in both cases, the Applicants are obligated to deliver 24/7 energy to the buyers, and the buyers, not the sellers, will determine whether to participate in the Basic Generation Service auction or use it elsewhere. Applicants conclude that they cannot control the capacity or the price of the energy in the Basic Generation Service auction.

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89. Regarding protestors’ claims that the proposed energy swaps could harm competition in other geographic markets by increasing the concentration of control of capacity and energy in other geographic markets, Applicants argue that any such swap would have to be approved under section 203 and that the Commission could address any competitive concerns. Moreover, Applicants argue that they control very little electric generation capacity in other geographic markets, so the possibility of harm to competition elsewhere is remote.

90. Applicants recognize protestors’ arguments that the antitrust agencies generally prefer structural mitigation to behavioral mitigation and that behavioral mitigation requires ongoing monitoring for compliance. In response, Applicants commit to establish a public compliance web site that will show how they are complying with the virtual divestiture and all other mitigation requirements.⁶³ Applicants reiterate their commitment that the annual auctions for three-year energy contracts will be administered by an independent auction manager.

91. Applicants respond to the numerous protests regarding their proposal for implementing the mitigation. In response to the PHI Companies’ concern that the three year baseload auction energy sales might not continue over the proposed 15-year period, Applicants state that the PHI Companies are mistaken, and restate their commitment from the Application:

Applicants explicitly reaffirm that the entire Baseload Mitigation Amount
of nuclear virtual divestiture (2,600 MW) will remain in place after 15 years, subject to a reduction in the mitigation amount if the Applicant’s PJM East nuclear capacity is decommissioned, derated, or sold or there is construction of new transmission transfer capability into PJM East.⁶⁴

92. A number of protestors question the 18-month time period for the fossil divestiture and argue that it should be shorter. For example, AAI states that antitrust agencies advocate shorter time periods for completing divestitures. In response, Applicants commit to “executing sales agreements and making filings before the Commission for the approval of the sales no later than one year after the closing date of the Transaction.”⁶⁵

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93. Regarding protestors’ arguments that the Merger Policy Statement requires Applicants to identify the specific units that will be divested, Applicants argue that while they did not identify the exact units, they did identify the location and the types of generation to be divested and the pool of generation facilities eligible for divesture. They further argue that by not specifying the exact units, they give potential buyers more flexibility and let market forces decide which units should be divested. Finally, they argue that in AEP/CSW, rather than accepting applicants’ commitment to divest portions of two generating facilities totaling 550 MWs, the Commission expressly directed applicants to divest “any unit or units totaling the same number of megawatts and having the same cost, operation, and location characteristics as the specific plants.”⁶⁶ They conclude that the Commission has made it clear that it is not necessary to specify the plants that will be divested to mitigate Appendix A screen failures.

94. Applicants respond to protestors’ arguments regarding the proposal to reduce the amount of the baseload mitigation MW-for-MW for any increase in transmission transfer capability into PJM-East or for any reduction in Applicants’ nuclear generating capacity due to de-rating, decommissioning, or sales of nuclear capacity in PJM-East. Applicants assert that the market power concern regarding nuclear units is that, because they are low-cost units that are always in merit, their owners benefit from any withholding of other units that would raise the market-clearing price.⁶⁷ They argue that a decrease in the amount of nuclear capacity held by Applicants, whether through divestiture, de-rating, or unit retirement, would have the same effect in terms of mitigating market power. Thus, any reduction in the nuclear capacity held by Applicants should be considered effective market power mitigation, because any such reduction reduces the ability to profit from withholding output from other units. Regarding decreases to the baseload mitigation amount for increases in transmission transfer capability into PJM East, Applicants argue that increasing transfer capability into PJM-East would enable competitive suppliers to defeat attempts by generators in PJM East to drive up prices by withholding output, and, thus, should also be considered effective market power mitigation.

95. Applicants respond to the numerous challenges to the effectiveness of their proposed interim mitigation. Regarding FirstEnergy’s assertion that the PJM MMU should monitor Applicants’ compliance with their interim mitigation plan, Applicants reiterate their commitment to establish a public compliance web site that will show how they are complying with the virtual divestiture and all other mitigation requirements,

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including the interim mitigation plan. Moreover, they state that the PJM MMU has access to all the bid data in the PJM markets and will be able to track the amount of capacity bid into the PJM market under the interim mitigation plan. Regarding FirstEnergy’s claim that the Application provides insufficient detail about the interim mitigation, Applicants refer to the Cassidy testimony, which describes the amount of the dispatch rights; the rights afforded the purchasers of the capacity; the terms of the master agreement for the sales; the price of the energy and capacity; the timing and duration of the interim sales; and any associated rollover provisions.⁶⁸

96. FirstEnergy asserts that Applicants’ proposal to bid the output of their nuclear plants into the PJM energy market at a $0 price is inadequate because nuclear plants do not set the market-clearing price, and, therefore, Applicants should propose bid caps for their generating units that are likely to set the price. Applicants respond that they are doing precisely what FirstEnergy recommends. They have committed to bid the mid-merit and peaking units (the units most likely to set the clearing price) into the PJM market subject to a variable cost bid cap. Applicants challenge various claims that they should only be allowed to charge cost-based rates. They say that such claims are unfounded and, as a practical matter, no protestors have explained how offers of cost-based sales could be made in the single-clearing-price PJM Market.

97. A number of protestors, including FirstEnergy and PHI Companies, request that Applicants provide transmission upgrades as part of their mitigation package. Applicants state that, while they have opted for generation divestiture rather than transmission expansion as their form of market power mitigation, they are engaged in the PJM Regional Transmission Planning Process, and commit to additional transmission expansion. Specifically, in addition to their existing transmission commitments, they commit to complete two transmission projects whether or not the merger is approved by the Commission, and, if the Commission approves the merger without an evidentiary hearing, they commit to fund $25 million of transmission projects on PJM’s list of Economic Projects over the next five years.⁶⁹

98. Applicants characterize a number of issues raised by protestors as being policy issues that have no merit and do not require a hearing to resolve. First, they respond to protestors’ claims that, if the merger is approved, it will halt future merger activity in PJM by increasing the level of market concentration. They argue that the Commission

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has determined that it will review mergers on their own merits, rather than based on the effect they could have on possible future mergers.⁷⁰

99. In addition, Applicants argue that claims that the merger would create a “mega-utility” with a dominant market position and that the Commission’s Appendix A analysis does not sufficiently address such a possibility are misguided. They state that no intervenor has identified any specific issues that cannot be addressed using the tools available to the Commission.

100. Applicants note that a number of protestors have argued that the merged firm will not pass the Commission’s screen for generation market power under its market-based rates review. In response, Applicants state that they disagree with protestors’ conclusions, but, more importantly, they argue that the Commission can address the issue of the merged firms’ market-based rates when Applicants make their updated market-based rates filing.

101. Applicants argue that NiSource’s protests regarding loop flows should be rejected because they are not related to the merger. They state that NiSource’s complaint is about loop flows that might arise due to ComEd joining PJM, and that the Commission already has a proceeding regarding loop flows between PJM and the Midwest ISO.⁷¹ They further note that NiSource has filed a complaint in Docket No. EL05-103 in which it raised the same concerns.

102. Applicants respond to FirstEnergy’s assertion that they have not demonstrated that their proposed internal corporate restructuring is consistent with the public interest. They state that FirstEnergy’s cite to the Commission’s finding in Ameren Energy is misplaced, because Applicants have committed that there will be no transfers of generation assets from merchant generating companies to traditional franchised utilities, which was the Commission’s concern in Ameren Energy.

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     C. The PJM MMU Study

103. The PJM MMU analyzed the effect of the proposed transaction on competition in PJM’s energy, capacity, regulation, and spinning reserve markets.⁷² In its energy market analysis, the PJM MMU looks at the market for all of PJM, as well as defined locational markets.⁷³ The PJM MMU notes that one must take care in interpreting the results and offers that one must recognize that Dominion entered the PJM market on May 1, 2005, so the market conditions before that date no longer exist. Further, the post-Dominion integration data reflects only a narrow range of market conditions.

104. The PJM MMU states that it calculated market concentration levels on a pre- and post-merger basis for two time periods: (a) October 1, 2004 through April 30, 2005, and (b) May 1, 2005 through May 8, 2005. The PJM MMU states that on average, the hourly energy market was moderately concentrated, both pre- and post-merger, during both periods. The post-merger increase in average HHIs ranges from 290 to 301, and the average HHI in the post-merger market is between 1,537 and 1,643.⁷⁴ The PJM MMU concludes that the proposed merger results in an increase in HHI that exceeds that specified as raising concern in the Merger Guidelines. It states that the proposed merger would significantly increase concentration in the energy market as defined by these metrics and the standards of the Merger Guidelines and therefore raises concerns about potential adverse competitive effects, absent mitigation.⁷⁵ The PJM MMU states that the divestiture of 4,500 MWh of generation would reduce the post-merger HHI levels to pre-merger levels and that the divestiture of 2,600 MWh of generation would reduce the post-merger HHI levels so that the increase is less than 100 points.

105. The PJM MMU states that in PJM’s locational marginal pricing based market, transmission constraints create smaller, locational markets with different structural characteristics than the aggregate market. Thus, the PJM MMU examines the locational

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markets created when the Western, Central, and Eastern interfaces are binding constraints. It also examines the locational eastern market created when the Keeney 500/230 kilovolt (kV) transformer is constrained. The PJM MMU states that it performed this analysis in a way that is fully consistent with PJM’s actual procedure for dispatching units to solve a constraint.⁷⁶ The PJM MMU notes that its analysis included only those units whose increased output would relieve the constraint. That is, the PJM MMU calculated the HHI based on the ownership of combustion turbine capacity that could relieve the transmission constraint. It states that its approach is consistent with the Commission’s approach that looks at a variety of demand conditions.

106. The PJM MMU states that the Eastern interface pre-merger HHI is 2,593, but that this market is structurally competitive because it passes PJM’s three-pivotal-supplier test for market concentration.⁷⁷ It states that the merger would result in an HHI increase of 972 points and the failure of the three-pivotal-supplier test. The PJM MMU states that this harm to competition could be mitigated by capping market offers when the Eastern interface market is not competitive; by the merged company agreeing to offer power from units only at marginal cost (as defined in the offer capping rules); or by adequate divestiture of generation by the merged company. The PJM MMU states there is sufficient capacity in the list of candidate facilities to return the post-merger HHI to pre-merger levels, but that it is not possible to state definitively how many MW of capacity must be divested without knowing which units would be divested and the purchasers of these units.⁷⁸

107. The PJM MMU states that the Western interface’s pre-merger HHI is 1,552, and that this market is structurally competitive because it passes the three-pivotal-supplier test for market concentration. It states that the merger would result in an HHI increase of 240 points, but that the market still passes the three-pivotal-supplier test. The PJM MMU concludes that the merger nonetheless raises concerns about potential adverse competitive effects absent mitigation, because it would significantly increase concentration in the Western interface market. The adverse competitive impact of the merger could be mitigated by capping market offers when the Western interface market is not competitive, an agreement of the merged company to offer units only at marginal

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cost, or adequate divestiture of generation by the merged company. The PJM MMU states that there is sufficient capacity within the list of candidate facilities to return the post-merger HHI to pre-merger levels, but that it is not possible to state definitively how many MW of capacity must be divested without an exact specification of the units to be divested and the purchasers of these units.⁷⁹

108. The PJM MMU states that the Central interface’s pre-merger HHI is 1,870, but that this market is structurally competitive because it passes the three-pivotal-supplier test for market concentration. It states that the merger would result in an HHI increase of 479 points, but that the market still passes the three-pivotal-supplier test. The PJM MMU concludes that the merger nonetheless raises concerns about harm to competition because it would significantly increase concentration in the Central interface market. This could be mitigated by capping market offers when the Central interface market is not competitive, an agreement of the merged company to offer units only at marginal cost, or adequate divestiture of generation by the merged company. The PJM MMU reiterates there was sufficient capacity within the list of candidate facilities to return the post-merger HHI to pre-merger levels, but that it is not possible to state definitively how many MW of capacity must be divested without an exact specification of the units to be divested and the purchasers of these units.⁸⁰

109. The PJM MMU states that the Keeney transformer market pre-merger HHI is 3,004 and that this market is not structurally competitive because it fails the three-pivotal-supplier test for market concentration. It states that the merger would result in an HHI increase of 161 points. The PJM MMU states that the adverse competitive impact of the merger could be mitigated by capping market offers when the Eastern-interface market is not competitive, an agreement of the merged company to offer units only at marginal cost (as defined in the offer capping rules), or adequate divestiture of generation by the merged company. The PJM MMU states there is sufficient capacity in the list of candidate facilities to return the post-merger HHI to pre-merger levels, but that it is not possible to state definitively how many MW of capacity must be divested without an exact specification of the units to be divested and the purchasers of these units.⁸¹

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D.

