EX-99.8 9 ex998.txt PACE TESTIMONY Exhibit PC-1 UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION ------------------------------------------------ ) Potomac Electric Power Company ) Docket No. EC01-___-000 Conectiv ) ------------------------------------------------ PREPARED DIRECT TESTIMONY OF JOE D. PACE I. Introduction Q. Please state your name and business address. A. My name is Joe D. Pace. My business address is 1600 M Street, N.W., Suite 700, Washington, D.C. 20036. Q. What is your occupation? A. I am an economist and a director of LECG, LLC. LECG is a firm providing expert analysis, litigation support and management consulting in economics, accounting and finance. Q. Please summarize your education and professional background. A. I received my bachelor's degree from the College of William and Mary in 1966 and my master's and doctoral degrees from the University of Michigan in 1967 and 1970, respectively. I specialized in the areas of industrial organization and public utility economics. While completing the requirements for my doctorate, I taught economics at the University of Michigan and served as an assistant planner with the Washtenaw County Planning Commission in Ann Arbor, Michigan. I joined National Economic Research Associates, Inc. ("NERA") in February of 1970. I became a vice president of NERA in 1973, a senior vice president in 1979, and executive vice president in May 1988. As executive vice president, I had overall responsibility for NERA's electric and gas utility consulting practice. I left NERA and joined the firm of Putnam, Hayes & Bartlett, Inc. ("PHB") as a managing director in September 1990. I assumed my present position in February of 1995. During my consulting career, I have directed projects involving a broad range of economic issues in the electric utility industry, in other regulated industries, and in unregulated industries as diverse as automobiles, computers, inertial navigation systems and textile machines. My professional background and experience are described more fully in Exhibit PC-2. Q. Have you previously testified as an expert witness? A. Yes. In numerous cases, I have previously submitted affidavits or presented testimony before the Federal Energy Regulatory Commission ("FERC" or "the Commission") addressing market power issues in the electric utility industry. This testimony has been presented in a number of different contexts, including applications for market-based pricing in traditional wholesale markets as well as in a restructured industry environment, horizontal mergers between electric utilities, and convergence mergers between electric and gas utilities. I also have testified on other issues involving the electric utility industry before the FERC, as well as before many state regulatory commissions, the United States Senate, the United States House of Representatives and the High Court of New Zealand. In addition, I have presented testimony in a number of federal and state court proceedings involving electric utilities, and other regulated and unregulated industries. Exhibit PC-2 identifies my prior testimony. Q. What is the purpose of your testimony in this case? A. I have been asked by Potomac Electric Power Company ("PEPCO") and Conectiv (collectively, "Applicants") to assess the potential competitive implications of their proposed merger (the "Merger"). Q. What analysis have you undertaken in order to provide this assessment? A. I have prepared an analysis of the horizontal and vertical market implications of the Merger consistent with the analytical framework outlined in the Commission's 1996 Merger Policy Statement and its recently issued Final Rule on merger analysis. I address energy, installed capacity and ancillary service product markets; and four relevant geographic or destination markets - - the PJM Interconnection L.L.C. ("PJM") region, as well as three sub-regions reflecting internal PJM transmission constraints. Market shares and HHIs are calculated for total capacity for the summer of 2002; and for economic and available economic capacity for the summer of 2002 and the winter of 2002-03 (the first full peak seasons after the expected closing date of the Merger). Uncommitted capacity market shares and concentration measures are not calculated because Conectiv is not forecast to have any uncommitted capacity in the pre-merger case. Ancillary service markets are reviewed briefly, since PEPCO has a de minimis ability to provide those services, and thus is not a significant actual or potential competitor in those markets. Potential barriers to entry into the generation business and vertical effects on competition also are addressed. Finally, retail markets for competitively supplied electricity, natural gas and energy management services are examined. II. Summary of Conclusions Q. Please summarize your conclusions regarding the likely competitive effects of the proposed PEPCO/Conectiv Merger. A. I conclude that the Merger will not adversely affect competition in any relevant market. This conclusion is based on the following considerations. 1. PEPCO has by and large exited the generation business, having divested almost 90 percent of its generation resources. It retains ownership through a subsidiary of only 806 MW of generation capacity in the PJM Interconnection, L.C.C. ("PJM") area, which amounts to only about 1.3 percent of the conservatively estimated 63,797 MW of total capacity expected to be in-service in PJM by the summer of 2002./1 Moreover, the PEPCO capacity is old, has relatively high energy production costs and very limited ancillary service capabilities, and has operated in the last two years at average annual capacity factors of only 3.0 percent (Benning Road) and 0.9 percent (Buzzard Point). As new more efficient capacity is added in PJM, the utilization of these two plants can be expected to decline even further below these low levels. During those relatively few hours when PEPCO's capacity is likely to be economic in the future, so too will be virtually all other capacity in PJM. -------- 1 Unless otherwise stated, all capacity figures cited throughout my testimony are based on summer ratings. Also, capacity owned by any PEPCO or Conectiv affiliate or subsidiary is attributed to the parent company. -------- 2. PEPCO has entered into transition purchase agreements ("TPAs") with Mirant, which acquired most of the generation resources divested by PEPCO. But the TPAs do not give PEPCO any control over the divested resources, or provide it with any capacity or energy that can be sold in competitive generation markets. While PEPCO retains the legal obligation to provide retail standard offer or default service, the TPAs transfer the power supply requirement supporting that obligation to Mirant. The TPAs do not give PEPCO, which is an all requirements customer of Mirant, any ability to limit the output of Mirant-owned or-contracted generation resources, or any ability to profit from those resources regardless of what happens to competitive wholesale or retail market prices. Thus, consistent with Order No. 642, the resources used by Mirant to meet its TPA obligations should not be, and are not, assigned to PEPCO. 3. Conectiv already has divested 331 MW of baseload generation capacity owned by its subsidiaries and it has signed contracts to sell an additional 2202 MW of capacity. If the divestiture program is completed as now contemplated, Conectiv will retain only 1,974 MW of existing generation resources in PJM, which will be held by merchant generation subsidiaries. In addition to this, Conectiv expects to bring 904 MW of capacity on-line at two new combined cycle plants by the summer of 2002. Also, at the completion of the divestiture program, Conectiv's subsidiaries, Atlantic City Electric Company ("ACE"), Delmarva Power & Light Company ("Delmarva") and Conectiv Energy Services, Inc. ("CESI"), will have "long-term" power purchase contracts for 2,688 MW of capacity and up to 2,437 MW of energy resources. However, contracts for 1,934 MW of that capacity and up to 1,150 MW of energy will expire within a year of the time the Merger is expected to be completed. Furthermore, the power purchase contracts covering most of this capacity and energy will give Conectiv no control over the dispatch or operation of the generation resources supporting those contracts. Nevertheless, if all the purchased generation is conservatively attributed to Conectiv, in the "completed divestiture" scenario, Conectiv will have 5,566 MW of capacity and 5,315 MW of energy resources in PJM by the summer of 2002, and this figure will decline substantially thereafter, unless expiring contracts are replaced by additional new capacity construction or long-term power purchase contracts. In this scenario, the Conectiv capacity will amount to only 8.7 percent of forecast PJM total capacity in the summer of 2002. 