exv99w2

Exhibit 99.2

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION


Exelon Corporation Public Service Enterprise Group Incorporated		) )		Docket No. EC05-43-000

ANSWER OF
EXELON CORPORATION AND
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED


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

Counsel for
Public Service Enterprise Group		Counsel for
Incorporated		Exelon Corporation
May 9, 2005

TABLE OF CONTENTS


				Page
TABLE OF CONTENTS				i

I.	INTRODUCTION			2

II.	THE FACTUAL ISSUES RAISED BY INTERVENORS HAVE ONLY A DE MINIMIS IMPACT ON THE COMPETITION ANALYSIS			7

III.	THERE ARE NO MATERIAL ISSUES OF FACT WITH RESPECT TO THE MARKET POWER ANALYSIS THAT REQUIRE A HEARING			9

	A.	Relevant Geographic Markets		9

		1.	Northern New Jersey	10

		2.	PJM Classic	11

		3.	PJM West and the “Rest of” Areas	12

	B.	Fuel Cost and Wholesale Power Price Assumptions		15

	C.	Sensitivity Analyses		17

	D.	New Entry Assumptions		18

	E.	Allocation of Available Transmission		19

	F.	Available Economic Capacity		20

	G.	Proposed Strategic Bidding Analyses		23

		1.	The Commission’s Merger Policy Does Not Require a Strategic Bidding Analysis	24

		2.	The Strategic Bidding Analysis Presented by Direct Energy Does Not Show Any Adverse Impact on Competition	25

IV.	THE APPLICANTS HAVE PROPOSED APPROPRIATE MITIGATION			26

	A.	The Applicants Have Proposed an Appropriate Level of Mitigation		26

		1.	The Only Assertion that the Applicants Failed to Provide Adequate Mitigation Is Based on a Miscalculation of the Proposed Mitigation	28

		2.	The Applicants Are Not Obligated to Divest Enough Generation to Ensure that Large Companies Can Purchase Any Amount of Divested Generation	29

		3.	The Additional Mitigation Proposed by the Applicants Allows the Numerical Restrictions on Purchasers to be Dropped and Provides “Headroom”	31

	B.	Virtual Divestiture is an Appropriate Tool For Long-Term Mitigation		34

		1.	Virtual Divestiture Provides Effective Mitigation	34


		2.	The Few Attacks on the Effectiveness of Virtual Divestiture Have No Merit	37

		3.	The Applicants’ Compliance With the Virtual Divestiture Commitment Can be Effectively Monitored	42

	C.	The Applicants Have Proposed Appropriate Mitigation For Capacity Markets		44

	D.	The Applicants’ Proposal for Implementing Mitigation is Appropriate		46

		1.	Term of Nuclear Auctions	46

		2.	Time Period for Divestiture	47

		3.	Identification of Divested Units	48

		4.	Reduction of Mitigation Requirement	50

		5.	The Applicants Have Proposed Appropriate Interim Mitigation	53

	E.	The Applicants Are Proposing Additional Transmission Upgrades		55

		1.	Existing Transmission Commitments	56

		2.	The Applicants Are Now Committing to Additional Transmission Upgrades Regardless of Whether the Transaction is Approved	58

		3.	The Applicants Commit to Further Upgrades in an amount of $25 million on PJM’s List of Economic Projects, Subject to Approval of the Merger Without a Hearing	59

V.	THE INTERVENORS’ POLICY ISSUES HAVE NO MERIT			61

VI.	THE TRANSACTION DOES NOT RAISE VERTICAL MARKET POWER ISSUES			64

	A.	No Transmission Issues Are Raised by the Transaction		64

		1.	Vertical Market Power	64

		2.	Ability to Influence PJM	65

	B.	No Vertical Issues Are Raised by the Transaction with Respect to Applicant’s Natural Gas Operations		66

VII.	THE TRANSACTION SATISFIES THE OTHER MERGER POLICY CRITERIA			72

	A.	Impact on Rates		72

	B.	Impact on Regulation		73

VIII.	THE OTHER ISSUES RAISED BY INTERVENORS ARE NOT RELEVANT TO THE COMMISSION’S INQUIRY			74

	A.	The Applicants Have Provided Sufficient Detail Regarding Their Proposed Internal Restructuring		74

	B.	The Loop Flow Issues Are Unrelated to the Transaction		76

UNITED STATES OF AMERICA

BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION


Exelon Corporation Public Service Enterprise Group Incorporated		) )				Docket No. EC05-43-000

ANSWER OF

EXELON CORPORATION AND

PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED

Pursuant to Rule 213 of the Commission’s Rules of Practice and Procedure, Exelon Corporation and its subsidiaries that are public utilities subject to the Commission’s jurisdiction (collectively, “Exelon”) and Public Service Enterprise Group Incorporated and its subsidiaries that are public utilities subject to the Commission’s jurisdiction (collectively, “PSEG”) (collectively, Exelon and PSEG are referred to as “Applicants”) hereby submit their Answer to the various Motions to Intervene, Protests and Requests for Hearing that have been filed in the above-referenced proceeding. The Applicants request authorization pursuant to Rule 213(a)(2) to answer the protests that have been submitted. The Applicants provide herein certain additions and clarifications to their proposal and believe that their Answer will be helpful to the Commission in analyzing the proposed Transaction and in determining that it is consistent with the public interest. Therefore, it should be accepted. See e.g. Ameren Corp., 108 FERC ¶ 61,094 at P 17 (2004)(accepting answer to protests in merger proceeding).

The Applicants also request permission to file this answer at this time. Included in the protests were 10 affidavits by expert economists, some of whom had performed their own detailed economic analyses of the transaction. It took time for the Applicants to review these analyses, obtain the relevant workpapers, and revise the Applicants’ own analysis accordingly. The short delay has allowed the Applicants the opportunity to

provide the Commission with a meaningful analysis that will be helpful in evaluating the impacts of the Transaction.

I. INTRODUCTION

As demonstrated in the Application, the proposed Transaction fully satisfies the Commission’s well-established merger criteria under Section 203 of the Federal Power Act. The Commission’s merger policy states that there is ordinarily no need for a hearing where Applicants’ proposal contains divestiture that eliminates all Appendix A screen failures. See Merger Policy Statement, FERC Stats & Regs. ¶ 31,044 at 30,112, (1996). (“It is important to give applicants some certainty about how filings will be analyzed and what will be an adequate showing that the merger would not significantly increase market power. . . . If applicants satisfy [the Appendix A] analytic screen in their filings, they typically would be able to avoid a hearing on competition.”). See also Order No. 642, FERC Stat. & Regs. ¶ 31,111 at 31,879 (2000).

Here, the Applicants not only satisfied this requirement, but have presented a proposal that has numerous procompetitive aspects. They committed to the most extensive divestiture (5,500 MW) ever submitted to the Commission, supported by a comprehensive Appendix A analysis showing that these divestitures eliminated screen failures in every relevant geographic market. Moreover, Applicants’ virtual nuclear divestiture proposal allows Applicants’ nuclear capacity to be assigned in smaller increments to more purchasers than would be the case if the nuclear units could be sold on a station-by-station basis. This will increase the number of potential suppliers in the market and should have a deconcentrating effect on the market. Further, the Transaction is intended to result in increased output of some underperforming nuclear assets, thereby

procompetitively increasing the supply of energy in the market. In short, Applicants’ proposal went to extraordinary lengths and more than satisfies every Commission criterion for approving a merger as consistent with the public interest.

Based on this record, the Applicants are entitled to rapid approval of the Transaction, which is important to all affected parties. It will make effective the several benefits described in the Application, including the procompetitive aspects of the Transaction described above. Such an outcome also would have important public policy benefits even beyond those from the direct results of the merger. It would reduce the impact of uncertainty on the financial markets, on the Applicants’ ability to engage in business planning, and on the Applicants’ employees while the merger application is pending. This is, of course, one of the reasons why the Commission approves merger transactions that pass its competitive screen without conducting a hearing.

None of the protests suggests otherwise. The most extensive of these are from large competitors of the proposed Exelon Electric & Gas Corporation (“EEG”). Their transparent and overriding concern is that EEG will be an efficient and low-cost competitor whose creation is likely to reduce prices and increase the competitive pressure on other large market participants. While the intervenors have submitted a large volume of paper, a careful review of these materials reveals that many of their contentions are duplicative, and none refutes the fundamental fact that the Transaction satisfies the Commission’s merger criteria.

The intervenors’ comments fall into four categories, each of which can be fully and directly disposed of at this juncture:

Immaterial Factual Errors. First, a few intervenors contend that Applicants’ Appendix A analysis contained certain factual data errors regarding the proper counting of certain generation or load. These alleged errors are completely immaterial, however. The attached Supplemental Testimony of Dr. Hieronymus accepts these contentions at face value and revises the Appendix A analysis to account for them. The revised analysis shows that Applicants’ initial divestiture commitments, even accepting the factual contentions of the intervenors, fully eliminate all Appendix A screen failures.

Analytical Issues Regarding the Appendix A Analysis. Certain intervenors raise issues regarding how Dr. Hieronymus performed his Appendix A analysis. These contentions demonstrably are without merit, and in many cases raise issues of policy with respect to how the analysis is to be conducted, which the Commission clearly can decide at this juncture without a hearing.

Issues Unrelated to the Commission’s Merger Policy. The intervenors raise a number of issues that the Commission should not, and does not consider when evaluating a proposed merger under Section 203 of the Federal Power Act. These include issues unrelated to the Transaction and issues resulting from ComEd’s admission into PJM. Whatever the substantive merits of these issues, they can be rejected without a hearing as not relevant to the Commission’s review of the Transaction.

Issues Regarding the Proposed Mitigation. Finally, the remaining comments principally concern the form of mitigation proposed (e.g., the virtual nuclear divestiture proposal) and the proposed limits that would restrict market participants having large market shares from purchasing divested assets. These are policy issues that again can be resolved without a hearing. None of the comments, either individually or in the

aggregate, can surmount the fundamental point that Applicants have proposed the full amount of mitigation required by the Commission’s Merger Policy and Regulations or can show that the virtual divestiture proposal is in any way inadequate to mitigate market power. Accordingly, the Commission can and should approve this Transaction based on the pleadings and affidavits before it, with nothing further from the Applicants.

Additional Mitigation to Avoid Delay

Nevertheless, the Applicants wish to be responsive and facilitate the Commission’s timely approval of this Transaction so that the significant benefits of the merger can be realized without undue delay. The Applicants therefore are willing to offer additional mitigation in response to the concerns raised in the protests, provided that the Commission approves the Transaction without the delay of a hearing.¹Most significant, the Applicants are willing to provide an additional 1,100 MW of generation divestiture. This generation will all be located either in the PJM East or Pre-2004 PJM markets, and it brings the total proposed divestiture to 6,600 MW – 4,000 MW of which will be physically divested fossil-fired units.

This additional divestiture will provide further “headroom” so that the sale of the divested plants to other existing owners of regional generation facilities will not result in unacceptable levels of market concentration. Dr. Hieronymus has conducted additional analyses demonstrating that this is the case. The additional 1,100 MW of divested

In the event that a hearing is ordered, the Applicants withdraw their additional mitigation proposed herein and revert back to their original proposed mitigation, which they believe completely satisfies the Commission’s requirements for mitigation of merger-related increases in market power and therefore addresses the competition issues that have been raised in this proceeding.

generation also will provide an extra margin of mitigation that will lay to rest any debate about small details of the analysis. In addition, the Applicants make five other new mitigation commitments, summarized as follows and described more fully in the body of this Answer:

(1)   Elimination of Limits on Purchasers. The Applicants propose to drop the limits on which entities may purchase generation, other than that no single entity may purchase more than 50% of the virtual divestiture amount. In order to assure the Commission that divestiture without specified limits will not lead to screen violations, the Applicants commit to make a compliance filing upon completion of their divestiture to demonstrate that the actual divestitures will not cause material screen failures.

(2)   Structural Safeguards for Virtual Divestiture. In response to concerns that the virtual divestiture of nuclear generation is not a structural remedy and will be difficult to monitor, the Applicants propose to implement additional measures that will add transparency to the auction process, provide more structure and make it easier for the Commission to monitor compliance. In particular, the Applicants will provide for the establishment of a publicly available web page that will detail exactly how the Applicants are complying with their virtual divestiture commitment and their compliance with their other interim and long-term mitigation requirements. The Applicants will put a link to this web page on the PJM OASIS, which will make it readily available to the public.

(3)   Additional Mitigation in Capacity Markets. In response to complaints that the Applicants will retain an ability to exercise market power in the capacity markets, the Applicants commit to bidding their entire net capacity position into the daily capacity market operated by PJM at a price of zero. This commitment will last until PJM implements its as-yet not finalized changes to its capacity markets, at which time, as the Applicants already have committed, they will submit a mitigation plan to the Commission that is tailored to the specifics of the new capacity markets.

(4)   Reduction in Time for Divestiture. In response to criticisms that the 18-month time period proposed for divestiture is too long, the Applicants will commit to having executed sales agreements and making filings at the Commission for the approval of the sales no later than one year after the closing of the Transaction.

(5)   Transmission Upgrades. Finally, the Applicants recognize that strengthening the transmission system within PJM will improve the viability of PJM’s markets. The Applicants therefore commit to: (1) accelerate certain transmission upgrades and make certain new transmission upgrades on their own system regardless of whether the Transaction is approved; and (2) fund transmission upgrades

identified by PJM as constrained facilities, contingent upon the approval and closing of the Transaction.

With these commitments, all of the principal objections to the Transaction are resolved. These commitments add to the historic divestiture to which Applicants already committed and ensure there is no doubt that the Transaction passes the screens. As described above, the Commission’s Merger Policy calls for granting approval without conducting an evidentiary hearing. That is precisely what the Commission should do here. The Applicants request that the Commission promptly issue an order approving the Application without a hearing.

II. THE FACTUAL ISSUES RAISED BY INTERVENORS HAVE ONLY A DE MINIMIS IMPACT ON THE COMPETITION ANALYSIS

In support of the Transaction, Dr. Hieronymus, one of the most experienced experts in conducting such analyses, provided an extremely thorough market study which he conducted in strict compliance with the prescriptions of 18 C.F.R. § 33.3. This analysis included all of the information required by the Commission in its Merger Regulations. Dr. Hieronymus fully explained and documented the assumptions that he used. Based on this analysis, Dr. Hieronymus concluded that the Transaction did not raise competition issues once the proposed mitigation was considered.

It is noteworthy that, notwithstanding the intense scrutiny imposed on Dr. Hieronymus’ analysis, only four relatively minor factual errors were identified in the assumptions used in Dr. Hieronymus’ analysis. These errors have only a de minimis impact on Dr. Hieronymus’ analysis.

1. First, the analysis should have included the 200 MW power purchase agreement under which PECO is purchasing power from Hoosier in 2006. Hoosier at 2-

3.² The delivery point under this contract is in Cinergy’s service territory, located in the MISO system. Inclusion of this small volume contract, with a delivery point located outside of PJM, has almost no impact on the analysis of PJM markets.

2. Second, the analysis should have included the PPL Companies’ recently completed 600 MW Lower Mount Bethel combined cycle facility. PPL at 44. This facility was not included on the database that Dr. Hieronymus used, but if it is in service it should be included. Of course, adding capacity to PPL actually results in a slightly less concentrated market.

3. Third, PEPCO asserted that Conectiv Energy Services, Inc. (“CESI”) does not own 4,800 MW of generation capacity located in PJM East as Dr. Hieronymus assumed. Although PEPCO’s protest did not identify the generation to which it referred, PEPCO subsequently gave the Applicants information regarding the CESI generation to support its assertion, in response to a written request. Some of the information provided by PEPCO is inconsistent with published data bases that Dr. Hieronymus used for his analysis. Nevertheless, the Applicants have revised their assumptions in accordance with the information provided by PEPCO.

4. Finally, Dominion asserts that Dr. Hieronymus neglected to subtract Dominion’s load obligations in his AEC calculations. Dominion at 6. Upon further review, Dr. Hieronymus determined that Dominion is correct, and that Dominion’s load obligations were inadvertently left out of the calculation.

Hoosier refers to an additional 200 MW power purchase agreement, but states that this agreement terminates at the end of 2005. Hoosier at 2. It therefore is not relevant to Dr. Hieronymus’ calculation for 2006.

Dr. Hieronymus has now rerun his analysis making these changes in order to determine whether these changes materially impact his conclusions. These new runs, included in the attached testimony of Dr. Hieronymus, demonstrate that the aggregate effect of these changes is inconsequential. See Hieronymus Supplemental Testimony at 6-8; Exhs. J-18, J-20 and J-21. The conclusion of the analysis presented in the Application – that the Transaction does not result in material screen failures after accounting for the proposed mitigation – remains valid.