Responses by Protestors to Applicants’ Answer and to the PJM MMU Study

110. NJBPU argues that EE&G’s plant retirements should not result in a MW-for-MW reduction in the amount of market power mitigation, because unlike divestiture, plant retirements do not create new competitors. It also asserts that more information is required to determine whether the mitigation plan is effective. Many different permutations of actual and virtual divestiture are possible, and the Commission cannot evaluate the merits of all of them without an evidentiary hearing.

111. FirstEnergy argues that because transmission expansion is required by the PJM Regional Transmission Expansion Plan, it cannot be considered market power mitigation. In addition, H-P Energy argues that Applicants’ commitment of $25 million towards transmission expansion projects may supplant transmission projects being built by merchant transmission companies. It further states that Applicants are unfairly bypassing the PJM RTEP process.

112. Protestors continue to question some of the assumptions in Dr. Hieronymus’ analysis and argue that the Applicants have offered mitigation based on inaccurate results that are favorable to Applicants. Specifically, FirstEnergy and the PPL Companies argue that the market prices used for electricity are still inaccurate. FirstEnergy further argues that what Applicants characterize as FirstEnergy’s witness’ “mistakes” were actually mistakes in Dr. Hieronymus’ database, and that upon correcting for Dr. Hieronymus’s mistakes, the merger fails the HHI screens. The PPL Companies argue that using actual FTR holdings to allocate imports to generators results in PJM-East market concentration that is considerably higher than indicated by Dr. Hieronymus, and that Applicants’ proposed divestiture is not sufficient to mitigate the harm to competition. FirstEnergy further argues that lifting the restrictions on who can buy the units will result in an inadequate amount of divestiture.

113. The PPL Companies argue that Applicants continue to ignore PJM Classic and Northern New Jersey as relevant geographic markets. In addition, the PPL Companies assert that EE&G may have the ability and incentive to shut down nuclear units to drive up energy prices. It says that Applicants did not address the effect of the proposed merger on PJM’s three-pivotal supplier rule.

E.

Applicants’ Answer to Protestors’ Responses and Comments on the PJM MMU Study

114. Applicants reply that the PJM MMU Study confirms the validity of their analysis. They read the PJM MMU Study as concluding that the proposed merger raises market power issues, but that the Applicants’ proposed mitigation can resolve them. Applicants note that the PJM MMU did not perform an Appendix A analysis, and advise the

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Commission not to rely on the PJM MMU Study as a substitute for one. Applicants note that their own Appendix A analysis shows that there are no screen violations after divestiture, so the Commission can find that the transaction will not harm competition without considering the PJM MMU Study. Applicants do, however, believe that the PJM MMU Study confirms Dr. Hieronymus’ analysis in two important respects: (1) the PJM MMU Study reaches results similar to those reached by Dr. Hieronymus regarding the state of the markets studied before and after the proposed merger, and (2) the PJM MMU concludes that it is possible to implement the mitigation proposed by the Applicants to address the market power issues associated with the proposed merger, depending on the units divested and who buys them.⁸²

115. With respect to point (2) above, Applicants argue that the need to identify the units to be divested and the purchasers of the capacity (before concluding that the transaction addresses market power concerns) can be met without further analysis or a hearing. It is not possible to identify the purchasers of the generation at present. Applicants commit to make a filing when they implement their divestiture in order to demonstrate, based on the specifics of the divested units and purchasers, that no material Appendix A screen violations will occur as a result of the divestiture.⁸³ Applicants state that the fact that the units it included as its divestiture candidates can return the markets to their pre-merger state should give the Commission confidence that their proposed divestiture of 1,200 MW of peaking generation can adequately mitigate screen failures in the PJM MMU’s energy submarkets.⁸⁴

116. Applicants criticize the PPL Companies’ supplemental affidavit from Dr. Kalt. They state that the affidavit does not respond to their May 9 Answer, that there is no reason Dr. Kalt could not have performed his analysis and included it in his original comments, and that Dr. Kalt’s analysis is easily dismissed because Financial Transmission Rights do not provide the holder with any physical right to import power.⁸⁵

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117. Likewise, Applicants state that FirstEnergy’s supplemental affidavit from Ms. Frayer presents a new study of the effect of the merger on energy markets that does not respond to the Applicants’ revised mitigation proposal. They state that Ms. Frayer analyzed a higher price for various market conditions, thus including more generation in her analysis than did Dr. Hieronymus. However, Ms. Frayer neglected to take into account, when assessing Applicants’ mitigation proposal, additional divested generation that is economic at higher prices. Applicants conclude that this results in a systematic understatement of the effectiveness of the mitigation they offer.

118. Applicants respond to FirstEnergy’s and the PPL Companies’ claim that Applicants’ commitment to fund additional transmission expansion projects is just a commitment to do what they are already required to do under PJM’s Regional Transmission Planning Process. They point out that one of the projects to which they commit is on the list of projects required by the Regional Transmission Planning Process, but that they are committing to accelerate the project so that it will be in service a year earlier than required by the Regional Transmission Planning Process. Applicants note that the other projects they propose are or will be on PJM’s Economic Project list and that transmission owners are under no obligation to go forward with projects on this list.⁸⁶ In response to concerns raised by H-P Energy that the Applicants may fund projects that H-P Energy already is pursuing, Applicants commit to not attempt to supplant any of the three projects identified by H-P Energy.⁸⁷

Discussion

119. Pursuant to Rule 214 of the Commission’s Rules of Practice and Procedure, 18 C.F.R. § 385.214 (2004), the timely, unopposed motions to intervene serve to make the entities that filed them parties to the proceeding. We will grant Allegheny Electric, H-P Energy and the Indiana Utility Regulatory Commission’s motions to intervene out-of-time, since we find that doing so will not unduly disrupt the proceeding or place an undue burden on the parties. Rule 213(a)(2) of the Commission’s Rules of Practice and Procedure, 18 C.F.R. § 385.213(a)(2) (2004), prohibits an answer to a protest unless otherwise ordered by the decisional authority. We will accept the answers filed herein because they have provided information that assisted us in our decision-making process.

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120. Applicants have shown that the merger, with the mitigation proposed, will not harm competition in any relevant energy market. We find that Applicants’ revised mitigation proposal, which increases the total mitigation from 5,500 to 6,600 MW and removes almost all of the restrictions on who can buy the assets, addresses the competitive concerns raised by intervenors.

     A. Adequacy of Applicants’ Analysis

121. Applicants have corrected the factual errors in their original analysis that commenters identified. This does not materially alter the results. We note that none of the protestors that identified the factual errors in Applicants’ original analysis argue that Applicants did not correct those errors.

122. We are not convinced by Applicants’ argument that Northern New Jersey is not a relevant geographic market. As noted by the PHI Companies and others, there are times when transmission constraints bind, leaving Northern New Jersey isolated from the rest of PJM-East. However, we agree with Applicants that, during those periods, the merger would not harm competition because Exelon does not have any generating facilities that would be combined with PSE&G’s existing generation in that load pocket. We note that there are times when imports from the rest of PJM East, where Exelon does own significant generating resources, would result in a merger-related increase in concentration due to Exelon’s share of the pro rata transmission allocation. In those cases, there are screen failures in the Northern PSEG market. We note Applicants have committed to mitigate all screen failures. We also note that Dr. Hieronymus’ testimony indicates that a 100 MW divestiture of generation capacity located in Northern PSE&G, along with the proposed mitigation for the PJM East market, is necessary to fully mitigate the merger-related increase in market concentration in Northern PSE&G. While Applicants have not explicitly committed to divesting 100 MW of generation located within Northern PSE&G, we consider the two statements above to be a commitment to do so, and we rely on that commitment in finding that the merger will not adversely affect competition in the Northern PSE&G wholesale electricity market.⁸⁸.

123. We reject arguments that “PJM-Classic” should be considered a separate relevant geographic market within PJM Pre-2004. We note that the PJM MMU report does not consider PJM-Classic as a separate market, and no one has shown that there are frequent binding transmission constraints that isolate PJM-Classic from the rest of PJM Pre-2004.

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124. We also reject arguments that PJM-West should be considered a separate geographic market. The critical issue in defining geographic markets is identifying the sellers who can physically and economically compete in the market. Given that the binding transmission constraints within PJM are predominantly west-to-east, it is reasonable to model PJM-East as a separate market within PJM, but not necessary to model PJM-West as a separate market because suppliers from all of PJM are able to sell into PJM-West.

125. Applicants have adequately addressed the protests concerning the fuel cost and wholesale market price assumptions in their analysis of energy markets. Dr. Hieronymus’ fuel cost and market price assumptions are consistent in that the assumed market price corresponds with the running costs of the units most likely to set the market-clearing price in the PJM energy markets for the given season-load conditions. We agree with Applicants that the fact that Dr. Hieronymus and Mr. Frame used different fuel cost and market price assumptions, but arrived at very similar results, indicates that the results are not sensitive to changes in fuel cost and market price assumptions. Moreover, the consistency of Dr. Hieronymus’ results across various assumed market prices shows that the results of the analysis are robust.⁸⁹ In addition, the PJM MMU Study largely confirms the accuracy of Applicants’ results, finding similar pre-merger and post-merger concentration levels.

126. Applicants appropriately accounted for generation entry and exit in their analysis. They used publicly available data from PJM covering the 2006 test year and included retirements and new plant entries that are reasonably expected to occur in 2005 and 2006. In OG&E, we noted that we will consider foreseeable and reasonably certain changes in market conditions as part of the baseline scenario.⁹⁰ Applicants have met that standard in their analysis.

127. Applicants and intervenors modeled various scenarios regarding who buys the divested assets. As noted by numerous protestors, as well as the PJM MMU Study, the effectiveness of Applicants’ proposed divestiture depends critically on the distribution of the buyers and their pre-existing presence as sellers in the PJM markets. Applicants initially addressed this issue by putting restrictions on the pool of eligible buyers and the

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amount of the divested capacity that any one purchaser can acquire. However, many protestors argued that such restrictions could harm the competitive process and could even allow Applicants to gain a dominant position in PJM by having only smaller, weaker competitors.

128. The parties raise valid issues on both sides of this argument. We find that Applicants’ elimination of the restrictions on eligible buyers addresses protestors’ concerns about harming the competitive process by freezing out some of the possible or likely purchasers of the assets. However, we need to be sure that, at the conclusion of the divestiture, competition has been restored to its pre-merger level, for the merger to be consistent with the public interest. Therefore, in addition to our section 203 review of the individual divestiture transactions, at the end of the divestiture process Applicants must make a compliance filing in this docket and we will review the results to be sure that concentration in the affected markets is close to pre-merger levels. If the analysis shows that the merger’s harm to competition has not been sufficiently mitigated, we will require additional mitigation at that time. We will direct Applicants to make a compliance filing within 30 days of the closing of the final divestiture, with an Appendix A analysis showing the post-merger-and-divestiture market concentration levels for economic capacity in all relevant markets.

129. We are not persuaded by arguments that Applicants should have used an economic (i.e. least cost) allocation rather than a pro rata allocation of scarce transmission transfer capability in their analysis. We have accepted the pro rata allocation methodology in numerous merger cases, and believe it reasonably models suppliers’ ability to compete in a given destination market. Moreover, in Order No. 642, we stated:

A variety of allocation methods are possible, and the Commission has acknowledged that certain methods provide more accurate and reasonable results than others (i.e., pro-rata as opposed to least-cost). Applicants must describe and support the method used and show the resulting transfer capability allocation.⁹¹

Here, Applicants have described and supported their transmission allocation methodology.⁹²

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130. Protestors raise a number of issues regarding Applicants’ Available Economic Capacity analysis. We agree with protestors and Applicants that in analyzing wholesale markets in retail choice states such as New Jersey and Pennsylvania, the native load deduction for the Available Economic Capacity calculation is difficult to assess. We have stated, in a number of contexts that as states move toward retail competition, native load obligations may change so that it is part of a broader set of contractual obligations, and we encourage applicants to test the sensitivity of the Available Economic Capacity results to changes in the native load assumptions.⁹³ Here, Applicants have analyzed Available Economic Capacity under two different assumptions of the native load obligation and reported similar results: moderately concentrated markets with screen failures under most season/load conditions. Most importantly, in all time periods, the divestiture proposed to address the screen failures identified in the Economic Capacity analysis more than offsets the increase in concentration shown in the Available Economic Capacity analysis. We conclude that Applicants have shown that the merger, as mitigated, will not harm competition when Available Economic Capacity is used to measure suppliers’ ability to compete in those markets.

131. We are not convinced by arguments that Applicants should have analyzed the merger’s effect on their ability and incentive to harm competition by engaging in strategic bidding (which is a form of unilateral market power). The Commission’s analysis focuses on a merger’s effect on competitive conditions in the market. That is, we look at the merger’s effect on the concentration of the relevant markets, as measured by the HHI. Protestors argue that the HHI solely looks for the possibility of the coordinated exercise of market power and misses the possibility of the unilateral exercise of market power. They say that Applicants have not shown that the merger will not increase the likelihood of the merged firm exercising unilateral market power. We reject this argument for two reasons. First, the Merger Guidelines recognize that the HHI does, in fact, convey information about the likelihood of the unilateral exercise of market power.⁹⁴ Second, in order to address the screen failures in various season/load conditions, Applicants have proposed divesting units with a range of operational and cost characteristics, including the types of units that protestors argue could be used to engage in strategic bidding or withholding in order to exercise unilateral market power.