4. If none of Conectiv's plans for further generation divestiture go through, it will continue to own 4,176 MW of existing generation resources; it plans to bring a total of 904 MW of new capacity on-line by the summer of 2002 as discussed above; and it will have "long-term" contracts for 2,246 MW of capacity and 1,537 MW of energy (although contracts for 1,492 MW of that capacity and up to 750 MW of that energy will expire by the end of February 2003). In this "no further divestiture" scenario, therefore, again assuming that all the purchased generation is attributed to Conectiv, it will have 7,326 MW of capacity resources and 6,617 MW of energy resources in PJM by the summer of 2002. In this case, Conectiv's capacity will amount to 11.5 percent of forecast PJM total capacity in the summer of 2002. 5. The combination of a PEPCO market share of 1.3 percent of relatively uneconomic capacity, and a Conectiv market share even in the "no further divestiture" scenario of 11.5 percent, results in a change in the Herfindahl-Hirschman Index ("HHI") attributable to the Merger of less than 30 points (which is equal to two times the product of the pre-Merger PEPCO and Conectiv market shares). Given that the PJM market is only very moderately concentrated (see Exhibits PC-7 and PC-8), this HHI change falls well within the FERC's screening guidelines safe harbor zone. 6. The competitive significance of the Merger is still further reduced by the fact that, even if Conectiv ends up divesting no additional capacity, its owned and purchased generation resources will be very heavily committed to meeting its retail standard offer or default service obligations during the next several years, especially during high load hours when PEPCO's generation resources may be economic. Indeed, to help meet these obligations, ACE has recently made two large capacity credit purchases. By the time the ACE and Delmarva retail default obligations are scheduled to terminate, a number of the power purchase contracts will have expired and other suppliers will have added another 8,000 MW of new capacity in PJM, substantially diminishing the relative significance of Conectiv's remaining holdings. Utilities such as Conectiv that have most or all of their generation resources dedicated to meeting retail load obligations at fixed prices have no financial incentive to withhold capacity and attempt to raise market prices. 7. Since it cannot be certain when Conectiv's divestiture plans will be completed, my detailed analysis of the Merger's likely impact on competition is based on the "no further divestiture" scenario. However, in this case, it should be apparent that if the Merger passes the competitive screening test in the "no further divestiture" scenario, it will do so in the "divestiture completed" scenario. In any event, for completeness, the "divestiture completed" market share and concentration calculations are presented in Appendix 1 to my testimony. 8. My analysis of total capacity in PJM is discussed in Section V of my testimony and summarized in Exhibit PC-7. As indicated there, the total capacity HHI is under 1,100 and the change attributable to the proposed merger is under 30 points. 9. The "Appendix A" analysis - - that is, the delivered economic and available economic capacity analysis, covering all relevant seasons and load periods, including imported supplies, recognizing internal transmission limits within PJM, and examining different fuel price scenarios - - is summarized in Exhibits PC-8 and PC-9. As Exhibit PC-8 shows, for economic capacity there are no violations of the Commission's screening guidelines. For the PJM market, the HHI never exceeds 1,014 and the change attributable to the proposed merger never exceeds 23 points. For the most constrained PJM sub-region (the east sub-region), most of the HHIs are below 1,700 and the change attributable to the proposed merger never exceeds 10 points. The available economic capacity analysis, summarized in Exhibit PC-9, similarly reveals that there are no screening violations. This is true because during the limited number of summer and winter peak hours when PEPCO's capacity is economic, Conectiv has relatively little available economic capacity. 10. A separate detailed analysis of ancillary service markets is not needed in this case to support the conclusion that the Merger will have no anti-competitive effects on those markets. Energy imbalance service is provided as part of the PJM energy spot market and need not be separately analyzed. Neither of the two PEPCO-owned plants has the capability to provide regulation service, so there is no need to address actual or potential markets for that ancillary service. Due to high costs, the slow response times of the Benning Road units, and other operating constraints, the generation owned by PEPCO is not anticipated to supply more than de minimis amounts of spinning or non-spinning (primary or secondary) reserves. Therefore, the Merger will have no material effect on the PJM markets for these services. 11. The Merger raises no barrier to entry or vertical market power concerns. The very substantial amount of new generation development currently underway in PJM provides the best evidence of the lack of significant barriers to entry into that market. Moreover, a specific examination of the Applicants' situation shows that they do not control any key inputs that could be used to impede competition in "downstream" generation markets. 12. The Merger will not adversely affect competition in any retail gas or electricity market. While PEPCO's unregulated subsidiary, PEPCO Energy Services, Inc. ("PESI") actively markets those services throughout the mid-Atlantic region (and markets retail natural gas to large commercial and industrial customers over a wider area ranging from New York to Florida), it still is a relatively small player, particularly outside its local territory. Even more significantly, however, prior to agreeing to the Merger, Conectiv discontinued its efforts to participate in markets for competitive retail electricity and gas service. Thus, PEPCO and Conectiv are not rivals for providing these services and the Merger cannot have a material effect on competition at the retail level. III. Description of the Applicants Q. Please provide an overview of PEPCO's energy-related business. A. PEPCO is a regulated electric utility providing transmission and distribution, and standard offer or default service, to approximately 700,000 customers located in Washington, D.C. and major portions of Prince George's and Montgomery counties in Maryland. In 2000, PEPCO's peak load was 5,721 MW and it sold 24,561 GWh to ultimate customers. PEPCO's transmission facilities are interconnected with Virginia Power, Allegheny Power and PJM. PEPCO, along with other PJM participants, shares three 500 kV interconnections with Allegheny Energy and a second 500 kV interconnection with Consolidated Edison of New York. PEPCO has successfully completed its generation divestiture plan. On December 19, 2000, it sold 5,154 MW of generating assets to Mirant Corp. (formerly Southern Energy, Inc.) consisting of the following power plants: Chalk Point (2,423 MW), Dickerson (837 MW), Morgantown (1,412 MW) and Potomac River (482 MW). Mirant also entered into back-to-back contracts with respect to PEPCO's purchased power contracts with FirstEnergy Corp. (450 MW of capacity and associated energy through 2005) and Panda-Brandywine, LP (230 MW through 2022). In addition, in January, 2001, PEPCO sold its 9.7 percent interest in the Conemaugh generating station (166 MW) to Allegheny Energy, Inc. and PPL Corporation. Q. What generation resources does PEPCO still own in the PJM area? A. PEPCO still owns the Benning Road and Buzzard Point stations, which were transferred to its unregulated subsidiary Potomac Power Resources Inc. ("Potomac Resources") in December 2000. Both stations are operated and maintained by Mirant pursuant to a three-year contract with Potomac Resources. The Benning Road plant has two 275 MW steam turbines placed in service in the 1950's and it burns No. 4 oil. In 1999, its average heat rate was 13,741 Btu/kWh, it was connected to load only 946 hours and it operated at a capacity factor of only 4.2 percent. In 2000, the Benning Road plant's average heat rate was 16,157 Btu/kWh, it was connected to load only 726 hours and it operated at a capacity factor of only 1.8 percent. At