III. THERE ARE NO MATERIAL ISSUES OF FACT WITH RESPECT TO THE MARKET POWER ANALYSIS THAT REQUIRE A HEARING

A number of the intervenors criticized the analytic approach used by Dr. Hieronymus in preparing his analysis. Many of these criticisms implicitly challenge the Commission’s Merger Policy and Merger Regulations and can be rejected out of hand. The remaining criticisms are without merit or raise legal or policy questions that can be resolved without a hearing. The more significant of the issues are discussed briefly below. These issues, as well as other less significant issues, are also addressed in detail by Dr. Hieronymus in his Supplemental Testimony, which is attached to this Answer.

A. Relevant Geographic Markets

In defining the relevant geographic markets for this analysis, Dr. Hieronymus followed “the instructions in the Revised Filing Requirements,” to identify “the destination markets that could potentially be impacted by the merger.” Hieronymus Testimony J-1, at 32:11-12. In doing so, Dr. Hieronymus expressly took into account all of the relevant facts concerning the “location of Applicants’ generation, transmission constraints, and price separation” within PJM. Id. at 32:13, 33:2-3.

Despite Dr. Hieronymus’ careful delineation of the proper destination markets, several Intervenors now criticize Applicants for not analyzing additional “markets.” Specifically, Ameren, PEPCO, and PPL complain that the following “markets” also should have been analyzed:

•   Northern New Jersey, see Kalt at 30; PEPCO at 31-32;

•   PJM Classic, see Kalt at 28-30;

•   The “Rest of” PJM Pre-2004 (PJM Pre-2004 with PJM East excised), see Fox-Penner/Pfeifenberger at 18-19;

•   “PJM West” (the portion of PJM that is west of PJM Pre-2004), see Fox-Penner/Pfeifenberger at 20-21.

Each of these contentions is entirely without merit and should be rejected.

1. Northern New Jersey

PPL and PEPCO claim that Dr. Hieronymus failed to “carry out a consistent screening analysis to determine the appropriate mitigation” for Northern New Jersey. Kalt at 30; see PEPCO at 31-32. This is simply wrong. Although Dr. Hieronymus concluded that Northern New Jersey is not a relevant market because Exelon owns no generation there, he nevertheless conducted a market screen analysis specifically for Northern New Jersey—including an assessment of the amount of generation that would need to be divested to cure the screen failures for Northern New Jersey. See Hieronymus Testimony J-1, at 53-54.³PPL’s assertion that Applicants’ market screen analysis is deficient with respect to Northern New Jersey thus has no basis in the record.

Dr. Hieronymus’ Appendix A analysis of the affected Northern New Jersey market is found in his workpapers, which were submitted in conjunction with his testimony and provided to both PPL and PEPCO.

2. PJM Classic

PPL also questions Applicants’ market analysis by asserting that, because of possible western interface transmission constraints, it “may” be appropriate to separately examine the “market” of PJM Classic separate and apart from the larger PJM Pre-2004 and PJM Expanded markets that Dr. Hieronymus assessed. Kalt at 29. See also Kalt at 22-23; Fox-Penner at 20-21 (arguing that Applicants failed to properly account for the Bedington-Black Oak constraint). However, although PJM’s western interface previously created a transmission constraint separating the Allegheny Power (“Allegheny”) system from PJM Classic and thus arguably separated Allegheny from PJM Classic, this is no longer the case now that Allegheny has been integrated into PJM. Today, PJM operates the system so that when constraints threaten to limit the western interface, certain generation units in PJM automatically are re-dispatched, preserving the flows from west to east.

The effect is that lower-priced power imports across the western interface are still possible—meaning that Allegheny and PJM Classic are not in separate markets. The PJM 2004 State of the Market Report, prepared by the PJM Market Monitor, explains:

Prior to the incorporation of [Allegheny Power], the primary controlling action for these [western] constraints had been . . . to restrict energy transfers through its system. . . . After [Allegheny] was integrated into the PJM market . . . , [however], a significant change in price impacts occurred. Rather than simply restricting relatively low-cost energy transfers, higher cost generating units were dispatched out of merit order (redispatched) in order to serve load in the transmission constrained areas. As a result, . . . [h]igher LMPs resulted only at those locations directly limited by a constrained facility while lower LMPs occurred elsewhere.

2004 PJM MMU State of the Market Report at 166 (emphasis added).⁴

The Market Monitor’s report thus makes clear that rather than making PJM Classic a separate market, the constraint on the western interface is now simply controlled through redispatch, and the Allegheny system is now properly included in the same market. Thus, the PJM Pre-2004 market, which is made up of PJM Classic plus Allegheny, is the appropriate market for Dr. Hieronymus to have analyzed.⁵

3. PJM West and the “Rest of” Areas

Finally, Ameren asserts that Applicants’ market screen analysis is not complete because Dr. Hieronymus did not separately analyze what Ameren refers to as (a) the “Rest of PJM Pre-2004” and (b) the “Rest of Expanded PJM,” or “PJM West.” Ameren’s claim would require a fundamental – and unwarranted – change in the Commission’s approach to performing its merger analysis.

It is well-established that transmission in PJM flows in an eastward direction. As a result, transmission constraints may occur at PJM’s interfaces where the power is

⁴		Neither Exelon nor PSEG own generation in the two areas affected by higher locational marginal prices, which are within the service territories of PEPCO and Baltimore Gas & Electric.

⁵		Dr. Fox-Penner also argues that a potential transmission constraint on the Wylie Ridge transformers on the Allegheny system means that Applicants should have assessed additional markets. See Fox-Penner at 20-21. This constraint, however, only confirms the correctness of Dr. Hieronymus’ definition of the relevant markets. The Wylie Ridge transformers are located the western edge of the Allegheny system – the western boundary of the PJM Pre-2004 market. In any event, Dr. Fox-Penner grossly overstated the effect of this constraint. Dr. Fox-Penner argues that in 2004 Wylie Ridge was binding 90% of on-peak hours, but what he fails to state is that, according to the PJM Market Monitor’s State of the Market report for 2004, this interface was binding only 7.3% of all hours in 2004, and that only 19% of those hours were on-peak. See 2004 State of the Market Report at 60.

moving eastward, but not for power moving westward. This is why Dr. Hieronymus analyzed PJM East as a separate market: power moving into this load pocket periodically is constrained. But PJM East’s status as a separate market due to these transmission constraints does not render the areas to the west separate markets as well. Power from the eastern portions of PJM is free to move westward and serve those areas, and therefore is in the market under the delivered price test.

The Commission has recognized that this definition of relevant markets used by Dr. Hieronymus is the right one. As the Commission explained in Wisvest-Connecticut, LLC, the “key issue” in “defining relevant geographic markets” is how transmission is constrained. 96 FERC ¶ 61,101, at 61,041-42 (2001). Thus, the Commission will examine “load pockets” as separate markets where transmission is constrained “such that no additional imports from outside the region are possible,” but it does not consider areas where there are no inbound transmission constraints to be separate markets. So too here: Dr. Hieronymus properly analyzed PJM East, PJM Pre-2004, and PJM Expanded as the relevant markets, because the relevant transmission constraints in PJM are on the western edges of PJM East and PJM Pre-2004. In fact, the Commission has never before assessed the western portion of PJM as a separate market, but has consistently analyzed PJM in light of the fact that the transmission constraints are in a west-to-east direction. See, e.g., Atlantic City Electric Co., 86 FERC ¶ 61,248 (1999); Potomac Electric Power Co., 96 FERC ¶ 61,323 (2001).

Here, no intervenor has asserted that there are westbound transmission constraints within PJM, because, as noted, there simply are none. Indeed, Ameren’s own argument

in favor of considering opportunity costs explicitly presumes that “the typical constraints are nearly always west to east,” not east to west. Fox-Penner at 19.

Thus, the approach promoted by Ameren not only is inconsistent with how the transmission constraints in PJM work and the Commission’s decisions, but it also contradicts the approach of the Commission’s Merger Policy Statement. Ameren’s argument that PJM West and the “Rest of” “markets” should be considered separately is based on an assumption that a competitive analysis should evaluate the relative opportunity costs of moving power from one market to another—namely, that the opportunity cost of sending power from “higher-priced” markets in the east to the “lower-priced” markets in the west is too high for sellers to engage in such transactions. Fox-Penner at 19. However, the Commission’s Merger Policy does not contemplate such an approach.

The Commission’s Appendix A analysis has been conservatively designed to overprotect against competitive concerns, with a presumption that if the analysis is passed, the merger is not anticompetitive. Order No. 592 at 30,119. The Commission has thus held that opportunity cost analyses should not be used to replace the competitive screen assessment, but should only “supplement” the required Appendix A analysis “[i]f merger applicants wish.” Order No. 642 at 31,889.

Ameren has not provided any supplemental opportunity cost analysis, but has instead ignored any opportunity costs and used the Appendix A approach to calculate market shares in the alleged “Rest of” “markets.” See Fox-Penner at 20-21.⁶Moreover,

⁶

Ameren’s approach would eliminate capacity that could be imported economically into its “Rest” market, because of opportunity cost considerations. However, after

just last year, Ameren also provided the Commission with an Appendix A analysis in support of its proposed merger with Illinois Power, an analysis the Commission relied on in approving the merger. See Ameren Corp., 108 FERC ¶ 61,094 at P. 22 (2004). In contrast to its litigation position here, Ameren did not then advise the Commission that it should not include any of the generation to its East in the Appendix A analysis due to “opportunity costs,” but rather relied on the Commission’s Appendix A analysis, just as Applicants have here. See id.

In short, the only complete and internally consistent assessment of market power in the record is the analysis presented by Applicants, which follows the methodology prescribed in the Commission’s regulations.

B. Fuel Cost and Wholesale Power Price Assumptions

Some intervenors question Dr. Hieronymus’ assumptions regarding the fuel costs and wholesale power prices used in the market power analysis. However, these analyses are demonstrably flawed. As explained below, there are several important reasons why the Commission can have confidence in the results derived by Dr. Hieronymus using his fuel and wholesale power price assumptions.

Most important, Dr. Hieronymus’ analysis links his assumptions about fuel costs with his assumptions about market prices for power. This recognizes the obvious

making this one adjustment to its analysis of the “Rest” market, Ameren reverts to the Appendix A approach and assumes that all generation physically located within the “Rest” market is available to serve that market, regardless of whether there are better opportunities to sell that energy elsewhere (there is a high opportunity cost for not exporting the energy). The approach of performing an Appendix A analysis that takes into account some opportunity costs and ignores others is clearly wrong, and the resulting calculations as a result have no value.

relationship between the cost of fuel – the primary variable input in the generation of electricity – and the market price of power. If this relationship is correctly captured, it makes the choice of the values used for fuel and power less important, because even if prices of fuel are different, the market price of power should change correspondingly, and vice-versa. Thus, with the correct relationship between price and fuel established, the same units should be able to satisfy the delivered price test at the same load conditions as the prices for fuel and power increase or decrease. See Hieronymus Supplemental Testimony at 19-20.

The critics of Dr. Hieronymus’ assumptions have ignored this important nexus between fuel costs and power prices. They are able to reach different results by changing one or the other of the assumptions used by Dr. Hieronymus, but those results are meaningless unless appropriate corresponding assumptions also are made with respect to how the assumed change in market prices will impact fuel prices and vice-versa.

Second, the criticisms of fuel cost assumptions ignore the fundamental relationship between different types of generation units that establish their merit order.

As Dr. Hieronymus testifies:

Changes in fuel costs do not change the merit order of plants under any plausible forecast; nuclear remains cheaper than coal and coal cheaper than gas. Plants with lower heat rates are dispatched before plants with higher heat rates using the same fuel type. For these reasons, fuel cost assumptions don’t change what is economic during various time periods and hence do not change HHIs and Applicants’ market shares.

Hieronymus Supplemental Testimony at 3.

Third, Dr. Hieronymus’ analysis of the various load conditions assumes a large number of different pricing points. This allows the Commission to see how the market reacts to different market prices, and in effect acts as a check on whether changes in

assumptions about prices make any difference in the analysis. This is, of course, one of the reasons why the Commission requires analysis of various load conditions.

Fourth, the analysis performed by Mr. Frame that the Applicants provided to the Commission uses different pricing points from those assumed by Dr. Hieronymus. However, like Dr. Hieronymus , Mr. Frame used pricing points and fuel cost assumptions that were consistent with one another. His results confirmed those of Dr. Hieronymus, and represent the equivalent of a sensitivity analysis using different pricing assumptions.

Finally, as Dr. Hieronymus points out in his testimony, some of the prices advocated by the other witnesses appear to be clearly wrong. For example, the coal price used by Ms. Frayer, $125/ton, is considerably higher than any projected market price for coal. Current prices are approximately $65/ton. Hieronymus Supplemental Testimony at 21. That Ms. Frayer was unable to recognize such an obvious error brings the assumptions underlying her price projections into question.

C. Sensitivity Analyses

FirstEnergy takes Dr. Hieronymus to task for not performing sensitivity analyses of his results using different price projections. Citing Order No. 642, the Commission’s regulations, and numerous cases, FirstEnergy asserts that such sensitivities are required, and notes the results of sensitivities perform by Ms. Frayer. FirstEnergy at 13-14.

The Commission’s Part 33 Merger Regulations do not require that sensitivity analyses be required for price data. Instead, Section 33.3(d)(6) of the Commission’s Merger Regulations simply provides that “Applicants must demonstrate that the results of the analysis do not vary significantly in response to small variations in actual and/or estimated prices.” Dr. Hieronymus satisfies this requirement by using different load

conditions in his analysis, each of which has a different assumed market price – at a range of prices that are closely grouped from $20/MWh to $80/MWh, and then a higher $250/MWh for the highest summer price. Comparing the results between these prices and load conditions allows the Commission to confirm that changes in prices will not change the results significantly.

Furthermore, as discussed above, the complementary analysis of Mr. Frame, which used somewhat different pricing points and other assumptions, independently confirms Dr. Hieronymus’ results. Mr. Frame’s analysis therefore represents a useful sensitivity analysis.

Finally, the Applicants note that the sensitivities used by Ms. Frayer do not represent “small variations” in prices, as contemplated by the Commission’s regulations, but instead involve prices that are different by 25%. Moreover, her sensitivities suffer from her failure, described above, to make corresponding changes in the assumptions regarding fuel costs. As a result, those sensitivities do not provide meaningful results.

D. New Entry Assumptions

First Energy asserts that Dr. Hieronymus’ analysis assumed the addition of 1,000 MW too much new generation in 2006 and that he underestimated the amount of unit retirements by 1,110 MW as well. FirstEnergy asserts that its witness, Ms. Frayer, accounted for these alleged errors in her analysis. FirstEnergy at 14. This argument is based on a misunderstanding of Dr. Hieronymus’ testimony, and it does not reflect what Ms. Frayer actually did in her analysis.

Dr. Hieronymus’ testimony on unit additions and retirements came in his discussion of whether there are barriers to entry in the PJM markets and whether as a

result long-term capacity markets are competitive, see Hieronymus Testimony, Exhibit J-1 at 74, and was not the basis for the generation assumptions he used in his Appendix A analysis. There, he relied on PJM reports as to which generation was already under construction and expected to be on-line by 2006, and which units are expected to be retired. Id. at 41.

Ms. Frayer apparently recognized that Dr. Hieronymus did not overestimate in his Appendix A analysis the amount of generation capacity that would be in service by 2006.⁷Dr. Hieronymus’ review of the workpapers to Ms. Frayer’s own Appendix A analysis reveals that, notwithstanding FirstEnergy’s assertions, Ms. Frayer used the exact same generation facilities in her analysis that Dr. Hieronymus used in his analysis, with only a few minor differences that do not relate to which units are included in the market. Hieronymus Supplemental Testimony at 15. Thus, FirstEnergy has not demonstrated any error in Dr. Hieronymus’ analysis, nor has it raised a material factual issue.

E. Allocation of Available Transmission

Two parties argue that economic allocation rather than pro rata allocation of imports is appropriate. Hoosier’s witness Mr. Russell argues that pro rata allocation systematically reduces the HHI. Russell at 5-6. PPL argues that use of pro rata allocation skews the results of the analysis by understating the allocation of import capability to Applicants’ low cost generation. PPL at 45; Kalt at 33.

⁷

Indeed, as discussed above, Dr. Hieronymus failed to account for PPL’s newly constructed Lower Mount Bethel combined cycle facility, which means that he actually understated the amount of new capacity being constructed in his analysis.

