exv99w2

Exhibit 99.2

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION


Exelon Corporation	)	Docket No. EC05-___
Public Service Enterprise Group Incorporated	)

APPLICATION FOR AUTHORIZATION OF
DISPOSITION OF JURISDICTIONAL ASSETS
UNDER SECTION 203 OF THE FEDERAL POWER ACT

J.A. Bouknight, Jr.
Douglas G. Green
Steptoe & Johnson LLP
1330 Connecticut Ave., NW
Washington, DC 20036
(202) 429-6222

R. Edwin Selover
Sr. Vice President and General Counsel
Richard P. Bonnifield
Vice President – Law
80 Park Plaza
Newark, New Jersey 07102

Counsel for
Public Service Enterprise Group
Incorporated

Mike Naeve
Matthew W.S. Estes
Skadden, Arps, Slate,
Meagher & Flom LLP
1440 New York Avenue, N.W.
Washington, D.C. 20005
(202) 371-7000

Elizabeth Anne Moler
Executive Vice President
A. Karen Hill
Vice President
101 Constitution Avenue, N.W.
Suite 400 East
Washington, DC 20001

Counsel for
Exelon Corporation

February 4, 2005

TABLE OF CONTENTS


					Page
TABLE OF CONTENTS						i
I.	INTRODUCTION					2
II.	DESCRIPTION OF THE APPLICANTS					4
	A.	Exelon				4
		1.	Energy Delivery			5
		2.	Generation			7
	B.	PSEG				8
		1.	PSE&G			9
		2.	PSEG Power			10
III.	DESCRIPTION OF THE TRANSACTION					12
	A.	The Transaction and Post-Transaction Structure				12
	B.	The Transaction Provides Important Public Interest Benefits				13
IV.	THE TRANSACTION IS CONSISTENT WITH THE PUBLIC INTEREST					15
	A.	Horizontal Competition Issues				16
		1.	Results of the Applicants’ Appendix A Analysis			16
		2.	The Applicants Will Mitigate All Screen Failures			19
			a.	Mitigation During Peak and Superpeak Load Conditions		20
			b.	Mitigation During Off-Peak Load Conditions		22
		3.	Analysis of Northern PSEG Market			29
		4.	The Proposed Virtual Divestiture Satisfies the Commission’s Mitigation Standards			30
		5.	Interim Mitigation			34
			a.	Interim Mitigation for Peaking, Mid-Merit and Coal Units		34
			b.	Interim Mitigation for Baseload Nuclear Capacity		35
		6.	Market Power in Capacity Markets and Ancillary Services			36
			a.	Mitigation of Capacity Market Screen Failures		36
			b.	Other Ancillary Services		40
		7.	Horizontal Market Power in Other Geographic Markets			42
			a.	ISO New England ("ISO-NE")		42
			b.	ERCOT		43


		Virtual Market Power Issues		44
		1.	No Potential for Abuse of Electric Transmission Market Power	44
		2.	No Potential for Abuse of Natural Gas Transportation Market Power	46
	C.	No Adverse Impact On Rates		48
		1.	Transmission Rates	48
		2.	Wholesale Requirements Rates	48
	D.	No Adverse Impact On Regulation		50
		1.	No Adverse Impact on Federal Regulation	50
		2.	No Adverse Impact on State Regulation	50
	E.	The Internal Restructuring is Consistent with the Public Interest		51
V.	INFORMATION REQUIRED BY PART 33 OF THE COMMISSION’S REGULATIONS			53
	A.	Section 33.2(a): Names and addresses of the principal business offices of the applicants.		53
	B.	Section 33.2(b): Names and addresses of persons authorized to receive notices and communications in respect to the Application.		53
	C.	Section 33.2(c): Description of Applicants.		53
	D.	Section 33.2(d): Description of the jurisdictional facilities owned and operated or controlled by Applicants, their parents or affiliates.		53
	E.	Section 33.2(e): Narrative description of the Transaction.		54
	F.	Section 33.2(f): Contracts with respect to the Transaction.		54
	G.	Section 33.2(g): Facts relied upon to show that the Transaction is in the public interest.		54
	H.	Section 33.2(h): Physical property.		54
	I.	Section 33.2(i): Status of actions before other regulatory bodies.		54
	J.	Section 33.5: Accounting Entries		54
VI.	CONCLUSION			55

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION


Exelon Corporation	)	Docket No. EC05-___
Public Service Enterprise Group Incorporated	)

APPLICATION FOR AUTHORIZATION OF
DISPOSITION OF JURISDICTIONAL ASSETS
UNDER SECTION 203 OF THE FEDERAL POWER ACT

Pursuant to Section 203 of the Federal Power Act (“FPA”) and Part 33 of the Commission’s Regulations, Exelon Corporation and its subsidiaries that are public utilities subject to the Commission’s jurisdiction (collectively, “Exelon”)¹ and Public Service Enterprise Group Incorporated and its subsidiaries that are public utilities subject to the Commission’s jurisdiction² (collectively, “PSEG”) (collectively, Exelon and PSEG are referred to as “Applicants”) hereby request that the Commission approve a transaction (the “Transaction”) that includes: (1) Exelon’s acquisition of PSEG and the resulting indirect merger of Exelon’s and PSEG’s jurisdictional public utilities; and (2) the subsequent internal restructuring and consolidation of Exelon’s and PSEG’s subsidiaries to establish a more efficient corporate structure for the combined company. As described in more detail below, the proposed Transaction meets the Commission’s standards for determining when a transaction is consistent with the public interest and as a result can be approved without a hearing. The Applicants request that the Commission grant its approval no later than August 1, 2005.

¹		The Exelon entities subject to the Commission’s jurisdiction are identified below in Exhibit B of this Application.

²		The PSEG entities subject to the Commission’s jurisdiction are identified below in Exhibit B in this Application.

I. INTRODUCTION

The combination of Exelon and PSEG to form Exelon Electric & Gas Corporation (“EEG”) will create a new, vital player in Midwest and Mid-Atlantic electricity markets. Exelon and PSEG support — and, in fact, have been strong advocates for — the further development of competitive electricity markets in both the wholesale and retail markets, consistent with the initiatives of the Federal Energy Regulatory Commission (“the Commission”), the Illinois Commerce Commission (“ICC”), the Pennsylvania Public Utility Commission (“PAPUC”), and the New Jersey Board of Public Utilities (“NJBPU”). The combination will lead to numerous efficiency and operating improvements in the combined generation fleet and also will further the development of competitive markets in these respective jurisdictions. A particularly important focus for EEG will be achieving enhanced operational and reliability efficiencies from the integration of their respective nuclear fleets, with associated regional reliability benefits and market price reductions. Indeed, the opportunity to achieve enhanced nuclear operating performance by applying Exelon’s world class nuclear operating expertise to PSEG’s nuclear generating assets is a primary motivating force driving the Transaction.

Exelon’s and PSEG’s core markets are located in the PJM region and, given the size of the two companies, it is not surprising that an Appendix A analysis indicates that horizontal market power issues are raised by combining their generation assets into a single company. The Applicants propose extensive mitigation, however, that completely mitigates any potential market power issues. In total, the Applicants propose to divest control over the output of 5,500 MW of generation.

Because the combination creates screen violations under all load conditions analyzed, the Applicants have proposed divestiture of all types of generation. With

respect to peaking, coal and mid-merit capacity, the Applicants propose to divest 2,900 MW of capacity. In combination with Applicants’ other mitigation proposals, this divestiture mitigates all Appendix A screen failures for peak and superpeak load conditions.

The Applicants’ Appendix A analysis also indicates screen failures during off-peak load conditions. The Commission has found that market power concerns are less of an issue during off-peak conditions due to the availability of considerable amounts of unused capacity and operational limitations on baseload capacity that make it difficult to withhold such capacity from the market. Nevertheless, the Applicants propose to completely mitigate all screen failures in off-peak load conditions. This will be accomplished by a “virtual divestiture,” which involves auctioning off long-term entitlements to baseload nuclear energy.

In total, the Applicants propose to divest control over 2,600 MW of baseload capacity through this energy sales process. These sales remove any merger-related ability or incentive for the Applicants to withhold capacity from the market, while at the same time permitting Exelon to apply its unique nuclear operating expertise to PSEG’s nuclear units in order to increase their output, as well as their reliability. Increased output from those units will, of course, be procompetitive.

Competitive retail markets rely on procurement of power from a competitive wholesale market and, thus, it is important from an ultimate customer perspective that the Transaction not increase market power in wholesale markets. Further, while not directly relevant to the Commission’s approval of this transaction, it is notable that the Transaction also will not eliminate any competitor in retail markets. Only Exelon has a retail marketing affiliate, and this affiliate is not active in eastern PJM. PSEG has no

retail marketing affiliates and, thus, no retail supplier is eliminated as a result of the Transaction.

Once the horizontal market power issues are resolved, there are no other significant issues raised by the Transaction. The Transaction will not create transmission market power issues inasmuch as the Applicants already have transferred control over their transmission systems to PJM, and no natural gas-electric vertical market power issues are implicated. Nor will the Transaction have any adverse impacts on rates or regulation. As a result, the Commission should be able to determine that the Transaction is consistent with the public interest and grant its approval without a hearing.

II. DESCRIPTION OF THE APPLICANTS

A. Exelon

Exelon is a registered public utility holding company that, through its subsidiaries, is one of the nation’s largest electric utilities. It distributes electricity to approximately 5.1 million customers in Illinois and Pennsylvania, and gas to 460,000 customers in the Philadelphia area. Exelon operates in three primary business segments, Energy Delivery, Generation, and Enterprises. The Enterprises business, which is being wound down, is an infrastructure and electrical contracting business directed primarily towards the communications and energy services industries.³ The Energy Delivery and Generation business segments are described below.

Enterprises exited a significant number of its business activities in 2003 and 2004, and plans to divest or otherwise wind down its remaining assets in 2005.

1. Energy Delivery

The Energy Delivery business segment consists of Exelon’s regulated energy delivery operations conducted by ComEd and PECO. It engages in three areas of business: (1) Retail Electric Services; (2) Transmission Services; and (3) Gas Services.

ComEd

ComEd is engaged principally in the purchase, transmission, distribution and sale of electricity to a diverse base of residential, commercial, industrial and wholesale customers in northern Illinois. ComEd’s retail service territory has an area of approximately 11,300 square miles and an estimated population of eight million. The service territory includes the City of Chicago, an area of about 225 square miles with an estimated population of three million. ComEd has approximately 3.6 million customers. ComEd does not own any generation, but instead purchases its requirements from Exelon Generation.

PECO

PECO is engaged principally in the purchase, transmission, distribution and sale of electricity to residential, commercial and industrial customers in southeastern Pennsylvania and in the purchase, distribution and sale of natural gas to residential, commercial and industrial customers in the Pennsylvania counties surrounding the City of Philadelphia. PECO provides electric delivery service in an area of approximately 2,000 square miles, with a population of approximately 3.9 million, including 1.5 million in the City of Philadelphia. Natural gas service is supplied in an approximate 1,900 square mile area in southeastern Pennsylvania adjacent to Philadelphia, with a population of approximately 2.4 million. PECO delivers electricity to approximately 1.5 million customers and natural gas to approximately 460,000 customers. Like ComEd, PECO

does not own any generation, but instead purchases its requirements from Exelon Generation.