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Furthermore, such strategic bidding or withholding could qualify as market manipulation under the Market Behavioral Rule #2⁹⁵ and result in, among other things, revocation of market-based rate authority.

132. Protestors argue that Applicants have erroneously interpreted the Commission’s HHI screen as an absolute standard for merger authorization and, thus have offered mitigation that is focused solely on passing the screen, rather than on mitigating the merger-related harm to competition. We agree with protestors that the mitigation needs to preserve competition, not necessarily to restore the HHIs to avoid screen violations. There are a number of ways to mitigate increases in market power (e.g. generation divestiture, transmission expansion, or behavioral measures such as must-offer requirements), and we have imposed various forms of market power mitigation depending on the circumstances. Applicants’ proposal to divest sufficient capacity to reduce market concentration to within the screening tolerance for increases from the pre-merger concentration level is one reasonable way to mitigate the merger-related harm to competition.⁹⁶ As stated above, the HHI conveys information about the likelihood of both the coordinated and unilateral exercise of market power. By restoring the HHI to near pre-merger levels, Applicants will restore competition to the pre-merger level, and meet their burden to show that the merger, as mitigated, will not harm competition in wholesale energy markets.

      B. Adequacy of Applicants’ Proposed Mitigation

133. We are not convinced by FirstEnergy’s arguments that Applicants’ proposed divestiture does not sufficiently mitigate the merger-related increase in market power. In both studies, FirstEnergy’s witness, Ms. Frayer, understated the amount of the proposed mitigation in various seasons because she assumed a lower price in the mitigation scenario than in the post-merger-without-mitigation scenario, thus not giving credit for some of the units being divested. In short, divested units that were “economic” were incorrectly considered “uneconomic” by Ms. Frayer.

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134. Protestors raise numerous issues regarding the effectiveness of Applicants’ proposed virtual divestiture of 2,600 MW of energy from nuclear capacity. In particular, many protestors argue that the Commission should only accept actual, physical divesture as effective mitigation. However, as stated above, there are a number of possible effective market power mitigation tools, and we have recognized that different options can be reasonable for a given set of circumstances. We have recognized that operational control of generation resources is a key element of market power analysis and mitigation.⁹⁷ Here, the virtual divesture effectively transfers control of the output of 2,600 MW of nuclear capacity from the merged firm to the purchasers. That is, the merged firm cannot withhold the energy from the market and the buyer of the firm rights, not the seller, determines where and to whom the energy is ultimately sold. Applicants have committed to sell all of the energy that is offered, regardless of the price of the bids, and that an independent auction monitor will oversee Applicants’ compliance with that commitment. Moreover, the liquidated damages provisions in the contracts, reduce the merged firm’s incentive to withhold output to drive up wholesale energy prices because it would be contractually obligated to pay the cost of any price increase. In effect, the virtual divestiture is a must-offer provision that removes the ability to withhold output, along with a contractual provision that reduces the incentive to withhold output in order to affect market outcomes. As we have said in numerous contexts, we are concerned about a merger’s effect on the merged firm’s ability and incentive to harm competition.⁹⁸ Furthermore, as a condition of the Commission’s approval, Applicants must agree that, if the virtual divestiture does not in fact mitigate the problems identified, Applicants will propose to the Commission mitigation that will mitigate the problems identified.

135. Protestors also object to the virtual divesture on the grounds that it will be difficult to monitor. For example, AAI notes that the antitrust agencies prefer physical divestiture because it removes the need for ongoing monitoring. We recognize that concern, but find two critical factors supporting virtual divesture as a reasonable alternative to physical divestiture. First, as we have stated in a number of cases, the operational characteristics of, and regulatory scrutiny over, nuclear units virtually eliminate the possibility of withholding output to drive up prices.⁹⁹ Second, Applicants have committed to establish an independent monitor to oversee the auction itself and Applicants’ compliance with the contracts, and Applicants will establish a public compliance website that will show how

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they are complying with the virtual divestiture and other mitigation requirements. We rely on those commitments in our finding that the virtual divestiture effectively mitigates the merger-related harm to competition. We will direct Applicants to make a compliance filing within 30 days of this order, detailing the process for the selection of the independent monitor.

136. We reject arguments that Applicants may have market power in the three-year and 15-year contract markets and that they may retain control of the contracts through the New Jersey Basic Generation Service auction. First, the Commission has determined that long-term capacity markets, absent specified entry barriers, are inherently competitive.¹⁰⁰ No protestor has raised compelling evidence that there are significant entry barriers in the PJM markets. Second, if Applicants attempted to withhold from the three-year contract market by selling only the 15-year contracts, as hypothesized by Ameren, the purchasers of the 15-year contracts would have an incentive to sell three-year contracts in response to any price increase. Regarding the PHI Companies’ argument about the New Jersey Basic Generation Service auction, Applicants have designed the three-year baseload energy auctions to support sales into the Basic Generation Service auction, but the buyers of the three-year baseload energy products will control the energy and can therefore resell them into the Basic Generation Service auction, or in some other manner. The fact that the buyers of the three-year baseload energy products may be likely to resell the energy into the New Jersey Basic Generation Service auction does not imply that the Applicants will regain control of the energy.

137. We reject FirstEnergy’s assertion that Applicants will receive the same price for the virtually divested energy as they would have in the absence of mitigation. First, as argued by Applicants, under the virtual divestiture plan, Applicants will receive the price determined in the auction for the three-year life of each contract, whereas if they retained control of the output of the nuclear units, they would be able to benefit from any market price increases during the same three-year period. Second, by giving up control of

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6,600 MW of through the divestiture and virtual divestiture, Applicants have adequately mitigated the merger-related increase in market power. Therefore, they would not be able to raise the price of energy by other means, as the previous contracts expire, in order to raise the price they receive for the three-year contracts.

138. Protestors have argued that, the proposed energy swaps could harm competition in other geographic markets. Any such energy swaps will require section 203 authorization, and we will review the effect on competition in those proceedings. We note that swaps with suppliers in markets adjacent to PJM, such as MISO or the New York ISO, might not warrant a MW-for-MW reduction in the mitigation amount because Applicants would get control of capacity that could sell into PJM, subject to transmission constraints. In such cases, the MW reduction in Applicants’ mitigation amount would be reduced by the merged firm’s pro rata share of the import capability into PJM.

139. Likewise, we reject arguments regarding this merger’s possible effect on future mergers. Future mergers will require section 203 authorizations, and we will review the effect on competition in those proceedings. We note, without prejudice to any future proceedings, that Applicants’ divestiture plan will restore the concentration level in the relevant markets to within 100 HHI of the pre-merger level, so there will be little effect on future mergers.

140. The PHI Companies say that the three year baseload auction energy sales might not continue over the proposed 15-year period. In response, Applicants commit that the entire Baseload Mitigation Amount of nuclear virtual divestiture (2600 MW) will remain in place after 15 years, subject to a reduction in the mitigation amount if the Applicant’s PJM East nuclear capacity is decommissioned, derated, or sold or there is construction of new transmission transfer capability into PJM East. Therefore, Applicants have adequately addressed the PHI Companies’ concerns regarding the duration of the baseload auction energy sales.

141. A number of protestors argue that the Merger Policy Statement requires Applicants to identify the specific units that will be divested. In response, Applicants argue that while they cannot now identify the exact units, they do identify the location and the types of generation to be divested and the pool of generators eligible to buy. In addition, the PJM MMU states that without knowing the exact units and the buyers of those units, it could not “make a meaningful assessment of the effectiveness of the proposed divestiture,” and “a supplemental analysis must be performed once a definitive declaration of the divested assets has been developed.”¹⁰¹ While the Merger Policy

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Statement does state that applicants must identify the specific units to be divested,¹⁰² in this instance, we find Applicants’ proposal sufficient because the divestiture can adequately mitigate the merger-related harm to competition; moreover, once the specific units have been identified, we will be able to ensure that they are appropriate units to make divestiture effective through the subsequent compliance filing discussed above. Finally, establishing a pool of generation eligible for divestiture, rather than specifying exact units, addresses protestors’ “reverse cherry picking” argument that Exelon will divest its least valuable units, rather than creating viable competitors by divesting the efficient units. Establishing a pool of generation eligible for divestiture allows the potential buyers of the plants to bid on the ones that they most highly value.

142. We note that, because of the way the PJM MMU did its analysis (using unit-specific historical energy sales and calculating HHIs for units that can relieve internal PJM constraints), it did need to know the exact plants that are going to be divested in order to assess the effectiveness of the proposed divestiture. However, under the Commission’s Appendix A analysis, we need to know the general location (i.e. control area or sub-region of an RTO) and cost characteristics of the generators being divested — not the actual units — in order to calculate the post-merger-and-divestiture HHIs. Applicants have provided that information and shown that, based on reasonable assumptions about the buyers of the assets, the post-merger-and-mitigation HHIs are sufficiently close to the pre-merger HHIs to mitigate the merger-related harm to competition. Moreover, Applicants have committed to provide an Appendix A analysis of the merger’s effect on competition, based on the actual acquirers of the actual divested assets, once they are known. We rely on that commitment in making our finding that the divestiture adequately mitigates any merger-related harm to competition in the relevant energy markets. If the analysis shows that the merger’s harm to competition has not been sufficiently mitigated, we will require additional mitigation at that time, pursuant to our authority under FPA.

143. We find that Applicants’ proposed MW-for-MW reduction of the amount of the baseload energy mitigation is reasonable. As stated earlier in this order, there are a number of reasonable market power remedies, including divesture and transmission expansion and we have relied on those remedies based on the circumstances before us. We agree with Applicants that offsets to the baseload mitigation amount for increases in transmission transfer capability into PJM East are reasonable because increasing transfer capability into PJM-East would enable competitive suppliers to defeat attempts by generators in PJM East to drive up prices by withholding output. In fact, in OG&E, we found that a transmission expansion was a reasonable form of mitigation for the increase

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in market power associated with OG&E’s acquisition of a rival generator.¹⁰³ Applicants have also made a convincing argument that a decrease in their nuclear capacity, whether through divestiture, de-rating, or unit retirement, would mitigate market power, because the incentive to withhold output is an increasing function of the amount of baseload capacity from which the merged firm could profit due to higher energy prices. Therefore, by reducing the amount of baseload capacity they control, they reduce their incentive to withhold marginal capacity in order to raise the market price.

144. We find that the amount of interim mitigation, along with Applicants’ variable cost bid caps for the mid-merit and peaking units, mitigates the merger-related harm to competition in the relevant energy markets. First, Applicants will offer the same amount of capacity in their interim mitigation (4,000 MW of fossil and 2,600 MW of nuclear) as in their proposed physical and virtual divestiture, which, as we explained above, adequately mitigates the merger-related harm to competition. Second, the commitment to bid the fossil units at variable cost eliminates the ability to harm competition by strategic bidding or economic withholding. In addition, we find that the Cassidy Testimony describing the amount of the dispatch rights; the rights afforded the purchasers of the capacity; the terms of the master agreement for the sales; the price of the energy and capacity; the timing and duration of the interim sales; and any associated rollover provisions, adequately describes the proposal. We rely on Applicants’ commitment to establish a public compliance web site that will show how they are complying with the
virtual divestiture and all other mitigation requirements, including the interim mitigation plan, and require that the interim mitigation be in place upon consummation of the merger.

145. We reject arguments that we should address in this proceeding whether Applicants will pass the Commission’s market-based rates screen. Any issues regarding Applicants’ generation market dominance will be addressed in the pending proceeding on Exelon’s triennial review filing, and in future similar proceedings.

146. NiSource’s concerns about loop flows are related to ComEd’s participation in the PJM RTO and power flows between the Midwest ISO and PJM, not to the merger. Therefore we will address NiSource’s issues regarding loop flows in the proceeding under Docket No. EL05-103.