Despite claims to the contrary, Dr. Hieronymus supported his choice of allocation method, Exhibit J-4, at 10, and his allocation is supported by Commission precedent.⁸Moreover, the allegations of both Hoosier and PPL overlook the critical fact that lower-cost generation is adequately represented in the analysis of lower market prices. As Dr. Hieronymus’ supplemental testimony explains, Hoosier’s and PPL’s contentions are wholly without merit. Applicants have adequately addressed the shares of low-cost generation that Applicants own outside of the relevant markets.⁹

F. Available Economic Capacity

Two parties attacked Dr. Hieronymus’ Available Economic Capacity (“AEC”) calculations: PPL and PEPCO. None of these attacks raises any material issues of fact, however. Nor do they detract from Dr. Hieronymus’ conclusion that the proposed mitigation will effectively mitigate any increase in market power for AEC.

As all parties agree, the AEC calculation was rendered much more difficult than in previous merger analyses because the states in PJM have largely moved to retail competition, thereby rendering it very difficult to match a utility’s generation capacity to

⁸		Although the Commission did not require a specific transmission allocation approach in its Merger Regulations, the Commission did state in Order No. 642 that “certain methods provide more accurate and reasonable results than others (i.e., pro-rata as opposed to least cost).” Order No. 642 at 31,894. The Commission has approved used of a pro rata approach on a number of occasions, including in its analysis of the FirstEnergy-GPU merger proceeding that included an analysis of the PJM market. See Ohio Edison Co., 94 FERC ¶ 61,291 at 62,043-44 (2001).

⁹		It also is notable that Dr. Hieronymus’ use of pro rata allocation is not opportunistic. Dr. Hieronymus always has used pro rata allocation. As Dr. Hieronymus explains in his testimony, based on his extensive experience, this has been found to produce more reasonable results.

retail loads, as required in order to conduct an AEC analysis. Similar data difficulties have led the Commission in the past to waive the requirement that an AEC calculation be submitted for regions with retail access. See Energy East, 96 FERC ¶ 61,322 (2001); Sithe Energies, 93 FERC ¶ 61,244 (2000). Nevertheless, Dr. Hieronymus performed two sensitivity analyses that bounded the results that would be reached if all necessary data were available. No party asserts that Dr. Hieronymus’ results do not effectively achieve this goal with the data that is available.

More important, Dr. Hieronymus does have accurate data regarding the Applicants’ own loads and resources and thus is able to accurately model Applicants’ own AEC. As a result, Dr. Hieronymus’ calculation of the Applicants’ total AEC is based on complete data for the Applicants and therefore is accurate, even if his data for other parties is necessarily lacking. As shown on his Exhibit J-8, the Applicants proposed to mitigate, through divestiture and virtual divestiture, more than the amount of AEC owned pre-merger by Exelon and/or PSEG in every load period for all three markets studied except during Winter Superpeak conditions in the PJM Pre-2004 market and during Winter Superpeak and Peak conditions in the Expanded PJM markets.

In other words, in all load conditions in PJM East and in almost all load conditions in the other markets studied, the Applicants proposed to divest more capacity than the AEC they acquired. Therefore they will control less AEC after the Transaction than they did before. In the three load conditions studied where this is not the case, the Applicant’s increase was fairly small under Dr. Hieronymus’ calculations and will be even less after the additional mitigation proposed in this Answer. In short, Dr. Hieronymus’ analysis demonstrates that the Transaction, including mitigation, will actually cause a

reduction in the Applicant’s share of the AEC market, which means that there can be no material AEC screen violations. By definition, a reduction in market share cannot constitute an adverse impact on competition.

PPL, through Dr. Kalt, makes two claims regarding the AEC calculation. First, although Dr. Kalt concedes that it is not possible to obtain all necessary data, he asserts that the Commission “collects considerable amounts of data on buyers’ and sellers’ transactions in New Jersey, and it is likely the case that the Merging Parties could develop a more refined analysis.” Kalt at 31. Second, Dr. Kalt notes that PSEG controls uncommitted capacity in New Jersey and asserts that “without knowing the actual extent of concentration in the available economic capacity markets, the Commission can never be certain that the mitigation ordered is adequate.” Kalt at 31. Dr. Kalt does not, however, state exactly what the additional New Jersey data is or how it could be used to develop a more refined analysis.¹⁰ Nor does Dr. Kalt explain how performing an analysis that includes data regarding New Jersey would lead to any other conclusion regarding the impact of the Transaction on AEC, given that the proposed mitigation reduces the Applicants’ control over AEC. Dr. Kalt’s criticisms should not lead to a rejection of the AEC analysis, especially given that the Commission ordinarily does not even require an AEC analysis under these circumstances, as described above.

PEPCO asserts that, in light of the data problems, Dr. Hieronymus should have performed sensitivity analyses “to improve the quality of [the] data.” PEPCO at 28. Of

¹⁰

Moreover, even if it were possible to obtain better data from New Jersey, that would not solve the data problems regarding the other PJM states with retail competition.

course, this is exactly what Dr. Hieronymus did. As noted above, he ran two sensitivities using two different assumptions regarding the load obligations in order to bracket the possible results and thereby “improve the quality” of his results.

PEPCO also asserts that it was inappropriate for Dr. Hieronymus to have assigned PECO’s provider of last resort (“POLR”) load responsibility to Exelon’s generation. Citing the Commission’s Edgar, Mountainview, and Allegheny cases,¹¹ PEPCO argues that Exelon Generation could not serve the PECO POLR load without a Commission-approved contract. PEPCO at 28. But Exelon Generation has just such a Commission-approved contract with PECO to serve PECO’s POLR load. See Exelon Generation, LLC, 93 FERC ¶ 61,140 (2000). Dr. Hieronymus’ treatment of the PECO load is thus fully consistent with the Commission’s policy regarding sales between affiliates.

G. Proposed Strategic Bidding Analyses

Several intervenors fault the Application for not including an analysis of strategic bidding or pricing in their competition analysis, Pa. OCA at 11; NJRPA at 10, 15; Biewald at ¶¶ 18-21, question whether the proposed mitigation is sufficient to prevent strategic bidding or pricing, Pa. OCA at 12, 19-20; Direct Energy at 3, 5; Kleit at 18, or claim that the virtual divestiture will not address strategic bidding and pricing, Pa. OCA at 27. The Commission should reject these arguments as wholly without merit.

¹¹

Edgar Electric Energy Co., 55 FERC ¶ 382 (1991); Southern California Edison Co., 106 FERC ¶ 61,183 (2004); Allegheny Energy Supply Co., LLC, 108 FERC ¶ 61,082 (2004).

1. The Commission’s Merger Policy Does Not Require a Strategic Bidding Analysis

Applicants did not submit the type of strategic bidding analysis requested by the intervenors because such an analysis is not required by the Commission’s Merger Policy or Merger Regulations and thus is not necessary. Indeed, the Commission specifically rejected calls for such a requirement when it adopted its merger filing requirements. The Commission concluded that “there are many issues that must be addressed before the Commission is able to determine the appropriateness of any particular model (i.e., completeness of the model and how strategic behavior is modeled).” Order No. 642, FERC Stat. & Reg. ¶ 31,111 at 31,916. Instead, the Commission relied upon well-established methodology and screening thresholds first established by the Department of Justice Merger Guidelines in 1982.¹²The methodology and screening thresholds were maintained in the 1984 and 1992 revisions to the Merger Guidelines,¹³ and have been accepted by federal courts. See e.g., FTC v. H.J. Heinz Co., 246 F.3d 708, 716 n. 9 (D.C. Cir. 2001); United States v. Baker Hughes, 908 F.2d 981, 988 (D.C. Cir 1990).

Moreover, there is no need to conduct novel strategic bidding analyses. Contrary to Dr. Kleit’s assertion that the Commission’s HHI screens are not valid for analysis of unilateral anticompetitive behavior, the DOJ/FTC Horizontal Merger Guidelines

¹²		U.S. Department of Justice and Federal Trade Commission, 1982 Merger Guidelines, 4 TRADE REG. REP. ¶ 13,102 (June 14, 1982).

¹³		U.S. Department of Justice and Federal Trade Commission, 1984 Merger Guidelines, 4 TRADE REG. REP. ¶ 13,103 (June 14, 1984); U.S. Department of Justice and Federal Trade Commission, Horizontal Merger Guidelines, 57 Fed. Reg. 41,552, 4 Trade Reg. Rep. ¶ 13,104 (Apr. 2, 1992) (“Horizontal Merger Guidelines”).

make it clear that it is appropriate to use the HHI to screen for unilateral effects of a merger as well as collusion effects. Horizontal Merger Guidelines § 2.0 (“Other things being equal, market concentration affects the likelihood that one firm, or a small group of firms, could successfully exercise market power.”).

The wisdom of the Commission’s decision to use the well-tested approach from the Merger Policy Guidelines instead of novel strategic bidding approaches is amply illustrated in the strategic bidding analysis submitted by Dr. Kleit on behalf of Direct Energy. As described below, Dr. Kleit’s analysis is filled with errors and questionable assumptions, all of which would require considerable additional consideration by the Commission before it could rely on Dr. Kleit’s approach. Given that the Appendix A approach has long been accepted as an appropriate test, there is no need to consider all the issues raised by Dr. Kleit or any other strategic bidding approach.

2. The Strategic Bidding Analysis Presented by Direct Energy Does Not Show Any Adverse Impact on Competition

Direct Energy is the only intervenor that even attempts to show that the Applicants could profitably engage in strategic bidding after the acquisition. Direct Energy relies on the affidavit of Dr. Kleit, which provides an academic discussion of the incentive to bid a generation unit above its marginal cost. He presents an abbreviated analysis that purports to show that the merged companies could potentially engage in strategic bidding under certain assumed conditions.

The flaws in Dr. Kleit’s analysis are described in detail by Dr. Hieronymus. See Hieronymus Direct Testimony at 38-39. The most important of these errors are: (1) Dr. Kleit fails to take account of the Applicants’ fixed-price load and sales obligations; (2) Dr. Kleit assumes that EEG will have perfect knowledge of the market when it

submits its bids; and (3) Dr. Kleit ignores the ability of the PJM Market Monitor to detect manipulative bidding schemes.

IV. THE APPLICANTS HAVE PROPOSED APPROPRIATE MITIGATION

The Applicants recognized that, unmitigated, the Transaction would cause screen failures that would raise competition issues. For this reason, the Applicants originally proposed mitigation that is unprecedented in scope – 5,500 MW of physical and virtual divestiture. Dr. Hieronymus’ analysis demonstrated that this divestiture eliminated the HHI screens and thus adequately mitigated the market power that otherwise would be created by the Transaction.

The intervenors raise two primary issues with respect to the proposed mitigation. First, they assert that the Applicants did not propose enough mitigation, either because Dr. Hieronymus miscalculated the amount of divestiture needed or because more divestiture is needed in order to allow the larger market participants to purchase divested generation and still not violate the HHI screens. Second, the intervenors assert that the Applicants’ proposed virtual divestiture does not adequately mitigate market power. Intervenors also attack the Applicants’ proposed mitigation in the PJM capacity markets and raise certain mitigation implementation issues.

The intervenors’ attacks on the proposed mitigation do not raise material factual issues, but instead raise legal and policy issues that can be resolved without a hearing. Moreover, those attacks have no merit, as described more fully below.

A. The Applicants Have Proposed an Appropriate Level of Mitigation

As an initial matter, some of the intervenors put misplaced reliance on statements by the Commission that the HHI screens are not absolute standards that demark the

boundary between a competitive and anticompetitive result, but instead are merely “guidelines” used to inform the Commission in its evaluation of proposed mergers. See, e.g., PEPCO at 23 (citing Merger Policy Statement, FERC Stats. & Regs. ¶ 31,044 at 30,118). See also PPL at 20; First Energy at 18-19. The intervenors have it backwards, however. The Commission made these statements with respect to mergers where there are screen violations, but there are factors that make the merger acceptable notwithstanding those screen violations. At the same time the Commission made it clear that a proposed merger that passes the screens ordinarily will not be set for hearing on the competition issue. The Commission reasoned:

It is important to give applicants some certainty about how filings will be analyzed and what will be an adequate showing that the merger would not significantly increase market power. This will allow applicants to avoid or minimize a hearing on this issue. Consequently, we will use an analytic screen (described in Appendix A) that is consistent with the [DOJ/FTC Merger] Guidelines. If applicants satisfy this analytic screen in their filings, they typically would be able to avoid a hearing on competition.

Id. (emphasis added). In Order 642, which adopted the current Part 33 Regulations, the Commission reiterated that a proposed merger that passes the “generally conservative check” imposed by the Appendix A screen typically will not be required to implement additional mitigation:

If the screen is violated, the Commission will take a closer look at whether the merger would harm competition. If not, and no intervenors make a convincing case that the merger has anticompetitive effects despite passing the screen, the horizontal analysis stops there.

Order No. 642, FERC Stats. & Regs. ¶ 31,111 at 31,879.

No intervenor has made any showing that the Transaction has anticompetitive effects despite passing the screen and that additional divestiture is required. Thus, under the Commission’s Merger Policy and Merger Regulations, the only question regarding the

sufficiency of the amount of mitigation required of the Applicants is whether they have mitigated market power to the extent required by the Appendix A screens. The arguments raised by the intervenors that not enough mitigation has been offered are without merit.

1. The Only Assertion that the Applicants Failed to Provide Adequate Mitigation Is Based on a Miscalculation of the Proposed Mitigation

Ms. Frayer is the only witness who claimed that the Applicants did not propose enough divestiture to mitigate the market power created by the Transaction in the markets analyzed by Dr. Hieronymus even with the proposed limitations on purchasers. She contends that 900 MW of additional mitigation is required in order avoid screen failures. Frayer at 72. This assertion, however, is based on a miscalculation of the mitigation proposed by the Applicants.

As Dr. Hieronymus testifies in more detail, Ms. Frayer’s contentions that more mitigation is required is based on her assertions that there are screen failures under two different load conditions – the “summer rest of peak” and “shoulder rest of peak” periods. However, in the summer rest of peak load condition, Ms. Frayer undercounted the amount of mitigation offered by the Applicants by over 1,200 MW. Had she considered the amount of mitigation actually included in the Applicants’ proposal, she would not have found a screen violation. With respect to the shoulder rest of peak period, Ms. Frayer did not factor in the impact of her changed assumptions on the amount of generation divestiture offered by the Applicants. Again, had she performed the calculation correctly, she would have found that the Applicants already offered more than enough mitigation. See Hieronymus Supplemental Testimony at 23-24.

2. The Applicants Are Not Obligated to Divest Enough Generation to Ensure that Large Companies Can Purchase Any Amount of Divested Generation

In the Application, in an effort to be conservative and to ensure that divestitures to large market participants do not create new screen failures, the Applicants proposed that no purchaser in the divestitures would be allowed to purchase more than half of the divested assets. In addition, Applicants proposed the following limitations: that (1) no entity with a market share exceeding 5% in PJM East or Expanded could buy any of the divested assets and (2) no entity with a market share exceeding 3-5% in these markets could buy more than 25% of the divested assets. The latter two restrictions were imposed to ensure that, once the divestitures were completed, taking into account who purchased which units, there would be no screen failures. Application at 21, 27. There hypothetically could otherwise be a screen failure if large incumbents in the market purchased the divested assets. Applicants intended that these pre-sale limits would also obviate the need for a compliance filing post-merger.

Some of the larger competitors of the Applicants object to these purchaser limitations as anticompetitive. PEPCO argues that the restrictions “maintain EEG’s position . . . as by far the largest owner of generation capacity in PJM East and in Expanded PJM. PEPCO at 43. PPL similarly asserts that the restrictions “are designed to leave EEG far larger than any other firm in the market.” PPL at 16. See also Hoosier at 5-6.

The solution, these intervenors argue, is to require more divestiture than is necessary to solve the screen violations calculated by Dr. Hieronymus. By requiring such additional divestiture, the Applicants will ensure that no screen failures will result from a

divestiture of assets to a company that already has a large market share in PJM. PEPCO at 43-44; PPL at 27; Kalt at 20-22; Fox-Penner/Pfeifenberger at 27; Graves at 21-22.

This argument fails because its fundamental premise is simply wrong. The Applicants are not in any way preventing any of their competitors from engaging in mergers or other transactions that would increase their market share. As discussed above and in Dr. Hieronymus’ testimony, the Transaction leaves the relevant geographic markets in an unconcentrated or moderately concentrated state that is not significantly different from the concentration levels that exist today. The other large companies are free to respond to the Transaction as they see fit, subject only to the same regulatory requirements applicable to the Applicants in this Transaction.

The sole intent and effect of the purchaser restrictions was to ensure that market concentration levels resulting from the divestiture required by the Transaction did not increase by an unacceptable amount. It simply cannot be the case that it is anticompetitive to take steps to ensure that a merger-related divestiture does not violate competitive screens and result in unacceptable increases in market concentration.