Retail Electric Services

Electric utility restructuring legislation was adopted in Pennsylvania in December 1996 and in Illinois in December 1997. Both Illinois and Pennsylvania permit competition by alternative generation suppliers for retail generation supply while transmission and distribution service remains fully regulated. Both states, through their regulatory agencies, established a phased approach for allowing customers to choose an alternative electric generation supplier; imposed caps on rates during a transition period; and allowed the collection of competitive transition charges from customers to recover costs that might not otherwise be recovered in a competitive market.

Under Illinois and Pennsylvania legislation, ComEd and PECO are required to provide generation services to customers who do not or cannot choose an alternative supplier. ComEd and PECO each have provider of last resort (“POLR”) obligations to provide generation services (i.e., power and energy) to those customers who do not take service from an alternative generation supplier or who choose to come back to the utility after taking service from an alternative supplier.

Transmission Services

ComEd and PECO have both placed their transmission systems under the operational control of PJM Interconnection, L.L.C. (“PJM”), which is the independent system operator and the Commission-approved RTO for the Mid-Atlantic and Midwest region in which it operates. PJM is the transmission provider under, and the administrator of, the PJM Open Access Transmission Tariff (“PJM Tariff”), operates the PJM Interchange Energy Market and Capacity Credit Markets, and conducts the day-to-

day operations of the bulk power system of the PJM region. Under the PJM tariff, transmission service is provided on a region-wide, open-access basis using the transmission facilities of the PJM members at rates based on the costs of transmission service.

Gas Services

Energy Delivery’s gas services business is conducted solely by PECO, and not by ComEd or any other Exelon company. PECO’s gas sales and gas transportation revenues are derived pursuant to rates regulated by the PAPUC. PECO’s gas facilities are limited to local distribution facilities. Neither PECO nor any other Exelon company owns any interstate natural gas facilities that are subject to the Commission’s jurisdiction under the Natural Gas Act.

PECO’s customers have the right to choose their gas suppliers or else purchase their gas supply from PECO at cost. Approximately 30% of PECO’s current total yearly throughput is supplied by third parties. Gas transportation service is provided on an open-access basis and remains subject to regulation by the PAPUC. PECO’s gas service area includes several independent gas-fired generators, all but one of which have bypassed the distribution system. One independent generator, a 28 MW plant, has a readily available bypass option and has negotiated a discounted distribution rate with PECO. PECO also provides gas transportation services to two affiliated generators at a negotiated discounted transportation rate.

2. Generation

Exelon’s generation business is conducted by Exelon Generation Company, LLC (“Exelon Generation”). Exelon Generation was created in 2001, when Exelon restructured its business operations following the Unicom-PECO merger. Exelon

Generation combines its large generation fleet with an experienced wholesale power marketing operation. Exelon Generation owns or controls, through long-term contracts, generation assets in the Northeast, Mid-Atlantic, Midwest, Southeast, South Central and Texas regions with a net capacity of approximately 33,000 MWs. Included in this capacity is Exelon Generation’s ownership interests in 11 nuclear generating stations, consisting of 19 units. All of the nuclear generating stations are operated by Exelon Generation, with the exception of Salem Generating Station (“Salem”), which is co-owned with, and operated by, PSEG Nuclear, LLC. A listing of Exelon Generation’s generation assets is attached as Exhibit J-3 to Dr. Hieronymus’ testimony.

Exelon Generation’s wholesale marketing unit, Power Team, a major wholesale marketer of energy, uses Exelon Generation’s energy generation portfolio, transmission rights and expertise to ensure delivery of energy to Exelon Generation’s wholesale customers under long-term and short-term contracts, including contracts for the load requirements of ComEd and PECO. Power Team markets any remaining energy in the wholesale bilateral and spot markets.

B. PSEG

PSEG is an exempt public utility holding company with four major subsidiaries: (1) Public Service Electric and Gas Company (“PSE&G”), a regulated electric transmission and electric and gas distribution business; (2) PSEG Power LLC (“PSEG Power”), the parent of most of PSEG’s US power production businesses; (3) PSEG Services Corporation (“PSEG Services”); and (4) PSEG Energy Holdings LLC (“PSEG Holdings”), the parent of PSEG’s other businesses including: (i) PSEG Global LLC (“PSEG Global”), is engaged in power production and distribution in selected domestic and international markets, and (ii) PSEG Resources LLC, which invests in energy-related

financial transactions. A more detailed description of PSE&G, PSEG Power and PSEG Global, which are the entities most relevant to the Commission’s Section 203 analysis, is provided below.

1. PSE&G

PSE&G is an operating public utility company engaged principally in the transmission and distribution of electric energy and gas service in New Jersey. PSE&G provides service to approximately 2.0 million electric customers and approximately 1.6 million gas customers. PSE&G’s electric and gas service area is a corridor of approximately 2,600 square miles running diagonally across New Jersey from Bergen County in the northeast to an area below the city of Camden in the southwest.

PSE&G also owns electric transmission facilities subject to the Commission’s jurisdiction under the FPA. PSE&G has transferred operational control over these facilities to PJM.

PSE&G, pursuant to an order of the NJBPU issued under the provisions of the New Jersey Electric Discount and Energy Competition Act (“EDECA”), transferred all of its electric generation facilities, plant, equipment and wholesale power trading contracts to PSEG Power and its subsidiaries in August 2000. Also, pursuant to an NJBPU order, PSE&G transferred its gas supply business, including its inventories and supply contracts, to PSEG Power in May 2002. PSE&G continues to own its transmission system and owns and operates its electric and gas distribution businesses.

PSE&G distributes electric energy and gas to end-use customers within its designated service territory. All electric and gas customers in New Jersey have the ability to choose an electric energy and/or gas supplier. Pursuant to NJBPU

requirements, PSE&G serves as the supplier of last resort for electric and gas customers within its service territory.

New Jersey’s Electric Distribution Companies (“EDCs”), including PSE&G, provide basic generation service (“BGS”) to retail customers located in New Jersey. The EDCs obtain the power they need to supply BGS through the use of two concurrent competitive wholesale auctions currently conducted each February.

PSE&G’s natural gas facilities consist entirely of local gas distribution facilities and neither PSE&G nor any other PSEG company owns any interstate natural gas facilities subject to the Commission’s jurisdiction under the Natural Gas Act. PSE&G provides open-access gas transportation over its facilities under terms and conditions established by the NJBPU. PSE&G serves eight current or former qualifying facilities (“QFs”) under contract with the utility, as well as two merchant generators: the Tosco plant (172 MW) and the Williams Red Oak plant (765 MW). These generating facilities served by PSE&G are under long-term gas distribution contracts or discounted tariffs. PSE&G also provides gas transportation services to affiliated generators in its service area.

2. PSEG Power

PSEG Power is a wholesale energy supply company that integrates its generating asset operations with its wholesale energy, fuel supply, energy trading and marketing and risk management function through three principal direct wholly-owned subsidiaries: PSEG Nuclear LLC (“PSEG Nuclear”), which owns and operates nuclear generating stations, PSEG Fossil LLC (“PSEG Fossil”), which develops, owns and operates domestic fossil and other non-nuclear generating stations and PSEG Energy Resources & Trade LLC (“PSEG ER&T”), which markets the capacity and production of PSEG

Fossil’s and PSEG Nuclear’s stations, manages the commodity price risks and market risks related to generation, and provides gas supply services.

Through its operating subsidiaries, PSEG Power competes as a wholesale electric generating company, primarily in the Northeast. Most of PSEG Power’s generating assets in the Northeast are located within PJM, although PSEG Power also owns generation assets in New York, Connecticut and the western part of PJM.

PSEG Power’s generation portfolio, along with that of PSEG Global, consists of approximately 18,000 MW of installed capacity in North America. PSEG Power’s generation capacity is sourced from a diverse mix of fuels comprised of natural gas, nuclear, coal, oil and pumped storage. A complete listing of PSEG Power’s generation assets is attached as Exhibit J-3 to the testimony of Dr. Hieronymus.

PSEG Power has an ownership interest, through PSEG Nuclear, in five nuclear generating units and operates three of them: the Salem Nuclear Generating Station, Units 1 and 2 (Salem 1 and 2), each owned 57.41% by PSEG Nuclear and 42.59% by Exelon Generation and the Hope Creek Nuclear Generating Station (“Hope Creek”), which is 100% owned by PSEG Nuclear. Exelon Generation operates the Peach Bottom Atomic Power Station Units 2 and 3 (“Peach Bottom 2 and 3”), each of which is 50% owned by PSEG Nuclear.

3. PSEG Global

In addition to its assets owned in other countries, PSEG Global jointly owns GWF Energy LLC, which in turn owns three generating facilities located in California. PSEG Global also owns generation assets in ERCOT. PSEG Global’s U.S. generation assets also are listed in Exhibit J-3 of Dr. Hieronymus’ testimony.

III. DESCRIPTION OF THE TRANSACTION

A. The Transaction and Post-Transaction Structure

Pursuant to the terms of the Agreement and Plan of Merger (the “Merger Agreement”) attached as Exhibit I, PSEG will merge into Exelon, thereby ending the separate corporate existence of PSEG. Each PSEG shareholder will be entitled to receive 1.225 shares of Exelon common stock for each PSEG share held and cash in lieu of any fraction of an Exelon share that a PSEG shareholder would have otherwise been entitled to receive. Exelon, which will be renamed Exelon Electric & Gas Corporation (“EEG”), will be the surviving company, remain the ultimate corporate parent of PECO and ComEd and the other Exelon subsidiaries and become the ultimate corporate parent of PSE&G and the other PSEG subsidiaries. Exelon common stock will be unaffected by the proposed Transaction, with each issued and outstanding share remaining outstanding following the Transaction as a share in the surviving company.

Diagrams depicting EEG’s post-Transaction corporate structure (as well as Exelon’s and PSEG’s pre-Transaction structures) are attached hereto as Exhibit C. EEG will continue to be a registered public utility holding company under PUHCA, and ComEd, PECO and PSE&G will continue to be operating franchised public utility companies. EEG will remain headquartered in Chicago but will also have energy trading and nuclear headquarters in southeastern Pennsylvania and generation headquarters in Newark, New Jersey. PSE&G will remain headquartered in Newark. PECO will remain headquartered in Philadelphia and ComEd will remain headquartered in Chicago.

In addition, EEG, as the surviving company of the Transaction, will assume all of PSEG’s outstanding indebtedness. The indebtedness of subsidiaries of PSEG will not be

assumed or guaranteed by EEG and will remain the obligation of such subsidiary and any of the guarantors of such indebtedness.