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147. We agree with FirstEnergy’s argument that transmission expansion that is required by the PJM Regional Transmission Expansion Plan should not be considered market power mitigation. As we stated in OG&E, changes in market conditions that are “foreseeable and reasonably certain to occur” are not mitigation.¹⁰⁴ Transmission upgrades, depending on where they fall in the PJM Regional Transmission Planning Process queue, can be foreseeable and reasonably certain to occur, and thus might not be considered mitigation. However, although we will accept Applicants’ transmission commitments, we are not relying on them in our finding that Applicants’ proposed mitigation adequately addresses the merger-related harm to competition. Rather we are relying on Applicants proposed sale of 6,600 MW of capacity to mitigate the merger-related harm to competition. As stated above, we will allow offsets to the baseload mitigation amount specifically for transmission expansions that increase import capability into PJM-East. At this time, Applicants have not proposed any new projects that would expand import capability into PJM-East. In order to grant an offset of the baseload mitigation amount, we will require Applicants to make a showing that any transmission upgrades would increase transfer capability into PJM-East, and that they were not foreseeable and reasonably certain as of June 2005. H-P Energy argues that Applicants’ commitment of $25 million towards transmission expansion projects may supplant transmission projects being built by merchant transmission companies. Applicants have addressed that concern, in part, by committing not to attempt to supplant any of the three projects identified by H-P Energy. In addition, we note that the PJM Regional Transmission Expansion Plan process identifies numerous transmission projects that could be undertaken by merchant transmission providers as well as other transmission providers and generators looking for interconnection. There are considerably more projects identified than undertaken in a given year. Therefore, we accept Applicants’ commitment to fund $25 million of transmission expansion projects and their commitment to avoid supplanting any of the H-P Energy identified projects. To avoid supplanting any other bidder seeking to fund any other project on PJM’s list of Economic Projects over the next five years, Applicants are required to bid only on those projects identified but not undertaken by any other entity. Additionally, we will require that Applicants follow all other procedures under the PJM Regional Transmission Expansion Plan for any transmission expansion projects.

148. Regarding FirstEnergy’s argument that Applicants have not demonstrated that their proposed internal corporate restructuring is consistent with the public interest, we note that, absent concerns about transfers of generation assets from unregulated merchant generating companies to regulated franchised utilities we expressed in Cinergy¹⁰⁵ and

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Ameren¹⁰⁶, the Commission has held that internal reorganizations will not result in harm to competition.¹⁰⁷ Here, Applicants have committed that there will be no transfers of generation assets from unregulated merchant generating companies to regulated franchised utilities. We rely on that commitment in finding that that internal corporate restructuring will not result in any harm to competition in any relevant market. In addition, as discussed infra, Applicants have committed to hold wholesale customers harmless from any merger-related costs so the internal reorganization will not adversely affect wholesale rates. Moreover, the internal restructuring will not adversely affect this Commission’s or any state commission’s ability to regulate the merged company. Therefore, we find that Applicants have shown that their proposed internal corporate restructuring is consistent with the public interest.

     C. Capacity Markets

1.

Applicants’ Analysis

149. Dr. Hieronymus also analyzed the effect of the merger on capacity markets in PJM-East and Expanded PJM. For PJM-East, he assumed the same 7,300 MW import capability as in his analysis of economic capacity. He reports that Exelon’s and PSE&G’s pre-merger shares of capacity in PJM-East are 18 and 25 percent respectively and that the merger would increase market concentration from 1,282 to 2,196 HHI, well above the Commission’s screening threshold for highly concentrated markets. For Expanded PJM, he assumed the same 7,500 MW import capability as in his analysis of economic capacity. He reports that Exelon’s and PSE&G’s pre-merger shares of capacity in Expanded PJM are 15 and 8 percent respectively and that the merger would increase market concentration from 799 to 1,044 HHI, above the Commission’s screening threshold for moderately concentrated markets. He states that Applicants need to divest 5,300 MW of capacity in PJM-East to eliminate the screen failures and restore market competition to the pre-merger level.¹⁰⁸

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150. PSE&G’s witness, Mr. Frame, analyzed the effect of the merger on competition in PJM-East and capacity markets. For PJM-East, he assumes the same 7,300 MW import capability as in his analysis of economic capacity. He reports that Exelon’s and PSE&G’s pre-merger shares of capacity in PJM-East are 16.8 and 24.0 percent, respectively, and that the merger would increase market concentration from 1,127 to 1,932 HHI, well above the Commission’s screening threshold for highly concentrated markets. For capacity markets, he assumed the same 7,500 MW import capability. He reports that Exelon’s and PSE&G’s pre-merger shares of capacity in Expanded PJM are 15.0 and 8.0 percent respectively and that the merger would increase market concentration from 687 to 926 HHI, within the Commission’s screening threshold for moderately concentrated markets.

151. As described above, Applicants commit to divest 2,900 MW of capacity in PJM-East in order to address the peak and screen failures identified in the analysis of economic capacity in PJM-East. Therefore, they state that they will need to mitigate an additional 2,400 MW of capacity, which they refer to as the “Capacity Mitigation Amount.” Applicants propose bidding into the PJM monthly and annual Planning Year capacity auctions the lesser of the Capacity Mitigation Amount or the entire net Unforced Capacity Position in PJM less 100 MW.¹⁰⁹

152. Applicants note that PJM is restructuring its capacity market, which may change relevant geographic capacity markets that could be affected by the merger. They commit to make a filing with the Commission 30 days after the closing of the merger in which they will make any necessary adjustments to their capacity market mitigation and will demonstrate the effect of that mitigation on PJM’s restructured capacity markets.

153. Exelon’s witness, Dr. Hieronymus, analyzes the effect of the merger, given Applicants’ proposed capacity mitigation, and finds that the merger does not harm competition in the PJM capacity markets. For PJM-East, with mitigation, market concentration is 1,380, within 100 HHI of the pre-merger concentration, within the Commission’s tolerance for moderately concentrated markets. For Expanded PJM, with mitigation, the capacity market is unconcentrated. Dr. Hieronymus concludes that Applicants’ proposed mitigation eliminates any harm to competition indicated by the screen failures in his analysis of PJM capacity markets.

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154. PSE&G’s witness, Mr. Frame, also finds that the proposed mitigation would eliminate the harm to competition in PJM capacity markets indicated by the screen failures. In his analysis of the PJM-East capacity market, he concludes that 4,614 MW of capacity would need to be divested in PJM-East and that no divestiture is necessary in Expanded PJM in order to restore market concentration to within the Commission’s tolerance level. Therefore, he finds that the proposed 5,300 MW of capacity mitigation more than offsets the harm to competition resulting from the merger.

2.

Protests

155. FirstEnergy argues that Applicants would own around 60 percent of the capacity and they could use that capacity to raise prices and otherwise exercise market power. Therefore, FirstEnergy states that that the Commission should direct Applicants to file an analysis of the effects of the forthcoming capacity markets, which are subject to redesign by PJM, and explain how Applicants’ proposed mitigation will effectively deter the exercise of market power in those markets. In the alternative to a follow-up filing, FirstEnergy states that the Commission should set this matter for hearing.

156. First Energy’s witness, Ms. Frayer, also reviewed and assessed Applicants’ proposed capacity market mitigation, and concluded that Applicants’ proposal is inadequate to mitigate their post-merger market power in PJM capacity markets. Ms. Frayer finds that Applicants would need to divest up to an additional 4,650 MW (above the 2,900 MW that Applicants have committed to divest) to mitigate market power in the PJM-Expanded capacity market, after the commencement of the single capacity market in June 2005. She also finds that Applicants would need to divest up to an additional 2,721 MW (above the 2,900 MW that Applicants have committed to divest) to mitigate market power in the PJM-East capacity market, after the establishment of local capacity markets.

3.

Applicants’ Answer

157. Regarding Applicants’ proposed capacity market mitigation, protestors argued that despite their commitment to bid up to 2,400 MW of capacity into the PJM daily capacity auction at a zero price, Applicants could still have incentive to withhold any other capacity in order to drive up the market-clearing price. In response, Applicants have committed to bid all of their uncommitted capacity at zero, which, they assert, will remove any economic incentive they may have had to withhold capacity in order to increase the market clearing price.

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4.

The PJM MMU Study

158. The PJM MMU stated that it analyzed the aggregate capacity market as well as defined locational capacity markets. It analyzed the aggregate capacity market using actual market data and total capacity. It analyzed locational capacity markets using total and incremental capacity, where incremental capacity includes only those units whose increased output would relieve the relevant transmission constraint. The PJM MMU notes that the structure of the capacity market makes for an extremely inelastic demand curve for capacity, and one needs to account for this fact in an analysis of the competitive impacts of the proposed merger.

159. The PJM MMU found the pre-merger PJM capacity credit markets to exhibit moderate levels of concentration in the daily capacity credit market and high levels of concentration in the monthly and multimonthly capacity credit markets. It found the average HHI for the daily capacity credit market to be 1,233 with a minimum of 820 and a maximum of 2,500. HHIs for the longer term monthly and multimonthly capacity credit markets averaged 2,125 with a minimum of 841 and a maximum of 4,151. The PJM MMU found the post-merger HHI in the daily capacity credit market to average 1,389, an increase of 156 points from the pre-merger value. Post-merger HHIs for the monthly and multi-monthly capacity credit market averaged 2,149, for an increase of 24 points from the pre-merger average.

160. The PJM MMU also evaluated the market structure for total capacity in the aggregate PJM market, and the PJM East and PJM Mid-Atlantic regional capacity markets. The results showed that the merger caused HHI increases of 314 and 241 points for the Total PJM pre- and post-Dominion markets, respectively, 501 for the PJM Mid-Atlantic market, and 1,120 to 1,810 points for the PJM East market, depending on assumptions made for imports. The results also showed that post-merger market concentration is moderate in total PJM and PJM Mid-Atlantic, and high in PJM East, and that there is a single pivotal supplier in every case.

161. The PJM MMU states that, given the potential for a locational capacity market in eastern PJM, it performed an additional analysis for this market to more accurately reflect the incremental way in which a locational capacity market would clear. The results of the locational incremental analysis for eastern PJM show the pre-merger HHI to be in the moderate range with a single pivotal supplier. The proposed merger resulted in an HHI change of over 100 points.

162. The PJM MMU found that the proposed merger results in an HHI increase that exceeds the threshold specified in the Merger Guidelines for both the aggregate and local capacity markets. The merger therefore raises concerns about potential adverse competitive effects, absent mitigation. The PJM MMU states that the merging companies’ proposal to offer capacity at a zero price represents a from of behavioral

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mitigation that would resolve the issue if properly structured. It states that the companies’ proposal must be structured so that it would provide the required mitigation for a variety of capacity market designs, given the current uncertainty about the ultimate design. If the capacity market were restructured so that all participants were required to offer all capacity into the market, it explains, the companies’ proposal would have to cover all capacity offered to the market (where the market would include the monthly and multi-monthly auctions, as well as the daily market).

5.

Protestors’ Responses to Applicants’ Answer and the PJM MMU Study

163. First Energy argues that Applicants proposal to bid all of their capacity at $0 will give them incentive to sell their capacity in the monthly (“term”) market for capacity, thus rendering their capacity mitigation ineffective. Moreover, FirstEnergy argues that the PJM MMU has expressed serious concerns about market power in PJM capacity markets. Therefore, FirstEnergy requests that the Commission condition the merger on Applicants not acquiring any additional generation within PJM until two years after the implementation of the restricted capacity markets, and on Applicants submitting a compliance filing once PJM’s capacity design is restructured, showing that they do not have market power in relevant capacity markets.

164. NJBPU argues that plant retirements can be a form of withholding to increase capacity market prices in a manner that would be profitable for the merged entity, but that would be riskier and less or unprofitable for PSE&G on a standalone basis. It states that the PJM MMU shares the concern that retirement may be a form of withholding. PJM itself is struggling with this issue and has not yet set policy much less had implementation experience. NJBPU discusses retirement policy including the need for a policy to “ensure that retirements are not used to exercise market power,“and PJM’s need for a “clear retirement policy,” with a “test for market power”.¹¹⁰

6.

Applicants’ Answer to Protestors’ Responses to Applicants’Answer and the PJM MMU Study

165. With respect to capacity markets, Applicants argue that the PJM MMU study effectively endorses Applicants capacity market mitigation. The PJM MMU study concludes that the proposal to offer capacity at a zero price represents a form of behavioral mitigation that would resolve the capacity market power issue if properly structured. Applicants note the PJM MMU’s concern that this mitigation might not work

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for other capacity market structures adopted by PJM in the future. In response, Applicants note that they have committed to proposing a new capacity market mitigation plan for the Commission’s approval 30 days after the closing of the Merger, when the details of the new PJM capacity markets should be known.

166. Applicants also dismiss Ms. Frayer’s assertion that they will circumvent their zero-bid proposal in the daily capacity market by bidding into term capacity markets. Applicants state that to the extent that they attempt to increase the term market price by withholding capacity from that market, the other market participants will know that the Applicants are required to offer their uncommitted capacity into the daily capacity market at a price of zero. As a result, if the price in the term markets were to exceed competitive levels as a result of withholding by the Applicants, participants in those markets can simply refuse to purchase term capacity from Applicants and instead purchase the capacity that the Applicants must offer into the daily market at a price of zero. Thus Applicants state that the requirement to bid capacity into the daily market at a price of zero mitigates market power in both the daily and term capacity markets.

7.