Nor is there any valid basis for intervenors who are significant market incumbents to argue that the Applicants should be required to over-mitigate in order to allow them to purchase assets that otherwise would create screen failures. The Applicants have committed to remedy screen failures caused by the Transaction, not those caused by others. They should not be required to over-mitigate solely because certain intervenors have posited highly-unlikely worst-case divestiture scenarios. The intervenors’ argument to this effect finds no support in law or the Commission’s regulations.

3. The Additional Mitigation Proposed by the Applicants Allows the Numerical Restrictions on Purchasers to be Dropped and Provides “Headroom”

Notwithstanding the fact that they are under no obligation to provide any more mitigation than is required to resolve any screen violations under the Transaction as proposed, the Applicants now are proposing to divest an additional 1,100 MW of generation located in the PJM East and PJM Pre-2004 markets to avoid the delay of an evidentiary hearing. The breakdown of the categories of generation proposed to be divested is as follows:



					PJM East or
Generation Type	PJM East				PJM Pre-2004				Total
	New		Total		New		Total		New		Total
Nuclear		0		2,400		0		200		0		2,600
Coal		0		550		150		150		150		700
Mid-Merit <$55		0		650		550		550		550		1,200
Mid-Merit >$55		200		900		0		0		200		900
Peaking		0		1,000		200		200		200		1,200
Total		200		5,500		900		1,100		1,100		6,600

Two aspects of this chart require explanation. First, the Applicants have broken down the “mid-merit” category of generation into three categories – coal-fired generation, mid-merit with a variable cost less than $55/MWH, and mid-merit with a variable cost greater than $55. This allows the Applicants provide greater clarity to the choices of generation units they are committing to divest, as discussed in more detail below.

Second, a significant amount of new generation divestiture is listed as being located either in PJM East or PJM Pre-2004. This generation reduces market power in the PJM Pre-2004 market, but because that market includes PJM East, it could be located either inside or outside of PJM East.

The Applicants stress that, while they continue to believe the amount of divestiture originally proposed is adequate, the proposed additional divestiture is intended to allow the Commission to avoid having to resolve any purported factual disputes and approve the Transaction without conducting an evidentiary hearing. As a result, this offer of additional divestiture is conditioned on the Commission approving the Transaction without the delay of a hearing. To the extent the Commission determines that a hearing nevertheless is necessary to review whether the Transaction raises competition issues, the Applicants withdraw their offer of additional divestiture and reserve the right to defend their original mitigation proposal at that hearing.

The additional amount of divestiture gives the Applicants more flexibility as to which entities may purchase the generation being divested. With this additional divestiture, the Applicants are willing to withdraw the restrictions on purchasers with 5% and 3-5% markets shares. The Applicants also are withdrawing the 50% limit on purchases of the fossil units. They are retaining, however, the 50% limit on total purchases of the virtually-divested nuclear capacity.

Applicants initially suggested these limitations for simplicity purposes, not to bar such entities from participating in the normal divestiture process. Applicants’ commitment to divest an additional 1100 MW in the event the Transaction is approved

without a hearing will create headroom that will facilitate divestiture sales to those parties with a significant market share.

In order to ensure that, with this additional divestiture, generation could be sold to large market participants without causing market power problems, Dr. Hieronymus performed analyses of various divestiture scenarios. First, he assumed that the divested generation is sold in four equal-sized packages to the four largest market participants in PJM East. Second, he assumed that all of the divested generation is sold to a single purchaser that does not currently own any capacity in PJM. In each instance, no screen failures resulted from the divestiture. See Hieronymus Supplemental Testimony at 47-50; Exhs. J-27, J-28 and J-29.

Although Dr. Hieronymus’ analysis shows that reasonable sales can take place without raising competitive concerns, the Applicants do not assert that this additional divestiture will cure all screen failures for all possible combinations of sales to companies with large market shares. Of course, as explained above, the Applicants are under no obligation to design a mitigation proposal that permits any existing market participant to purchase any amount of the divested generation. The Applicants therefore intend to structure the divestiture in a fashion that will, in their judgment, balance the competing goals of obtaining the best price for their generation and not causing market power problems.

Therefore, the Applicants will make a compliance filing concomitant with the divestiture sales so that the Commission can review the results of those sales. Using the same data and assumptions that were included in the Applicants’ revised Appendix A

analysis attached hereto,¹⁴ this compliance filing will show changes in HHIs for the same markets, which will allow the Commission to be assured that no material market screen failures will have resulted.

B. Virtual Divestiture is an Appropriate Tool For Long-Term Mitigation

The Applicants’ virtual divestiture proposal was criticized by a number of intervenors. Two categories of arguments were raised. First, intervenors argued that virtual divestiture is not as effective as physical divestiture in mitigating market power. Second, intervenors argued that compliance with the virtual divestiture commitment would be difficult to monitor and would create opportunities for the Applicants to avoid the commitment that they have made. The Commission should not accept either of these contentions.

1. Virtual Divestiture Provides Effective Mitigation

The intervenors who contended that the virtual divestiture proposal would not provide effective mitigation offered no coherent analysis of the proposal. Instead, the intervenors relied almost exclusively on the fact that the Commission has never approved sales of capacity as a long-term mitigation proposal. See, e.g. Pa OCA at 12; Amtrak at 7-8; Hoosier at 4-5; APPA at 8. A few intervenors also asserted that the virtual divestiture proposal is not well defined and leaves room for the Applicants to withhold capacity from the market. FirstEnergy at 43; AAI at 8-9.

¹⁴

For purposes of modeling the virtual divestiture, that capacity will be assigned to purchasers under 3-year contracts, 15-year contracts and swaps. To the extent that any nuclear divested capacity is still subject to interim mitigation, that capacity will be assumed to be allocated in proportion to the New Jersey BGS auction sales in effect for the most recent PJM year.

The Commission has never considered any long-term mitigation similar to that proposed by the Applicants, however, and certainly never has rejected such a proposal. Rather, the Commission has indicated that such an approach might be acceptable. In its Merger Policy Statement, when discussing divestiture of generation, the Commission discussed a possible alternative for divestiture that is very similar to the Applicants’ virtual divestiture proposal:

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

Merger Policy, FERC Stats. & Regs. ¶ 31, 044 at 30,137. The Applicants are not proposing to operate their units as a collective joint venture, but they are proposing to virtually divest ownership rights to energy to a number of owners who then can bid the purchased product into the PJM market or sell that energy independently.

In Order No. 642, the Commission made clear that it will not require physical divestiture (or any other type of mitigation), stating that “[w]e do not believe that we should outline specific actions that applicants must take as mitigation . . . there are numerous mitigation measures that can be effective.” Order No. 642, FERC Stats. & Regs. ¶ 31,111 at 31,900. The Commission went on to state that it would consider the adequacy of various mitigation measures on a case-by-case basis. Id.

The Applicants did submit the necessary analysis here. They provided a detailed discussion of their proposal, both in the Application and in the testimony of Mr. Cassidy and Mr. Sabatino, explaining that the rights to energy that they are selling are firm rights, and that the Applicants would be obligated to pay liquidated damages if they fail to deliver. Cassidy Testimony at 12; Sabatino Testimony at 8-9. Since the liquidated

damages are based on the cost of “covering” (i.e. the cost of purchasing replacement energy), if the Applicants were to attempt to withhold energy subject to the virtual divestiture from the market in order to raise prices, they would have to pay as damages the cost of the withheld energy at the increased price – a strong disincentive to such a withholding strategy.

Furthermore, the obligation to deliver energy is not tied to the output of any unit. Under the three-year auction and equivalent long-term contract option there is an obligation to deliver 24/7 regardless of which units are operating. Even under the long-term contract option tied to the operating characteristics of a specific unit, the Applicants will guarantee the delivery of a specified amount of energy based on the unit’s historic capacity factor, regardless of the actual operations of that unit. Thus the Applicants will have completely divested any economic interest in the virtually-divested capacity, including any ability to profit from the energy sold by withholding generation on the margin.

Indeed, as they explained in the Application, the virtual divestiture is superior to physical divestiture in at least two respects. First, because the purchaser of the energy is obligated to accept deliveries of the energy regardless of the availability of the units, the virtually divested capacity cannot be withheld from the market by the purchaser. Second, because the three-year auction will offer 25 MW blocks of baseload energy, the nuclear capacity can be divested in much smaller increments than if an entire nuclear station were to be divested. This should create a less concentrated market than would result from physical divestiture.

The Applicants also demonstrated that the operating characteristics of nuclear units as a practical matter eliminate any ability or incentive to withhold these units from the market on a short-term basis. The testimony of Mr. Crane describes the various restrictions that prevent the operators of nuclear facilities from varying the output of nuclear facilities. Crane Testimony at 20-24. This testimony provides the Commission assurance that, putting aside the mitigating effects of the virtual divestiture proposal, there is no real danger that the Applicants would withhold those units from the market and attempt to exercise market power. The Commission has recognized this truth about nuclear and other baseload units on a number of occasions. 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).

2. The Few Attacks on the Effectiveness of Virtual Divestiture Have No Merit

A few intervenors made more specific ad hoc attacks on the effectiveness of the virtual divestiture proposal. These attacks, however, are without merit.

The Commission’s Decision in Allegheny Is Inapplicable

For example, FirstEnergy cites to the Commission’s order in the proposed Allegheny-DQE merger as standing for the proposition that the Commission has rejected the sale of power as a long-term mitigation measure. FirstEnergy at 45 (quoting Allegheny Energy, Inc., 84 FERC ¶ 61,223 at 62,070 (1998)). What FirstEnergy leaves out of the language it quotes, however, is the reason why the Commission was concerned with the mitigation proposal – which is that the applicants had retained the unfettered discretion to reject all bids for the purchase of power. Id. (noting that “the merged company reserves the right to reject any and all bids.”) In that event, the Commission

found that the applicants would retain control over the generation facility that was subject to the mitigation.

Here, by contrast, the Applicants have not retained the right to reject bids, but instead have committed to sell all of the energy put up for auction regardless of the price of the bids. This obligation will be verified by an independent auction monitor. The Commission has found in several subsequent cases that the sale of power subject to such a commitment to sell in fact does transfer control over the generation and constitutes adequate mitigation. 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).¹⁵

Applicants Will Not Receive the Same Price as in the Absence of Mitigation

FirstEnergy also asserts that the Applicants have proposed “to receive the same price (i.e. post-merger, post-mitigation) for the energy that they would receive in the absence of mitigation.” FirstEnergy at 46. This attack reflects a fundamental mischaracterization of the virtual divestiture proposal.

In fact, the Applicants will not receive the same price for energy post-merger, post-mitigation that they would receive absent mitigation. Instead, under the virtual divestiture proposal, the price for the energy will be established at the auction (or at the time of the execution of a long-term contract) and will be fixed for the term of the contract regardless of the market price for energy at the time the energy is delivered by

¹⁵

As explained in the Application, although these cases involve only interim mitigation proposals, there is no reason why the power sales cannot mitigate market power on a longer-term basis. See Application at 30-33.

the Applicants. This means that the Applicants will not be able to benefit from increases in the market price of energy produced from their virtually divested capacity and will not have the incentive to attempt to increase the market price to increase profits from such capacity.

Allegations Regarding Market Power for the Three-Year Contracts Are Unfounded

Ameren witnesses Fox-Penner and Pfeifenberger offer hypothetical arguments about the three-year Baseload Auction contracts. First, they hypothesize at pages 23-25 of their affidavit that the Applicants may have market power for three-year contracts for the sale of energy and that Applicants might be able to withhold such contracts from the market by instead selling energy under long-term 15-year contracts. In a closely related argument, Fox-Penner/Pfeifenberger also assert that the Applicants might be able to influence the price paid at the auctions for the three-year virtual divestiture contracts. According to them, the Applicants would achieve this result by withholding capacity in the short-term markets and thereby increasing the short-term market price. This in turn would influence the prices that bidders would offer in the Baseload Capacity Auctions. Fox-Penner/Pfeifenberger Aff. ¶ 68.

The first hypothetical concern raised by Fox-Penner/Pfeifenberger is based on their hypothesis that the Applicants might be able to exercise market power in a “market” for 3-year contracts by “withholding” the sale of some of these contracts through the sale of 15-year contracts instead. Fox-Penner/Pfeifenberger Aff. ¶ 69. The result – they assert – would be to increase the prices that the Applicants receive for the sale of energy under the 3-year contracts. Thus, the concern they raise is not whether the virtual divestiture will work to mitigate market power in the short-term EC and AEC markets for which

they are intended, but instead whether the Applicants might be able to exercise market power to artificially increase the price that they obtain under the auctions for the 3-year products.

The Applicants do not concede that there is a separate “market” for 3-year contracts, but even if there were, the Fox-Penner/Pfeifenberger analysis falls apart upon further scrutiny. First, they ignore the fact that the virtual divestiture will be adding a supply of 3-year contracts from nuclear units to the market. Even if the Applicants were to sell at least some of the virtual divestiture capacity through 15-year contracts, that does not take away from the fact that, in the end, Applicants are still adding capacity to the 3-year contract market, which Fox-Penner/Pfeifenberger say is a beneficial product.

Second, and more fundamentally, there is no barrier to the supply of 3-year contracts by those that hold 15-year contracts. Holders of 15-year contracts could easily resell power in 3-year contract lengths if it became profitable to do so, thereby providing competition for the Applicants. It is the very act of selling energy to third parties under contracts longer than three years that makes it available to the market and thereby checks any possible exercise of market power by the Applicants in a hypothesized 3-year market. The sale of 15-year contracts in lieu of 3-year contracts would not constitute a withdrawal that would have the effect of withholding of capacity that can participate in a “market” for 3-year contracts.

Moreover, the Commission’s own analysis of long-term markets is consistent with the last point. The Commission has found that long-term markets generally are competitive. Indeed, this is the analysis accepted by the Commission in its most recent case involving the merger of traditional franchised electric utilities, which ironically

involved Ameren, Fox-Penner/Pfeifenberger’s client in this proceeding. See Ameren Corp., 108 FERC ¶ 61,094 at P. 21 (2004). See also, e.g. Puget Sound Energy, Inc., 107 FERC ¶ 61,082 at P. 18 (2004); Jersey Central Power & Light Co., 87 FERC ¶ 61,014 at 61,039 (1999).

Regarding Fox-Penner’s and Pfeifenberger’s second argument, it simply would not be possible for Applicants to act in a way that would influence the price bid for long-term contracts. In order for buyers to pay a non-competitive price for the 3-year contracts, they would have to be convinced that there would be a sustained exercise of market power, even after the mitigation that the Applicants have proposed. But such sustained activity, once mitigation has occurred, would have to occur in a market that is continuously monitored by a Commission-approved market monitor. Ameren’s speculation that purchaser in this auction would raise their bids in anticipation that they would be able to benefit from market power in the post-auction world is not logical and is unsupported by any analysis.

The Applicants Will Not Retain Control Over Virtually Divested Energy

Dr. Cicchetti contends that since the parties that will buy the three-year products will likely resell their purchases into the BGS market, “these MWs are still in the relevant markets and should be reflected in the market share that EEG will control.” Cicchetti at 22. Dr. Cicchetti goes on to make the argument that since the 15-year contract is firm energy, as is the three-year product, they are substitutes and therefore (presumably by analogy to his first argument) should also be regarded as under EEG’s control for purposes of HHI calculation. Id. at 23. These arguments are misconceived. The buyers of the three-year and 15-year products will have the exclusive right to choose whether to

use that product to participate in the BGS auction or use it elsewhere, and since the Applicants are obligated to deliver the energy resource on a 24/7 basis, they cannot control the capacity or its price in the BGS auction.

The Attacks on the Proposed Use of Swaps Are Without Merit

Finally, both Dr. Fox-Penner and Dr. Cicchetti hypothesize that swaps could create market power problems in other geographic markets. However, any such issues would not be merger related. As Dr. Hieronymus demonstrated, there is little overlap between Applicants’ generation that is located outside of PJM. Any hypothetical market power problem in non-PJM markets would be due to combining a third party’s generation with generation in that market acquired by that third party from EEG. Presumably a Section 203 application would have to be filed in conjunction with such a swap, and any such market power issues would be reviewable in the context of that transaction. In such event, the facts underlying that review would be unrelated to this Transaction.

3. The Applicants’ Compliance With the Virtual Divestiture Commitment Can be Effectively Monitored

The second line of attack on the virtual divestiture proposal is that it requires ongoing monitoring to ensure the Applicants’ compliance. The intervenors noted that the Department of Justice generally prefers structural mitigation to behavioral-type mitigation like capacity sales, and listed the need for continued monitoring as a primary reason for this preference. See e.g., AAI at 9-11; PPL at 26-27. They argue that the Commission cannot rely on virtual divestiture to occur without continued Commission oversight and therefore virtual divestiture should be rejected.