In addition to the changes resulting from the Merger Agreement, the Applicants intend to revise their corporate structure. Although not yet completely finalized, the Applicants currently propose to implement the following changes. These changes also are reflected on the post-Transaction organizational chart included as part of Exhibit C.

1. PSE&G will become a direct subsidiary of Exelon Energy Delivery Company LLC. The current subsidiaries of PSE&G will remain intact.

2. PSEG Energy Holdings LLC (“PSEG Holdings”) will become a direct subsidiary of EEG, as the successor to PSEG. The current subsidiaries of PSEG Holdings will remain intact.

3. PSEG Services Corporation (“PSEG Services”) will sell all of its assets to Exelon Business Services Company (“Exelon BSC”), change its name, and remain as a non-energy subsidiary. Exelon BSC will be the sole “service company” of EEG.

4. After obtaining any appropriate consents from the PSEG Power debt holders and restructuring, 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 either be merged into Exelon Generation or retained as direct subsidiaries of Exelon Generation.

B. The Transaction Provides Important Public Interest Benefits

The combined company will serve over seven million electric customers and two million gas customers in three states. By sharing resources and best practices, the Transaction will enhance operations and strengthen the combined company’s ability to provide cost-effective, safe and reliable service and will affirmatively promote the public interest in a number of substantial ways.

(a) Increased Scale and Scope; Diversification. The combined company will have increased scale and scope in both energy delivery and generation. In addition,

the combined company is expected to have greater diversification and balance in its energy delivery business and generation portfolio. This increased scale, scope and diversification is expected to result in improved service and reliability. With respect to the energy delivery business, the combined company will have three urban utility franchises with service areas encompassing more than 18 million people. The combined company also will have a large gas distribution portfolio to complement its electric distribution business. The combined generation portfolio will be more balanced in terms of geography, fuel mix, dispatch and load-servicing capacity.

(b) Commitment to Competition. Exelon and PSEG have been staunch advocates for competitive retail and wholesale markets in electricity and gas. This shared vision will allow the new company to be even more active in the promotion of competitive markets and the development of energy-related services. In addition, New Jersey, Pennsylvania and Illinois all have passed legislation bringing competition to the electric industry, and are in varying phases of the transition to full competition. The regulatory knowledge and experience of each company will enhance the merged company’s ability to manage the transition to competition for the benefit of both customers and shareholders.

(c) Improved Nuclear Operations. Given Exelon’s strong, successful performance in running the nation’s largest nuclear fleet, the Applicants expect to realize improved stability, higher capacity utilization rates and lower costs from combining nuclear operations under one management. See Testimony of Mr. Crane. Higher capacity utilization rates means that the Applicants would be producing more energy from their nuclear fleet that can be sold in the wholesale markets, which should have a procompetitive effect in the wholesale energy markets located in the PJM region where

the Applicants are located. This in turn should be beneficial to the Applicants’ retail customers as well as to retail customers throughout the PJM region.

Increasing nuclear output will have a small but significant tendency to lower wholesale prices. This is because increasing the amount of energy at “the bottom of the stack” will in at least some hours lower the PJM marginal cost. All else being equal, therefore, this should lower LMP prices, particularly in PJM East.

(d) Anticipated Financial Strength and Flexibility. The diversification of the energy delivery and generation portfolios of the combined company should result in a more stable cash flow, with approximately half of the combined company’s earnings and cash flow coming from the three regulated utilities and approximately half coming from the unregulated generation business.

(e) Sharing of Best Practices. The Transaction will combine companies with complementary areas of expertise; Exelon’s expertise in the generation operations and PSEG’s expertise in the transmission and distribution operations.

(f) Synergies. The Transaction will create the opportunity to achieve meaningful cost savings not only through the sharing of best practices, but also through the elimination of duplicative functions, improved operating efficiencies in transmission and distribution, nuclear and other generation operations, and supply chain benefits from improved sourcing.

IV. THE TRANSACTION IS CONSISTENT WITH THE PUBLIC INTEREST

In determining whether a proposed disposition of jurisdictional facilities is consistent with the public interest under Section 203 of the FPA, the Commission

evaluates the impacts of the proposed disposition on competition, rates and regulation.⁴ Furthermore, when considering impacts on competition, the Commission reviews both horizontal competition issues resulting from increases in concentration in electric energy and capacity markets, and vertical competition issues resulting from increases in the ability or incentive to leverage control over electric transmission and natural gas transportation facilities to enhance revenues in generation markets.⁵ As discussed below, with the comprehensive mitigation plan volunteered by the Applicants, the Transaction will have no adverse effects in any of these areas.

A. Horizontal Competition Issues

1. Results of the Applicants’ Appendix A Analysis

PJM operates the largest centrally dispatched, competitive wholesale electricity market in the United States. The market is well-functioning, and has in place comprehensive and Commission-approved market monitoring and mitigation procedures to address attempts by market participants to exercise generation or transmission market power. The PJM market monitor has the authority to identify and deter, and has been effective in deterring, withholding or other attempts at market manipulation. Notably, the operation of PJM mitigation is essentially automatic whenever sub-areas within PJM are constrained.

⁴		Merger Policy Statement, III FERC Stats. & Regs, ¶ 31,044 at 30,111 (1996) (“Merger Policy Statement”); Revised Filing Requirements under Part 33 of the Commission’s Regulations, 1996-2000 FERC Stats. & Regs., ¶ 31,111 at 31,872 (2000) (“Revised Filing Requirements”).

⁵		Id. at 31,111 at 31,872.

Both Exelon and PSEG are active participants in PJM wholesale markets. Collectively, they control approximately 40,000 MW of generation capacity in those markets, of which approximately 17,000 MW of generation is located in the western part of PJM that only recently was integrated into PJM, and approximately 23,000 MW of generation is located in the Mid-Atlantic part of PJM that consists of the original PJM members plus Allegheny Power.

In order to determine the impact of the Transaction on competition in the PJM market and elsewhere, the Applicants engaged Dr. Hieronymus to perform an “Appendix A” analysis⁶ of the Transaction as required by the Commission’s Merger Regulations. The results of this analysis are described in detail in the attached testimony of Dr. Hieronymus, and summarized below.

As Dr. Hieronymus explains, the initial task was to determine the geographic markets that should be used for his analysis. The Commission has held that when, as is the case here, merger applicants are members of an RTO, it is appropriate to consider the RTO as a single market.⁷ However, due to known transmission constraints within PJM that periodically limit west to east power flows, Dr. Hieronymus also analyzed three geographic sub-markets within PJM.

⁶		The Appendix A analysis was first described in the Merger Policy Statement, III FERC Stats. & Regs. ¶ 31,044 at 30,130-135. The requirements of the Appendix A analysis since have been incorporated into the Commission’s regulations (the “Merger Regulations”) at 18 CFR § 33.3 (2004).

⁷		Revised Filing Requirements, ¶ 31,111 at 31, 884-5 (citing Atlantic City Electric Company and Delmarva Power & Light Company, 80 FERC ¶ 61,126 (1997); Consolidated Edison Co., Inc. and Northeast Utilities, 91 FERC ¶ 61,225 (2000)).

For the Commission’s convenience, attached as Appendix 1 is a map showing these market boundaries. The markets analyzed by Dr. Hieronymus are as follows:

•   “Expanded PJM” consists of all of the geographic markets that constitute the PJM RTO. In addition to “PJM Pre-2004” described below, Expanded PJM includes PJM West⁸ and PJM South.⁹ Arguably, under the Commission’s policy, Expanded PJM is the only geographic market that needs to be analyzed, since it constitutes the RTO in which the Applicants are located. Indeed, the Commission has accepted the Expanded PJM market as the appropriate market for conducting market power analyses for market-based rate applicants located in PJM.¹⁰ Nevertheless, Dr. Hieronymus analyzed a number of smaller markets as well.

•   “PJM Pre-2004” is the original PJM Mid-Atlantic market before PJM was expanded, plus Allegheny Energy. PJM Pre-2004 includes nine utility systems whose service territory covers all or part of Pennsylvania, New Jersey, Maryland, Delaware, Virginia, West Virginia, Ohio and the District of Columbia. This market can be separated from the Expanded PJM market during hours when there are constraints limiting deliveries from certain of the newer PJM companies (AEP, ComEd, Dayton) into PJM Pre-2004.

•   “PJM East” is the eastern portion of PJM Pre-2004, on the eastern side of transmission constraints that limit the amount of energy that can be transferred from lower cost generation in the western part of PJM Pre-2004. Although it could be argued that the Commission should not view PJM East as a separate market, there periodically are transmission constraints that separate this market, and the Commission previously has examined smaller submarkets within PJM in examining market power issues.¹¹ PJM data shows that transmission into PJM East was constrained approximately 200 hours in 2003 and 275 hours in 2004. As a result, Dr. Hieronymus analyzed the smaller PJM East market as well.

•   “Northern PSEG” is the constrained portion of PSE&G’s control area. Dr. Hieronymus also considered whether to analyze Northern PSEG as a relevant geographic market. However, only PSEG owns generation in the Northern PSEG area, and not Exelon, so there is no overlap between the Applicants. Given that there is no overlap of generation ownership, Dr. Hieronymus does not believe that it is appropriate to consider Northern PSEG as a relevant geographic market. Nevertheless, to be conservative Dr. Hieronymus considered the Northern PSEG geographic market as well.

⁸		PJM West includes the former control areas of Allegheny Energy, AEP, Commonwealth Edison, Dayton Power & Light, and Duquesne Power.

⁹		PJM South will include the current Dominion Virginia Power control area.

¹⁰		Virginia Electric and Power Company, 108 FERC ¶ 61,242 (2004); Dayton Power and Light Company, 109 FERC ¶ 61,268 (2004).

¹¹		See, e.g. Atlantic City Electric Co., 86 FERC ¶ 61,248 at 61,896-97 (1999).

As Dr. Hieronymus explains in more detail, his analysis shows that the Transaction could result in market concentration screen failures for the Economic Capacity measure of generation ownership during the off-peak, peak and superpeak load conditions that he analyzed in PJM East, PJM Pre-2004 and Expanded PJM during all three seasons studied — Summer, Winter and Shoulder. As expected, the largest screen failures are in PJM East, which is the market where both PECO and PSE&G are located. In PJM East, the post-merger Economic Capacity HHIs are highly concentrated for all 10 load conditions analyzed (above 1,800), and the HHI increase in each time period is from 900 to 1,150. While the Economic Capacity results for Expanded PJM and PJM Pre-2004 are less extreme, they result in moderately concentrated post-merger markets with HHI increases above 100, and in many instances significantly above 100.

Dr. Hieronymus’ calculations using the Available Economic Capacity measure suffer from the requirement that a series of assumptions are necessary with respect to how load requirements are met in markets with retail access. However, under the assumptions used by Dr. Hieronymus, there are post-transaction screen violations for Available Economic Capacity in the PJM East and PJM Pre-2004 markets, but not in Expanded PJM.