current oil prices, the Benning Road plant is dispatched at about $65/MWh. Due primarily to District of Columbia air quality restrictions, the Benning Road units have severe operational constraints and slow unit response rates that prevent them from being qualified as regulation capable. They are not started to provide spinning reserves and, in any event, because of their slow ramp rate (2 MW per minute), can provide at most 20 MW of spinning reserves each. Beyond this, Benning Road's start-up time is too slow for it to provide non-spinning reserves. The Buzzard Point plant consists of 16 units of 16.5 MW each (for a total of 256 MW) that burn No. 2 oil. In 1999, the plant's average heat rate was 18,833 Btu/kWh, it was connected to load only 242 hours and it operated at a capacity factor of only 1.2 percent. In 2000, the Buzzard Point plant's average heat rate was 20,614 Btu/kWh, it was connected to load only 114 hours and it operated at a capacity factor of only 0.8 percent. At current oil prices, the Buzzard Point plant is dispatched at about $90/MWh. The Buzzard Point units are not qualified as regulation capable. They normally operate at full load when they are on-line and thus do not provide spinning reserves. Q. Does PEPCO own or control any generation resources in the United States outside of PJM? A. None of any significance. Through subsidiaries, it owns 50 percent of a 2 MW run-of-the-river hydroelectric plant in New York whose output is sold under a long-term contract, as well as minority interests in five solar generation units in California (with a total of 150 MW of capacity), whose output also is sold under a long-term contract. Q. What is the state of retail competition in PEPCO's service area? A. Retail competition has been introduced both in PEPCO's Maryland and District of Columbia service territories. Customer choice began for all Maryland customers on July 1, 2000 and for all District of Columbia customers on January 1, 2001. As part of the restructuring agreements, PEPCO's retail rates have been reduced by 4 to 7 percent, and it is obligated to be the default service provider through June 2004 and January 2005, respectively, for Maryland and District of Columbia customers not selecting a competitive supplier. Q. How does PEPCO meet its retail default service power supply obligations? A. PEPCO is meeting this obligation by way of two Transition Power Agreements ("TPAs") with Mirant. While PEPCO remains the "load serving entity" for regulatory and PJM purposes, the TPAs require Mirant to supply full requirements capacity and ancillary services to meet PEPCO's default service obligations in Maryland through June 2004 and in the District of Columbia through January 2005. PEPCO is required to purchase 100 percent of its default service energy requirements from Mirant in year one and at least 75 percent of its default service energy requirements in year two. PEPCO has the option to take up to 100 percent of its default service energy requirements from Mirant in years two through four and, given the relatively low fixed energy prices contained in the TPAs, it is virtually certain to do so absent a presently unforeseeable reduction in PJM energy prices. In essence, the TPAs transfer the power supply responsibilities associated with PEPCO's default service obligations to Mirant. Mirant is free to use any owned or purchased network and non-firm generation resources it chooses to meet its TPA obligations, and at any given moment, PEPCO does not even know what resources Mirant is using to meet its loads. The TPAs do not give PEPCO access to any capacity or energy resources for any purpose other than meeting its default service requirements. Q. What unregulated energy-related businesses does PEPCO engage in? A. PEPCO provides diversified competitive retail energy services through its wholly owned unregulated indirect subsidiary PESI. PESI currently provides unregulated energy and energy-related products and services throughout the mid-Atlantic region and beyond. Its products include electricity, natural gas, energy-efficiency contracting, equipment operation and maintenance, fuel management and appliance warranties. PESI covers its retail sales of gas and electricity with matching wholesale commodity contracts purchased in the market. PESI also has contracted to supply full requirements service to the Southern Maryland Electric Cooperative ("SMECO"), which has a peak load of approximately 600 MW, for the years 2001 through 2004. Q. How does PESI supply SMECO's power requirements? A. Merrill Lynch Capital Services is contractually obligated to PESI to meet SMECO's full requirements at fixed prices for the duration of the SMECO contract. In this case, PESI effectively "flipped" the power supply obligation to Merrill Lynch. PEPCO does not own or control any generation resources as a result of this transaction. Q. Have you included the PEPCO TPAs with Mirant and the two SMECO contracts among your exhibits? A. Yes. The four contracts are attached as Exhibits PC-10 through PC-13. Q. Turning now to Conectiv, please provide an overview of its energy-related business. A. Conectiv is a registered public utility holding company formed on March 1, 1998 as a result of the merger involving Delmarva and Atlantic Energy, Inc. (the parent of ACE). Delmarva provides electric utility service to approximately 480,000 electric customers in Delaware, Maryland and Virginia, and natural gas service to approximately 109,000 customers in northern Delaware. ACE serves approximately 500,000 electric customers in southern New Jersey. In 2000, the Delmarva peak load was 3,226 MW, the ACE peak load was 2,329 MW, and the two companies sold 22,004 GWh of electricity to ultimate customers. Both Delmarva and ACE own transmission facilities interconnected to PJM and have rights to use the 500 kV lines within PJM under various operating agreements. Delmarva's gas distribution facilities supply only the northern part of New Castle county in Delaware. They do not serve any electric generator and no potential electric generator has requested a connection to the Delmarva gas distribution system. CESI, a wholly-owned subsidiary of Conectiv, owns and has rights to use 90 percent of one 7 mile long intrastate pipeline running to the Hay Road and Edgemoor plant sites. CESI's gas transportation capacity is expected to be taken up by the new generation capacity now being developed by Conectiv at those sites. Delmarva owns and has rights to use the other 10 percent of this pipeline for utility purposes. Conectiv now owns 4,176 MW of generation capacity in PJM but it is in the process of divesting a substantial portion of that capacity. In December 2000, Delmarva sold its interests in its nuclear generating stations (Peach Bottom and Salem, totaling 331 MW) to PSEG Power LLC and PECO Energy Company (now part of Exelon). ACE has contracted to sell its interests in those two plants, along with its entitlement in Hope Creek (383 MW in total) to the same buyers, but this sale has been delayed pending receipt of all necessary approvals from the New Jersey Board of Public Utilities ("NJBPU"). Conectiv also has agreed to sell to NRG Energy 1,819 MW of fossil-fueled capacity consisting of the following plants: BL England (447 MW), Deepwater (185 MW), Indian River (784 MW) and Vienna (170 MW), as well as Conectiv's interest in Conemaugh and Keystone (233 MW). The sale of generation to NRG is also delayed pending receipt of all necessary approvals from the NJBPU. Assuming that approval is granted and the asset sales are closed, Conectiv will retain 1,974 MW of its existing generation capacity. The generation assets Conectiv plans to retain have been transferred by ACE and Delmarva to Conectiv Atlantic Generation Company, L.L.C. and Conectiv Delmarva Generation Inc. Q. Does Conectiv have operational control over all the PJM capacity that it owns? A. No. It owns minority interests (under 8 percent shares) in a number of units that account for 616 MW of its generation capacity. Clearly, it has no operational control over these resources but I have nevertheless attributed this capacity to Conectiv. A Conectiv subsidiary also owns 50 percent of the 47 MW Vineland unit which has been sold to the Vineland municipal utility through 2019. My analysis attributes that capacity to Vineland and it is not included in the Conectiv generation resource numbers discussed above. Q. What long-term purchased power arrangements do ACE and Delmarva have? A. ACE has contracts for 1,571 MW of capacity and up to 866 MW of energy that have a term of one year or longer, and extend at least to the summer of 2002. The sellers