In response to these arguments, the Applicants are proposing additional measures that will make it easier for the Commission to monitor the Applicants’ compliance with

the virtual divestiture commitment and that will create a structure that ensures full adherence with that commitment. In particular, the Applicants commit that they will establish a public compliance web site that will show exactly how they are complying with the virtual divestiture requirement, as well as with their other mitigation requirements. It will show: (a) the results of their annual baseload energy auctions, including the quantity of energy sold, price and the identity of the purchasers;¹⁶ (b) all long-term contracts that have been awarded, including the quantity of energy sold, price and identity of the purchasers; (c) the total amount of virtual divestiture in place; (d) the Applicants’ total required virtual divestiture taking into account all reductions in this requirement detailed in the virtual divestiture proposal; (e) the total amount of generation divested; and (f) the status of all required interim mitigation. In order to make this website readily available, a link to this website will be placed on the PJM OASIS.

This data can be confirmed through publicly available sources. For example, the results of the three-year baseload auctions will be made available by the independent auction manager. The resulting contracts must be included on the Electronic Quarterly Reports mandated by the Commission. Information regarding generation divestiture also will be included in filings at the Commission.

Finally, the Applicants already have proposed that the annual auctions for the three-year contracts be conducted under the auspices of an independent auction manager. See Cassidy Testimony at 11. Therefore, the Commission can be assured that the auctions will be conducted in a fair and nondiscriminatory fashion.

¹⁶

The purchasers will not be identified until the date of the next EQR filing following the award of contracts under the auction.

To the extent that there is a claim that the Applicants are not in compliance, the Commission will retain the jurisdiction to resolve such claims. Such a task should be fairly straightforward, however, and will not involve the burdensome monitoring responsibilities described in the intervenors’ comments.

As a result, the Commission should find that the virtual divestiture proposal can be monitored and therefore can be implemented effectively. Such a conclusion should put to rest any claim that the virtual divestiture proposal does not represent an appropriate long-term mitigation of market power for baseload nuclear capacity.

C. The Applicants Have Proposed Appropriate Mitigation For Capacity Markets

Dr. Hieronymus analyzed the merger’s impact on market concentration in PJM’s installed capacity (ICAP) markets. He analyzed two geographic markets: Expanded PJM and PJM East. The Expanded PJM market analysis is the only currently relevant analysis, because PJM will use a single ICAP market for its entire footprint beginning June 1, 2005.¹⁷

Dr. Hieronymus’ study indicated that, assuming no capacity mitigation commitments, merger-related changes in HHIs in the ICAP markets would exceed acceptable levels as identified by the Commission. Id. at 59. However, the Applicants’ proposed mitigation measures in the energy markets – the divestiture of 2,900 MW of

¹⁷

Dr. Hieronymus separately analyzed PJM East because PJM currently is considering the adoption of a locational ICAP proposal, projected to begin in 2007 or 2008. Due to this uncertainty, the Applicants have also offered to analyze the new PJM locational ICAP market, and, if necessary, propose new mitigation when that new market structure is identified. Thus, the PJM East analysis was primarily illustrative.

generation in PJM, was more than sufficient to resolve the potential ICAP problem identified in Expanded PJM. Hieronymus Testimony at 61. In addition, because the PJM East analysis showed that the merged company would need to divest additional capacity above the 2,900 MW to reduce HHI changes in the hypothetical PJM East ICAP market, the Applicants proposed to bid their net capacity position, up to 2,400 MW, in the daily PJM ICAP auction market at zero. Dr. Hieronymus’ analysis demonstrated that this commitment resolved the market screen failure in the hypothetical PJM East market. Id. at 11.

Despite Dr. Hieronymus’ careful and thorough analysis, several intervenors contend that his conclusions as to the capacity markets are inaccurate. At the same time, other intervenors assert that Applicants’ proposal to bid a zero price for up to 2,400 MW of capacity is insufficient because, assuming that the merged company has more than 2,400 MW of uncommitted capacity, it could exercise market power by economically withholding this excess capacity, and the 2,400 MW bid at zero would still receive the higher market clearing price resulting from the withholding. Therefore, they assert, Applicants’ proposal will not mitigate the merged company’s market power.

The Applicants believe that the criticisms of Dr. Hieronymus’ analysis are not valid for a number of reasons, which are described by Dr. Hieronymus. See Hieronymus Supplemental Testimony at 26-31. However, the Commission need not resolve the disputes over this analysis, because the Applicants now are eliminating the 2,400 MW cap on their agreement to bid uncommitted capacity at zero until such time as a new ICAP market is introduced and the Applicants make their promised compliance filing. Rather, the Applicants will bid the entirety of their net capacity position in the daily

ICAP market, as calculated by PJM,¹⁸ at zero. This change resolves any concern about economic withholding of excess capacity post-merger: the offer to bid all net capacity into the market at zero completely removes any market power no matter how it is calculated.

D. The Applicants’ Proposal for Implementing Mitigation is Appropriate

1. Term of Nuclear Auctions

PEPCO asserts that “[t]here is no explicit commitment in the Applicants’ testimony that the three year [baseload energy auction] sales would continue over the minimum 15-year period.” PEPCO at 38-39. PEPCO is wrong about this. However, to ensure clarity, Applicants explicitly reaffirm that the entire Baseload Mitigation Amount of nuclear virtual divestiture (2600 MW) will remain in place after 15 years, subject to a reduction in the mitigation amount if the Applicant’s PJM East nuclear capacity is decommissioned, derated, or sold or there is construction of new transmission transfer capability into PJM East. Application at 28. During this time both the long-term firm sales contracts and the nuclear baseload energy auction features of the virtual divestiture will continue in force.

Although it is correct that the long-term contracts will be for a term of at least 15 years or for the life of the nuclear unit, whichever is shorter, the virtual divestiture commitment will not necessarily terminate at the end of the contracts. When one of these long-term virtual divestiture contracts terminates and the baseload nuclear energy represented by that contract continues to be required to satisfy the Baseload Mitigation

PJM already calculates market participants’ net capacity position as a matter of course.

Amount, then either another long-term contract will be executed or the energy will be auctioned off in the Baseload Auction. See Application at 27-28. In short, all features of the virtual divestiture commitment will remain in place continuously until the market concentration issues have been resolved.

2. Time Period for Divestiture

Applicants requested a period of 18 months from merger consummation to complete the divestitures. Certain intervenors contend that the period should be shorter, claiming that policy at the Department of Justice ordinarily contemplates more rapid divestitures. E.g., AAI at 15. In the case of utility mergers, however, in addition to conducting a sophisticated auction process with associated negotiations, the divestitures of generating units often require regulatory approvals.¹⁹Applicants have no control over the duration of these regulatory proceedings, which in some circumstances can require over two years to consummate. See American Electric Power Co., 90 FERC ¶ 61,242 at 61,792 (2000) (“AEP/CSW”). Nevertheless, in response to criticisms that the time for divestiture is too long, the Applicants in good faith propose to shorten the time they will take to implement the divestitures. The Applicants commit to executing sales agreements and making filings at the Commission for the approval of the sales no later than one year after the closing date of the Transaction.

In this case, the Commission must approve the transfer. No state public service commission approval is required.

3. Identification of Divested Units

Some intervenors argue that the proposed mitigation plan is unacceptable because it does not specify precisely which units will be divested. See, e.g., AAI at 14, Midwest Generation at 5. These arguments are misconceived and should not be credited.

As an initial matter Applicants’ proposal in fact does specifically identify, in Exhibit J-12, each generating unit that is eligible for the Applicants’ divestiture commitments, whether it will mitigate screen failures in the Summer, Winter, and Shoulder periods, and whether it constitutes nuclear baseload, coal, mid-merit, or peaking capacity.²⁰Furthermore, as the Application explained, each of the identified units is located in PJM East, and Applicants will let the market decide which of these divestiture-eligible units will be sold in each category by giving prospective purchasers the opportunity to bid among them. Applicants’ proposal, in short, specifies exactly which units are subject to the divestiture commitment, and this includes each of the units that will be divested.

As explained above, the Applicants’ generation divestiture commitment requires the divestiture of at least 700 MW of coal-fired generation and 1,200 MW of additional generation that must be economic at $57.75/MWh. This means that the Applicants will

²⁰

Because additional generation units now are eligible for divestiture under the new divestiture commitment, the Applicants have attached a new list of all eligible units at Appendix 2.

be required to divest at least three and possibly more of the following eight:


Bergen		1,225 MW combined-cycle
Conemaugh		732 MW coal – combined Exelon & PSEG interest
Cromby		144 MW coal
Eddystone 1-2		579 MW coal
Hudson 2		608 MW coal
Keystone		738 MW coal – combined Exelon & PSEG interest
Linden		1,218 MW combined-cycle
Mercer 1-2		648 MW coal

This information provides a finite group of units that will provide the bulk of the capacity to be divested. The Applicants, however, have not yet determined exactly which of these units to divest – a decision that depends in large part on a consideration of the economic returns to be achieved from the sale, taking into account the compliance filing obligation to ensure no undue increases in market concentration, as described above. It would be poor policy to require the Applicants to specify the exact units to be sold before the implications of such choices have been fully evaluated.

Indeed, the Commission made clear in the AEP-CSW merger case that it is not necessary to pre-specify the particular unit that will ultimately be divested to mitigate Appendix A screen failures. In that case, to mitigate screen failures, AEP had proposed to divest a partial interest in two particular plants, 300 MW of the Northeastern plant in SPP and 250 MW of the Frontera plant in SPP. The Commission rejected the proposal to divest a partial interest in these units. Instead, it directed Applicants to divest any unit or units totaling the same number of megawatts and having the same cost, operation, and location characteristics as the specified plants. See AEP/CSW, 90 FERC at 61,792. The Commission thus adopted a comparable approach to that which Applicants propose here: permitting the sale of any combination of divestiture-eligible units to mitigate the screen failures.

4. Reduction of Mitigation Requirement

Under Applicants’ proposal, the amount of virtual nuclear divestiture (the Baseload Mitigation Amount) will be reduced megawatt-for-megawatt to the extent that (1) Applicants’ nuclear generating capacity in PJM-East is decommissioned, de-rated permanently, or sold; or (2) additional transmission transfer capability into PJM-East is constructed via projects not included in the PJM Regional Expansion Plan effective as of June 2005. Application at 28. This provides for a rational phase-out of the mitigation as Applicants’ nuclear plants come to an end of their useful life or as incremental transmission expansions increase competition.

Some intervenors object to reducing the Baseload Mitigation Amount even when these nuclear units are decommissioned, de-rated, or transferred. Ameren asserts that though such events may decrease Applicants’ market dominance, the proposed reductions should not be accepted because they do not take into account that other factors, such as new entry, other plant retirements, or unknown future conditions that may be favorable to the new company’s market position. E.g., Fox-Penner at 27; PPL at 23. This argument does not survive scrutiny.

First, reductions in the mitigation commitment to reflect plant retirements is consistent with how physical divestiture works. If the purchaser of a divested unit retires that unit after 10 years, the merger applicants are not required to then divest another unit. There is no reason to treat virtual divestiture any differently.

Second, the fact is that, when and if a nuclear unit within PJM East comes to the end of its useful life and must be decommissioned or de-rated, that generating capacity simply will not exist, and will not produce any energy. No basis exists to require the

virtual divestiture of baseload energy associated with the acquisition of incremental capacity that no longer exists and has come to the end of its useful life.

Third, as the Commission has noted on a number of occasions, for nuclear generating units, a withholding strategy is operationally impractical and readily detectable. 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).²¹The fundamental market power concern for these units therefore is not that they will be withheld from the market. Rather, the market power issue is that because these units are low cost and are always “in merit” in the energy market, their owner will earn whatever the energy market price is on each megawatt of their output. Hence if market power is exercised, and prices are raised above competitive levels, the entitlement holder to the nuclear energy will receive the higher prices on that energy, potentially creating an incentive to exercise market power. Given that a nuclear unit cannot practicably be withheld, the market power concern that underlies the nuclear divestiture requirement is this potential ability to get the market price on sales of the associated nuclear energy.

But, when and if the nuclear unit no longer exists, it cannot produce any energy on which its owner can earn above-competitive prices in the energy market. Thus, once a nuclear unit is legitimately and permanently decommissioned or derated, the market power concern that the virtual divestiture requirement is intended to mitigate no longer

²¹

See also the testimony of Applicant witness Crane, who explains that such cycling of nuclear units is not realistically practicable. Crane at 21-24.

exists. This is true irrespective of whether in the future other units owned by other companies are built, retired, or sold, or if market conditions change.

Finally, the earliest potential decommissioning date projected for any of Applicants’ nuclear units in PJM East is 2009, nearly five years from now, and even for that plant, no decision has yet been made whether to decommission. Intervenors’ argument that other retirements may occur or that market conditions may change are thus not only purely hypothetical, they are not even hypothetically caused by the merger. It is idle to speculate about entry, future mergers, or other unknown events not caused by the merger. Applicants’ proposal focuses not on speculation, but on the simple fact that they will not possess, and cannot sell energy from, nuclear capacity in PJM-East that is legitimately decommissioned, derated, or sold.²²

Raising only these same hypothetical contentions, Ameren alone also opposes allowing incremental transmission expansion into PJM-East to reduce Applicants’ Baseload Mitigation Amount.²³Fox-Penner at 9. Ameren’s opposition to this element of

²²		For all the reasons discussed above there is no merit to the contentions of PEPCO witness Cicchetti who concocts a hypothetical example suggesting that decommissioning of nuclear units would cause EEG’s market share to increase. Cicchetti at 27. His analysis unrealistically assumes that decommissioning would occur long before the projected date and he ignores the potential changes in the marketplace that would likely occur by the time the units actually are decommissioned. Nor does he take into account the fact that legitimate decommissioning of the units would eliminate the market power concern – i.e., the receipt of market prices on baseload nuclear energy – that virtual divestiture is designed to address in the first place.

²³		To the best of Applicants’ knowledge, Ameren is not a significant market participant in PJM East. Therefore, the basis for its interest in this subject, which is unique among the intervenors, is not immediately apparent. No such objections have been raised by the parties that would benefit from increased transfer capability into PJM East.

the mitigation plan is without basis. The Commission’s policies clearly favor transmission expansions into constrained regions, and it should create incentives for such expansions where doing so is otherwise consistent with the public interest. Increasing transfer capability into PJM-East would permit additional competitive supply to enter the PJM-East market at times of constraints and such new supply would be available to defeat attempts by generators to drive up prices. Thus, expanding the transfer capability into PJM-East by “x” amount of megawatts would not only prevent Applicants from earning above-competitive prices on the same number of megawatts of energy—it also would potentially reduce market prices for every market participant. Because such an expansion would mitigate against any attainment of above-competitive prices on Applicants’ energy sales and reduce prices and increase competition for the market as a whole, Applicants’ proposal is both meritorious and consistent with the public interest.

5. The Applicants Have Proposed Appropriate Interim Mitigation

FirstEnergy raises three issues regarding the Applicants’ proposal for interim mitigation: (1) that the PJM Market Monitor should be required to monitor the Applicants’ compliance with their interim mitigation proposals; (2) that the Applicants have not provided enough detail regarding their proposed interim mitigation sales; and (3) that the proposal for interim mitigation of the nuclear units of bidding those units into the market at a price of $0 is not adequate because the nuclear units do not set the market price. FirstEnergy at 50-52. FirstEnergy’s witness Ms. Frayer echoes the last of these concerns. Frayer at 65-66.

The Applicants do not believe that there is any need to adopt FirstEnergy’s first proposal to have the PJM Market Monitor oversee the interim mitigation. As described

above, the Applicants already have committed to establish a publicly available web site that will, among other things, track interim mitigation. As also described above, the Market Monitor will have the ability to track the amount of interim mitigation actually entered into to confirm that in fact the interim mitigation is being implemented.

FirstEnergy’s assertion about the amount of detail provided by the Applicants regarding their interim mitigation auctions – that “other than noting points of delivery and the term of service, Applicants fail to provide crucial details about these interim auctions,” FirstEnergy at 51 – is simply not correct. Many more details are provided in both the Application and in the testimony of Mr. Cassidy. For example, the Application states that the contracts will be a “virtual unit transfer” type of product tied to specific units with the purchaser acquiring full dispatch and unit offering rights, as well as the Unforced Capacity (“UCAP”) associated with the unit. Application at 34-35. Mr. Cassidy provides significant additional detail, including further description of how the strike price will be calculated and that the EEI Master Agreement will be used for the sales. Cassidy Testimony at 5-7.