Commission Determination

167. Applicants have shown that the merger, with the mitigation proposed, will not harm competition in any relevant capacity market. In addition to the physical divestiture of 4,000 MW of generating capacity, Applicants have committed to bid all of their uncommitted capacity at zero. Therefore, they will have no ability to withhold capacity in order to increase the market clearing price. As noted by the PJM MMU, Applicants’ proposal to offer capacity at a zero price represents a form of behavioral mitigation that would resolve the capacity market power issue if properly structured. We share the PJM MMU’s concern that this mitigation might not work for other capacity market structures adopted by PJM in the future. Therefore, when the Commission approves a new capacity market for PJM, we will require Applicants to submit a new analysis of the merger’s effect on the PJM capacity market and, if the analysis shows that the merger-related harm to competition is not fully mitigated, propose a new mitigation plan for the Commission’s approval within 30 days of any such approvals.

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     D. Ancillary Services

1.

Applicants’ Analysis

168. Applicants state that the merger will not harm competition in any relevant ancillary services markets. They state that PJM does have markets for spinning reserves and regulation services, and therefore analyze competition in those markets. Dr. Hieronymus states that Exelon and PSE&G have 6 and 39 percent shares of the Mid-Atlantic spinning reserve capability, respectively.¹¹¹ He estimates that the market is moderately concentrated with a merger-related increase of 507 HHI. He finds that a divestiture of 147 MW of spinning reserve capacity would be necessary to bring the effect of the merger within the Commission’s tolerance level. Dr. Hieronymus concludes that Applicants’ proposed divestiture of 2,900 MW of fossil-fired generation capacity, some of which is capable of providing spinning reserves, will sufficiently mitigate the merger-related harm to competition in the spinning-reserve markets. PSE&G’s witness, Mr. Frame, comes to the same conclusion, based on his review of the available PJM data.

169. Dr. Hieronymus also reviews the most recent available data for the PJM regulation market. He reports that the market is moderately concentrated, with Exelon and PSE&G holding 13 and 12 percent shares of the 2,011 MW of regulation-capable capacity in the Mid-Atlantic zone of PJM respectively. Therefore, the merged firm will have approximately 25 percent of the regulation-capable capacity (approximately 500 MW) in PJM Mid Atlantic Area Council (PJM MAAC), more than half of which is pumped-storage capacity, which he argues is generally an uneconomic source of regulation. He notes that the merged firm will not be a pivotal supplier of regulation services because there are more than 1,500 MW of competing supply able to serve a peak load of approximately 700 MW. He concludes that the merger will not harm competition in the PJM regulation market. PSE&G’s witness, Mr. Frame, notes that the 2003 PJM Market Monitor Unit Report states that within PJM MAAC, there are 113 generating units capable of providing 2,011 MW of reserve capacity, and that in 2003, regulation requirements in PJM MAAC ranged from 220 MW to 750 MW. He concludes that because the regulation market demand can be met more than two times over by alternative suppliers at the peak, and by a far greater amount during the off-peak, the merger will not harm competition in the PJM regulation market.

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170. Mr. Frame describes the ancillary services markets in PJM and states that there are two spinning reserve products offered in PJM: Tier 1 and Tier 2. He states that Tier 1 spinning reserves are provided by the unloaded capacity of steam generating units that have been bid into the PJM energy market, but have not been called on to produce energy. He concludes that because the provision of Tier 1 spinning reserves is essentially a by-product of participating in the energy markets, the merger’s effect on competition in the Tier 1 spinning reserves market will not materially differ from the merger’s effect on competition in energy markets. He concludes that because Applicant’s proposed divestiture will mitigate any merger-related harm to competition, it will also mitigate any harm to competition in the Tier 1 Spinning PJM reserve market.

171. Mr. Frame states that Tier 2 spinning reserves are used when Tier 1 reserves are exhausted, and, historically, have been provided by hydroelectric units and combustion turbines with condensing capacity. He states that PSE&G and Exelon currently control 1,191 and 196 MWs of capacity capable of providing Tier 2 spinning reserves within the MAAC region of PJM, respectively.¹¹² He argues that the Applicants’ proposed divestiture will likely offset any merger-related increase in the concentration of the Tier 2 spinning reserves market, because Applicants plan to divest more than 196 MWs of generation capacity capable of providing Tier 2 spinning reserves, so the merged firm will have a smaller share of the market than PSE&G’s pre-merger share.

172. FirstEnergy questions Applicants’ conclusion that the merger will not adversely affect competition in ancillary services markets. FirstEnergy’s witness, Ms. Frayer, argues that Dr. Hieronymus has not supported his assertion that regulation and spinning reserves prices are intrinsically linked to energy market prices. She further argues that, because Applicants have not specified the exact units that will be divested, it is premature to conclude that the proposed mitigation plan for energy also satisfies ancillary services market concerns.

2.

PJM MMU Study

173. The PJM MMU states that its merger analysis focuses on the Mid-Atlantic Regulation Market as the spinning reserves market most likely to be affected by the merger. It states that its results are based on 12 months of actual spinning reserves market data through March 31, 2005.

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174. The PJM MMU calculated hourly HHI values based upon regulation offered, regulation offered and eligible, and regulation assigned as follows: Average HHI for pre-merger regulation offered — 1,692; Average HHI for regulation offered and eligible — 1,772; and Average HHI for regulation assigned — 2,497. The post-merger analysis is based on actual regulation market data for the twelve months that ended March 31, 2005, modified to combine the ownership of PSE&G and Exelon resources into a single company. The average post-merger HHI for regulation offered was 1,795, for a change of 103 points, for regulation offered and eligible it was 1,900, for a change of 128 points, and for regulation assigned it was 2,628, for a change of 131 points.

175. The PJM MMU states that the analysis of the regulation market shows that the proposed merger results in an increase in HHI that exceeds the increase specified in the Merger Guidelines. It states that the proposed merger would significantly increase concentration in the regulation market as defined by these metrics and the standards of the Merger Guidelines and therefore raises concerns about potential adverse competitive effects, absent mitigation. It bases its conclusion on the 128 point increase in average HHI for offered and eligible regulation. The PJM MMU states that mitigation of the merger effects could be provided by an application of existing PJM market rules to the PJM Mid-Atlantic Regulation Market; the merged company could agree to offer its regulation capability into the market at cost-based levels. It states that as an alternative, the merged company could agree to offer its regulation capability into the market at cost-based rates. The PJM MMU further notes that the anticompetitive effects of the merger could be mitigated by divestiture of regulation resources in the Mid-Atlantic Regulation Market, but that it is not possible to evaluate the Applicants’ proposed divestiture plan without knowing which units would be divested.

176. The PJM MMU states that its merger analysis focuses on the Mid-Atlantic Regulation Market as the spinning reserves market most likely to be affected by the merger. Its results are based on 12 months of actual spinning market data through March 31, 2005. The PJM MMU analyzed the Tier 2 spinning reserve market (where Tier 2 resources include units that are backed down to provide spinning capability and condensing units synchronized to the system and available to increase output). It found the pre-merger average HHI to be 4,651 and the average post-merger HHI to be 4,671, a change of 20 points. The PJM MMU states that the proposed merger results in an increase in the HHI that is less than that specified in the Merger Guidelines, and that the merger does not raise competitive concerns in the spinning reserves market. The PJM MMU’s analysis differs in two ways from the Commission’s Delivered Price Test. Its analysis includes all regulation capability offered into the market without regard to cost. In addition, its analysis includes all regulation offered by each supplier, while the Delivered Price Test uses the gross supply by participants net of their load obligation.

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3.

Commission Determination

177. We recognize that ancillary service market data are not as readily available as that for energy and capacity markets. As such, we find Applicants’ reliance on the PJM Market Monitor Reports to be a reasonable way of analyzing the effect of the merger on competition in those markets. Moreover, while pivotal supplier and market share analyses are not part of the Commission standard review in section 203 cases, we find them informative here, given the lack of sufficient data for complete analysis of the merger’s effect on the ancillary service market concentration.

178. We find that the merger, as mitigated, will not harm competition in PJM ancillary services markets. Applicants have shown that there are numerous supply alternatives in the PJM ancillary services market. In addition, the divestiture of fossil units in PJM will include units capable of providing spinning reserves and regulation services. Applicants’ analysis shows that their proposed divestiture will reduce their control of capacity able to supply ancillary services to less than the pre-merger level, under reasonable assumptions regarding the units that are ultimately divested. In addition, the PJM MMU found that the anticompetitive effects of the merger could be mitigated by divestiture of regulation resources in the Mid-Atlantic Regulation Market, where almost all of the fossil units Applicants have proposed divesting are located. Regarding FirstEnergy’s concern that it is premature to conclude that the proposed mitigation plan for energy also satisfies ancillary services market concerns because Applicants have not specified the exact units that will be divested, as we stated regarding the mitigation for energy markets, Applicants have committed to provide an analysis of the merger’s effect on competition, based on the actual acquirers of the actual divested assets, once they are known. We rely on that commitment in making our finding that the divestiture adequately mitigates any merger-related harm to competition in the relevant ancillary services markets. If the analysis shows that the merger’s harm to competition has not been sufficiently mitigated, we will require additional mitigation at that time.

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     E. Vertical Market Power Issues

1.

Applicants’ Analysis

179. Applicants address the effect of combining their transmission and generation assets. They state that the only transmission owning entities involved, ComEd, PECO, and PSE&G, have all transferred operational control over their transmission facilities to the PJM RTO. Applicants state that the Commission has held on a number of occasions that such a transfer to a fully-functioning, Commission-approved RTO addresses the possibility of abuse of transmission market power.¹¹³

180. Applicants also address the concern that the transaction will allow them to obtain some control over the PJM decision-making process. They state that the transaction will have no effect on the makeup of PJM’s independent Board of Directors. Applicants further state that with respect to the Members, Reliability, and Electricity Market Committee, PECO, the voting member for Exelon, and PSE&G, the voting member for PSE&G, are both in the Transmission Owners sector, which has a 20 percent voting interest in the committees. Applicants expect that the transaction will result in the Exelon and PSE&G votes combining into a single vote, increasing EE&G’s voting interest from 10 percent (the current share for each of PECO and PSE&G) to 11 percent. They argue that this increase of 1 percent in a voting sector that has a total 20 percent voting interest is de minimis. They also note that even this change will be negated if Dominion Virginia Power joins the Transmission Owner Sector.

181. Applicants state that, with respect to the PJM East Transmission Owner’s Agreement, voting rights are counted both based on individual members and on a weighted basis. A two-thirds vote in each category is required to approve all major changes, and at least three opposition votes are required to defeat any major change. They state that EE&G’s increased share of individual member votes will be de minimis, going from one-in-nine to one-in-eight under the PJM East Transmission Owner’s Agreement, and from one-in-14 to one-in-13 if the East, West, and South Transmission Owner’s Agreements are consolidated into a single agreement, as is currently under consideration. Applicants note that EE&G’s weighted share will go up more significantly, but provisions limiting the weighted vote of an individual transmission owner to a maximum of 25 percent and requiring a two thirds vote on each an individual and a weighted basis protect other transmission owners from EE&G’s increased weighted share. EE&G will not be able to veto any proposed TOA changes because at least three individual votes are required for such block.

Docket No. EC05-43-000		63

182. Applicants also address the effect of combining their natural gas distribution and electric generation assets. PECO provides natural gas distribution service to only one electric generator, a 28 MW facility owned by Merck.¹¹⁴ They note that there are two other independent generators in PECO’s service area, but these generators take service directly from an interstate natural gas pipeline. Furthermore, they argue that newly built generation facilities could readily avoid PECO’s small service area or connect directly to an interstate pipeline.¹¹⁵ They state that PSE&G’s natural gas distribution system serves eight current or former generating facilities in New Jersey under contract with the utility, as well as two merchant generators (the Tocso plant and the Williams Red Oak plant). They note that the latter facilities are served by PSE&G under long-term natural gas transportation contracts or discounted tariffs.¹¹⁶ Applicants further state that both companies provide natural gas distribution services to affiliated generation facilities.

183. Applicants’ witness, Dr. William Hieronymus, states that no vertical market power concerns arise as a result of the transaction’s combination of natural gas distribution facilities and electric generation assets. This is because new generation can connect to one of EE&G’s Local Distribution Companies (LDCs) or directly interconnect with a pipeline system, so the local distribution company cannot impede entry by other competitors. Dr. Hieronymus further states that the simple ownership of LDCs’ operations does not allow Applicants to self-deal or use other means of using gas LDCs to favor affiliated activities. He notes that distribution tariffs are regulated by the state public utility commissions, which impose open access distribution requirements. Further, the ability to earn even ceiling rates in distribution tariffs is frequently constrained by bypass alternatives or the existence of long-term contracts.