are: Merrill Lynch Capital Services (221 MW of capacity/2 and up to 400 MW of on-peak energy through July 2002); Reliant Energy (442 MW of capacity through September 2002); Allegheny Energy (442 MW of capacity through September 2002); Delmarva Resource Management (75 MW of capacity and energy through August 2016); Chambers Cogeneration (188 MW of capacity and energy through March 2024); and Logan Generating Company (203 MW of capacity and energy through December 2024). Only the Chambers and Logan contracts are dispatchable by ACE. In addition, contingent upon the asset sale to NRG, ACE will purchase 442 MW of capacity and around-the-clock energy from NRG through August 2002. Delmarva and CESI have power purchase contracts with a term of one year or longer that provide up to 675 MW of capacity and up to 671 MW of energy. The sellers are Philadelphia Electric Company ("PECO") (one contract for delivery of 387 MW of capacity and up to 350 MW of energy through February 2003, and another contract for 269 MW to 308 MW of capacity and 206 MW to 237 MW of energy through May 2006) and Dynergy (100 MW of firm energy through 2005). Only the 387 MW contract with PECO allows any energy scheduling flexibility, and that is limited by substantial minimum take and month-ahead scheduling requirements. In addition, contingent upon the asset sale to NRG, Conectiv will purchase 500 MW of firm around-the-clock energy from NRG through 2005. In total, therefore, as of the summer of 2002, Conectiv will have purchased power contracts with a term of one year or longer totaling 2,246 MW of capacity and up to 1,537 MW of energy without the asset sale to NRG; and 2,688 MW of capacity and up to 2,437 MW of energy if and when the NRG sale is completed. -------- 2 In a number of cases, actual contract values are stated in terms of MW of "unforced capacity", which is capacity after allowance for forced outages. Unforced capacity quantities are divided by 1.0 minus the PJM average forced outage rate of 9.58 percent to convert them into an installed capacity equivalents, which are the capacity measures cited throughout my testimony. -------- It is important to recognize that a number of the contracts identified above expire within a year or less of the anticipated Merger closing date. Order 642 calls for a reasoned analysis of how to treat purchased power contracts and, in my judgement, a forward looking analysis of post-Merger market conditions should accord little if any significance to contracts expiring shortly after the anticipated Merger closing date. Nevertheless, to be conservative, I have included those contracts in my analysis. My analysis also attributes all the purchased capacity and energy resources to Conectiv even though it does not have any dispatch control over most of it. Q. Have you prepared an exhibit summarizing the purchased power contract terms discussed in your previous response? A. Yes. Exhibit PC-3 provides that summary. As this exhibit shows, the Conectiv purchased power contracts fall into four categories: (1) contracts for capacity (884 MW) that provide no associated energy; (2) must take contracts (up to 812 MW of energy in the no further divestiture case and 1712 MW in the divestiture completed scenario) that give Conectiv no scheduling flexibility; (3) one contract for up to 350 MW of energy that provides only limited scheduling flexibility on a month-ahead basis; and (4) only two contracts for 391 MW of capacity that are dispatchable. Q. What do you understand Conectiv's plans to be regarding possible development of new generation capacity? A. Conectiv now has one 550 MW combined cycle plant under construction adjacent to the existing Hay Road power plant in Delaware. All of this plant's capacity is expected to be on-line by the beginning of the summer of 2002. A second 550 MW combined cycle plant has been approved by the Conectiv Board of Directors. Construction of this plant has not yet begun (indeed a final site has not been selected), but Conectiv expects to bring on-line 354 MW of simple cycle combustion turbine capacity at this plant by the beginning of summer 2002, with the remaining 186 MW coming on-line a year later. Even though the second plant has not yet begun construction, I have conservatively included its capacity in calculating Conectiv's and the merged company's market shares. Looking further into the future, Conectiv has an additional 15 combustion turbines on order that can be configured into six more 550 MW combined cycle plants. Should Conectiv choose not to build those additional plants, it would then sell its combustion turbine rights and any interests it has in potential development sites. Q. Have you prepared an exhibit summarizing Conectiv's owned and purchased generation resources in PJM in the pre- and post-divestiture cases? A. Yes, that information is provided in PC-4. Q. Does Conectiv own interests in any generation resources in the United States outside PJM? A. Yes, but those holdings are insignificant. Conectiv owns 27.5 percent of a 20 MW hydroelectric unit in Maine whose output is sold under a long term contract. It also owns 50 percent of a 34 MW wood burning plant and a minority interest in a 30 MW solar plant. Both of these plants are located in California and their output is sold under long-term contracts. I should also note that Conectiv owns 50 percent of an 80 MW unit in Pennsylvania that currently is connected to the New York Power Pool. However, this plant is being connected to PJM and I have included it in the Conectiv-owned PJM capacity figures cited above. Q. Please identify the municipal and cooperative utilities located in the general geographic area served by Conectiv. A. There are a number of such entities. Eight municipal utilities located in Delaware (Newark, New Castle, Middletown, Smyrna, Clayton, Milford, Lewes and Seaford), are members of the Delaware Municipal Electric Corporation ("DMEC") that purchase partial requirements service from Delmarva under bundled contracts running through 2003. DMEC also purchases power from Delmarva on behalf of its members. Berlin, Maryland (as of June 1, 2001), Dover, Delaware, Easton, Maryland, and three distribution cooperatives that are members of the Old Dominion Electric Cooperative ("ODEC"), are transmission customers connected to Delmarva's system that provide their own generation and/or procure supplies competitively. Pursuant to a recent agreement, Berlin will begin in June of this year purchasing its full requirements (above its local generation) from CESI at market based rates for a term of two years. Finally, Vineland, New Jersey is a transmission customer connected to ACE's system that self-generates and procures power competitively. Q. What is the state of retail competition in the ACE and Delmarva service areas? A. Retail competition was introduced in ACE's service area beginning on August 1, 1999. Since that date, all ACE customers have been able to choose an alternative electricity provider. As part of the restructuring, ACE's retail rates have already been reduced by 7 percent and a further reduction is scheduled. ACE is obligated to supply default electricity service to customers who do not choose an alternative provider through July 31, 2003. Retail competition was introduced in Delmarva's Delaware service area beginning on October 1, 1999. At that time, Delmarva's Delaware retail residential rates were reduced by about 7.5 percent, and retail customer choice began to be phased in. All Delmarva Delaware customers were permitted to choose an alternative supplier as of October 1, 2000. In Delaware, Delmarva is the default service supplier for customers who do not choose an alternative supplier, and that obligation extends through September 2002 for commercial and industrial customers and September 2003 for residential customers. Delmarva's Maryland customers were given the right to choose an alternative supplier beginning July 1, 2000. At that point, Delmarva's Maryland residential retail rates were reduced by about 7.5 percent. In Maryland, Delmarva is the default supplier for customers who do not choose an alternative supplier and that obligation extends through June 2003 for non-residential customers and through June 2004 for residential customers. In Virginia, Delmarva's retail customers will be eligible for choice as of January 1, 2002. Delmarva's Virginia retail rates have been reduced by about 2 percent with further reductions scheduled at the closing of its fossil-fuel plant sale to NRG. After that time, its Virginia retail rates will be frozen until 2004. Delmarva's default supplier obligation in Virginia extends to at least