In attacking the Applicants’ proposal to bid their nuclear units into the market at a price of $0 during the short period of time before the first interim baseload auction can be conducted, Ms. Frayer observes that the nuclear units rarely set the market price and therefore the commitment to bid at $0 will not reduce the market price. She suggests that the Applicants be required “to propose bid caps for other assets that are more likely to be price setting.” Frayer at 65. This, of course is precisely what the Applicants already are proposing to do. Their interim mitigation proposal for their mid-merit and peaking units, which are the “price-setting” units that Ms. Frayer refers to, provides for cost-based bid

caps for those units before the Applicants enter into the mitigation contracts for those units. See Application at 35.

Citizen Power et al. assert that the “only effective interim mitigation plan is for Exelon-PSEG to charge only cost-based rates until the sale/swap of assets is complete.” Citizen Power et al. at 10. Other than making the bare statement, however, they provide no explanation as to why this should be the case. Nor do they explain how the Applicants could make sales at cost-based rates into the PJM markets, which establishes market-clearing prices that apply to all sales into those markets. As a result, this argument should be rejected.

E. The Applicants Are Proposing Additional Transmission Upgrades

Various parties to this proceeding have commented on the need for additional transmission infrastructure investment in PJM and have urged applicants to take actions to address both congestion and transmission constraints on their respective systems. See, e.g., FirstEnergy at 47; PEPCO at 45-46.

In other merger proceedings, various applicants have proposed to upgrade transmission infrastructure at some point in the future in order to assist them in meeting the requirements of the Commission’s Appendix A analysis. See, e.g. Ameren Services Co., 101 FERC ¶ 61,202 at P. 32 (2002). Applicants have chosen not to go that route, and have proposed an unprecedented market power mitigation package instead. Nonetheless, Applicants recognize that transmission expansion projects can provide an important public interest benefits. The Applicants are well aware of the Commission’s recent expressions of concern about the pace of transmission expansion and of the Commission’s ongoing deliberations pertaining to a Transmission Policy Statement. See,

e.g. Transcript, Technical Conference, Docket Nos. ADOS-5-000 et al. at 124-25 (April 22, 2005).

With the Commission’s concerns in mind, applicants note that they are already committed to making significant transmission expansion investments. Those investments are described in detail below. In addition, as described below, Applicants will commit to fund further upgrades on PJM’s list of Economic Projects, provided that the Commission approves the proposed Transaction without a hearing. Applicants wish to convey their willingness to address transmission issues in general, and specific reliability and economic upgrades, in order to address the Commission’s ongoing policy initiatives to upgrade transmission infrastructure in order to enhance reliability and to further the development of competitive wholesale power markets.

1. Existing Transmission Commitments

The Applicants have funded and continue to fund substantial transmission upgrades. As members of PJM, the Applicants are subject to a formal regional transmission expansion planning process that is open to all stakeholders. Unlike areas that do not have formal regional planning processes, the process by which Applicants build transmission is both public and transparent.

Within PJM, there are planning processes for both reliability and economic upgrades. In general, reliability upgrades must be undertaken by Transmission Owners whereas economic upgrades are voluntary. The Applicants have substantial reliability investment commitments as a result of the PJM Regional Transmission Expansion Planning Process (RTEP Process). This includes approximately $320 million in upgrades for Exelon and approximately $260 million in upgrades for PSE&G. Attached as

Appendix 1 is a list of all projects committed to by the Applicants for the time period

2005-2008. The most significant of these are as follows:

•   PSE&G will replace three 500/230kV autotransformer banks – two at Branchburg in Northern New Jersey and one at New Freedom in Southern New Jersey. All of these projects will increase import capability as well as reducing congestion. The derated transformers are scheduled to be replaced by summer 2007. The new transformer banks will have a summer normal rating of approximately 900 MVA each. The PJM published estimate of unhedged congestion associated with Branchburg is almost $200 Million/year.

•   PSE&G will install a new nineteen (19) mile 230kV high voltage underground cable from Essex to Aldene in Northern New Jersey, which will also include a new 700 MVA, 230 kV phase angle regulator (PAR) and a 100 MVAr shunt reactor for service by the end of 2006. This project provides additional transfer capability into the constrained Northern PSE&G zone and satisfies multiple other reliability based criteria. The PAR will also allow mitigation of congestion on the Roseland to Athenia transmission corridor.²⁴

•   Exelon will install a new 9.7 mile 345kV line between the existing Silver Lake substation and a new transmission substation (TSS) at Pleasant Valley in the northern part of the ComEd system prior to June 1, 2005. This project, which also includes installation of a new 345/138kV autotransformer at Pleasant Valley, will prevent overloads in the northern part of the ComEd system under contingency conditions, thus enhancing reliability and reducing congestion. The project also will provide voltage support for the northern area of the ComEd system and minimize the risk of voltage collapse during extreme contingency conditions.

•   Exelon will install two major 345kV lines connecting three substations south of the Chicago central business district in 2008.²⁵These lines will connect Crawford Station, the new West Loop TSS and Taylor TSS providing 345kV service to West Loop TSS and networking the 345kV system that now is radial into the southern part of Chicago. These transmission lines will not only provide increased reliability and flexibility but will provide the infrastructure to reduce the timeline to build additional transmission reinforcements in the event of retirement

²⁴		PJM shows gross congestion in 2004 for this corridor (the Cedar Grove-Roseland 230kV lines and the Cedar Grove to Clifton line) to exceed $10 million. See http://www.pjm.com/planning/economic-planning/2003-04-05-monthly-congestion-summary.xls (“PJM Congestion Summary”).

²⁵		For additional information, see http://www.exeloncorp.com/comed/newsroom/2005/20050317.shtml.

of older generation in the area, thus shortening the exposure period for RMR contracts. In addition, Exelon will install two-345/138kV autotransformers at West Loop TSS, completing the upgrade of service to the northern part of the Chicago central business district.

2. The Applicants Are Now Committing to Additional Transmission Upgrades Regardless of Whether the Transaction is Approved

As shown above, the Applicants continue to invest in the expansion of the transmission system for reliability. With this filing, Applicants are committing to implement two projects beyond what is required in the RTEP that they believe will provide important benefits to the PJM region. These projects will be implemented, regardless of whether the merger is approved.

The first of these projects involves accelerating the completion of a project that is listed in the RTEP, thus making its benefits available earlier than projected in the RTEP. The second project is on the PJM list of Economic Projects located on Exelon’s system. PJM has started a process to provide for economic upgrades – those transmission upgrades that go beyond what is needed to provide reliable service to customers. This is a new concept because (1) these projects are voluntary, (2) these projects are for congestion relief, not reliability, and (3) a participant can fund an economic project located anywhere on the PJM transmission system, instead of requiring the owner of the facilities on which the improvement is being made to pay for the upgrade. This process is still in its infancy. It starts with PJM publishing a list of possible economic projects and can end with PJM requesting the Commission to direct transmission owners to construct such projects.

    The two transmission projects that the Applicants are committing to are as follows:

•   Advancement of the replacement of two Branchburg 500/230kV autotransformers prior to the summer of 2006: As stated above, the RTEP requires PSE&G to replace those transformers prior to the summer of 2007. PSE&G has advanced the order of the necessary equipment, and, subject to timely delivery of the new transformers and obtaining the necessary transmission outages to perform the installation, PSE&G will voluntarily advance the replacement of these transformers.

•   Reconductor the North Wales to Whitpain 230kV line: PJM shows unhedgeable congestion of $2.7 million due to this line.²⁶Exelon will either reconductor this line or eliminate the congestion due to a project that will reduce loadings on this line in 2009.

3. The Applicants Commit to Further Upgrades in an amount of $25 million on PJM’s List of Economic Projects, Subject to Approval of the Merger Without a Hearing

Applicants are willing to make a major commitment to develop new transmission infrastructure in PJM; however, identifying specific projects to undertake as of this date is difficult. PJM is on the verge of listing new projects to be included in its RTEP process.27 As a condition of their membership in PJM, PJM Transmission Owners will be required to fund the transmission upgrades that are ultimately included on the new RTEP list and assigned to each Transmission Owner. In addition, PJM is expected to update its current list of Economic Projects in the near future.

Applicants have carefully examined the current RTEP list, and the current Economic Project list with an eye toward expanding their own commitment to develop transmission infrastructure. In light of the uncertainty about which projects on the

²⁶		See id.

²⁷		The new RTEP list is expected to be released for discussion at the Transmission Expansion Advisory Committee meeting tomorrow, May 10, 2005.

current Economic Project list will be included on the updated RTEP list, and uncertainty over which projects will be included on the updated Economic Project list, it is difficult for the Applicants to identify specific new projects to construct. In lieu of making a commitment to construct specific projects, Applicants hereby commit to fund $25 million of such projects (approximately $5 million per year for five years), during the five years following consummation of the merger, if the Commission approves the merger without a hearing. These projects may be located on the transmission systems of Applicants or of other companies, as provided by the PJM requirements for Economic Projects.

This funding, together with the substantial projects described above for reliability, will provide important support for further development of competitive wholesale markets. As mentioned above, the PJM effort with respect to Economic Projects is in its infancy and will evolve. Applicants will continue to monitor this effort. If the Commission approves the Merger without a hearing, the Applicants will make a compliance filing with the Commission within 90 days following consummation of the merger detailing the project plan and rate recovery for this investment.²⁸The specific projects will be coordinated with PJM, considering benefits to customers and coordination with the owner(s) of the facilities to avoid project delays.

Applicants believe that these voluntary commitments represent a continuing good faith effort on their part to enhance the operation of competitive wholesale power markets by providing the necessary transmission infrastructure to support both reliability and competition. As mentioned above, the PJM process for

²⁸

Applicants expect to be able to recover these investments in accordance with Schedule 12 of the PJM Open Access Transmission Tariff.

identifying Economic Projects is in its infancy and will evolve. Applicants will continue to participate in this effort. Applicants pledge to work with PJM, and other interested parties, to encourage the construction of additional economic upgrades in the PJM region. In particular Applicants pledge to work with PJM to refine the process and criteria for identifying economic upgrade projects, to further the development of detailed plans for economic upgrades, and to participate in constructing upgrades identified as appropriate to reduce congestion and to enhance wholesale competition in the region.

V. THE INTERVENORS’ POLICY ISSUES HAVE NO MERIT

In an implicit recognition that their attacks on the Transaction are otherwise without merit, some intervenors raise arguments, couched as “policy” arguments, that presumably would cause the Commission to reject the Transaction even though the Merger Policy standards have been satisfied. These arguments are without merit.

The Size of EEG Alone Does Not Raise Any Public Interest Issues

Certain intervenors argue that the Commission should reconsider its Merger Policy and use of an Appendix A analysis because of the size of the merged company. For example, Ameren asserts that the Transaction will create a “mega utility” that will have a dominant market position. Ameren further asserts that the Commission should rethink whether the Appendix A analysis captures the market power issues associated with the creation of such a mega utility. Ameren at 8-10. Other intervenors also refer to the large size of the merged company as representing a special factor that should be considered independent of the Appendix A screen analysis. See PEPCO 9-22; AAI at 3-5.

However, the intervenors do not identify any unique issues associated with the merged company’s size that cannot be addressed through the tools already available to the

Commission. Ameren asserts that the merged company will be able to dominate other market participants even if the screens are satisfied, but other than making the bald assertion, does not explain how this could happen based solely on the size of the merged company. See Fox-Penner – Pfeifenberger Aff. at ¶¶ 22 24. See also PEPCO at 16-18; PPL at 17-18. The only conceivable threat to these competitors from the increased size and efficiency of the merged company is that such efficiencies will allow EEG to drive down regional electric prices, hurting their bottom line. The potential for the reduction of PJM electric prices, is a reason to approve the Transaction, not a reason to reject it.

Other of these arguments go to such issues as the nature of the virtual divestiture commitment and the ability of the merged company to create transmission constraints through the operation of generation. See Fox-Penner – Pfeifenberger Aff. at ¶¶ 26-28; 38-40. These issues, which as discussed below have no merit, have nothing to do with the size of the merged company. They certainly provide no grounds for changing the Commission’s Merger Policy, or for rejecting the Transaction even though it passes the Appendix A screens and otherwise is consistent with the standards of the Merger Policy.

The Commission Should Not Consider Impact of the Transaction on Future Mergers Between Other Members of PJM

Several intervenors that have large market shares in PJM contend that the proposed Transaction should be rejected because they believe that it would make it more difficult for them to complete large mergers of their own at some point in the future. See PEPCO at 15-19; Ameren at 8-10; see also Pa. OCA at 11-13. Presumably these intervenors’ concern is that the Transaction will increase concentration in PJM, making it more difficult for future mergers of market participants with large market shares to satisfy the Appendix A market screens. It is ironic that these large energy companies

would argue, in the same pleading, that (1) large mergers are inappropriate, (2) the proposed transaction is inappropriate because it interferes with those companies’ own ability to enter into a large merger, and (3) they believe the largest utilities should be allowed to purchase the bulk of any generation the Applicants divest.

In any event, the Commission decided long ago that it would review merger proposals before it on their own merits, without engaging in any comparison of the merger with other merger alternatives that have not yet been proposed.²⁹Accordingly, the question of whether this merger should be rejected so that as yet unproposed mergers involving PEPCO, Ameren, or any other utility intervenor could more easily proceed is not properly in issue in this proceeding.³⁰

Moreover, the factual underpinning for this contention does not bear scrutiny. All three of the relevant markets impacted by the Transaction are either unconcentrated or moderately concentrated markets and will remain so after the Transaction’s consummation, once Applicants’ proposed mitigation is taken into account. Indeed, the Transaction should not make future mergers any more difficult than the two previous

²⁹		See Ohio Edison Co., 85 FERC ¶ 61,203, at 61,846 (1998) (rejecting intervenors’ request to “look at possible future mergers when assessing the potential competitive effects of a proposed merger”); Southern California Edison Co., 47 FERC ¶ 61,196, at 61,684 (1989) (Trabant, C., concurring) (“Any [future impact of a merger] must be demonstrated to have an adverse effect on the existing competitive situation, which by definition, involves the current competitive situation in a particular geographic region under prevailing law, policy and practice [if it is to be addressed by the Commission].” (emphasis added)); see also Central Vermont Pub. Serv. Corp., 52 FERC ¶ 61,278, at 61,102 03 (1990).

³⁰		Of course, the current concentration levels in each of the markets analyzed by Applicants are greater because of the two mergers that created PEPCO Holdings and by FirstEnergy’s prior merger with General Public Utilities Co., a fact that seems to have slipped the minds of both of them.

mergers that combined FirstEnergy and General Public Utilities Company or that created PEPCO Holdings Inc. While it is true that a future merger between two large market participants might raise competition issues, that would be the result of the size of those market participants, not this Transaction.

VI. THE TRANSACTION DOES NOT RAISE VERTICAL MARKET POWER ISSUES

A. No Transmission Issues Are Raised by the Transaction

1. Vertical Market Power

As the Applicants noted in their Application, they all have transferred control over their transmission systems to the PJM RTO. Under well established Commission precedent, when merger applicants have transferred control over their transmission systems to an independent entity such as an RTO, that mitigates any possibility that the applicants will be able to use their control over transmission facilities to gain a competitive advantage for their generation facilities. See Application at 44.

Notwithstanding this clear Commission precedent, the American Antitrust Institute (“AAI”) asserts that participation in an RTO may not adequately mitigate the potential exercise of vertical market power. Citing to a show cause order in which the Commission initiated an investigation of Exelon regarding alleged sharing of non public information regarding maintenance outages, AAI asserts that the potential for the abuse of vertical market power still exists. AAI at 17-18.

However, as AAI acknowledged, the Commission never found any violations in the proceeding that AAI cites. Indeed, what AAI leaves out of its protest is that the Commission found that "[t]he record in this proceeding does not establish a violation of the FPA and the Commissions Standard of Conduct sufficient to warrant further

enforcement proceedings.” PJM Interconnection, L.L.C., 97 FERC ¶ 61,319 at 62,463 (2001) (emphasis added). Further, the Commission provided for a change in PJM procedures designed to prevent the type of behavior included in the allegations that the Commission investigated. Thus, the proceeding cited by AAI shows that: (1) Exelon did not act improperly; and (2) the potential for the problem under PJM’s rules has been addressed and cannot represent a possible avenue for the exercise of vertical market power. Certainly, AAI has presented no basis for concluding that the Commission should change its policy regarding RTO membership.

Ameren and its witnesses raise similarly vague allegations regarding the sufficiency of RTO membership. They assert that “Applicants’ increased control over regional generation facilities may allow them to manipulate transmission constraints on the PJM controlled grid.” Ameren at 16 (citing Fox Penner Pfeifenberger Aff. ¶ 38). However, Ameren does not point to any specific generation facilities or describe any specific situation in which the Transaction will increase the Applicants’ ability to manipulate transmission constraints on the transmission grid. Nor does Ameren discuss the PJM market rules and the ability of the PJM Market Monitor to address any attempts by the Applicants to act as Ameren suggests.