Docket No. EC05-43-000		64

184. Dr. Hieronymus states that other vertical concerns are not present because both Pennsylvania and New Jersey have in place codes of conduct between gas and electric affiliates; both utilities are governed by the Commission’s Order No. 2004;¹¹⁷ and the amount of generation served is so small that knowledge of customers’ operations is of no commercial value to electric generators. He conducted the analysis required under section 33.4 of the Commission’s regulations, analyzing the downstream markets for PJM East, PJM Pre-2004, and Expanded PJM. He notes that the Commission has found that market power in both the upstream natural gas market and the downstream electric market is necessary for a vertical market power problem. After accounting for Applicants’ mitigation commitments, he found that neither the PJM Pre-2004 nor the Expanded PJM downstream markets are highly concentrated post-merger. However, the PJM East market remains highly concentrated post-mitigation,¹¹⁸ so he analyzed the PJM East upstream market, consistent with the Commission’s regulations.¹¹⁹ He found this market not to be highly concentrated and concludes that competitive conditions will not be conducive to a vertical foreclosure strategy.

185. PSE&G’s witness, Mr. Frame, also concludes that the combination of Applicants’ natural gas and electric generation resources would not harm competition. He states that neither Exelon nor PSE&G owns any interstate natural gas pipelines and that the natural gas facilities owned by their affiliated LDCs are available to electric generators on a state regulated open access basis.

Docket No. EC05-43-000		65

2.

Protests

186. The AAI asserts that membership in an RTO is not sufficient to ensure that sellers will not be able to exercise vertical market power through their ownership of transmission, citing a show cause order in which the Commission initiated an investigation of Exelon regarding alleged sharing of non-public information regarding maintenance outages.¹²⁰

187. No party contests Applicants’ description of the PJM governance structure. The PHI Companies assert, however, that EE&G might be positioned to exert undue influence on the PJM RTO as a result of its holding the largest transmission investment in PJM.

188. Protesters dispute Applicants’ claim that they will not be able to exercise vertical market power in the natural gas market. Direct Energy asserts that Applicants’ analysis is flawed for two reasons. First, Applicants use data that incorrectly represents interstate pipeline capacity deliverable to relevant markets, and says Applicants omitted capacity served in eastern Pennsylvania (in PJM East) in their calculation of Columbia Gas Transmission and Texas Eastern Transmission pipeline’s deliverability from Pennsylvania to New Jersey and from New Jersey to Delaware, respectively. Direct Energy claims that as a result, Applicants have understated Columbia Gas and Texas Eastern’s contribution to the PJM East gas market. Direct Energy also claims that Applicants have overestimated the size of the PJM gas market by incorrectly counting as deliveries in PJM gas that goes through PJM, but is ultimately delivered in New York and New England. Direct Energy’s witness, Dr. Briden, states that as a result, Applicants’ analysis understates the concentration in the upstream natural gas market, which he claims will be highly concentrated after the merger.¹²¹

189. The POCA expresses concern regarding EE&G’s 35.6 percent share of natural gas transportation capacity in the PJM East market. It states that with one party controlling a substantial amount of a capacity in such a constrained market, the exercise of market power could result in significantly increased gas costs to other LDCs and marketers in that market.¹²² The Commission should examine the amount of capacity that EE&G

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would hold on individual pipelines, as many LDCs in the Northeastern markets are captive to one or two pipelines. EE&G may be able to withhold capacity and raise natural gas prices.

190. The Division of the Ratepayer Advocates also expresses dissatisfaction with Applicants’ analysis of the natural gas market. Division of the Ratepayer Advocate states that the Application does not address horizontal market power issues that may result from the merger of the PHI Companies’ and PSE&G’s gas capacity assets, the potential for aggregating additional power by providing asset management services for third parties, or the effect of such activities on various markets. Division of the Ratepayer Advocate says that with the Applicants holding 35.6 percent of available capacity in the PJM East market area, any additional control of gas capacity resources (for example, through asset management agreements) would place the Applicants in a position to exert market power through various actions.¹²³ Division of the Ratepayer Advocate’s witness, LeLash, further states that Applicants fail to provide information concerning the control of storage capacity held by the entities holding the interstate transportation entitlements.¹²⁴ The City of Philadelphia echoes the concern that Applicants could abuse their market power in the transportation of natural gas to gain a competitive advantage in the relevant natural gas distribution markets.¹²⁵

191. Three protesters (FirstEnergy, Direct Energy, and POCA) express concerns that concentration in the upstream and downstream markets may allow the exercise of market power. FirstEnergy states that post-mitigation, the upstream PJM East market is at least moderately concentrated and the PJM East downstream market is highly concentrated. Direct Energy adds that because both the upstream and downstream markets will be highly concentrated after the merger, the proposed merger raises vertical market power concerns for which Applicants offer no mitigation.”¹²⁶ Direct Energy’s witness, Dr. Briden, suggests mitigation in the form of a transfer of a share of Applicants’ natural gas pipeline capacity to third party marketers not affiliated with Applicants. The POCA states that Applicants should not dismiss as irrelevant the failure to pass the downstream portion of the vertical market power test (in PJM East), because the ability to affect

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electricity prices through the control of natural gas supply or delivery could result in increased prices to all consumers, particularly since gas-fired plants operate on the margin and often set the market-clearing price in PJM.

3.

Applicants’ Answer

192. Applicants reply to AAI’s protest by stating that the Commission never found any violations in the proceedings that AAI cite. They conclude that AAI has presented no basis for concluding that the Commission should change its policy regarding RTO membership. They similarly dismiss, as mere speculation, the PHI Companies’ assertion that Applicants will be able to exert influence on PJM.

193. Applicants address concerns regarding the effect of the merger on the upstream natural gas market by restating their assertion that the transaction will not create a new situation where the combined entity could increase electric prices by denying gas supplies to other participants. Applicants state that because of their substantial divestiture commitment, they will have less Available Economic Capacity in the downstream electric market than they do today and that the upstream market will not be highly concentrated post-merger. Applicants’ witness, Dr. Hieronymus, answers protests that he calculated the HHI incorrectly by stating first that capacity that is bound for New York or New England is often sold into PJM East. Further, Dr. Hieronymus states that Direct Energy calculated upstream HHIs incorrectly by failing to remove Applicants’ northern-bound capacity in their calculations. He also states that Dr. Briden incorrectly calculates “others” share in the HHI calculations as the sum of their market shares, quantity squared, as opposed to the sum of the squares of the individual market shares. Correcting for these errors, he states, the upstream HHI is 1,651, so there are no vertical market power concerns.¹²⁷

194. Applicants address protesters’ concerns regarding the storage market by stating that Applicants own no storage capacity and contract for relatively small amounts (less than 12 percent) of PJM’s storage capacity. They state that because their share of storage capacity is smaller than their share of pipeline capacity, the storage market raises no vertical concerns.

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4.

Protestors’ Response to Applicants’ Answer

195. With regard to natural gas, the NJBPU states that it is concerned that the availability of spot market, short-term interruptible transportation in a market with peak period deliverability constraints is inadequate for new generation project developers and their lenders. It further argues that the Commission must decide whether the total pipeline capacity controlled by the Applicants will serve as a barrier to entry.¹²⁸

196. Direct Energy repeats its claim that Applicants overstated the size of the PJM East natural gas market. With respect to the purported error in the “others” category of his HHI calculation, Direct Energy witness Briden states that Dr. Hieronymus made the same mistakes in Exhibit J-16 of his original testimony.

197. With regard to electric transmission, the NJBPU agues that Applicants’ membership in PJM does not, by itself, ensure that their ownership and control of major electric transmission systems cannot be used to favor affiliated generation or hinder competing suppliers. The NJBPU remains concerned that influence in favor of corporate objectives may skew the projects that are built and stymie competing projects that could help other suppliers.

5.

Commission Determination

198. Applicants have shown that the combination of their generation and transmission facilities will not harm competition. Applicants have, pre-merger, transferred operational control over their transmission facilities to PJM, and the Commission has held, on a number of occasions, that such transfer mitigates the ability to use control of transmission assets to harm competition in wholesale electricity markets. We agree with Applicants that AAI’s protest does not provide a basis for concluding that the Commission should change its policy regarding RTO membership.¹²⁹

199. Applicants have shown that that the proposed merger will not allow them to control PJM. While no party contests Applicants’ description of PJM’s governance structure, the PHI Companies speculate that Applicants might be able to exert “undue influence” on PJM as a result of holding the largest transmission investment in PJM. However, it does not explain how this would happen.

Docket No. EC05-43-000		69

200. Applicants have shown that the combination of their generation and natural gas distribution facilities will not harm competition. In Order No. 642, we stated that in order for a merger to create or enhance vertical market power, both the upstream and downstream markets must be highly concentrated.¹³⁰ Applicants’ witness, Dr. Hieronymus, has shown that, given the mitigation, the downstream markets are not highly concentrated after the merger. Moreover, he has shown that the upstream market is not highly concentrated. Applicants have shown that protesters’ claims to the contrary result, in part, from selective omission of relevant capacity, an assertion that protesters do not counter. Dr. Hieronymus’ Exhibit J-16 clearly shows the “others” market share to be 16.7 percent, and their contribution to HHI to be 19. Had he used the calculation method Dr. Briden attributes to him, his contribution to HHI for “others” would have been 279 points, not 19.

201. We disagree with NJBPU’s assertion that Applicants will be able to foreclose new generation entry. Neither company owns interstate pipeline facilities, so this is not a convergence merger comparable to those in which the Commission has identified vertical market power issues as a result of the combination of electric and gas utilities. While Applicants do own natural gas LDCs through PECO and PSE&G, they do not own interstate transportation facilities. Potential entrants seeking fuel supplies can opt for a direct connection to the interstate pipelines serving the relevant markets rather than Applicants’ LDCs. Therefore, the merger does not give Applicants the ability to impede entry of gas-fired generating facilities.

202. Applicants have also shown that their presence in the natural gas storage market is small enough not to raise competitive concerns here. Applicants do not own storage facilities, and estimate their contracted share of the storage market to be less than 12 percent. Therefore, they would have little ability to influence downstream electricity prices.

203. With regard to the POCA’s and the Division of the Ratepayer Advocates’ concerns regarding horizontal effects in the natural gas market, we note that, under section 203 of the FPA, we consider the effects of an increase in concentration in the upstream market to the extent that it could harm competition in wholesale electricity markets. Here, as noted above, Applicants have shown that both the upstream and downstream markets are not highly concentrated, thus the horizontal upstream combination will not harm competition in the relevant downstream wholesale electricity markets.

Docket No. EC05-43-000		70

     F. Effect on Rates

1.

Applicants’ Analysis

204. Applicants state the transaction will not adversely affect the rates for any wholesale power or transmission customers. First, Applicants commit to hold transmission customers harmless from any increase in Commission-jurisdictional transmission rates to the extent that such costs exceed demonstrated savings related to the transaction. Applicants further state that no wholesale power rates will be affected because, of the three franchised utilities involved in the merger (ComEd, PECO and PSE&G), only ComEd has any wholesale requirements customers, and Applicants commit to hold ComEd’s customers harmless from any merger-related costs that exceed demonstrated merger-related benefits. Exelon and PSE&G’s remaining customers are charged market-based rates that will not be affected by the seller’s cost of service and, thus, will not be affected by the merger.

2.

Protests

205. The POCA says that the PJM OATT would allow the Applicants to file surcharges mechanisms or formula rates that might allow transmission rates to increase without reflecting the benefits of the merger.¹³¹

206. Dowagiac states that without proper mitigation, consumers will face both power and transmission cost increases as a result of the proposed merger. Dowagiac argues that the proposed mitigation measures are long-term and complex and will allow numerous opportunities for Applicants to exercise market power. It is also skeptical of Applicants’ pledge to protect current consumers from price increases as a result of the proposed merger. Dowagiac states that, regarding the ComEd and PECO merger, ComEd and PECO “pledged not to let financial injury fall on Dowagiac... [which is] now paying SECA charges of $1,107.83/MW- month to ComEd for PJM service.”¹³² Therefore, based on the current merger proposal and Exelon’s history in past mergers, Dowagiac argues that the Commission should condition the approval of the proposed merger on the fulfillment of all conditions associated with the ComEd and PECO merger. Specifically, Dowagiac requests that Exelon be directed to protect Dowagiac against any possible financial injury resulting from either the current merger proposal or the ComEd/PECO merger.

Docket No. EC05-43-000		71

3.

Applicants’ Answer

207. In response to protestors’ assertions that the merger would harm wholesale competition in PJM, thus, adversely affecting wholesale electricity rates, Applicants state that they have already addressed those concerns with the proposal to mitigate any merger-related harm to wholesale competition. In addition, in order to address the POCA’s concern that Applicants’ hold harmless commitment is inadequate, Applicants clarify that their hold harmless agreement allows for no surcharge or formula rate that would allow them to recover merger-related costs unless those costs were offset by merger-related savings.¹³³

208. In response to Dowagiac’s protest regarding through-and-out transmission rates related to ComEd’s participation in the PJM RTO, Applicants argue that Dowogiac’s complaints are not related to the merger and should be addressed in Docket No. EL02-111 or another appropriate forum.¹³⁴

4.