January 1, 2004. Q. How does Conectiv plan to meet its retail default service obligations? A. Conectiv will meet this obligation in significant part with generation capacity it already owns or has under contract. The combined ACE and Delmarva retail default service summer peak loads are forecast to be 6,254 MW in 2002 and 6,405 MW in 2003 (assuming that no significant retail loads are lost to other suppliers during this period). Given the required 19 percent installed capacity reserve margin, Conectiv will need 7,442 MW and 7,622 MW, respectively, to meet its forecast summer 2002 and summer 2003 obligations. As discussed above, in the no further divestiture scenario, Conectiv will have 7,326 MW of capacity resources in the summer of 2002 and this will drop to 6,020 MW by the summer of 2003 (as a result of 1,492 MW of expiring contracts and 186 MW of new capacity coming on-line). Thus, Conectiv is not expected to have any uncommitted capacity. Indeed, it will need to acquire a small amount of additional capacity or capacity credits to meet its forecast obligations in the summer of 2002 and it will have to obtain about 1,500 MW of additional resources to meet its forecast summer 2003 obligations. In the completed divestiture scenario, Conectiv will need to acquire additional capacity resources amounting to over 1,800 MW and 3,700 MW, respectively, to meet its forecast summer 2002 and summer 2003 load obligations. Q. Please describe Conectiv's participation in unregulated retail energy markets. A. During 2000, Conectiv began exiting a number of retail business activities. In mid- to late 2000, Conectiv sold its heating, ventilation and air conditioning business and portions of its Conectiv Thermal Systems, Inc., which constructed and operated district heating and cooling systems. Conectiv also began exiting from the competitive retail energy business. Although it still retains some customers, Conectiv is not signing up new customers, and is returning existing customers to the default service supplier as existing contracts expire. Q. Does Conectiv have any other significant unregulated business operations? A. Yes. Through its subsidiary, CESI, Conectiv trades electricity, gas, oil and coal. Its annual revenues from this activity total about $2.5 billion, with over 60 percent associated with gas trading. Trading activities are focused on the mid-Atlantic area, but significant sales also are made elsewhere. IV. Competitive Analysis Framework Q. What is the purpose of this section of your testimony? A. Here I describe the general approach used to analyze whether a horizontal merger will create or enhance market power. A horizontal merger is one involving two or more firms that compete in the same relevant market. Market power is the ability profitably to increase and maintain prices above competitive levels for a significant period of time. Q. What are the key parts of an analysis of potential horizontal market power issues? A. The first step is to define relevant product and geographic markets and identify the participants in each of these markets. Relevant products are defined by identifying all products or services sold by the merging parties in competition with one another, and then including products or services offered by other suppliers that are close substitutes for the merging parties' offerings. Relevant geographic markets are identified by grouping similarly situated customers for which the merging companies compete. Relevant market boundaries should encompass additional products or geographic areas even if the merging parties do not currently compete there if they are perceived as realistic potential competitors. The second step is to calculate the market shares of each of the participants and the pre- and post-transaction concentration levels in these markets. Market concentration is a measure that reflects the extent to which a few firms account for market sales or capacity. Markets with many firms and low levels of concentration generally are presumed to be competitive. Markets with fewer firms or high levels of concentration require more detailed analysis to determine whether significant market power exists. Thus, market concentration is used to distinguish between markets where there are enough participants to result in competitive outcomes and markets where further analysis is required to evaluate the prospects for a successful exercise of market power. The HHI is a commonly used measure of market concentration. This index is calculated by summing the squares of the market shares of the firms in the market. For example, a market with four firms having markets shares of 35 percent, 25 percent, 22 percent, and 18 percent would have an HHI value of 1,225 + 625 + 484 + 324, or 2,658. Markets with a large number of firms, each with a small market share (say, 5 percent or less), have HHI values that are very low (under 500 where no share exceeds 5 percent). Markets served by a single provider have an HHI of 10,000. In its Final Rule, the FERC adopted the market concentration screening criteria set out in the Horizontal Merger Guidelines of the U.S. Department of Justice and the Federal Trade Commission. These concentration-screening criteria divide the range of potential HHI values into three regions. If the post-merger HHI is below 1,000, the market is deemed unconcentrated and an exercise of market power is presumed unlikely. These markets "pass" the HHI screen and ordinarily require no further analysis. If the post-merger HHI is between 1,000 and 1,800 the market is deemed to be moderately concentrated. If the merger increases the HHI less than 100 points in a moderately concentrated market, the merger is presumed unlikely to result in competitive effects. If the increase is over 100 points, however, the Horizontal Merger Guidelines state that significant competitive concerns may arise, and further analysis is required to determine whether harm to competition is likely. Finally, if the post-merger HHI is above 1,800 the market is deemed "highly concentrated." If the HHI increase arising from a merger in a highly concentrated market is less than 50 points, significant competitive effects are presumed unlikely. If the increase is between 50 and 100 points, then the Horizontal Merger Guidelines state that significant competitive concerns may arise, and further analysis is required to determine whether harm to competition is likely. If the increase in a highly concentrated market is above 100 points, the Horizontal Merger Guidelines presume that merger will be "likely to create or enhance market power or facilitate its exercise." This presumption may be overcome if ease of entry or other considerations make the exercise of market power unlikely. When a merger fails to satisfy the safe harbor concentration-based screening criteria, the next step in the analysis is to consider in more detail the competitive effects likely to result from the proposed transaction. The additional analysis generally focuses on the ability or incentive of one or more firms to restrict supply in order to increase prices. Also, in assessing horizontal mergers, an analysis of barriers to entry facing new suppliers or expansion by existing suppliers is often crucial. In the absence of significant barriers to entry, existing firms in an industry are unlikely to be able to exert substantial market power because any attempt to raise prices above competitive levels would attract the entry of new providers. Thus, entry can deter or counteract an exercise of market power. On the other hand, where barriers to entry are substantial, new providers would find it difficult or impossible to enter the market on a timely basis in response to an attempt by existing firms to raise prices above competitive levels. In the case of mergers found to be anti-competitive, the final step in the analysis is to ask whether the merger may nevertheless be socially beneficial due to cost reductions or other efficiencies likely to result that otherwise would not be achievable. Q. In what circumstances do mergers raise potential vertical market power concerns? A. Vertical issues arise if a proposed merger will result in increasing the ability or incentive of the combined firm to take actions at one level of the production chain (input or upstream markets) to adversely affect prices or output at another level (output or downstream markets). As shown in Sections VI and VII below, in this case, the proposed PEPCO/Conectiv merger raises no substantive vertical market power issues. V. Market Share and Concentration Analyses (Competitive Screening Analysis) Relevant Product and Geographic Markets Q. What