2. Ability to Influence PJM

The Applicants explained in the Application how the Transaction will not expand in any material fashion their ability to influence the decisions made by PJM or to threaten its independence. This is because the Board of Directors of PJM is completely independent of all PJM members and the combined company still will not have a significant voting interest in any PJM committees. Nor will the combined company have

the ability to control the voting under the various PJM Transmission Owners’ Agreements. See Application at 44 46.

No party contests the Applicants’ description of the various agreements relating to the governance of PJM or argues that the Applicants have understated their voting interests under those arrangements. PEPCO, however, asserts that the Applicants nevertheless “might be positioned to exercise extraordinary influence on the PJM RTO” as a result of the fact that it will have the largest transmission investment in PJM. It asserts that “[t]he professed needs and available resources of such a dominant constituent could influence RTO decision making.” PEPCO at 19.

In making this argument, PEPCO in essence asks the Commission to discard all the work that the Commission has done in crafting the governance provisions of Order No. 2000 and in its subsequent RTO implementation cases. It would have the Commission find that, notwithstanding the fact that all of the Commission’s criteria for independence are satisfied, the Applicants still have the ability to exercise control over PJM.

There is no need, however, for the Commission to change its independence criteria. Other than making a bare assertion, the PEPCO has not demonstrated how and to what extent the merged company could influence PJM decisionmaking due to its size, nor has it shown how such influence might give the merger company any competitive advantage. PEPCO’s unsupported assertions should be rejected.

B. No Vertical Issues Are Raised by the Transaction with Respect to Applicant’s Natural Gas Operations

Intervenors also raise objections to Applicants’ analysis showing that no vertical market power issue is raised in this proceeding.

As explained in the testimony of Dr. Hieronymus, this proposed merger would not create any new vertical relationship. Hieronymus Testimony, Exh. J 1 at 15-16. Rather, each company operates a natural gas distribution system within its electricity service territory, with no overlap. Neither company owns interstate pipeline facilities. In short, this is not a “convergence” merger comparable to those in which the Commission has identified vertical market power issues as a result of the combination of electric and gas utilities.

Thus, as a threshold matter, because the Transaction will not create a new situation where the combined entity conceivably could increase electric prices by denying gas supplies to other participants, the Transaction simply does not create the kind of anticompetitive situation with which the Commission has been concerned. See San Diego Gas & Elec. Co. and Enova Energy, Inc., et al., 79 FERC ¶ 61,372, at 62,561 62 (1997), order denying reh’g, 85 FERC ¶ 61,037 (1998); Dominion Resources, Inc. and Consolidated Natural Gas Co., 89 FERC ¶ 61,162, at 61,447 48 (1999).

Indeed, as Dr. Hieronymus’ testimony demonstrates, nothing about the Transaction would increase Applicants’ ability to increase electric prices by withholding gas supplies. Rather, all the evidence proves that Applicants will have no ability to rival generators from acquiring gas supplies. First, Applicants do not own interstate transportation facilities, so they cannot stop entry of new generation plants. New rival generators in PJM East could connect directly to interstate pipelines. Second, the interstate capacity rights that Applicants do own are dedicated almost entirely to serving

the customers of their retail affiliates.³¹Third, Applicants are unable to withhold their interstate capacity because under FERC rules, the interstate pipeline has the obligation to make available any unnominated capacity to other customers on an interruptible basis.³²These facts—which Intervenors have not disputed—are crucial. By themselves, they demonstrate that after the Transaction the Applicants will not have the ability to withhold gas supplies.

Notwithstanding this lack of vertical effect, Dr. Hieronymus’ analysis would be dispositive in any case. Intervenors do not dispute the Commission’s rule that, with respect to fuel supplies, no vertical market power issue is presented unless both the upstream and downstream markets become highly concentrated. See, e.g., Engage Energy America, LLC, 98 FERC ¶ 61,207, at 61,750 (2002); El Paso Energy Corp., 92 FERC ¶ 61,076, at 61,332 (2000); Long Island Lighting Co., 80 FERC ¶ 61,035, at 61,079 (1997). For two reasons, Applicants pass this test.

First, as a result of Applicants’ substantial divestiture commitment, Applicants will have less available economic capacity in the downstream electric market after the merger than they do today. Thus, it is clear that the merger will actually decrease, not increase, Applicants’ incentive to use its ownership of both gas capacity and electric

³¹		The vast majority of Applicants’ capacity is committed for serving retail gas customers on their distribution systems. For instance, PSEG serves 99 percent of the residential customers on the PSE&G system. See NJBPU at 5.

³²		Intervenors assert that Dr. Hieronymus is wrong that Applicants cannot withhold their capacity as a result of the release market, because capacity holders are “free to nominate any level of their entitlement and are not obligated to release capacity into the market.” See LeLash at 5. This misses the point. Under Commission rules, capacity that is not used by Applicants’ available on an interruptible basis from the pipeline company. See 18 C.F.R. § 284.9.

resources to raise electric prices.³³Consequently, regardless of the concentration of the capacity on upstream interstate pipelines, the merger should not be deemed to make the downstream electric market less competitive for purposes of assessing potential vertical market power. See Long Island Lighting Co., 80 FERC at 61,078 (no vertical concern where incentive to exercise market power is not increased by merger).

Second, even if the downstream market were considered vulnerable to anticompetitive behavior, the upstream market will not be highly concentrated post merger. Dr. Hieronymus’ analysis shows that the upstream natural gas HHI is 1572. See Exhibit J 16. Intervenors nevertheless claim that this calculation is too low because Dr. Hieronymus measured too large an upstream market, by including capacity that in fact flows through PJM East but is bound for New York and New England. See Direct Energy at 8; Briden at 6 7; Pa. OCA at 23. The logic of this argument, however, is not consistent with the way the natural gas market works. Nor would removing “northern bound” actually increase the upstream HHI as Intervenors claim.

Natural gas capacity that is deliverable into New York or New England is often sold into PJM East. A substantial portion of PSEG’s natural gas capacity is considered “New York” capacity, because it is deliverable on a firm basis past the Linden “bottleneck” up to New York City city gate. Recent expansion of the Iroquois pipeline, as well as the entry of the Portland Natural Gas Transmission System and the Maritimes and Northeast pipelines in New England, have expanded northeastern capacity by more

³³

For the same reason, it is irrelevant that the electric market in Northern New Jersey will remain highly concentrated post merger. This is already the case today, and is not an effect that can be attributed to the Transaction.

than 600 MMcf/d according to EIA data. This means that some firm capacity that travels through PJM East to the north can be released or used for bundled sales in that market. Industry pricing data indicate that profitable trading opportunities exist between these markets.³⁴As a result, an action taken to increase the price of gas in PJM East would only increase the possibility of trades for New York or New England “bound” capacity, neutralizing any price effect of the action.

New York and New England “bound” capacity can also help to prevent discrimination against generation companies within PJM East. If Applicants attempted to disadvantage rival generators with their own capacity, the generators could purchase replacement supplies from “northern bound” shippers and the northern bound shippers could purchase replacement supplies in PJM East. Indeed, given that rival generation companies can connect to interstate pipelines running through PJM—a fact the Intervenors do not contest—there can be no claim that a vertical market power issue is created by the merger. See Hieronymus J-1 at 30.

More importantly, excluding this “northern bound” capacity from the market share calculation would not cause the upstream market to become highly concentrated as these intervenors claim. They cannot pick and choose which capacity to leave in the market calculation and which to remove. If they remove some New York - and New England deliverable capacity, they must remove it all. This would include PSE&G’s capacity on the Transco line, which, like the other “northern bound” capacity excluded by these intervenors, is deliverable to the New York City area and receives New York prices

³⁴

See Hieronymus’ Supplemental Testimony at 45 ¶ 20.

in the spot market.³⁵An HHI calculation that uses Direct Energy witness Briden’s data,³⁶but simply excludes all New York-and New England- deliverable capacity, confirms that the HHI for the upstream market would be no higher than 1651—precluding any claim of vertical concerns. See Hieronymus Supplemental Testimony at 45-46.

Finally, these intervenors are also wrong that Dr. Hieronymus failed to adequately consider the effect of storage capacity on the upstream market. See LeLash at 4; Pa. OCA at 23. Applicants do not own storage facilities. Rather, they contract for relatively small amounts of storage capacity that cannot reasonably be claimed to create a competitive concern. In fact, prior studies of storage capacity that have been accepted by the Commission demonstrate that the market for firm capacity relevant to Exelon and PSEG is not highly concentrated.³⁷In this market, Applicants estimate that their combined storage capacity is less than 12 percent.³⁸ See Hieronymus Supplemental Testimony at 46. Thus, even if it were appropriate to consider the separate market for gas

³⁵		As noted above, the vast majority of Applicants’ capacity is committed to retail gas customers on their distribution systems. If excluding northern bound capacity is proper because it is “committed” to another market, it would also be proper to exclude the Exelon and PSEG capacity that is “committed” to serving retail customers other than electric generators.

³⁶		Dr. Briden’s workpapers demonstrate that while initially accounting for all capacity into PJM East, his final capacity calculation erroneously excluded some of the “other” capacity attributable to smaller players in the market. Applicants’ revision to Dr. Briden’s calculation also corrects this error by restoring the “other” capacity number to the full figure originally reflected in Dr. Briden’s workpapers.

³⁷		See,e.g., Affidavit of Dr. John R. Morris, El Paso Corporation and The Coastal Corporation, FERC Docket No. EC00 73 000, Exh. JRM 30 (Mar. 31, 2000).

³⁸		As shown in the FERC Index of Customers, Exelon currently has about 16 Bcf of capacity under contract, and PSEG has about 82 Bcf. Market size is approximately 840 Bcf.

storage, this market would be immaterial, because Applicants’ share of storage capacity is even smaller than their share of pipeline capacity.³⁹

VII. THE TRANSACTION SATISFIES THE OTHER MERGER POLICY CRITERIA

A. Impact on Rates

Only a few intervenors raised issues regarding the impact of the Transaction on rates. Most of these attacks were based on the assertion that the Transaction would lessen competition and cause an increase in wholesale power markets, which would translate back to increases in retail rates. Citizen Power et al. at 10-11; Environmental Law & Policy Center at 2. These arguments simply restate the assertions regarding the impact of the Transaction on competition, and should be rejected for the same reasons that the competition issues should be rejected as described above.

³⁹		Intervenors also raise several other arguments that are plainly irrelevant under the Commission’s merger policy. Intervenors claim, for instance, that Dr. Hieronymus improperly failed to conduct a horizontal analysis of the wholesale, retail, and spot markets, Philadelphia Gas Works at 7-8; Moser at 3; Pa. OCA at 22; NJRPA at 16; that he should have analyzed individual pipelines, Pa. OCA at 23; that Applicants could influence rate settlement proceedings for natural gas, Moser at 3; and that they could use their combined influence to thwart competition using asset management deals. NJRPA at 16, LeLash at 4.

		Of course, the Commission has been clear that the objective of its Section 203 analysis is to assess “a proposed merger’s effect on competition [and] . . . output in electricity markets"—not on gas markets. Order No. 642 at 31,879. Nor is it proper to examine individual pipelines in a Section 203 case; in a geographic region, capacity used on one facility can be replaced from another. Likewise, the merger does not change the fundamental nature of asset management services, which is to maximize the value of the assets for their owners—not Applicants. And the fact that Applicants might participate in rate settlements cases is irrelevant, since those proceedings are conducted under the protection of Commission procedure.

The Pa. OCA raises one additional issue, asserting that the Applicants’ hold harmless commitment for transmission rates is not adequate. According to the Pa. OCA, the PJM OATT “would allow the Applicants to file surcharge mechanisms or formula rates that might allow transmission rates to increase without reflecting the benefits of the merger.” Pa. OCA at 33 34.

The Applicants do not believe that this should be an issue. However, in order to address any concerns raised by the Pa. OCA, the Applicants clarify that their hold harmless commitment also will apply to any surcharge mechanisms or formula rates that apply to the transmission charges that they can collect under the PJM OATT. In other words, no surcharge of formula rate can be implemented that would allow the Applicants to recover merger-related costs unless those costs are offset by merger-related savings.

B. Impact on Regulation

Only two issues were raised regarding the impact of the Transaction on regulation. First, the Pa. OCA asserts that the Commission cannot rely on the Pennsylvania Public Utility Commission’s (“PAPUC”) review of the proposed Transaction to assure itself that Pennsylvania regulation will not be impaired. To support this assertion, the Pa. OCA observes that, when the Applicants filed their application for approval of the Transaction at the PAPUC, they also requested a declaratory order that the PAPUC does not have jurisdiction over the Transaction. Pa. OCA at 37-38.

As an initial matter, the Applicants would note that the PAPUC has processed their application as if it has jurisdiction and is planning to subject the application to a merits review. The PAPUC has given no indication whatsoever that it intends to grant the Applicants’ petition for declaratory order. In this regard, the Applicants believe that it

is telling that the PAPUC has intervened in this proceeding, but has not raised any concerns regarding the impact of the Transaction on its jurisdiction or requested the Commission’s assistance in this regard.

In any event, the Transaction will not have any impact on Pennsylvania state regulation of the Applicants. The Transaction does not in any way affect the structure or status of PECO, which is the utility subject to the PAPUC’s regulation. PECO already is part of a registered public utility holding company system, and PECO already has divested its generation and entered into a wholesale power purchase agreement with Exelon Generation. The Transaction will not in any fashion change the extent or nature of the PAPUC’s jurisdiction over PECO or any other entity that it currently regulates.

Citizen Power et al. assert that the Transaction could impact regulation in New Jersey in the event that PUHCA is repealed. Citizen Power et al. at 5-6. There is no need to address this claim. Citizen Power et al. do not contest the fact that the Applicants have filed an application before the New Jersey Board of Public Utilities (“New Jersey BPU”) for the approval of the Transaction. To the extent that the concern about the impact of the repeal of PUHCA has any legitimacy, the New Jersey BPU can address this issue in its own proceeding. Again, it is telling that the New Jersey BPU itself has not requested the Commission’s assistance on this issue.

VIII. THE OTHER ISSUES RAISED BY INTERVENORS ARE NOT RELEVANT TO THE COMMISSION’S INQUIRY

A. The Applicants Have Provided Sufficient Detail Regarding Their Proposed Internal Restructuring

The Applicants noted in their Application that they had not finalized their plans for the corporate structure of EEG after the Transaction, and requested that the

Commission approve additional transfers of jurisdictional companies that own generation or sell power, subject to certain limitations. In particular, the Applicants stated that no such transfers would involve the transfer of generation from merchant generation companies to the three traditional franchised public utilities – PSE&G, PECO or ComEd. See Application at 51 52.

FirstEnergy attacks this request, asserting that the “Applicants do not identify or provide any information regarding the jurisdictional - public utilities that will be affected and how they will be affected.” FirstEnergy at 55. This simply is not true. The Applicants made clear that the jurisdictional regulated utilities will not be affected at all. The request is limited to transfers other than to the regulated utilities. In other words, there may be transfers within the EEG Ventures and/or PSEG Energy Holdings branches of the corporate structure shown on the organizational chart in Exhibit C, but there will be no transfers of jurisdictional entities to or from the regulated utilities under the EEG Energy Delivery group of companies. These internal transfers within the unregulated branches of EEG do not raise any public interest issues, as the Commission has found. Order No. 642, ¶ 31,111 at 31,902 03.

FirstEnergy also cites from the Commission’s Ameren Energy case for the proposition that some types of internal transfers of jurisdictional companies do potentially raise competition issues. FirstEnergy at 55 (quoting Ameren Energy Generating Co., 103 FERC ¶ 61,128 at P. 36 (2003). The Applicants agree. That is why they have not requested that the Commission approve any transfers of the type that the Commission found to potentially raise issues in Ameren Energy, i.e. transfers of generation assets from merchant generation companies to traditional franchised utilities.

It is precisely because the Applicants are not requesting approval for such transfers that the Commission can be comfortable that the internal transfers subject to the Applicants’ request will not raise any public interest issues and can be approved.

B. The Loop Flow Issues Are Unrelated to the Transaction

NiSource does not oppose the proposed Transaction. Rather, NiSource very candidly admits that it is concerned about “an existing operational and competitive problem” regarding loop flows. NiSource at 4. NiSource details what it asserts are loop flow problems that it alleges have resulted as a consequence of ComEd’s participation in PJM.

Although NiSource couches its arguments in terms of increased loop flows resulting from the Transaction, it is clear that what NiSource really is concerned about is the existing situation, and that it is attempting to use the proposed Transaction as leverage in its ongoing dispute with Exelon. See, e.g. NiSource at 8 (“It has now become apparent that ComEd’s choice to join PJM is also creating an adverse impact on NiSource through increased loop flows.”). The Commission has established a process for dealing with loop flow issues between PJM and MISO as a result of ComEd’s joining PJM. See Joint Operating Agreement filed in Docket No. ER04-375, which was first accepted in Midwest Independent Transmission System Operator, Inc., 106 FERC ¶ 61,251 (2004). In addition, issues concerning loop flows as a result of ComEd and AEP’s entry within PJM for the MI and WI Companies were part of the approval of ComEd’s entry into PJM, Alliance Companies, 100 FERC ¶ 61,137, at PP 53-54 (2002), order on r’hrg and providing clarification, 103 FERC ¶ 61,274 (2003). NiSource never protested loop flows as part of ComEd joining PJM.

Moreover, on May 2, 2005, NiSource filed a complaint in Docket No. ELO5 103, in which it raised the exact same issues as it raised in this proceeding. The complaint proceeding represents an appropriate mechanism for addressing NiSource’s loop flow concerns. The Commission therefore has no need to address NiSource’s allegations in this proceeding.

C. The Impact of the Transaction on Market Based Rates is Not Relevant to this Proceeding

A number of intervenors assert that the merged company will not qualify for market based rates. They argue that the Commission should take into account this fact in evaluating the impact of the Transaction on competition. FirstEnergy at 38-39; Ameren at 18-19; Dominion at 9-10; PJM Industrial Customers’ Coalition at 11.

The Applicants disagree with this assertion regarding their ability to qualify for market based rates. The Applicants plan to make a filing with the Commission in the future analyzing their market power in order to justify charging market based rates. They fully expect that they will satisfy the standards established by the Commission.

That issue, however, is not relevant for the Commission’s consideration of the Transaction. The Commission’s Merger Regulations and Order No. 642 make clear that the Commission applies its Appendix A HHI analysis to proposed mergers, not its market based rate analysis. The Commission therefore need not consider this issue at this time, but can address it when the Applicants make their updated market based rate filing.

D. Dowogiac’s Rate Issue is Not Relevant to this Proceeding

Dowogiac’s protest relates entirely to its rate treatment under provisions relating to ComEd’s transition to membership in PJM and the replacement charges for through-and-out transmission rates for certain PJM and Midwest ISO transactions that are being

litigated in Docket No. EL02-111. Dowogiac makes no claim that any of its issues relate to the proposed Transaction, and its only effort to link its protest to the Transaction in any respect is that Exelon made certain rate commitments to Dowogiac in the merger of PECO and Unicom, and that “the history of how Exelon has treated other merger related assurances presents reason to fear that Exelon’s committing to them, they will not in fact happen.” Dowogiac at 3.

Exelon strongly disputes Dowogiac’s one sided version of the dispute. However, this is not the forum for resolving that dispute. Instead, Dowogiac should pursue its claims in Docket No. EL02-111 or some other proceeding intended to address the question of transition charges to replace through-and-out transmission rates.

CONCLUSION

The Applicants have adhered faithfully to the Commission’s policies, and have responded responsibly and liberally to the contentions of the intervenors, addressing all legitimate concerns and significantly expanding their divestiture commitments to obviate

any plausible opposing position. The Applicants respect that the Commission promptly approve the Transaction without conducting an evidentiary hearing.

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
R. Edwin Selover		(202) 371-7000
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		101 Constitution Avenue, N.W.

		Suite 400 East
Counsel for		Washington, DC 20001
Public Service Enterprise Group
Incorporated		Counsel for
		Exelon Corporation
May 9, 2005

CERTIFICATE OF SERVICE

Pursuant to Rule 2010 of the Commission’s Rules of Practice and Procedure, I hereby certify that I have this day served the foregoing document upon each person designated on the service list compiled by the Secretary in this proceeding.

Dated May 9, 2005, at Washington, D.C.


		/s/ Matthew W. S. Estes

		Matthew W.S. Estes
		Skadden, Arps, Slate,
		Meagher & Flom LLP
		1440 New York Avenue, N.W.
		Washington, DC 20005
		(202) 371-7227

Appendix 1

Transmission Projects Being Funded by the Applicants

Exelon



	In-Service
Description	Date		Cost Estimate (Sk)
Install Silver Lake — Pleasant Valley 345 kV and Pleasant Valley 345/138 kV		2005	$	13,867
Re-conductor Des Plaines — Howard 138 kV		2005	$	1,581
Install auto-close scheme at Waukegan		2005	$	50
Reconductor 500 ft section of Electric Junction –North Auroral38 kV		2005	$	429
Install 161 MVAR capacitor bank on 230kV bus at North Wales.		2005	$	1,610
Circuit Breaker Upgrades: Whitpain, Island Road		2006	$	200
Eliminate delayed tripping on 138kV cable circuit 1318 at Fisk Station 11.		2005	$	1,556
Upgrade 138kV lines 15912/13 between Northbrook TSS 159 and Northbrook TDC 212.		2005	$	1,993
Circuit Breaker Upgrades at Lombard.		2005	$	824
Circuit Breaker Upgrade at Rock Falls		2005	$	504
Install approximately 144 Mvar of shunt capacitor banks.		2005	$	4,176
Revise protection scheme on 138kV line 17713 and move reclosing on 138kV line 17712 to Chicago Heights.		2005	$	30
Install high speed sectionalizing to trip bus-tie 1-2 at Blue Island TSS 76 for faults on 138kV line 7611.		2005	$	50
Replace Peach Bottom CB		2006	$	750
Circuit Breaker Upgrades: Cromby, Chichester		2006	$	200
Install new Grenshaw TSS 197 138kV ring bus.		2006	$	28,000



	In-Service
Description	Date		Cost Estimate (Sk)
Install a protection scheme at Wayne TSS 144 to automatically restore 345kV buses 6 and 9 for 345kV line 11126 and 14401 contingencies.		2006	$	200
Increase capacity of 138kV line 15623 from Cherry Valley TSS 156 to Alpine TSS 160 tap.		2006	$	4,600
Install 1st 345/138kV autotransformer at East Frankfort TSS 66.		2006	$	10,600
Install protection scheme to auto-close 345kV R-B bus-tie at Elwood TSS 900 for an outage of 345kV line ll622.		2006	$	100
Install a protection scheme to automatically close the 138kV R-B bus-tie circuit breaker at Dresden Station 12 for an outage of Tr. 83 at Dresden.		2006	$	100
Increase capacity of Wolfs-Oswego 138kV line 14302.		2006	$	2,000
Reconfigure TSS 108 Lockport 345kV bus to relocate line 10804 from bus 1 to bus 6.		2006	$	300
Install a 2nd circuit breaker in series with 138kV bus-tie circuit breaker 1-2 at TSS 135 Elmhurst.		2006	$	1,500
Upgrade the following circuit breakers for short circuit interrupting capability: 15507, 15508 CB’s at TSS 107 Dixon		2006	$	850
Install approximately 150 Mvar of shunt capacitor banks.		2006	$	4,300
Upgrade 138kV Line 11110 between Electric Junction TSS 111 and the Warrenville Tap		2006	$	905
Install 138kV substation at West Loop TSS 148.		2007	$	47,000
Install 345kV transmission lines and two autotransformers at West Loop TSS 148.		2008	$	191,000
Total Exelon Projects:			$	319,275

PSE&G



	In-Service
Description	Date		Cost Estimate (Sk)
Add 150 MVAR capacitor at Aldene 230 kV		2005	$	1,500
Add 150 MVAR capacitor at Camden 230 kV		2005	$	1,500
Add Special Protection Scheme at Bridgewater to automatically open 230 kV breaker for outage of Branchburg - Deans 500 kV and Deans 500/230 kV #1 transformer		2005	$	100
Bypass the Essex 138 kV series reactors		2005	$	500
Install third Branchburg 500/230 kV transformer		2005	$	15,000
Install two breakers at lake Nelson 230KV		2005	$	5,200
Replace six (6) overstressed Circuit Breakers		2005	$	2,000
Replace terminal equipment to increase Brunswick - Adams -Bennetts Lane 230 kV to conductor rating		2005	$	500
Replace wavetrap on Branchburg — Flagtown 230 kV		2005	$	500
Build new Essex — Aldene 230 kV cable connected through a phase angle regulator at Essex		2006	$	60,000
Replace six (6) overstressed Circuit Breakers		2006	$	2,000
Replace thirteen transmission class transformers and associated equipment		2006	$	18,800
Replace wavetrap on Flagtown — Somerville 230 kV		2006	$	500
Upgrade Deans 230 kV breaker #1-5		2006	$	100
Upgrade Deans 230 kV breaker #1-7		2006	$	100
Upgrade Deans 230 kV breaker #1-9		2006	$	100


Upgrade Deans 230 kV breaker #7-8	2006	$	100
Add 100MVAR capacitor at West Orange 138kV substation	2007	$	1,500
Close the Sunnymeade “C” and “F” bus tie	2007	$	5,000
Install 230/138kV transformer at Metuchen substation	2007	$	10,000
Make the Bayonne reactor permanent installation	2007	$	5,000
Reconductor Kittatinny — Newton 230 kV with 1590 ACSS and replace wavetrap at Newton	2007	$	30,000
Replace all de-rated Branchburg 500/230 kV transformers	2007	$	60,000
Replace all de-rated New Freedom 500/230 kV transformers and build transfer bus	2007	$	15,100
Replace six (6) overstressed Circuit Breakers	2007	$	2,000
Upgrade the Edison — Meadow Rd 138kV “Q” circuit	2007	$	2,000
Upgrade the Edison — Meadow Rd 138kV “R” circuit	2007	$	2,000
Reconductor 605 ft of the Kearny-Turnpike “D” 138 KV circuit	2008	$	200
Loop the W-1323 line into the Bayway 138 KV bus	2008	$	10,000
Relocate the X-2250 circuit at Hudson	2008	$	5,000
Replace six (6) overstressed Circuit Breakers	2008	$	2,000
Total PSEG Projects:		$	258,300

Appendix 2

Mitigation-Eligible Units

Summer

Economic

Economic <

Between $25

Between $55

Between $80

$25

and $55/MWh

and $80/MWh

and $250/MWh

Unit

Type

PJM East

Conowingo

512

Yards Creek

200

Eddystone 1-2

579

Cromby 1

144

Hudson 2

608

Mercer 1-2

648

Bergen, 1ST, 1SC, 1CC

1,225

Linden CC

1,218

Bergen 3

Sewaren 1-4

453

Hudson 1

383

Kearny 7-8

300

Pennsbury 1-2

Cromby 2

201

Kearny (PSEG)

134

Burlington (PSEG)

168

Eddystone 3-4

760

Essex

Linden 7-8

156

Edison

168

Fairless Hills

Cromby IC1

IC1

Delaware 1

Schuylkill 1, 10-11, IC1

ST, GT IC1

199

Croydon

384

Essex 10, 11, 12

536

Edison

336

Richmond

Kearny 9, 10, 12

330

National Park

Falls

Moser

Delaware 9-12

Eddystone 10-40

Southwark 3-6

Chester 7-9

Burlington 8-11

389

Summer

Economic

Economic <

Between $25

Between $55

Between $80

$25

and $55/MWh

and $80/MWh

and $250/MWh

Unit

Type

Bayonne 1-2

Sewaren 6

129

Mercer 3

129

Linden 5,6

160

Sub-Total

11,091

512

4,622

2,831

3,126

PJM Pre-2004 (*)

Muddy Run

1,070

Keystone 1-2

738

Keystone

Conemaugh 1-2

732

Conemaugh

Sub-Total

2,549

—

2,540

—

Note: Units are economic within 105% of market price.

(*) Reflects combined interest of Exelon and PSEG in Keystone and Conemaugh.


	C.	The Impact of the Transaction on Market-Based Rates is Not Relevant to this Proceeding	77

	D.	Dowogiac’s Rate Issue is Not Relevant to this Proceeding	77

CONCLUSION			78

	*(1)*	*Elimination of Limits on Purchasers.* The Applicants propose to drop the limits on which entities may purchase generation, other than that no single entity may purchase more than 50% of the virtual divestiture amount. In order to assure the Commission that divestiture without specified limits will not lead to screen violations, the Applicants commit to make a compliance filing upon completion of their divestiture to demonstrate that the actual divestitures will not cause material screen failures.

	*(2)*	*Structural Safeguards for Virtual Divestiture.* In response to concerns that the virtual divestiture of nuclear generation is not a structural remedy and will be difficult to monitor, the Applicants propose to implement additional measures that will add transparency to the auction process, provide more structure and make it easier for the Commission to monitor compliance. In particular, the Applicants will provide for the establishment of a publicly available web page that will detail exactly how the Applicants are complying with their virtual divestiture commitment and their compliance with their other interim and long-term mitigation requirements. The Applicants will put a link to this web page on the PJM OASIS, which will make it readily available to the public.

	*(3)*	*Additional Mitigation in Capacity Markets.* In response to complaints that the Applicants will retain an ability to exercise market power in the capacity markets, the Applicants commit to bidding their entire net capacity position into the daily capacity market operated by PJM at a price of zero. This commitment will last until PJM implements its as-yet not finalized changes to its capacity markets, at which time, as the Applicants already have committed, they will submit a mitigation plan to the Commission that is tailored to the specifics of the new capacity markets.

	*(4)*	*Reduction in Time for Divestiture.* In response to criticisms that the 18-month time period proposed for divestiture is too long, the Applicants will commit to having executed sales agreements and making filings at the Commission for the approval of the sales no later than one year after the closing of the Transaction.

	*(5)*	*Transmission Upgrades.* Finally, the Applicants recognize that strengthening the transmission system within PJM will improve the viability of PJM’s markets. The Applicants therefore commit to: (1) accelerate certain transmission upgrades and make certain new transmission upgrades on their own system regardless of whether the Transaction is approved; and (2) fund transmission upgrades

	•	Northern New Jersey, see Kalt at 30; PEPCO at 31-32;

	•	PJM Classic, see Kalt at 28-30;

	•	The “Rest of” PJM Pre-2004 (PJM Pre-2004 with PJM East excised), see Fox-Penner/Pfeifenberger at 18-19;

	•	“PJM West” (the portion of PJM that is west of PJM Pre-2004), see Fox-Penner/Pfeifenberger at 20-21.

•	PSE&G will replace three 500/230kV autotransformer banks – two at Branchburg in Northern New Jersey and one at New Freedom in Southern New Jersey. All of these projects will increase import capability as well as reducing congestion. The derated transformers are scheduled to be replaced by summer 2007. The new transformer banks will have a summer normal rating of approximately 900 MVA each. The PJM published estimate of unhedged congestion associated with Branchburg is almost $200 Million/year.

•	PSE&G will install a new nineteen (19) mile 230kV high voltage underground cable from Essex to Aldene in Northern New Jersey, which will also include a new 700 MVA, 230 kV phase angle regulator (PAR) and a 100 MVAr shunt reactor for service by the end of 2006. This project provides additional transfer capability into the constrained Northern PSE&G zone and satisfies multiple other reliability based criteria. The PAR will also allow mitigation of congestion on the Roseland to Athenia transmission corridor.²⁴

•	Exelon will install a new 9.7 mile 345kV line between the existing Silver Lake substation and a new transmission substation (TSS) at Pleasant Valley in the northern part of the ComEd system prior to June 1, 2005. This project, which also includes installation of a new 345/138kV autotransformer at Pleasant Valley, will prevent overloads in the northern part of the ComEd system under contingency conditions, thus enhancing reliability and reducing congestion. The project also will provide voltage support for the northern area of the ComEd system and minimize the risk of voltage collapse during extreme contingency conditions.

•	Exelon will install two major 345kV lines connecting three substations south of the Chicago central business district in 2008.²⁵These lines will connect Crawford Station, the new West Loop TSS and Taylor TSS providing 345kV service to West Loop TSS and networking the 345kV system that now is radial into the southern part of Chicago. These transmission lines will not only provide increased reliability and flexibility but will provide the infrastructure to reduce the timeline to build additional transmission reinforcements in the event of retirement

	The two transmission projects that the Applicants are committing to are as follows:

•	Advancement of the replacement of two Branchburg 500/230kV autotransformers prior to the summer of 2006: As stated above, the RTEP requires PSE&G to replace those transformers prior to the summer of 2007. PSE&G has advanced the order of the necessary equipment, and, subject to timely delivery of the new transformers and obtaining the necessary transmission outages to perform the installation, PSE&G will voluntarily advance the replacement of these transformers.

•	Reconductor the North Wales to Whitpain 230kV line: PJM shows unhedgeable congestion of $2.7 million due to this line.²⁶Exelon will either reconductor this line or eliminate the congestion due to a project that will reduce loadings on this line in 2009.