Responses to Applicants’ Answer

209. H-P Energy argues that Applicants should not be able to use the automatic cost recovery provisions of Schedule 12 of the PJM OATT without meeting all of the safeguards and procedures of Schedule 12. They state that the safeguards contained in Schedule 12 ensure that mandatory charges imposed on market participants are just and reasonable, and that Applicants have not justified bypassing any of those Commission-approved safeguards.¹³⁵

5.

Commission Determination

210. The Commission finds that Applicants have shown that the transaction will not adversely affect wholesale rates. We rely on Applicants’ hold harmless commitment for transmission rates in making this finding. In addition, wholesale power rates will not be adversely affected by the merger because, only ComEd has any wholesale requirements customers and Applicants commit to hold ComEd’s customers harmless regarding any

Docket No. EC05-43-000		72

merger-related costs that exceed demonstrated merger-related benefits. We rely on Applicants’ hold harmless commitment in finding that wholesale customers’ rates will not be adversely affected by the merger. Applicants’ other wholesale customers are charged market-based rates that will not be affected by the seller’s cost of service and, thus, will not be affected by the merger.

211. We agree with H-P Energy that Applicants should not be able to use the automatic cost recovery provisions of Schedule 12 of the PJM OATT. Applicants shall make the appropriate filings under section 205 of the FPA, related to cost recovery of any transmission expansion projects. Finally, we find that Dowagiac’s arguments regarding through-and-out transmission rates will be addressed in the complaint filed under Docket No. EL02-111.

     G. Effect on Regulation

1.

Applicants’ Analysis

212. Applicants state that the transaction will not adversely affect federal regulation. They state that the transaction will not result in the formation a new holding company under PUHCA that would preempt the Commission’s jurisdiction. They note that the transaction will bring PSE&G into the Exelon registered holding company system, and the Applicants commit to waive the pre-emptive effects of the Securities and Exchange Commission’s jurisdiction on this Commission under Ohio Power.¹³⁶

213. Applicants state the transaction will not adversely affect state regulation. They have filed for approval from the Pennsylvania Public Utility Commission (PaPUC) and the NJBPU, both of whom will therefore be able to protect their own jurisdiction. Applicants state that while the Illinois Commission does not have jurisdiction over the transaction, it does have jurisdiction to regulate ComEd, and they have filed notice of the transaction with the Illinois Commission. They further state that after the merger is complete, ComEd’s ownership will not change; it will remain an operating company within a registered holding company system. They conclude that the transfer will not have any effect on regulation of ComEd under Illinois law and that ComEd will remain under the jurisdiction of the Illinois Commerce Commission.

Docket No. EC05-43-000		73

2.

Protests

214. POCA argues that while Applicants submitted their application to the PaPUC, Applicants argued that the PaPUC lacks jurisdiction over this merger and only requested approval of the PaPUC in the alternative. Therefore, POCA requests that the Commission examine the potential adverse impact of the proposed merger on state regulation. Since this proposed merger would create one of the nation’s largest public utility holding companies and presents significant market power issues with a novel and untested mitigation proposal, POCA requests that the Commission investigate all issues related to the proposed merger by establishing further discovery, a hearing and access to further filings to determine if the proposed merger satisfies the Commission’s guidelines and is in the public interest.

215. Citizen Power, et al. raises concerns about the merger’s effect on power markets in general, and, in particular, the NJBPU’s regulatory authority, if the PUHCA is repealed.¹³⁷

3.

Applicants’ Answer

216. In response to the POCA’s concerns about the effect of the merger on state regulation in Pennsylvania, Applicants argue that the merger will not affect the structure of PECO, the one affected utility that is under the PaPUC’s jurisdiction. They further note that the PaPUC has intervened in the proceeding before the Commission, but has not raised any concerns regarding the effect of the merger on its regulatory authority or requested that the Commission address that issue. In response to Citizens Power, et al.‘s concerns about the effect of the merger on regulation if PUHCA is repealed, Applicants argue that the NJBPU can address any issues related to PUHCA repeal in the merger proceeding before it. In addition, they note that the NJBPU has not requested that Commission assist it on this issue.

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4.

Commission Determination

217. We find that the merger will not adversely affect Commission or state regulation. We rely on Applicant’s commitment to follow the Commission’s Ohio Power policy in finding that the merger will not adversely affect Commission regulation. Applicants have shown that the transaction will not harm any state’s ability to regulate any of the merging parties. The merger is subject to review by the NJBPU, who can therefore protect its jurisdictional interests. We note that the PaPUC has intervened in the proceeding before the Commission, but has not requested that the Commission address any issues regarding the effect of the merger on its regulatory authority. Furthermore, the PaPUC, the Illinois Commerce Commission, and the NJBPU will retain regulatory authority over the merged company. We note that none of the affected state commissions have requested that the Commission address the effect of the merger on state regulation.

The Commission orders:

     (A) Applicants’ proposed merger and internal restructuring is hereby authorized, subject to Commission acceptance of the Applicant’s compliance filings, as discussed in the body of this order.

     (B) The foregoing authorization is without prejudice to the authority of the Commission or any other regulatory body with respect to rates, service, accounts, valuation, estimates or determinations of costs, or any other matter whatsoever now pending or which may come before the Commission.

     (C) Nothing in this order shall be construed to imply acquiescence in any estimate or determination of cost or any valuation of property claimed or asserted.

     (D) The Commission retains authority under sections 203(b) and 309 of the FPA to issue supplemental orders as appropriate.

     (E) Applicants shall make any appropriate filings under section 205(a) of the FPA, as necessary, to implement the proposed Transaction.

     (F) Applicants must submit their proposed final accounting within six months of the consummation of the merger. The accounting submission should provide all merger-related accounting entries made to the books and records of PSE&G, along with appropriate narrative explanations describing the basis for the entries.

     (G) Applicants shall make a compliance filing to the Commission within 30 days of the completion of their divestiture, providing an Appendix A analysis of the merger’s effect on competition in energy and capacity markets, given actual plants and

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assets divested and the actual acquirers of the divested assets. If the analysis shows that the merger’s harm to competition has not been sufficiently mitigated, Applicants must propose additional mitigation at that time.

     (H) Applicants shall make a compliance filing to the Commission within 30 days of this order showing that they have established an independent monitor to oversee the baseload energy auction and Applicants’ compliance with the terms of the energy contracts; and that they have established a public compliance website the showing how they are complying with the virtual divestiture and other mitigation requirements, including the interim mitigation.

     (I) Applicants shall notify the Commission within 10 days of the date that the merger has been consummated.

By the Commission.

( S E A L )

		Magalie R. Salas,
		Secretary.

Exhibit D-11.1

113 FERC ¶ 61,299
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Joseph T. Kelliher, Chairman;

Nora Mead Brownell, and Suedeen G. Kelly.

Exelon Corporation		Docket Nos. EC05-43-000
Public Service Enterprise Group, Inc.		EC05-43-001

ORDER DENYING REHEARING, ACCEPTING COMPLIANCE FILING AND GRANTING CLARIFICATION

(Issued December 21, 2005)

1. Numerous entities¹ filed requests for rehearing of the Commission’s Merger Order² authorizing the merger of Exelon Corporation (Exelon) and Public Service

Docket Nos. EC05-43-000 and 001			2

Enterprise Corporation, Inc. (PSEG) (collectively, Applicants) under section 203 of the Federal Power Act (FPA).³ In this order, we deny the requests for rehearing.

Background

2. Applicants requested Commission approval of a transaction that includes Exelon’s acquisition of PSEG and the resulting indirect acquisition of Exelon’s and PSEG’s jurisdictional facilities and the internal restructuring and consolidation of Exelon’s and PSEG’s subsidiaries establishment of a new corporate structure for the new entity, Exelon Electric & Gas Corporation (EE&G). The Commission determined that proposed transaction, which included mitigation of harm to the competitive market through substantial divestiture of generation and several compliance filings with the Commission, is consistent with the public interest, as required by section 203 of the FPA.⁴

3. Several parties filed timely requests for rehearing. Applicants filed an answer, and NJBPU filed an answer to Applicants’ answer. Philadelphia Gas filed a motion to strike Applicants’ answer to the requests for rehearing.

Discussion

A.

Procedural Matters

4. When late intervention is sought after the issuance of a dispositive order, the prejudice to other parties and burden upon the Commission of granting the late intervention may be substantial. Thus, movants bear a higher burden to demonstrate good cause for granting such late intervention.⁵ Action Alliance of Senior Citizens of Greater Philadelphia, Philadelphia Association of Community Organizations for Reform Now, Service Employees International Union, SEIU New Jersey State Council, Tenant

Docket Nos. EC05-43-000 and 001			3

Action Group and the Utility Workers Union of America Local 601 have not met this higher burden.

5. Pursuant to Rule 713(d) and Rule 213(a)(2) of the Commission’s Rules of Practice and Procedure,⁶ answers to requests for rehearing are not permitted. Therefore, the Commission will reject Applicants’ answer to the requests for rehearing. Since we reject Applicants’ answer, we find Philadelphia Gas’ motion to strike Applicants’ answer moot.

6. On August 1, 2005, pursuant to the Merger Order, Applicants submitted a compliance filing outlining the independent administration of the baseload energy auction, including the hiring of an auction manager and an independent auction monitor.⁷ Notice of the August 1, 2005 compliance filing was published in the Federal Register, with comments due on or before December 8, 2005. The City of Philadelphia filed a timely protest to the compliance filing. We will accept Applicants’ compliance filing, as discussed below.

B.

Did the Commission Fail to Address Protestors’ in the Merger Order?

1.

Requests for Rehearing

7. Several parties argue that the Commission failed to address comments made in response to Applicants’ proposal. NJBPU states that the Commission ignored the report of the PJM Interconnection, LLC (PJM) Market Monitoring Unit (PJM MMU) evaluating the merger’s effect on the PJM-administered markets. NJBPU argues that the PJM MMU has access to historical market information and additional information relating to the specific PJM region which makes the PJM MMU analysis superior to the Applicants’ Appendix A analysis and the “only bona fide assessment” of the merger’s effects on the PJM markets.⁸

8. Additionally, NJBPU states that the Commission failed to recognize that the PJM MMU recommended more precise mitigation than that proposed by Applicants. NJBPU also argues that the Commission failed to address arguments that Applicants’ Appendix A analysis was based on questionable assumptions and thus understated Applicants’ market power and the mitigation necessary to ameliorate that market power. Some of these errors are assuming a low share of transmission import capacity and

Docket Nos. EC05-43-000 and 001			4

ignoring the effect of retirement of facilities and the possibility of withholding or other strategic bidding.

9. PPL argues that the Commission failed to address its comment that Applicants improperly analyzed the Northern New Jersey and PJM Classic markets, including evaluating appropriate mitigation in the Northern New Jersey market and the amount of import capability applicants have in the PJM Classic market. PPL also states that the Commission never responded to the issue of increased cost-capping under PJM’s three pivotal supplier rule.

2.

Commission Determination

10. It is simply not correct that the Commission failed to address these issues. The Commission addressed the analysis of the PJM MMU specifically in PP 103-109 of the Merger Order and throughout the Commission’s discussion section. The Merger Order also addresses the issues of properly analyzing the Northern New Jersey and PJM Classic markets in evaluating Applicants’ market power.⁹ PPL argues that the Commission did not address increased cost-capping under PJM’s three-pivotal-supplier rule. We did not directly address the three-pivotal-supplier rule because we made a finding, based on Applicants’ Appendix A analysis, that competition in the relevant capacity markets would not be adversely affected by the merger.¹⁰ We do not use the three-pivotal-supplier rule in our analysis of a merger’s effect on competition. Rather, it is a test used by the PJM Market Monitor to determine when bid caps should be put into place.

11. While the Commission disagrees that we failed to address these issues in the Merger Order, we will once again explain the basis for many of the decisions in the Merger Order below.

C.

Should the Commission Have Established an Evidentiary Hearing to Evaluate Issues of Material Fact?

1.

Requests for Rehearing

12. Several parties argue that the Commission should have established an evidentiary hearing to evaluate numerous disputed issues of material fact, such as inconsistencies and concerns about Applicants’ Appendix A analysis and the proposed divestiture.¹¹

Docket Nos. EC05-43-000 and 001			5

13. For example, Public Citizen states that Applicants’ analysis and economic expert witness were not subject to cross-examination and discovery.¹²

14. PaOCA and Illinois argue that the Commission’s failure to establish an evidentiary hearing denied parties a meaningful opportunity to be heard and to develop a complete record.¹³ PaOCA identifies several issues that, it argues, require a opportunity for discovery, cross-examination and full analysis through an evidentiary hearing. Denial of such an opportunity, PaOCA argues, would violate the parties’ due process rights.¹⁴

15. NJ Ratepayer Advocate argues that the Commission erred in failing to establish an evidentiary hearing to evaluate numerous issues of material fact, including Applicants’ ability to engage in strategic bidding and the effect Applicants’ gas operations will have on competition.¹⁵ NJ Ratepayer Advocate also identifies several other issues that should have been analyzed through an evidentiary hearing and argues that the Commission’s failure to order the hearing was arbitrary and capricious and was not reasoned decision-making.¹⁶

16. PPL argues that the Commission’s failure to order an evidentiary hearing to address the issues of material fact was not “a consideration of the relevant factors.”¹⁷ PPL states that the Commission ignored expert testimony, exhibits and analysis that demonstrated that material issues of fact existed.¹⁸ This failure to establish a hearing terminated the parties’ ability to explore these issues through discovery and cross-examination, according to PPL .¹⁹

Docket Nos. EC05-43-000 and 001			6

2.