product and geographic markets have you determined to be relevant to an assessment of the Merger in this case? A. The relevant products in this case include at the wholesale level non-firm energy, differentiated by PJM load level; short-term capacity (firm energy); long-term capacity; and potentially those ancillary services sold at market-determined rates, including energy imbalance service, regulation service, spinning reserves and non-spinning reserves. To evaluate these product markets, I examined the four capacity measures traditionally evaluated by the Commission: total capacity, uncommitted capacity, economic capacity and available economic capacity. To be specific, as discussed further below, non-firm energy market conditions are differentiated by PJM load levels, and concentration in those markets is measured by delivered economic and available economic capacity. Short-term capacity markets are examined by looking at total and uncommitted capacity measures. However, since Conectiv is not anticipated to have any uncommitted capacity, there is no need to determine other suppliers' shares of uncommitted capacity or calculate HHIs to know that the merger will have no impact on those measures. Following Commission precedent, long-term capacity markets are presumed to be competitive absent the existence of significant barriers to entry. Section VI of my testimony demonstrates that such barriers do not exist in the geographic markets relevant to assessing the proposed merger of PEPCO and Conectiv. Turning to ancillary services, as discussed above, the two generation plants retained by PEPCO are no more than de minimis actual or potential suppliers of ancillary services. As a result, the Merger cannot materially affect competition in any ancillary service markets and therefore no further analysis of those markets is warranted. The relevant wholesale destination or geographic markets in this case include the PJM area, as well as three sub-regions within PJM defined by potentially binding constraints on west to east power flows within the region. Prior Commission decisions have found these areas to be the appropriately defined relevant geographic markets when assessing competitive conditions in PJM. In the case at hand, PEPCO's capacity is in the west sub-region of PJM, while virtually all of Conectiv's capacity is in the east sub-region of PJM. Thus, when binding transmission constraints occur at the same time that PEPCO's units are economic to run, its capacity has to compete with all other capacity in west PJM, or west and central PJM, for the limited capability to transmit power eastward. This further diminishes the competitive significance of the PEPCO generation and indicates that the Merger cannot have an anti-competitive impact on any PJM sub-region. Nevertheless, to be conservative, I have separately analyzed as distinct geographic markets east PJM, east plus central PJM, and east plus central plus west PJM. No screening violations occur in any sub-region. Data for the years 1999 and 2000 show that the east and west interfaces are congested in many more hours than the central interface, although there is no congestion on any of the three PJM internal interfaces during the vast majority of all hours. To be specific, in the 1999-2000 period, the east interface was congested during 396 hours (2.3 percent of all hours), the west interface was congested during 118 hours (0.7 percent of all hours) and the central interface was congested during only 27 hours (0.2 percent of all hours). Q. Did you calculate market share and concentration statistics for any geographic markets outside PJM and, if not, why? A. I did not because such an analysis is not necessary to conclude that the Merger will have no adverse effect on competition in those markets./3 Other market areas interconnected with PJM can be relevant wholesale destination markets. However, neither PEPCO nor Conectiv control any generation resources in those areas, thus the merged company's competitive significance in other markets, by definition, must be substantially less than in the PJM market. Accordingly, there is no reason to conduct a competitive screening analysis for destination markets outside PJM to conclude that the Merger will have no adverse effect on competition in those markets. -------- 3 Each of the Applicants has made sales outside PJM in the past. The Applicants' sales for the last three years are summarized in Exhibit PC-5. -------- Q. Who are the potential sellers in the relevant PJM markets you have identified? A. The potential sellers of wholesale capacity or energy in the PJM market and its sub-regions include all owners of generation capacity within PJM, as well as interconnected suppliers that can deliver competitively-priced power to PJM. However, it should be recognized that the analysis of PJM power markets is not particularly sensitive to the treatment of imports. This is true for three reasons. First, there is no available long-term firm import capability into PJM, Second, there typically is less than 700 MW of available monthly firm import capability into PJM. Third, the total non-firm import capability into PJM varies depending on system conditions but is typically 5,000 MW or less (less capability already used for firm transactions). Due to these factors, during high load hours in the summer season, net imports into PJM are generally only in the 3,000 MW to 5,000 MW range, and they are substantially lower during winter peak hours. Therefore, even if imports into PJM are ignored altogether, as long as the prices examined in the delivered price test cover a reasonable range, the calculated market shares and HHIs for the PJM market will be affected very little. Given this, in order to simplify the delivered price analysis and make it conservative, I limited the pool of outside suppliers to 13 entities: AEP, Amergen, Cinergy, Allegheney Power, Virginia Power, First Energy, Carolina Power and Light, AES, Calpine, NRG, Mirant, PG&E and Reliant. This list includes the suppliers that historically have made relatively large sales into PJM, as well as all owners of capacity within PJM that also have significant resources located within three wheels elsewhere in the eastern interconnection. By restricting the pool of potential outside suppliers (but including all participants already controlling some capacity within PJM), the scarce transmission import capacity is allocated in an extremely conservative way. Exhibit PC-6 identifies the suppliers selling into PJM during the most recent two-year period available (1998-1999) and shows the MWh quantities involved. Time Periods Analyzed Q. What time periods have you examined? A. Since the Merger is not expected to be consummated until late this year or early in 2002, I have focused my analysis of total and uncommitted capacity on the summer of 2002, and my analysis of economic and available economic capacity on market conditions as they are expected to exist in the summer peak season of 2002 and the following winter peak season of 2002-03. Q. For the economic and available economic capacity calculations, how did you divide up the summer 2002 and winter 2002-03 periods for analysis? A. My delivered price analysis examines summer super-peak, high-peak and peak conditions; as well as winter peak conditions. Since the only two generation plants owned by PEPCO are peaking plants with high energy production costs and very low annual capacity factors, it follows that the Merger's potential impact on competition will be limited to relatively high load and high price periods. Based on an examination of PJM load and price data for the year ending February 28, 2001 (thus capturing the last full winter season), I divided the year into the following periods for more detailed examination in the Appendix A analysis: summer (June - September) hours when PJM loads exceed 45,000 MW (summer super-peak hours); summer hours when the PJM load is between 40,000 MW and 44,999 MW (summer high-peak hours); summer hours when the PJM load is between 35,000 MW and 39,999 MW (summer peak hours); and winter (December - February) hours when PJM load exceeds 35,000 MW (winter peak hours). Table 1 below presents load and price data for the last year.