2. The Applicants Will Mitigate All Screen Failures

From Dr. Hieronymus’ analysis, it is clear that, regardless of the geographic market studied, the Transaction will result in Appendix A screen failures that must be mitigated. The exact mitigation required is complicated, however, by the fact that the screen violations take place during all load conditions, including superpeak conditions when peaking units with high fuel costs are running, peak conditions when the most expensive peaking units are not running, and off-peak conditions when the only units

running are baseload units with low fuel costs. This means that mitigation is required for each of the three following categories of generation: (1) peaking units; (2) mid-merit units; and (3) baseload nuclear units.

Different considerations apply to these different types of units. As a result, the Applicants propose different approaches for, on the one hand, mitigating the screen failures that occur during peak and superpeak load conditions and, on the other hand, the screen failures that occur during off-peak load conditions. These approaches are described in more detail below.

a. Mitigation During Peak and Superpeak Load Conditions

The Applicants Propose to Divest Coal, Mid-Merit and Peaking Generation

The Applicants propose to engage in generation divestiture to address the screen failures associated with peak and superpeak load conditions. The Commission stated in the Merger Policy Statement that divestiture is an acceptable method of market power mitigation,¹² and has reaffirmed this statement in a number of subsequent merger cases.¹³

As Dr. Hieronymus explains, his analysis shows that the Applicants would need to divest approximately 1,000 MW of peaking capacity and 1,900 MW of mid-merit capacity, of which at least 550 MW must be coal-fired, in PJM East in order to eliminate peak and superpeak screen failures.¹⁴ These amounts are based on the assumption that

¹²		Merger Policy Statement, III FERC Stats. & Regs. ¶ 31,044 at 30,137.

¹³		See, e.g., Allegheny Energy, Inc., 84 FERC ¶ 61,223 (1998); American Electric Power Co., 90 FERC ¶ 61,242 (2000).

¹⁴		In addition to the amount of peaking and mid-merit generation described in this section, the Applicants also will mitigate their market power in nuclear baseload capacity as described below which, in addition to mitigating screen failures in off-peak hours is necessary to mitigate screen failures in peak and super peak hours as well.

the generation is sold in equal amounts to two buyers, and that no purchaser already owns significant amounts of capacity in the relevant markets.

The Applicants therefore propose to divest 1,000 MW of peaking capacity and 1,900 MW of mid-merit capacity, including at least 550 MW of coal-fired capacity which, when combined with the proposed nuclear baseload mitigation, should fully mitigate the screen violations in the peak and superpeak load conditions in all three geographic markets. The divestiture will occur either through a swap of assets with owners of generation located outside of Expanded PJM or through an outright sale of the generating facility.

No more than half of this capacity, i.e. 1,450 MW will be sold to a single purchaser. In addition, no capacity will be sold to a market participant with a greater than 5% share of installed capacity in either PJM East or Expanded PJM, as identified in Exhibit J-9 to Dr. Hieronymus’ testimony. Furthermore, no more than 25% of this amount of capacity, i.e., 725 MW, will be sold in the aggregate to market participants with 3% - 5% of the total installed capacity in either the PJM East or the Expanded PJM markets. Dr. Hieronymus’ analysis shows that these restrictions will ensure that the proposed mitigation eliminates the screen failures that he identified.

The Applicants have not yet identified the specific plants that they intend to divest. However, they recognize that the Commission needs to be assured that the divested generation will be located in PJM East to ensure that the Applicants’ screen violations will be adequately mitigated. As a result, attached as Exhibit J-12 to Dr. Hieronymus’ testimony is a list of peaking, mid-merit and coal-fired generation facilities that will be considered for divestiture, along with the location of that generation, in order to accomplish the required divestiture of at least 2,900 MW of peaking, mid-merit and

coal-fired generation. As this list shows, the generation facilities to be considered for divestiture are all located in PJM East and thus also will mitigate market power in the broader PJM markets.

Divestiture Will Be Completed Within 18 Months After the Merger

The Commission has recognized that divestiture can take some time, and that merger applicants should not be rushed into a divestiture process that would cause them to sell at below-market prices. For example, in AEP, the Commission allowed a two-year time period for divestiture to take place.¹⁵ The Applicants propose that they be given 18 months to complete the proposed divestiture of peaking, mid-merit and coal-fired generation. The Applicants intend to complete the divestiture more quickly, but 18 months may be necessary to conduct an auction, negotiate all necessary agreements, and obtain all necessary regulatory approvals. The Applicants recognize that the Commission will require interim mitigation to be put in place until the divestiture is completed.¹⁶ The Applicants’ proposed interim mitigation proposal is discussed in more detail below.

b. Mitigation During Off-Peak Load Conditions

The Applicants propose a different mitigation approach to resolving the Appendix A screen failures that occur in off-peak load conditions. Rather than divesting their nuclear baseload units, the Applicants propose to implement a “virtual divestiture” whereby they will divest themselves, through sales of long-term firm energy rights, of any incremental merger-related ability to withhold baseload energy. The proposed virtual

¹⁵		AEP, 90 FERC ¶ 61,242 at 61,792 (2000).

¹⁶		Merger Policy Statement, III FERC Stats. & Regs. ¶ 31,044 at 30,136. See also AEP, 90 FERC at 61,792-94; Ameren Services Co., 101 FERC ¶ 61,202 (2002); Ameren Corp., 108 FERC ¶ 61,094 (2004).

divestiture also will eliminate any merger-related ability of EEG to profit on its baseload facilities from a withholding of mid-merit or peaking facilities.

The mitigation alternative of auctioning baseload energy rather than selling nuclear units is appropriate for several reasons. First, as discussed below, sales of baseload energy under firm long-term contracts would be as effective as a divestiture of nuclear unit(s) in mitigating any adverse effects that the merger might have on wholesale and retail competition.

Second, an outright sale of nuclear units would not be in the public interest because it would eviscerate the very operating, efficiency and reliability benefits that motivate the proposed Transaction. As explained in the testimony of Mr. Crane, the Applicants intend to apply the world class operating expertise of Exelon to increase the reliability, availability and safety of PSEG’s nuclear capacity. Indeed, because a prime motivation for the Transaction relates to achieving these benefits for the Applicants’ nuclear generation, it is unlikely that the Transaction would be consummated if the Applicants are not permitted to retain ownership and control of PSEG’s nuclear units. In turn, the increase in nuclear availability factors that the Applicants hope to achieve should result in more energy being produced, which should have a procompetitive effect on the market.

Dr. Hieronymus’ analysis shows that there needs to be a transfer of control over 2,400 MWs of baseload capacity in PJM East, if transferred to two entities. However, the Applicants do not propose to auction off the sale of entitlements to 2,400 MWs of baseload energy on a 100% load factor basis. That is because their nuclear generating capacity does not operate on a 100% load factor basis. Given Exelon’s historic average nuclear capacity factor of approximately 93% described in the testimony of Mr. Crane,

the sale of approximately 2,250 MW of energy on a 100% load factor basis is the equivalent of the sale of approximately 2,400 MW of capacity operating at a 93% capacity factor.

Use of historic capacity factors to establish the amount of required virtual divestiture provides an additional public benefit. EEG will have an incentive to increase the capacity factors of its nuclear units in order to increase the benefit it receives from those units. An increase in capacity factors means, of course, an increase in output from the units, which provides an additional procompetitive benefit.

Dr. Hieronymus’ analysis shows that the divestiture of an additional 200 MW of baseload capacity will be needed to mitigate screen failures in the larger PJM Pre-2004 market. Divestiture of this additional amount can occur anywhere in Pre-2004 PJM. The amount of virtual divestiture required thus is the energy equivalent of 2,400 MW of capacity in PJM East plus 200 MW of capacity in Pre-2004 PJM for a total of 2,600 MW of capacity. This total is referred to as the “Baseload Mitigation Amount.”

This virtual divestiture will take one of two forms: (1) a firm sales contract (“Long-Term Contract”) for a term that expires no earlier than 15 years following the close of the transaction (the “Long-Term Contract Option”), or (2) an annual auction, in 25 MW blocks, of 3-year firm entitlements to baseload energy (the “Baseload Auction Option”). Each of these two options is described in more detail below. As was the case with the divestiture of peaking, mid-merit and coal-fired generation, no single purchaser will be allowed to purchase more than 50% of the whole Baseload Mitigation Amount.

The sum of the baseload energy entitlements divested under the two options will always equal or exceed the Baseload Mitigation Amount. Thus, when the Baseload Mitigation Amount is 2,600 MW and the Applicants sell 400 MW to one purchaser under

a 15-year contract and 600 MW to a second purchaser under a second 15-year contract, the minimum amount of baseload energy that will be divested under the Baseload Auction Option will be 1,600 MW.

(i) Details of Baseload Auction Option

Under the Baseload Auction Option, the merged company will conduct annual auctions of 3-year firm entitlement to 25 MW blocks of baseload energy. After an initial phase-in, approximately one-third of the Baseload Mitigation Amount, reduced by the amount of any sales under the Long-term Contract Option, will be auctioned each year (the “Auction Amount”). The process for conducting the Baseload Auction Option is described in more detail in the testimony of Mr. Cassidy.

As Mr. Cassidy explains, the auctions will be held annually to coincide with the New Jersey BGS auctions (currently held in February). The term of the firm energy product to be auctioned will coincide with the term of the load obligations that are subject to the BGS Auction (i.e., running from the June 1 following the auction date until May 31, three years later).

The product to be auctioned will be a 3-year firm obligation to take 25 MW of baseload energy on a 24 x 7 basis. The price per MW will be established through a simultaneous multi-round ascending clock auction process, to be administered by an independent party. The Applicants will make sales regardless of the price determined under the auction.

The delivery point for the firm energy product associated with the PJM East mitigation will be based on an aggregate of the Applicant’s nuclear generating buses located primarily in the PJM East region (which aggregate could change as a result of

decommissioning, derates, or sales under the Long-Term Sales Option from a single PJM East nuclear facility). The remaining 200 MW associated with the mitigation required for the broader markets can be delivered at the PJM West Hub, unless EEG agrees to a different delivery point.

The testimony of Mr. Sabatino, who is experienced in the marketing of power in the Northeast, including PJM, demonstrates that market participants would view this as an attractive product. Mr. Sabatino explains that the availability of a substantial amount of baseload energy in small blocks, with delivery in PJM East and pursuant to a transparent auction process, will coincide with the needs of market participants throughout PJM East. Although the timing of the auction is intended to coincide with the needs of BGS auction participants, the product is valuable to all PJM East market participants, firms competing for retail sales, and participants in bilateral wholesale transactions.

The first auction to be conducted under the Baseload Auction Option will be used to phase into the subsequent annual auctions of one-third of the Auction Amount. In the initial auction, one-third of the Auction Amount will be sold for a one-year term, one-third will be sold for a two-year term, and one-third will be sold for a three-year term. In each of the subsequent annual auctions, one-third will be sold for three years.

