<DOCUMENT>
<TYPE>EX-99.8
<SEQUENCE>9
<FILENAME>ex998.txt
<DESCRIPTION>PACE TESTIMONY
<TEXT>
Exhibit PC-1
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
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)
Potomac Electric Power Company ) Docket No. EC01-___-000
Conectiv )
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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.
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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.
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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.
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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.
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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>
<CAPTION>
Table 1
PJM Load And Price Data
------------------------ -------------- ------------------------- --------------- ------------------------
Number of Load Range Average Price Price Range Covering
Season Hours (MW) ($ MWH) 80% of Hours* ($MWH)
------------------------ -------------- ------------------------- --------------- ------------------------
<S> <C> <C> <C> <C>
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.
----------------------------------------------------------------------------------------------------------
</TABLE>
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.
<PAGE>
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:
</TEXT>
</DOCUMENT>