Commission Determination

17. The Commission has broad discretion regarding when to set matters for hearing.²⁰ If the Commission can resolve disputed issues based on the written record, then the Commission is not required to establish an evidentiary hearing to address disputed issues of fact.²¹ No party has shown why the voluminous written record²² in this case was inadequate.

D.

Did the Commission Fail to Evaluate Market Power in the Natural Gas Market?

1.

Requests for Rehearing

18. NJPBU and Philadelphia Gas argue that the Commission did not consider all the evidence in finding that the merger would not have anticompetitive effects on the natural gas market. They state that the Commission ignored the analysis of Dr. Paul Carpenter, which indicated that the merger will affect natural gas prices in the PJM East market due to Applicants’ control of upstream gas capacity and storage.²³ Dr. Carpenter’s analysis concluded that Applicants will have significant market power in the relevant natural gas market. The HHI screen failures are not remedied by the mitigation because the mitigation only attempts to remedy the horizontal concentration in the electricity market, not the vertical concentration in the natural gas market.²⁴

19. NJ Ratepayer Advocate argues that the Commission erred in failing to evaluate the natural gas markets because there is a potential for horizontal market power in natural gas transportation and storage rights. This market power could lead to gas price manipulation even in the absence of a high level of concentration in the market.

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2.

Commission Determination

20. With respect to the vertical competitive impacts of a merger, the Commission examines three issues: (1) foreclosure/raising rivals costs; (2) competitive coordination; and (3) regulatory evasion.²⁵ The Commission has held that in order for a merger to have an adverse impact on competition by increasing the merged firm’s ability or incentive to engage in foreclosure or raise rivals’ costs, both the upstream and downstream markets must be highly concentrated.²⁶

21. NJBPU, Philadelphia Gas, and NJ Ratepayer Advocate either misunderstand the Commission’s standard for consistency with the public interest, or propose a new standard. As explained in the Revised Filing Requirements, we examine the effect of a merger on the upstream natural gas market, but only in conjunction with the downstream wholesale electric energy market. And only if both of these markets are concentrated do we have concerns.²⁷

22. The FPA does not grant the Commission authority to examine the horizontal impact of a merger on natural gas markets alone, which is what the parties ask. The Commission did indeed examine concentration in the natural gas market, in conjunction with concentration in the wholesale energy market, and determined that the merger did not raise an issue with respect to foreclosure.

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E.

Did the Commission Err in Accepting Applicants’ Proposal to Allocate Transmission Transfer Capacity on a Pro Rata Basis?

1.

Requests for Rehearing

23. Hoosier Energy argues that the Commission erred in accepting Applicants’ allocation in their study of scarce transmission transfer capability on a pro rata basis. It argues that this method of allocation creates a bias towards lower HHI estimates in the market analysis by maximizing the hypothetical participation of all potential competitors, regardless of price.²⁸ Hoosier Energy argues that the Commission ignored the argument that a least cost access method should be used to enable low cost suppliers to secure firm transmission rights, thus possibly precluding more expensive suppliers from access to the market.²⁹

2.

Commission Determination

24. We will deny Hoosier Energy’s request for rehearing. As we stated in the Merger Order, we are not persuaded that Applicants should have used an economic (i.e. least cost) allocation rather than a pro rata allocation of scarce transmission transfer capability in their analysis. We have accepted the pro rata allocation methodology in numerous merger cases,³⁰ and believe it reasonably models suppliers’ ability to compete in a given destination market. Moreover, Hoosier’s argument that the use of the pro rata allocation creates a bias towards lower HHI estimates by maximizing the hypothetical participation of all potential competitors, regardless of price, ignores a key feature of the DPT: only sellers with costs within 5 percent of the market price are assumed to be competing for the scarce transmission capability. All sellers with a profit opportunity would be competing to sell into the destination market. The pro rata allocation method recognizes that and gives appropriate weight to the potential sellers based on relative size.³¹

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F.

Should the Commission Have Evaluated Applicants’ Ability to Engage in Strategic Bidding?

1.

Requests for Rehearing

25. NJ Ratepayer Advocate argues that the Commission should have required Applicants to conduct a further analysis of their ability to engage in strategic bidding. Due to the nature of the Basic Generation Service auctions and the large market share Applicants will have in New Jersey, NJ Ratepayer Advocate states that Applicants could engage in strategic bidding in the Basic Generation Service auctions and exercise market power. However, the Commission determined that Applicants would not be able to exercise market power and engage in strategic bidding based on the analysis of the HHI screen and the Commission’s Market Behavior Rules.³²

2.

Commission Determination

26. We deny rehearing. Strategic bidding is a form of economic withholding, which is a way of exercising market power.³³ In the Merger Order, we gave two reasons why the Applicants’ Appendix A analysis did address the merger’s effect on Applicants’ incentive or ability to engage in strategic bidding. First, the DOJ Merger Guidelines recognize that the HHI conveys information about the likelihood of the unilateral exercise of market power.³⁴ Second, in order to address the screen failures in various season/load conditions, Applicants proposed divesting units with a range of operational and cost characteristics, including the types of units that protestors argue could be used to engage in strategic bidding or withholding. Using widely accepted measures of a merger’s effects on competition and the market power of the merged firm, Applicants showed that the proposed divestiture would mitigate any increase in the merged firm’s market power and thus its ability to harm competition through strategic bidding.

G.

Did the Commission Employ a Flawed Competitive Analysis?

1.

Requests for Rehearing

27. PPL argues that the Commission should have required Applicants to address the

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concerns PPL raised as to whether Applicants’ chosen price levels accurately reflected market prices; instead the Commission accepted Applicants’ vague response that “choosing market prices... is as much an art as it is a science.”³⁵ PPL asserts that the accuracy of Applicants’ DPT should have been set for hearing.³⁶

2.

Commission Determination

28. We deny PPL’s request for rehearing. Applicants supported their DPT by: (1) providing tests of the sensitivity of their results to changes in the critical parameters in the model; (2) answering protestors’ specific questions regarding assumed input prices and wholesale energy market prices; (3) providing an analysis by PSEG’s witness, Mr. Rodney Frame, that confirmed Dr. Hieronymus’ results.³⁷ In addition, as we stated in the Merger Order, the PJM MMU Study largely confirmed the accuracy of Applicants’ results, finding similar pre-merger and post-merger concentration levels. PPL has not explained why this was not adequate.

H.

Did the Commission Ignore Evidence of Applicants’ Power Marketing in Analysis?

1.

Requests for Rehearing

29. Public Citizen argues that the Commission should have discussed the failure of Applicants’ market concentration analysis to address Applicants’ power marketing activities.³⁸

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2.

Commission Determination

30. We deny Public Citizen’s request for rehearing. The Appendix A analysis focused on capacity controlled by all potential sellers in the relevant market. Without control of capacity, whether through ownership of physical assets or through power purchase agreements, sellers cannot harm competition in wholesale energy markets. If Applicants (or any other potential suppliers) gain control of generation capacity through power marketing activities, the Appendix A analysis does consider power marketing activity, but simply the presence of a large power marketing operation does not, in itself, confer any additional market power on the merged firm or on any other seller.

I.

Did the Commission Improperly Fail to Consider Supplemental Evidence?

1.

Requests for Rehearing

31. Philadelphia Gas argues that the Commission ignored evidence it submitted pointing out errors in Applicants’ analysis that affected the evaluation of the proposed merger’s effect on the delivered gas market in PJM East.³⁹

2.

Commission Determination

32. Comments and protests to the proposed merger were due on or before April 11, 2005. In response to the numerous comments and protests filed in response to Applicants’ proposed merger, on May 10, 2005 Applicants made a supplemental filing that amended their proposed analysis and mitigation. The Commission then provided all parties with an additional opportunity to respond to the supplemental filing with comments due on or before May 27, 2005. Several parties, including Philadelphia Gas, filed additional comments in response to Applicants’ amended filing and many of the additional comments included lengthy responses to the Applicants’ amended market power analysis. However, one month after the comment date had already passed, Philadelphia Gas filed additional comments disputing Applicants’ amended market power analysis.

33. The Commission did not accept Philadelphia Gas’ additional comments due to the lateness of its filing. The Commission has discretion whether to accept a late-filed answer. After reviewing Philadelphia Gas’ June 27, 2005 filing, the Commission determined that it did not provide new information that would have assisted the Commission in its decision-making process. Therefore, the Commission properly declined to accept the late-filed comments. However, we note that Philadelphia Gas’ arguments actually duplicated arguments raised by FirstEnergy, NJ Ratepayer Advocate

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and Pennsylvania Office of the Consumer Advocate, among others, and those arguments were addressed.

J.

Did the Commission Improperly Approve the Merger Based in Part Upon Compliance Filings and Future Actions?

1.

Requests for Rehearing

34. Hoosier Energy, PaOCA and Illinois state that the Commission failed to meet the section 203 standard by approving the merger based on its “understanding” that further mitigation may be required in the future if the proposed mitigation proves insufficient.⁴⁰

35. NJBPU argues that the Commission violated section 203 by finding that the proposed merger is consistent with the public interest after determining that the proposed mitigation and divestiture may not adequately mitigate the merger’s harm to competition.⁴¹ NJBPU states that the Commission requirement of compliance filings to demonstrate that the mitigation actually does mitigate the harm to competition after the merger has already been consummated does not satisfy the public interest standard in section 203.⁴² This would be an after-the-fact determination that the merger is consistent with the public interest and is contrary to the requirement that we find that the merger is consistent with the public interest before approving it.⁴³

36. Based on the Commission’s finding that additional mitigation may be required if the mitigation conditions accepted in the Merger Order are not adequate to remedy the harm to competition, Philadelphia Gas argues that the Commission has failed to make the statutorily required finding that the merger is consistent with the public interest .⁴⁴ Philadelphia Gas contends that the Commission seeks to “hedge its bets” in approving the merger by stating its right to impose additional future mitigation.⁴⁵ Philadelphia Gas claims that, by asserting its right to impose future mitigation, the Commission is

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admitting that the merger is not in the public interest, even though the Merger Order found that the merger does satisfy the public interest standard under section 203.⁴⁶ Finally, Philadelphia Gas states that it is not clear whether the Commission has the authority to impose additional mitigation and divestiture obligations.⁴⁷

2.

Commission Determination

37. Section 203(a) states that if the Commission determines that a proposed merger is consistent with the public interest, then the Commission shall approve the proposed transaction.⁴⁸ Section 203(b) clarifies that the Commission may approve a proposed merger upon a finding that it is consistent with the public interest and “... upon such terms and conditions as it finds necessary or appropriate to secure the maintenance of adequate service and the coordination in the public interest of facilities subject to the jurisdiction of the Commission.”⁴⁹ Thus, while the Commission must find that proposed mergers are consistent with the public interest before they can be approved, the Commission can do this by imposing conditions and requiring supplemental filings to demonstrate both that the additional conditions have been met and that the accepted mitigation is actually ensuring that markets are not harmed.

38. The Commission determined in the Merger Order that the proposed merger of Exelon and PSEG is consistent with the public interest. However, due to the size of the proposed merger, the Commission decided to exercise its section 203(b) powers and order compliance filings to ensure that the mitigation plan proceeds as expected to ensure that market power does not increase. The Commission retains its right under section 203(b) to order future mitigation, if necessary, to ensure that the proposed merger and mitigation remain consistent with the public interest.

39. The Commission has ordered additional filings in previous mergers to ensure that the mitigation will alleviate market power concerns resulting from the merger. In approving the merger of American Electric Power Company, Inc. and Central and

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SouthWest Corporation, for instance, the Commission permitted the companies to divest different generation upon a compliance filing with the Commission.⁵⁰

40. Here, the Commission is requiring that Applicants provide compliance filings with an updated Appendix A analysis upon completion of the divestiture to ensure that the Applicants are fulfilling their mitigation obligations and to permit the Commission to monitor the market in the wake of the merger. The compliance filings are just one method the Commission uses to be doubly sure that market power concerns are resolved.

K.

Should the Commission Have Required Applicants to Specify the Units to be Divested?

1.

Requests for Rehearing

41. Hoosier Energy states that the Commission did not engage in reasoned decision-making because the Merger Order did not require Applicants to specify the exact units they plan to divest. The Commission violated its own Merger Policy Statement⁵¹ and regulations, Hoosier Energy argues, by approving the merger without knowing which specific units Applicants plan to divest. Hoosier Energy also states that the Commission did not explain why it did not follow the Merger Policy Statement or section 33.3 of the Commission’s regulations.⁵²