(ii) Long-Term Contract Option

Under this option, the Applicants will sell, on a bilateral basis, entitlements to PJM East baseload nuclear energy with terms of at least 15 years. As consideration for transferring long-term rights to their PJM East nuclear energy, Applicants will receive either cash or similar rights to energy in regions outside of PJM (i.e., an energy swap).

Applicants will offer two alternative long-term products. The first will be identical to the product offered under the Baseload Auction Option, except that the term of the agreement will be for a minimum of 15 years following the close of the Transaction (i.e., a firm 24 x 7 must-take product to be delivered at the aggregate of the Applicant’s PJM East nuclear buses).

The alternate product will be similar, but based on the performance characteristics of a designated PJM East nuclear facility. Thus the delivery point and energy availability will be based on the actual unit. The Applicants will, however, guarantee the delivery of an annual amount of energy from the facility based on its historic capacity factor. For this product, the term of the contract will be the lesser of 15 years or the date on which the unit is retired. If the unit is permanently derated, the contract amount will be correspondingly reduced. This product will be more practical if Applicants are to enter into energy swap agreements because it is unlikely that swap partners will be able to offer a product similar to the aggregate nuclear bus product.

The Applicants commit that they will impose the same restrictions under their Baseload Energy Mitigation that they apply to divestiture with respect to who can purchase the capacity. The Applicants will not at any time make sales under the Long-Term Contract Option to any purchaser that currently owns greater than 5% of the installed generating capacity in either PJM East or in Expanded PJM as identified on Exhibit J-9 of Mr. Hieronymus’ testimony. Furthermore, the Applicants will not sell under the Long-Term Contract Option to market participants that own 3% - 5% of the installed generation capacity in Expanded PJM or PJM East for more, in the aggregate, than 25% of the Baseload Mitigation Amount. When a contract entered into under the Long-Term Contract Option terminates, the Applicants will determine whether their

remaining Baseload Mitigation Amount, taking into account any reductions provided for below, requires that some or all of the energy represented by that contract continue to be subject to virtual divestiture. If the Baseload Mitigation Amount has been reduced below the level that is being mitigated by other effective virtual divestiture contracts, then the capacity represented by that contract need not be mitigated further. To the extent that some or all of the capacity released by an expired contract still must be subject to virtual divestiture in order to meet the remaining Baseload Mitigation Amount, the Applicants may either resell that capacity under a new Long-Term Contract that satisfies the requirements described above, or the required amount of capacity will be added to the next Baseload Energy Auction.

(iii) Reductions in Baseload Mitigation Amount

The Baseload Mitigation Amount will be reduced, megawatt by megawatt, in the event of any of the following with respect to baseload nuclear capacity located in PJM East: (a) the sale of a nuclear generating unit to a non-affiliated entity; (b) the retirement or permanent derating of a nuclear generating unit; and (c) the construction of additional transmission transfer capacity into PJM East, excluding any increases in transfer capacity that might result from the construction of projects included in the PJM Regional Transmission Expansion Plan that is effective as of June 2005, which will give the Applicants an additional incentive to pursue and encourage the construction of new transmission projects. Moreover, before retiring any unit located in PJM East during the first 15 years following the closing of the Transaction, the Applicants will attempt to sell that unit by auction. They will sell the unit if the sale can be concluded on terms that yield a positive price and recover the fair value of the property to EEG, taking into account alternative uses of the property, as determined by an independent appraiser.

3. Analysis of Northern PSEG Market

As explained above, Dr. Hieronymus does not believe that the Northern PSEG market is a relevant geographic market, because Exelon owns no generating capacity within that zone. Nevertheless, Dr. Hieronymus conducted an Appendix A analysis limited to this area, and it showed screen failures. This is because other generation in PJM East is “squeezed down” by the transmission limit into northern PJM. Thus, while Exelon’s share of this market is less than in PJM East, PSEG’s is larger.

That does not mean that any additional mitigation should be required for the Northern PSEG market. In fact, Dr. Hieronymus explains that no mitigation is required because EEG will have no more generation in the market than did PSEG before the Transaction. Thus, the incentive to raise prices in that market will be no greater after the Transaction , and will be reduced to the extent the Applicants, pursuant to their mitigation plan, divest coal, mid-merit or peaking generation in northern New Jersey, because in either case the Applicants will have the same amount of, or less, generation that benefits from higher northern New Jersey prices.

The ability to raise prices in Northern PSEG also will not be increased after the merger. The amount of the Applicants’ generation inside Northern PSEG will be the same or less after the Transaction, so there will be no additional ability to withhold generation from the market. The only change caused by the Transaction will be that EEG will have more generation outside the market than PSEG had before the merger, but any generation that EEG might withhold outside the constrained market will not affect prices inside the constrained market.

If the Commission determines, however, that additional mitigation is necessary, the Applicants would agree to mitigate the northern New Jersey screen failures. The

screen failures would be eliminated by the divestiture of no more than 100 MW of coal-fired generation and no more than 100 MW of mid-merit generation. This is a subset of the 5,500 MW of overall mitigation. The Applicants would agree to meet this requirement either by divesting such generation in northern New Jersey as part of their overall divestiture commitment or by delivering baseload energy into northern New Jersey (or selling it at the Applicants’ PJM East buses plus a basis differential into northern New Jersey). As with other divestitures, selling or delivering generation with a lower variable cost also mitigates the screen failure.

4. The Proposed Virtual Divestiture Satisfies the Commission’s Mitigation Standards

The combined effect of the Applicants’ mitigation proposals for baseload, coal, mid-merit and peaking energy markets will be the outright divestiture of 2,900 MW of generating facilities, and the transfer of the energy equivalent of 2,600 MW of baseload capacity to unaffiliated parties under long-term firm contracts, for a total divestiture of control over 5,500 MWs of generating capacity. Although the Commission never has addressed the use of long-term firm contracts for permanent market power mitigation, a commitment to the sale of long-term firm rights to energy from nuclear baseload units will cure the merger’s Appendix A failures during off-peak periods.

Under the Commission’s regulations, generation capacity is attributed for competition analysis purposes “to the party that has authority to decide when generating resources are available for operation,” and also may be assigned based on other “operational control criteria.”¹⁷ The reason for this requirement is that the Commission is

¹⁷

18 CFR § 33.3(c)(4)(i)(A) (2004).

concerned about the ability to profitably withhold generation from the market, which is the way that an entity with horizontal market power exercises that market power. If baseload energy is sold by the Applicants into the market with a firm delivery obligation, that energy cannot be withheld by the Applicants from the market to raise prices. As a result, that capacity is not attributed to the merger applicants for competition analysis purposes.¹⁸

The proposed virtual divestiture clearly meets this standard. As described more fully below, the Commission has found that firm energy sales transfer control and constitute adequate mitigation on an interim basis.¹⁹ There is no reason why firm sales of energy on a long-term basis cannot mitigate market power on a long-term basis as well.

Moreover, the Commission frequently has observed that the need to protect against physical or economic withholding of baseload capacity is questionable.²⁰ When load levels and prices are at their lowest point, supply curves are nearly horizontal. There is scant incentive to withhold baseload generation from the market because any withheld generation can be replaced by other available supplies with operating costs similar to the marginal unit that would set prices absent withholding.

Furthermore, during off-peak load conditions most if not all of the generation in PJM is supplied either by coal units that are operating at minimum or partial load set

¹⁸		Ameren Corp., 108 FERC ¶ 61,094 at P44 (2004).

¹⁹		See American Electric Power Corp., 91 FERC ¶ 61,208 (2000); Ameren Services Co., 101 FERC ¶ 61,202 (2002); Ameren Corp., 108 FERC ¶ 61,094 (2004).

²⁰		See Merger Policy Statement, III FERC Stats. & Regs. ¶ 31,044 at 30,134-35; Atlantic City Electric Company, 86 FERC ¶ 61,248 at 61,902 (1999).

points, or by nuclear units that cannot readily be cycled down and then cycled back up hours later to meet intermediate and peak load requirements. As explained in the testimony of Mr. Crane, such cycling is operationally impractical because it can result in a temporary build up of “poisons” (neutron-absorbing isotopes) in fuel rods that inhibit the reaction process. For this reason, the Commission has recognized on a number of occasions, including the merger of PECO and Unicom that formed Exelon, that it is difficult to engage in a withholding strategy through the use of nuclear units.²¹ EEG’s baseload fleet will be predominately nuclear, particularly in PJM-East. Thus when loads are low, EEG will have little or no physical ability to withhold baseload supply to influence prices.

Not only does the Applicants’ proposal eliminate any merger-related incentive for EEG to withhold baseload energy from the market, but it also reduces any merger-related incentive for EEG to withhold its remaining mid-merit, coal or peaking capacity from the market. Because a minimum of the energy-equivalent of 2,600 MW of EEG’s baseload capacity always will be committed to unaffiliated parties at fixed prices, EEG will not be able to profit on that capacity from any price increases that might result from a withholding of its other units. Thus with the proposed mitigation in place, the Transaction will not increase the ability or incentive of EEG to withhold capacity from the market.

In addition to the fact that the Applicants’ mitigation proposal will eliminate the ability and economic incentive for EEG to withhold energy or artificially increase prices,

²¹

See U.S. Gen. New England, 109 FERC ¶ 61,361 at P 23 (2004); Ohio Edison Co., 94 FERC ¶ 61,291 at 62,044 (2001); Commonwealth Edison Co., 91 FERC ¶ 61,036 at 61,134 n. 42 (2000).

the PJM Market Monitoring Unit will exercise substantial, ongoing oversight over the market participants in order to ensure that the market continues to function in a competitive manner. Indeed, the existence of a full-time market monitor in PJM should enhance the Commission’s willingness to accept the proposed mitigation programs.²² In addition, market participants surely will monitor and enforce the Applicants’ commitments to make forward sales.

It also is noteworthy that the PJM tariff incorporates several provisions that provide financial incentives for the Applicants and other market participants to increase generation output. For example, PJM requires all units that are Capacity Resources to bid into the day-ahead market to their maximum capacity. If a bid is accepted and the unit becomes unavailable in real time, the unit owner must pay the market the difference between the real-time market closing price and the day-ahead closing price.

Thus, the proposed mitigation eliminates any merger related screen failures, while preserving the significant benefits of improving the reliability and output of the Applicants’ combined nuclear fleet. By expanding nuclear capacity factors, and in particular the capacity factors for the Salem and Hope Creek nuclear units operated by PSEG, the Transaction should result in greater supplies of baseload energy and lower PJM market prices.

²²

See, e.g. Atlantic City Electric, 86 FERC ¶ 61,248 at 61,902 (1999) (noting that PJM market monitor proposal “will . . . serve to minimize opportunities for the sustained exercise of market power.”)