Table 1 PJM Load And Price Data ------------------------ -------------- ------------------------- --------------- ------------------------ Number of Load Range Average Price Price Range Covering Season Hours (MW) ($ MWH) 80% of Hours* ($MWH) ------------------------ -------------- ------------------------- --------------- ------------------------ Summer 2000 ------------------------ -------------- ------------------------- --------------- ------------------------ Super Peak 71 45,019-- 49,462 $84 $55 - $126 ------------------------ -------------- ------------------------- --------------- ------------------------ High Peak 236 40,005-- 44,979 53 38 - 75 ------------------------ -------------- ------------------------- --------------- ------------------------ Peak 457 35,000-- 39,993 37 19 - 57 ------------------------ -------------- ------------------------- --------------- ------------------------ Winter 2000-01 ------------------------ -------------- ------------------------- --------------- ------------------------ Peak 581 35,008-- 41,489 58 27 - 100 ---------------------------------------------------------------------------------------------------------- *Excludes highest and lowest 10 percent of prices in each period. ----------------------------------------------------------------------------------------------------------
To cover the observed range of prices at these load levels, my delivered price analysis focuses on six price levels ranging from $50 to $125 per MWh. At the high end of the range, all PJM capacity is economic; below the low end of the range, no PEPCO capacity is economic, so the HHI cannot change as a result of the Merger. Data Sources Q. Please identify the types of input data required to carry out your installed capacity, and delivered price or economic capacity analyses. A. In addition to the historic PJM load and price data discussed above, the required inputs are as follows: (1) Existing generation capacity and new capacity under construction in PJM, by owner; (2) The estimated variable energy production cost of each unit; (3) Long-term capacity purchases and sales; (4) Transmission capacity limits among zones within PJM and from interconnected regions into PJM; (5) Generation capacity owned by the 13 suppliers outside PJM included in the Appendix A analysis, along with the estimated cost of delivering energy from those sources to PJM; and (6) Estimated summer 2002 and winter 2002-03 native or retail default loads for which various suppliers are responsible. Q. Can you describe the sources you used to develop the input dataset? A. Yes. The primary data source for generation plant capability in PJM is the Mid Atlantic Area Council ("MAAC") Response to the 2000 NERC Data Request (formerly the MAAC EIA-411), dated April 1, 2000 (the "MAAC Report"). The MAAC Report provides data on summer and winter capacity for all generation units in PJM and identifies jointly owned units. Jointly owned plants were assigned to their individual owners in proportion to their ownership shares. MAAC Report data were adjusted for known asset divestitures not reflected in the report. New utility and merchant plants scheduled to enter service by the summer of 2002 or the winter of 2002-03 were included in the database if they have started construction. New generation plants, including their stage of development, were identified using generation queue data found on the PJM website, trade press announcements and information from individual company websites. The dispatch price for each unit was calculated as follows. Unit heat rates were taken from the Energy Information Agency ("EIA") Form 860 (dated 1995). This source covered virtually all generators in PJM. In the few instances where no heat rate was reported for a unit in Form 860, estimates were used based on the type of unit. Natural gas, fuel oil and kerosene prices were estimated based on available futures prices for the summer of 2002 and the winter of 2002-03. As a practical matter, the Appendix A calculations are affected only by the relative levels of oil and natural gas prices. Therefore, to provide sensitivity analyses, additional scenarios were run varying oil prices relative to natural gas prices by plus or minus 20 percent. All coal and nuclear units have fuel costs that are very low relative to the range of electricity prices being analyzed ($55 per MWh and above), so for simplicity, a common average fuel cost of $1.58 MMBtu was used for all coal units in PJM and $1.00 MMBtu was used for all nuclear units. Data on long-term firm sales and purchases were obtained from the MAAC Report, a review of 1999 FERC Form 1 submissions, and PJM participant websites. Capacity sold under long-term agreements whose detailed terms are not known is attributed to the buyer. Purchased resources are assumed to be located in the seller's area. Transmission limits within PJM are reported on the PJM website. Currently, the west to east zonal limits are: East interface--4,728; Central interface--3,500; and the West interface--5,934. Based on a review of past interconnection capability studies and actual imports during peak hours, with one exception, the import capability was set to 1,587 MW from the New York Power Pool ("NYPP") and the simultaneous ECAR/Virginia Power import limit was set at 3,412 MW. The exception relates to those rare occurrences when the internal West interface is congested. During those times, imports from ECAR and Virginia Power tend to be substantial but net imports from NYPP tend to be low or negative. Thus, my analysis of the east plus central plus west PJM market assumes imports from NYPP are zero, while imports from ECAR and Virginia Power are limited to 3,000 MW. A 450 MW long-term purchase from First Energy is assumed to have priority access to the ECAR/Virginia Power import capability in either case. As previously noted, actual limits vary depending upon system conditions, but imports play such a small role in the analysis that use of these estimated import limits is reasonable. Forecast summer 2002 and winter 2002-03 peak loads for all load serving entities in PJM were obtained from the PJM Load Forecast Report dated February 2001. The load patterns within each season for each supplier were assumed to mirror the overall PJM load pattern. For supply sources outside of PJM, Form 1 data were used for investor-owned utilities and web pages were used for independent power producers. In instances where heat rates were not reported, generic values by unit type were used and similar units were grouped together to simplify the analysis. Q. Do your workpapers contain the documentation and support for the Appendix A analysis as required by Section 33.3 of Order No. 642? A. Yes, the workpapers provide all the documentation necessary to support the Appendix A analysis presented in my testimony and in Appendix I to my testimony. The workpaper index specifies where all information required by Section 33.3 of Order No. 642 is found. Total and Uncommitted Capacity Analysis Q. Please present the results of your total and uncommitted capacity analysis. A. As discussed above, PEPCO owns and controls only 806 MW of generation capacity, none of which is committed. By the summer of 2002, Conectiv's owned and purchased capacity will be 7,326 MW if no additional units are divested, assuming that both new plants approved for construction are completed on time. Given Conectiv's forecast summer retail default service peak load of 6,254 MW, after allowance for required reserves (equal to 19.0 percent of peak load), it will have no uncommitted capacity. Given this, there is no need to calculate uncommitted capacity market shares and HHIs. Total installed generation capacity in PJM is conservatively estimated to be 63,797 MW by the summer of 2002. The only new capacity included in these calculations (except for the second plant under development by Conectiv) is that which can be clearly identified as already under construction with scheduled in-service dates by the summer of 2002. Given the lack of firm import capability into PJM, no outside capacity resources are included in the analysis other than those already committed to PJM companies, which my analysis includes among their resources. Exhibit PC-7 shows individual market shares for total capacity in PJM, the HHI and the change in HHI attributable to the Merger in the "no further divestiture" scenario. As indicated there, the total capacity HHI for the PJM market is only 1,079, and the change attributable to the proposed merger is only 29 points. This clearly passes the FERC's competitive screening test. Since there is no sub-regional installed capacity requirement in PJM (that is, load serving entities in the east sub-region, for example, are not required to purchase capacity resources located in the east), I have not calculated total capacity market shares or concentration ratios for the three sub-regions within PJM. Economic and Available Economic Capacity Analysis Q. Please describe the "Appendix A" or "delivered price analysis" you have