5. Interim Mitigation

a. Interim Mitigation for Peaking, Mid-Merit and Coal Units

As noted above, the Commission in the past has recognized that divestiture can take time to accomplish, and the Commission has not necessarily required that divestiture be completed before a merger closes. However, when there are significant competition concerns, as is the case with a merger between the Applicants, the Commission does require that interim mitigation be put in place pending divestiture or other permanent mitigation (such as transmission expansion or joining an ISO or RTO).²³

The most common interim mitigation measure for addressing horizontal market power is the sale of long-term firm rights to capacity and energy until the permanent mitigation is in place. The Commission has approved such sales as interim mitigation measures on a number of occasions.²⁴

Therefore, the Applicants propose that, within 30 days following the end of the month in which the Transaction closes, the Applicants will sell the rights to 2,900 MW of energy and capacity from designated coal, mid-merit and peaking facilities in PJM East. The restrictions described above that apply to the divestiture regarding who can purchase capacity and how much capacity can be purchased apply to these interim sales as well. These sales are described in more detail in the testimony of Mr. Cassidy.

The interim contracts will have a minimum term of one month and will be in effect for no longer than a period of 18 months from the close of the Transaction. If a

²³		See Revised Filing Requirements, ¶ 31,111 at 31,900; See also, AEP, 90 FERC ¶ 61,242 at 61,792 (2000).

²⁴		See American Electric Power Corp., 91 FERC ¶ 61,208 (2000); Ameren Services Co., 101 FERC ¶ 61,202 (2002); Ameren Corp., 108 FERC ¶ 61,094 (2004).

designated unit subsequently is divested, the contract associated with that unit will be assignable without consent to the party who acquires the designated unit. The product will be a “virtual unit transfer” type of product, tied to specific units, and with the counterpart acquiring full dispatch and unit offering rights (i.e., the buyer will be responsible for offering the unit into the PJM energy, capacity and ancillary services markets). The dispatch parameters for the product will match the dispatch parameters on file with PJM for the subject units; for example, unit start-up time, minimum run time, ramp rates, and high and low operating limits. The product also will include all of the Unforced Capacity associated with the subject unit. Until such time as the entire 2,900 MW of this capacity is committed under interim mitigation contracts, Applicants will bid 2,900 into the PJM day-ahead (and, if not dispatched, into the PJM real-time) market at a price not to exceed the equivalent of PJM cost-capped rates (i.e., variable cost defined in PJM’s Cost Development Task Force rules plus 10 percent).

b. Interim Mitigation for Baseload Nuclear Capacity

Prior to the initial February auction under the long-term baseload mitigation plan, Applicants will conduct an auction of interim firm entitlements to firm 25 MW blocks of energy. The interim product to be offered for sale will be identical to the product offered pursuant to the Baseload Auction Option, with two exceptions. The first exception is the product will be sold for a shorter term than the three-year product sold in the Baseload Auction Option. To the extent possible, the term(s) of the interim energy contracts will coincide with the terms of products most commonly purchased in the PJM markets. For example, if there is a 13 month period between the commencement of sales under interim contracts and the commencement of sales under the Baseload Auction Option, rather than auctioning an equivalent of 2,600 MW of capacity for 13

months (which would not be a standard market product), the Applicants would separately auction 2,600 MW of capacity for one-month, and 2,600 MW of capacity for 12 months. One-month and 12-month products are more commonly traded in PJM markets.

The second difference between the interim product and the long-term product is that the Applicants will deliver the product either at the PJM East nuclear generation aggregate bus, or alternatively at the PJM West Hub combined with a basis differential between the PJM West Hub and the PJM East nuclear generation aggregate bus. This alternative delivery arrangement is proposed because the market at the PJM West Hub is much more liquid than PJM East, and Applicants will be better able to quickly divest rights to the energy equivalent of 2,600 MW of capacity at that location. As explained by Mr. Cassidy, the two products are equivalent.

The interim baseload auctions will be completed within 90 days following the month in which the Transaction closes. Until that time, Applicants will bid all of their PJM East nuclear generation into the PJM day-ahead market at a price of zero.

6. Market Power in Capacity Markets and Ancillary Services

In addition to studying energy markets, Dr. Hieronymus also analyzed whether there are any competition issues raised in the PJM capacity and ancillary services markets. The results of his analysis are summarized below.

a. Mitigation of Capacity Market Screen Failures

Current PJM Capacity Market

Beginning in June 2003, PJM implemented a single PJM capacity market that included the Mid-Atlantic region and what was then called PJM West (i.e., Allegheny Energy). This market included both Daily and Monthly Unforced Capacity (“UCAP”) Credit markets. In 2004, with the integration of ComEd, a Monthly (and multi-monthly)

Installed Capacity Credit market was introduced. Effective June 1, 2005, there will be a single capacity market that includes all current PJM members. UCAP remains the measure of relevance for the capacity market. Under UCAP, each unit’s capacity is adjusted to account for its average forced outage rate. Although the capacity credit markets are based on UCAP, Dr. Hieronymus does not have data on unit-specific forced outages. As a result, he analyzed the market based on installed capacity (“ICAP”). As Dr. Hieronymus explains, the use of ICAP instead of UCAP should not materially impact the results of the analysis.

Dr. Hieronymus analyzed two definitions of capacity markets: Expanded PJM and PJM East. Because PJM currently operates a single capacity market, Expanded PJM is the currently relevant market. However, to be conservative given that PJM is considering moving to smaller capacity markets, as described below, Dr. Hieronymus also analyzed PJM East as if it were a separate capacity market.

Dr. Hieronymus found that the ICAP in PJM East is highly concentrated, and the HHI change resulting from the merger is about 900 points, assuming none of the Applicants’ capacity is committed to the market. The ICAP market for Expanded PJM is unconcentrated pre-merger, and barely moderately concentrated post-merger with an HHI change of 243 points, again assuming none of the Applicants’ capacity is committed to the market. The assumption that the Applicants’ capacity is not committed is a conservative one, since in fact the Applicants are obligated to obtain capacity for their own loads and other long-term capacity commitments, and only have the excess available for sale in the market.

Nevertheless, the Applicants are proposing to mitigate their market power as if PJM were a separate capacity market, and based on their total capacity rather than on

uncommitted capacity. Dr. Hieronymus determined that divestiture of 5,300 MW will eliminate screen failures in PJM East. As described above, Applicants are committing to divest 2,900 MW of generation, which is more than enough to mitigate screen violations in Expanded PJM. This leaves an additional 2,400 MW of ICAP to be mitigated in PJM East.

With respect to the 2,900 MW of peaking, mid-merit and coal-fired capacity to be divested as part of the mitigation plan described above, within 30 days following the month in which the Transaction closes, Applicants will enter into interim firm contracts for the sale of 2,900 MW of both energy and capacity from designated units, thereby reducing the mitigation amount in the interim (pre-divestiture) period by the same 2,900 MW.

This leaves 2,400 MW of capacity to be mitigated, an amount that could be reduced if more than 2,900 MW of peaking, mid-merit and coal capacity is divested. The 2,400 MW of capacity less any capacity divested in excess of 2,900 MW is referred to as the “Capacity Mitigation Amount.” The Capacity Mitigation Amount also will be reduced, similar to the Baseload Mitigation Amount, megawatt by megawatt by the amount of any divestiture, derating or retirement of the Applicants’ generation capacity in PJM East and for any increase in transfer capability into PJM East resulting from transmission upgrades in addition to those provided in the PJM Regional Transmission Expansion Plan that is effective as of June 2005. As was the case with reductions in the Baseload Mitigation Amount, before retiring a unit located in PJM East during the first 15 years following the closing of the Transaction, the Applicants will offer that unit for sale in an auction. The Applicants will be obligated to sell the unit if they are able to

negotiate terms that result in a positive price and recover the fair value of the property to EEG, taking into account its alternative uses, as determined by an independent appraiser.

In order to mitigate any residual market power concerns regarding the Applicants’ ability to influence prices in the PJM capacity markets, Applicants commit to bid into the PJM monthly and annual Planning Year capacity auctions at a zero price the lesser of (1) The Capacity Mitigation Amount or (2) their entire net Unforced Capacity Position in PJM, less 100 MW.²⁵ Prior to the first annual PJM Planning Year capacity auction in which the merged company can bid, Applicants will bid their net PJM Unforced Capacity Position in PJM less 100 MW into each PJM monthly auction. Once they are able to participate in the annual Planning Year auction, the Applicants’ commitment will be to bid into each Planning Year annual auction at a zero price. After that, to the extent that Applicants have any net capacity available in a month, Applicants will bid the additional net capacity into the monthly auction, up to the total Capacity Mitigation Amount less the amount bid into the last annual auction.

Future PJM Capacity Markets

The PJM capacity market is expected to be significantly restructured, as part of an ongoing effort to improve system reliability and price signals. As Dr. Hieronymus describes, in addition to altering the price mechanism (for example, basing capacity payments on a “demand curve” that specifies the price of capacity given different levels of supply and ensuring prices that support entry at the point when capacity is needed), PJM is considering the introduction of a new series of auctions and a more formalized

²⁵

The Applicants need to retain a small amount of uncommitted UCAP due to the fact that their UCAP obligations can fluctuate for various reasons, including an increase in the POLR load obligation, so they need to keep a small amount of uncommitted capacity to hedge this risk.

bilateral market for capacity. The proposal is to eventually have four-year forward base auctions. Incremental Auctions would supplement Base Auctions three times during the four year period. In addition, local capacity requirements may be imposed to ensure local reliability in transmission constrained areas.

The zones to be created for the initial auction are under discussion, but it appears that locational zones will not be applicable until the 2007-08 planning year at the earliest. The zonal structure of markets will be reanalyzed in the future and appropriate changes made. The Applicants commit to making a filing 30 days after the closing of the Transaction, by which time the details of the new PJM capacity markets should be known, in which they will make any necessary adjustments to their mitigation proposal and also will demonstrate their proposal’s effectiveness under the new markets. Upon approval by the Commission, that proposal will replace the mitigation proposed herein.

b. Other Ancillary Services

Dr. Hieronymus also analyzed whether any market power issues were raised by the Transaction with respect to other ancillary services. Under the Merger Policy Statement, the Commission requires that Applicants consider the impact of a transaction on markets for ancillary services, specifically spinning reserves, non-spinning reserves and imbalance energy.²⁶ PJM does not have an imbalance energy market distinct from its spot energy markets since there is no requirement to submit balanced schedules. PJM’s spinning reserve market includes quick start units, essentially peaking units. There is no separate non-spin reserve market. PJM does, however, operate a market-based regulation

²⁶

Revised Filing Requirements, ¶ 31,111 at 31,884.

market. As a result, Dr. Hieronymus analyzed the PJM regulation and spinning reserve markets.

(i) Regulation Service

The PJM regulation market in 2003 was moderately concentrated, but available regulation supply relative to demand for the service was high. According to the Market Monitor, in the PJM Mid-Atlantic in 2003 there were 113 units qualified to produce about 2,011 MW of regulation capability, but requirements ranged from approximately 750 MW for the peak period to approximately 220 MW for the off-peak period.²⁷ Applicants have about 500 MW of regulation capability, about one-quarter of the capability identified by the Market Monitor.

The primary factor used by PJM to select the units used for regulation is opportunity costs, which means that detailed cost information is necessary to determine market shares at different load levels. Dr. Hieronymus did not have the information necessary to do this analysis. However, he explains in his testimony that, even without the Applicants’ 500 MW of regulation capability, there still is over 1,500 MW of unaffiliated capability left, which is twice as much unaffiliated capability in the market as the 750 MW of regulation required during peak hours. As a result, Dr. Hieronymus concludes that the Applicants are far from being pivotal suppliers of regulation service and cannot exercise market power.

(ii) Spinning Reserves

Dr. Hieronymus also found screen violations in the PJM Mid-Atlantic market for spinning reserves, with HHI increases of approximately 500. However, as Dr.

²⁷

2003 State of the Market, PJM Market Monitoring Unit, March 4, 2004, pages 27 and 136.

Hieronymus explains, these increases will be completely mitigated by the proposed divestiture of certain of the Applicants’ peaking and mid-merit generation. The nuclear units owned by the Applicants do not provide spinning reserves.

7. Horizontal Market Power in Other Geographic Markets

The Applicants own smaller amounts of generation capacity in geographic markets other than PJM, including New England, New York, the Southeast, Texas and the California ISO. The only markets in which the Applicants each own generation before the Transaction, however, are in New England and Texas (ERCOT). Dr. Hieronymus therefore performed an analysis of these two markets to determine whether any competitive concerns are raised.

a. ISO New England (“ISO-NE”)

Exelon owns 630 MW of generation in ISO-NE. This consists of generation located at New Boston and West Medway, which is within the Northeastern Massachusetts (“NEMA”) load pocket and a few megawatts of generation located in Maine. PSEG owns 967 MW of generation in ISO-NE including Bridgeport Harbor and New Haven Harbor located within the Southwest Connecticut load pocket and a few megawatts of generation located in New Hampshire. Thus, the smallest relevant market identified by Dr. Hieronymus in which the Applicants’ generation competes is ISO-NE as a whole. Dr. Hieronymus calculated that, relative to the total amount of generation located in ISO-NE (in excess of 30,000 MW), Exelon’s generation is only 2% and PSEG’s generation is only 3% of total ISO-NE capacity. As Dr. Hieronymus testifies, New England is generally an unconcentrated market, and under any relevant condition studied, the Applicants’ post-Transaction market shares would not cause HHI screen failures.

In this regard, the Applicants note that the Commission recently approved a transaction that involved the purchase of approximately 2,800 MW of capacity in New England by a generator that already owned about 2,000 MW of capacity in New England.²⁸ Since the Transaction involves combining 601 MW of generation owned by Exelon with 957 MW of generation owned by PSEG, the results of a Competitive Screen Analysis is by definition less than that of the transaction which the Commission recently approved. No further analysis of the ISO-NE market is necessary.

b. ERCOT

Exelon owns or controls via long-term contract 3,651 MW of generation in ERCOT,²⁹ mostly located in the North zone of ERCOT, with a small amount located in the Houston zone. PSEG owns 2,026 MW of affiliated generation in ERCOT, located in either the South or West zones. Because the Commission has no jurisdiction over ERCOT, arguably the Commission has no authority to consider horizontal market power issues in ERCOT. Nevertheless, the Applicants asked Dr. Hieronymus to analyze any potential market power issues in the ERCOT market.

Dr. Hieronymus testifies that, because Applicants’ generation is located in different zones within ERCOT, the only potentially relevant market is ERCOT as a whole. Dr. Hieronymus calculates that, relative to ERCOT’s total generation in excess of 80,000 MW, Exelon’s generation is less than 5% and PSEG’s generation is only 2.5% of ERCOT capacity. These shares are small and the combination of Applicants’ shares

²⁸		USGen New England, Inc., 109 FERC ¶ 61,361 at P 17 (2004). The Order describes applicant’s (i.e., Dominion’s) analysis as follows: “For Economic Capacity, the post-acquisition New England market is unconcentrated (Herfindahl-Hirschman Index (HHI) < 1000)...

presents no competitive concerns in ERCOT. Specifically, Dr. Hieronymus calculated that the change in HHI is only about 20 points in peak periods and will be well under screen thresholds in other periods. A full Competitive Screen Analysis is not necessary to conclude that the effect of the Transaction in the ERCOT market does not raise any competitive issues.

B. Vertical Market Power Issues

1. No Potential for Abuse of Electric Transmission Market Power

Although not addressed in the Merger Policy Statement or in the Commission’s Part 33 merger regulations, the Commission in recent years has started to consider the extent to which merger applicants can abuse the market power that they enjoy through the ownership of transmission facilities to give themselves an advantage in energy markets. The Transaction does not raise this concern, however. ComEd, PECO and PSE&G, the only transmission-owning entities involved, all have transferred operational control over their transmission facilities to PJM. The Commission has held on a number of occasions that such a transfer adequately addresses the abuse of transmission market power issue.³⁰

Nor should the Commission be concerned that the Transaction will allow the Applicants to obtain any measure of control over PJM. First, PJM has an independent Board of Directors, and the Transaction will have no impact whatsoever on the makeup of that Board. With respect to the Members, Reliability and Electricity Market Committees, PECO³¹ and PSE&G³² each are in the Transmission Owner sector which,

²⁹		This includes an 830 MW purchase (tolling agreement) from a plant that is capable of being dispatched into ERCOT or Entergy.

³⁰		See, e.g., Ameren Corp., 108 FERC ¶ 61,094 at P 61.

³¹		PECO is the voting member for Exelon.

collectively, has a 20% voting interest on these Committees. The Applicants expect that, after the Transaction, the Exelon and PSE&G votes will be combined into a single vote, just as the ComEd and PECO votes were combined into a single vote after ComEd joined PJM.

Thus the combination of PECO and PSE&G would reduce the current number of members in the Transmission Owners sector from 10 to 9, which would mean that EEG would have an 11% voting interest in the Transmission Owner sector, whereas PECO and PSE&G each have a 10% voting interest before the Transaction. This increase of 1% voting interest in a sector that in turn has only 20% voting interest is de minimis, and even this increase would be completely negated if Dominion Virginia Power elects to join the Transmission Owner sector, which would move EEG back to the 10% that PECO and PSE&G each currently have.

Voting rights under the PJM East Transmission Owner’s Agreement (“East TOA”) are counted both based on individual members and on a weighted basis, and a two-thirds vote in each category is required to approve all major changes. Moreover, for items requiring a two-thirds majority, there must be at least three votes opposing a proposed action in order for the proposal to be defeated. EEG’s increased share of individual members votes will be equally de minimis, going from 1 in 9 to 1 in 8 under the East TOA agreement, and from 1 in 14 to 1 in 13 if the East TOA, West TOA and South TOA agreements are consolidated into a single agreement, which currently is under consideration. EEG’s weighted share will go up more significantly, but the other transmission owners are protected by the fact that: (1) a two-thirds vote is required for

³²

PSE&G is the voting member for PSEG.

major issues both on a weighted and individual basis; (2) no transmission owner in the East TOA will be deemed to have more than a 25% vote on a weighted basis regardless of its actual weighted ownership, so EEG’s weighted vote will be capped at 25%; and (3) EEG will need to get at least two other transmission owners to vote with it in order to block any change proposed by the other unaffiliated transmission owners, which means that EEG will not have the ability to veto any proposed changes.

2. No Potential for Abuse of Natural Gas Transportation Market Power

The Commission’s Merger Policy and Merger Regulations do address the issue of the potential abuse of market power in the transportation of natural gas to gain a competitive advantage in energy markets. The concern is that when the ownership of natural gas assets serving electric generation facilities is combined with the ownership of electric generation facilities, the potential is created for the resulting merged company to use its control over the natural gas facilities to disadvantage the competing owners of the electric generation facilities.³³

PECO provides gas distribution service to only one electric generator, a 28 MW facility owned by Merck. There are two other independent generators located in PECO’s service area, but these generators take service directly from an interstate natural gas pipeline instead of from PECO. Furthermore, newly built generation facilities could readily avoid PECO’s small service area or connect directly to an interstate pipeline. PSE&G’s gas distribution system in New Jersey serves eight current or former qualifying facilities (“QFs”) under contract with the utility, as well as two merchant generators:

³³

Revised Filing Requirements, 1996-2000 FERC Stats. & Regs.¶ 31,111 at 31,904. The regulations governing vertical market power appear at Section 33.4 of the Merger Regulations.

the Tosco plant (172 MW) and the Williams Red Oak plant (765 MW). These generating facilities served by PSE&G are under long-term gas transportation contracts or discounted tariffs. Both companies also provide natural gas distribution services to affiliated generation facilities.

Notwithstanding the fact that PECO and PSE&G both serve electric generation facilities, no vertical market power concerns are raised with respect to the Transaction, as Dr. Hieronymus explains. As an initial matter, it is unlikely that either PECO or PSE&G could take any actions that would disadvantage competitors served on their distribution systems. Their distribution tariffs are regulated by the respective state public utility commissions, who have imposed an open access distribution requirement on PECO and PSE&G. The ability to earn even the ceiling rates under these tariffs is constrained by bypass alternatives or existing long-term (sometimes discounted) contracts. Moreover, both Pennsylvania and New Jersey have in place codes of conduct between gas and electric affiliates that limit information sharing and, in any event, the amount of generation served is so small that any information shared would be of little use to the Applicants’ generation business. In short, none of the vertical concerns that the Commission focused upon in prior vertical mergers exists in this merger and the Transaction does not create or enhance vertical market power.

Nevertheless, Dr. Hieronymus conducted the required analysis under Section 33.4 of the Commission’s regulations. He analyzed the downstream market for PJM East, PJM Pre-2004 and Expanded PJM. After taking into account Applicants’ mitigation commitments, neither the PJM Pre-2004 or the Expanded PJM downstream market is highly concentrated post-Transaction. Since these downstream markets are not highly

concentrated, consistent with the Commission’s regulations, the competitive conditions for a successful vertical foreclosure strategy are not present in those markets.³⁴

Dr. Hieronymus determined that, for PJM East, the post-Transaction downstream market is highly concentrated. However, his analysis of the upstream market showed that it is not highly concentrated, which again means that no market power issues are raised.³⁵

C. No Adverse Impact On Rates

In considering the impacts of a merger on rates, the Commission looks primarily at impacts on transmission rates and on rates for long-term wholesale requirements customers. The Transaction will not have an adverse impact on either of these categories of rates.

1. Transmission Rates

With respect to transmission rates, the Applicants propose a “hold harmless” commitment, i.e. they will not seek to include merger-related costs in their filed transmission revenue requirements unless they can demonstrate merger-related savings equal to or in excess of the merger-related costs so included. The Commission has approved this type of commitment in its Merger Policy Statement and in a number of subsequent cases.³⁶

2. Wholesale Requirements Rates

Of the three traditional franchised utilities involved in the Transaction, only ComEd has any wholesale requirements customers. These customers’ rates should not be

³⁴		Revised Filing Requirements, FERC Stats. & Regs. ¶ 31,111 at 31,904. See also Energy East Corp., 96 FERC ¶ 61,322 at 62,229 (2001).

³⁵		Id.

³⁶		Merger Policy Statement, ¶ 31,044 at 30,124. See also Ameren Corp., 108 FERC ¶ 61,094 at P 6-8 (2004).

D. No Adverse Impact On Regulation

1. No Adverse Impact on Federal Regulation

The Commission’s primary focus in considering the impact of a transaction on federal regulation is whether the Transaction will create a registered holding company under PUHCA and cause the Commission to lose jurisdiction over intra-holding company transfers under Ohio Power.³⁷ Here, although the Transaction does bring PSEG into a registered public utility holding company system, the Commission’s authority over the Applicants will not be impaired as a result of the proposed restructuring and transfer of ownership interests. Consistent with the Commission’s Merger Rule, the Applicants commit to waive any claim of Ohio Power preemption of the Commission’s ability to regulate intra-company transactions within a registered public utility holding company system. Such a commitment fully addresses the Commission’s concerns.³⁸

2. No Adverse Impact on State Regulation

The Commission does not consider the impact of a transaction on state regulation when the affected state commission has the ability to review and approve the Transaction.³⁹ Here, the Applicants are filing applications for approval of the Transaction at two of the three affected state commissions, the PAPUC and the NJBPU. These commissions therefore will have the ability to protect their own jurisdiction. As a result, the Commission need not consider the impact of the Transaction on state regulation in Pennsylvania and New Jersey.

³⁷		Ohio Power Co. v. FERC, 954 F.2d 779 (D.C. Cir. 1992).

³⁸		Merger Policy Statement, ¶ 31,044 at 30,124-25.

³⁹		Id., ¶ 31,044 at 30,125.

That leaves Illinois. Although the ICC has no jurisdiction over the Transaction, the Applicants nevertheless are giving notice of the Transaction to the ICC and providing the same information as would be called for under Section 16-111(g) of the Illinois Public Utilities Act.

In any event, the Transaction has no impact on regulation in Illinois. The regulatory status of ComEd, the only one of the Applicants subject to the jurisdiction of the ICC, will not change as a result of the Transaction. ComEd’s ownership does not change, and there are no changes either in the assets owned by ComEd or its contracts or conduct of its business. Furthermore, ComEd’s status as an operating electric utility owned by a registered holding company will not change.

Because the Transaction does not change ComEd, its business, its assets, or its regulatory status in any fashion, the Transaction will not have any impact on ComEd’s regulation under Illinois law in any fashion. The ICC will have the same jurisdiction to regulate ComEd after the Transaction that it currently has today, before the Transaction. Thus, the Transaction will have no adverse impact on state regulation in Illinois.

E. The Internal Restructuring is Consistent with the Public Interest

As noted in Section II.A above, the Applicants intend to engage in some internal restructuring of EEG’s corporate structure in addition to what is required by the Merger Agreement. This restructuring, which is described in more detail in Section III, involves consolidating the various companies owned by Exelon and PSEG into a structure that makes more sense for the combined company.

This consolidation raises no issues under the Commission’s Merger Policy and can be readily approved. As the Commission has recognized, ordinarily internal

corporate restructurings do not raise public interest concerns.⁴⁰ However, the Applicants recognize that the Commission strictly reviews transfers of generation from unregulated merchant companies to traditional franchised utilities that will use the generation to serve their load.⁴¹ That concern is not raised here. No generation of any sort will be placed under the control of ComEd, PECO or PSE&G, the three franchised utilities involved. As a result, the restructuring does not implicate the Commission’s concerns that competition will be impacted by having a traditional franchised utility acquire affiliated generation.

As noted in Section II.A above, the Applicants have not yet completely finalized their corporate restructuring plans. The Applicants request that the Commission approve further changes not described herein that may be decided upon prior to the closing of the Transaction, provided that none of these changes involves transferring unregulated generation facilities so that they are under the control of ComEd, PECO or PSE&G, the Applicants’ traditional franchised utilities.

Finally, as described in Section II.A., the Applicants expect that PSEG Fossil will cease to exist as a separate entity and that it will be survived by Exelon Generation. Presently, PSEG Fossil, together with Jersey Central Power and Light Company, is a co-licensee of the Yards Creek Pumped Storage Project, which has a Part I hydroelectric license (Project 2309). The Applicants will make a separate application under Part I of the FDA for the approval of the partial transfer of this license from PSEG Fossil to Exelon Generation.

⁴⁰		Revised Filing Requirements, ¶ 31,111 at 31,902-03.

⁴¹		See, e.g., Cinergy Services, Inc., 102 FERC ¶ 61,128 (2003); Ameren Energy Generating Co., 103 FERC ¶ 61,128 (2003).

V. INFORMATION REQUIRED BY PART 33 OF THE COMMISSION’S REGULATIONS

Applicants submit the following information pursuant to Part 33 of the Commission’s Regulations.

A. Section 33.2(a): Names and addresses of the principal business offices of the applicants.

Exelon’s principal executive offices are located at 10 South Dearborn Street, Chicago, Illinois 60603.

PSEG’s principal executive offices are located at 80 Park Plaza, Newark, New Jersey 07102.

B. Section 33.2(b): Names and addresses of persons authorized to receive notices and communications in respect to the Application.


Mike Naeve
Skadden, Arps, Slate,		J.A. Bouknight, Jr.
Meagher & Flom LLP		Steptoe & Johnson LLP
1440 New York Avenue, NW		1330 Connecticut Ave., NW
Washington, DC, 20005		Washington, DC 20036
(202) 371-7070		(202) 429-6222
Fax: (202) 393-5760		Fax: (202) 828-3612
Email: mnaeve@skadden.com		Email: jbouknig@steptoe.com

A. Karen Hill
Vice President		Richard P. Bonnifield
Exelon Corporation		Vice President-Law
101 Constitution Avenue, N.W.		Public Service Enterprise Group, Inc.
Suite 400 East		80 Park Plaza – TSA
Washington, DC 20001		Newark, NJ 07102-4184
(202) 347-7500		(973) 430-6441
Fax: (202) 347-7501		Fax: (973) 623-3261
Email: Karen.Hill@exeloncorp.com		Email: Richard.Bonnifield@pseg.com

C. Section 33.2(c): Description of Applicants.

See Section II, and Exhibits A through F, attached.

D. Section 33.2(d): Description of the jurisdictional facilities owned and operated or controlled by Applicants, their parents or affiliates.

See Section II and the testimony of Dr. Hieronymus.

E. Section 33.2(e): Narrative description of the Transaction.

A narrative description of the Transaction is provided in Part III of this Application.

F. Section 33.2(f): Contracts with respect to the Transaction.

See Exhibit I.

G. Section 33.2(g): Facts relied upon to show that the Transaction is in the public interest.

The facts relied upon to show that the Transaction is consistent with the public interest are set forth in Part IV of this Application.

H. Section 33.2(h): Physical property.

See Exhibit K.

I. Section 33.2(i): Status of actions before other regulatory bodies.

See Exhibit L.

J. Section 33.5: Accounting Entries

Attached as Appendix 2 are pro forma accounting entries showing the proposed accounting for the Transaction on the books of PSE&G, the only entity subject to the Commission’s jurisdiction that is required to use the Commission’s Uniform System of Accounts whose books will be affected by the Transaction. In addition, certain other PSEG companies that use the Uniform System of Accounts are expected to be consolidated into Exelon Generation. These entities are PSEG Fossil, PSEG Nuclear and PSEG ER&T. Because Exelon Generation is not required to keep its books in accordance with the Uniform System of Accounts, no accounting entries are shown for these companies.

VI. CONCLUSION

As demonstrated above, as well as in the attached testimony and exhibits, the Transaction is consistent with the public interest as defined by the Commission in its Merger Policy Statement, Part 33 regulations, and merger cases. The Applicants request that the Commission approve the Transaction, without a hearing, no later than August 1, 2005.


		Respectfully submitted,


/s/ J.A. Bouknight, Jr.		/s/ Mike Naeve

J.A. Bouknight, Jr.		Mike Naeve
Douglas G. Green		Matthew W.S. Estes
Steptoe & Johnson LLP		Skadden, Arps, Slate,
1330 Connecticut Ave., NW		Meagher & Flom LLP
Washington, DC 20036		1440 New York Avenue, N.W.
(202) 429-6222		Washington, D.C. 20005
		(202) 371-7000

R. Edwin Selover
Sr. Vice President and General Counsel		Elizabeth Anne Moler
Richard P. Bonnifield		Executive Vice President
Vice President—Law		A. Karen Hill
80 Park Plaza		Vice President
Newark, New Jersey 07102 Counsel for		101 Constitution Avenue, N.W.
Public Service Enterprise Group Incorporated		Suite 400 East
		Washington, DC 20001

		Counsel for
		Exelon Corporation

February 4, 2004

	•	“Expanded PJM” consists of all of the geographic markets that constitute the PJM RTO. In addition to “PJM Pre-2004” described below, Expanded PJM includes PJM West⁸ and PJM South.⁹ Arguably, under the Commission’s policy, Expanded PJM is the only geographic market that needs to be analyzed, since it constitutes the RTO in which the Applicants are located. Indeed, the Commission has accepted the Expanded PJM market as the appropriate market for conducting market power analyses for market-based rate applicants located in PJM.¹⁰ Nevertheless, Dr. Hieronymus analyzed a number of smaller markets as well.

	•	“PJM Pre-2004” is the original PJM Mid-Atlantic market before PJM was expanded, plus Allegheny Energy. PJM Pre-2004 includes nine utility systems whose service territory covers all or part of Pennsylvania, New Jersey, Maryland, Delaware, Virginia, West Virginia, Ohio and the District of Columbia. This market can be separated from the Expanded PJM market during hours when there are constraints limiting deliveries from certain of the newer PJM companies (AEP, ComEd, Dayton) into PJM Pre-2004.

	•	“PJM East” is the eastern portion of PJM Pre-2004, on the eastern side of transmission constraints that limit the amount of energy that can be transferred from lower cost generation in the western part of PJM Pre-2004. Although it could be argued that the Commission should not view PJM East as a separate market, there periodically are transmission constraints that separate this market, and the Commission previously has examined smaller submarkets within PJM in examining market power issues.¹¹ PJM data shows that transmission into PJM East was constrained approximately 200 hours in 2003 and 275 hours in 2004. As a result, Dr. Hieronymus analyzed the smaller PJM East market as well.

	•	“Northern PSEG” is the constrained portion of PSE&G’s control area. Dr. Hieronymus also considered whether to analyze Northern PSEG as a relevant geographic market. However, only PSEG owns generation in the Northern PSEG area, and not Exelon, so there is no overlap between the Applicants. Given that there is no overlap of generation ownership, Dr. Hieronymus does not believe that it is appropriate to consider Northern PSEG as a relevant geographic market. Nevertheless, to be conservative Dr. Hieronymus considered the Northern PSEG geographic market as well.