conducted. A. As indicated above, an "Appendix A" or "delivered price analysis" has been conducted covering the relevant range of prices found in the summer super peak, high peak and peak hours; and in the winter peak period. For each season, six market price levels were examined. A base case and two alternative fuel price scenarios were analyzed. The analysis examined PJM and three sub-regions within PJM as distinct relevant geographic markets. All calculations are for the "no further divestiture" scenario for Conectiv./4 Thus, delivered economic and available economic capacity market shares and HHIs each were calculated for a total of 144 scenarios. The results are summarized in Exhibits PC-8 and PC-9. As shown in those exhibits, there are no screening violations in any scenario. In the PJM-wide market, the economic capacity HHI never exceeds 1,014 and the maximum change attributable to the Merger is only 23 points, while the available economic capacity is always under 1,050 and the maximum change attributable to the Merger in only 30 points. In the East sub-region of PJM, which is the most concentrated market, the economic capacity HHI is generally below 1,700 and the maximum change in HHI attributable to the Merger is 10 points. In those nine out of 36 instances in which the economic capacity HHI is over 1,800, the merger has no effect in eight cases and increases the HHI by only 5 points in the ninth case. Available economic capacity HHIs for the East sub-region are generally below 1,000 and the maximum change attributable to the merger is only 28 points. -------- 4 Comparable statistics for the divestiture completed scenario are presented in Appendix 1. -------- VI. Barriers to Entry Q. What analysis of potential barriers to entry have you undertaken? A. I have examined the level of new generation capacity development now under way in the PJM area as this provides the best evidence regarding the existence or nonexistence of significant entry barriers. In addition, I have assessed whether the Applicants own or control key inputs to new generation capacity development that could be used to impede competition, including control over generation plant sites, fuel supplies, fuel transportation services, needed environmental permits, and electric transmission services. Q. Please describe the new generation capacity development activity now underway in the PJM Area. A. During the current year, 2,500 MW of new generation capacity is expected to be brought into service in PJM. An additional 12,664 MW of capacity is under construction or pending construction at this time, and this is viewed by PJM as likely to come into commercial service by 2004./5 This is expected to result in comfortable reserve margins for the region in the near term./6 Beyond this, an additional 32,000 MW of projects are in the PJM interconnection study queue in earlier stages of development. The 162 projects in the PJM queue have requested interconnections at 130 different substations. This clearly indicates that a multitude of sites are being considered for development. In my opinion, this provides strong evidence of the absence of significant barriers to entry in the PJM markets. -------- 5 Testimony of Cynthia Taylor on behalf of the PJM Interconnection, LLC before the New Jersey Senate Hearing on Electricity Reliability; February 7, 2001. See attachment G and H. 6 Testimony of Cynthia Taylor on behalf of the PJM Interconnection, LLC before the New Jersey Senate Hearing on Electricity Reliability; February 7, 2001. See attachment G and H. -------- Q. What is your conclusion regarding whether either or both of the Applicants own or control key inputs to new generation development that could be used to impede competition in the long run? A. Obviously, the level of development activity occurring in PJM is inconsistent with the proposition that PEPCO or Conectiv could have such control. However, I have verified this by examining the Applicants' lack of control over key generation inputs. My findings are as follows. PEPCO owns only two generation plant sites, and they are not well suited for new or substantially expanded generation capacity development due to their urban location and lack of natural gas service. Furthermore, PEPCO does not own or control any fuel supplies or fuel transportation facilities, or environmental permits needed for new generation capacity development. Non-discriminatory access to PEPCO's transmission facilities is assured by PJM's administration of the regional open access transmission tariff. Conectiv and its subsidiaries have a limited number of existing generation sites, some of which may be suitable for expansion, and the company is actively considering acquiring additional sites. However as noted above, there already are over 100 sites throughout PJM now being considered by other developers with plans for over 45,000 MW of potential generation additions. Therefore, I conclude that Conectiv has no special advantage in acquiring new generation sites. Conectiv does not own or control any significant fuel supplies or environmental permits beyond those needed to meet its own requirements. While Delmarva owns a local gas distribution system, it covers only 275 square miles, or only about 3 percent of the Conectiv service area. Moreover, the Delmarva gas distribution system currently serves no electric generators and it does not have sufficient capacity to accommodate any significant amount of new generation development. As previously discussed, the capacity in the 7 mile long pipeline owned by CESI is expected to be fully utilized by the generation projects Conectiv is already developing. Finally, as is true throughout PJM, nondiscriminatory access to Conectiv's electric transmission facilities is assured by the PJM regional open access tariff. In summary, it is clear that the proposed merger of PEPCO and Conectiv will not result in creating or heightening barriers to entry into the electric generation business. VII. Vertical Market Power Considerations Q. Does the proposed merger of PEPCO and Conectiv raise any substantial vertical market power concerns. A. No. The Merger would result in harm to competition through vertical effects on electricity markets only if the merged firm would have market power in "upstream" input markets that could be used to adversely affect prices and outputs in "downstream" electricity markets, and if the ability or incentive to use that power was enhanced by the Merger. As a general matter, the upstream inputs likely to be of significance to downstream generation competitors are fuel supplies and fuel transportation services, as well as electric transmission services. As discussed in the entry barrier section immediately above, there is no prospect of the merged firm being able to exercise market power over these or any other relevant upstream input markets. VIII. Competition in Retail Electricity and Gas Markets Q. Please describe your analysis of retail electricity and gas markets. A. Given the circumstances of this case, my analysis of the potential impact of the proposed merger on retail energy-related markets can be abbreviated. This is true because PEPCO and Conectiv are not significant actual or perceived potential competitors with one another in retail electricity or gas markets. As discussed above, while PESI is actively marketing such services over a wide area, Conectiv is withdrawing from the competitive retail electricity and gas businesses, and that decision was made prior to the decision to merge with PEPCO. If a more comprehensive analysis of competitive retail energy markets had been necessary and appropriate, a proper analysis would show the relevant markets to be very broad geographically and the number of potential competitors in those markets (at prices attractive to any unregulated supplier) to be numerous. Q. Does this conclude your testimony? A. Yes, it does. UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION ------------------------------ ) Potomac Electric Power Company ) Docket No. EC01-__-000 Conectiv ) ------------------------------ PREPARED DIRECT TESTIMONY OF JOE D. PACE City of Washington ) ) District of Columbia ) ss: I, the undersigned, Joe D. Pace, being duly sworn, depose and say that the contents of the foregoing testimony on behalf of Potomac Electric Power Company and Conectiv, are true, correct, accurate and complete to the best of my knowledge, information, and belief. /s/_______________________________ Joe D. Pace Subscribed and sworn to before me this ____ day of May, 2001. ---------------------------------- Notary Public ---------------------------------- My commission expires: