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Exhibit D-1
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Ohio Edison Company, )
The Cleveland Electric Illuminating )
Company, The Toledo Edison Company, ) Docket No. EC01- -000
Pennsylvania Power Company, American )
Transmission Systems, Inc. and their )
public utility affiliates )
)
and )
)
Jersey Central Power & Light )
Company, Metropolitan Edison Company, )
Pennsylvania Electric Company )
and their public utility affiliates )
JOINT APPLICATION FOR APPROVAL OF MERGER
This Joint Application For Approval Of Merger ("Application") is filed
with the Federal Energy Regulatory Commission ("Commission" or "FERC") pursuant
to Section 203 of the Federal Power Act ("Act"), 16 U.S.C. ss.824b (1994), Part
33 of the Commission's regulations thereunder, 18 C.F.R. ss.33 (2000), and the
Commission's Merger Policy Statement.(1)
The lead applicants on one side of the proposed merger ("Merger") are
Ohio Edison Company ("OE"), The Cleveland Electric Illuminating Company ("CEI"),
The Toledo Edison Company ("TE"), Pennsylvania Power Company ("PP"), American
Transmission
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(1) Inquiry Concerning the Commission's Merger Policy Under the Federal
Power Act: Policy Statement, Order No. 592,
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Systems, Inc. ("ATSI"), and their public utility affiliates (hereafter, the
"FirstEnergy Companies"(2)), all of whom are wholly-owned direct or indirect
subsidiaries of FirstEnergy Corp., an exempt public utility holding company.(3)
On the other side of the Merger, the lead applicants are Jersey Central Power &
Light Company ("JCP&L"), Metropolitan Edison Company ("MetEd"), and Pennsylvania
Electric Company ("Penelec"), and their public utility affiliates (hereafter,
the "GPU Companies"), all of whom are wholly-owned direct or indirect
subsidiaries of GPU, Inc., a registered public utility holding company.(4)
JCP&L, MetEd and Penelec do business, and are sometimes referred to herein in
the singular form, as "GPU Energy." The FirstEnergy Companies and GPU Companies
are referred to herein as the "Applicants."
Under the Merger, GPU, Inc. will be merged with and into FirstEnergy
Corp., which will be the surviving corporation.
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(continued...)
FERC Stats. and RegsP. 31,044 (1996), RECONSIDERATION DENIED, Order No.
592-A, 79 FERCP. 61,321 (1997).
(2) For ease of reference, some or all of the FirstEnergy Companies will
sometimes be referred to herein in singular form as "FirstEnergy" or
"FirstEnergy Companies."
(3) The other public utility affiliate of FirstEnergy Corp. is FirstEnergy
Trading Services, Inc. ("FETS").
(4) The other public utility affiliates of GPU, Inc. are York Haven Power
Company, and GPU Advanced Resources, Inc.
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Upon closing of the Merger, each of the GPU Companies will become wholly-owned
subsidiaries of FirstEnergy Corp; and JCP&L, MetEd and Penelec (each doing
business as GPU Energy) will continue to operate as distribution companies in
their respective retail service areas as separate subsidiaries, just as OE, CEI,
TE and PP, the traditional public utility companies now owned by FirstEnergy
Corp., will continue to operate in their respective retail service areas as
separate distribution subsidiaries. ATSI also will continue to exist as a
wholly-owned, separate transmission company subject to the Commission's
jurisdiction.
I. REQUEST FOR EXPEDITED CONSIDERATION AND NO HEARING
The Applicants request that the Commission issue a final order
approving the Merger, without an evidentiary hearing, by March 31, 2001. The
Applicants hope to obtain all required regulatory approvals by April 30, 2001 so
that the Merger can be closed by the end of the second quarter of 2001.
The Merger will create a combination among utilities that provide
retail services, including supplier of last resort obligations, in three states
that already have mandated retail customer choice: (a) Ohio, which permits
retail choice as of January 1, 2001, and (b) Pennsylvania and New Jersey, where
retail choice has already commenced under state law. The introduction of retail
competition presents significant new
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risks and challenges to the Applicants that were until recently essentially the
sole providers of electricity in franchised areas. The Applicants intend to
remain in the generation business and to compete for retail sales both within
and outside their service areas in the Northeast quadrant of the United States
through subsidiaries engaged in competitive electric sales. The Merger is
intended in large part to enhance the Applicants' ability to meet these
challenges. Prompt approval of the Merger, to ensure that its consummation is
not delayed, is therefore justified.
In Applicants' view, the Application contains more than sufficient
information to allow the Commission to find that the Merger is consistent with
the public interest, i.e., that it will have no adverse impact on (i)
competition, (ii) ratepayers subject to protection under the Merger Policy
Statement, or (iii) federal or state regulation. In addition, the Application
contains information on restructuring initiatives the Applicants have recently
completed, have underway, or will soon initiate. In the event, however, that the
Commission requires additional information, the Applicants will comply with the
Commission's requests on an expedited basis.
Further, if the Commission cannot approve the Merger as proposed, the
Applicants request the Commission to identify specifically any measures or
conditions that, if taken or agreed
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to by the Applicants, would render an evidentiary hearing unnecessary. This
procedure was employed in OHIO EDISON COMPANY, ET AL., 80 FERC (Paragraph)
61,039 at 61,107-08 (1997). SEE ALSO ALLEGHENY ENERGY, INC., ET AL., 84 FERC
(Paragraph) 61,223 at 62,073 (1998).
II. OVERVIEW
The Merger will combine two directly connected public utility holding
company systems. The Merger will not have any adverse competitive effects in the
affected states primarily because: (a) of initiatives and commitments the
Applicants, who have been for some time industry leaders in the procompetitive
restructuring and realignment of generation and transmission assets, have
already undertaken or made;(b) the FirstEnergy Companies do not own sufficient
capacity to meet their existing peak load requirements and they purchase
additional amounts of power to serve those requirements; and (c) GPU Energy is
essentially a transmission and distribution system, and will add only 285 MW of
installed generation to the approximately 12,500 MW FirstEnergy now owns, and
has, since 1998, made access to its transmission facilities available through an
approved independent system operator.
Further, as to transmission, FirstEnergy (now via ATSI) has maintained
full compliance with the Commission's open access policies, as set forth in
Order Nos. 888 and 889, as modified
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and clarified on rehearing and affirmed on appeal(5) (hereafter, "FERC Open
Access Policy"). Simultaneously, FirstEnergy has been instrumental in the
formation of the "Alliance," a transmission organization that aspires to become
one of the first Commission-authorized Regional Transmission Organizations (an
"RTO") under Order No. 2000 (the "RTO Final Rule").(6) The Commission already
has conditionally authorized the Alliance's formation. SEE Orders issued in
Docket Nos. EC99-80-000, ER99-3144-000, and subdockets thereof, on December 20,
1999 and May 18, 2000, 89 FERC P. 61,298 and 91 FERC P. 61,152 (hereafter, the
"Alliance Orders"). SEE ALSO the September 15, 2000 Compliance Filing of the
Alliance in Docket Nos. ER99-3144-004 and EC99-80-
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(5) Promoting Wholesale Competition Through Open Access Non-Discriminatory
Transmission Services By Public Utilities; Recovery Of Stranded Costs
By Public Utilities And Transmitting Utilities, Order No. 888, FERC
Stats. & Regs, (paragraph) 31,036, clarified, 76 FERC (paragraph)
61,009 and 76 FERC (paragraph) 61,347 (1996), on reh'g, Order No.
888-A, FERC Stats. and Regs, (paragraph) 31,048, clarified, 79 FERC
(paragraph) 61,182 (1997), on reh'g, Order No. 888-B, 81 FERC
(paragraph) 61,248, on reh'g, Order No. 888-C, 82 FERC (paragraph)
61,046 (1998); Open Access Same-Time Information System And Standards
Of Conduct, Order No. 889, FERC Stats. & Regs. (paragraph) 31,035, on
reh'g, Order No. 889-A, FERC Stats. & Regs. (paragraph) 31,049, on
reh'g, Order No. 889-B, 81 FERC (paragraph) 61,253 (1997); AFF'D,
TRANSMISSION ACCESS POLICY STUDY GROUP, ET AL. V. FERC, 225 F.3d 667
(D.C. Cir. 2000).
(6) Regional Transmission Organizations, Order No. 2000, FERC Stats. and
Regs. (paragraph) 31,089 (2000), ORDER ON REH'G, Order No. 2000-A,
(March 8, 2000), FERC Stats. and Regs. (paragraph) 31,092 (2000)
(codified at 18 C.F.R.ss.35.34(h)).
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004 (not consolidated) (hereafter, the "Alliance Compliance Filing").
GPU Energy likewise has embraced utility restructuring but by a
different, albeit complementary, path. On October 12, 1997, GPU Energy announced
it would begin to divest its generation assets and thereafter to concentrate on
delivering electricity to customers. Since then, GPU Energy has disposed of
thousands of megawatts ("MW") of installed capacity and now owns only about 285
MW of installed capacity.
Additionally, of course, GPU Energy, in its role as a transmission
provider, is in full compliance with FERC Open Access Policy via its
participation in PJM Interconnection, L.L.C. ("PJM"). As an independent system
operator ("PJM/ISO"), PJM is responsible for the operation and control of the
bulk electric power transmission system, including all of GPU Energy's
transmission facilities, throughout major portions of five mid-Atlantic states
and the District of Columbia. The Applicants fully expect PJM/ISO to become one
of the first regional organizations to achieve full compliance with the RTO
Final Rule and thereby to become the "PJM/RTO". Indeed, GPU Energy joined with
PJM and the other transmission-owning utilities in the PJM/ISO in a filing that
sets forth the few enhancements necessary for PJM to satisfy the requirements of
the RTO Final Rule.
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Shortly following the Merger's closing, FirstEnergy's public utility
system will consist of (a) essentially the same amount of installed generating
capacity that FirstEnergy now owns and operates, (b) a new combination of
adjoining transmission systems, composed of (i) a western system owned,
controlled, and operated by ATSI, which is committed to the Alliance RTO, and
(ii) an eastern system, which will remain under the full operational control of
PJM/ISO, and (c) utility distribution systems that will provide services to
nearly 4.3 million customers in Ohio, Pennsylvania, and New Jersey.
FirstEnergy and ATSI recognize that the Alliance RTO has not yet been
approved by FERC. To avoid any market power concerns the Commission may have
regarding approval of the Merger pending final action on the Alliance RTO
filing, the Applicants make the following commitment as a condition of the
Commission's prompt approval of the Merger without an evidentiary hearing on
market power issues:
In the event that the Alliance fails to be approved by the
Commission, ATSI commits to file an application for approval
to participate in another RTO that complies with the RTO Final
Rule.
Overall, FirstEnergy and the GPU Companies believe that the Merger is a
key strategic step in becoming a premier energy and related services provider in
the region where its subsidiaries
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currently operate. The Merger constitutes a natural alliance of companies with
adjoining service areas and interconnected transmission systems, which will
eliminate duplicative costs, maximize efficiencies and increase management and
operational flexibility.
III. TESTIMONY AND MITIGATION
A. Testimony
Anthony J. Alexander, President of FirstEnergy Corp., provides an
overview of FirstEnergy, its electric generation transmission and distribution
facilities and operations, the Merger, FirstEnergy's transition to retail
competition, the Alliance RTO, the effect of the Merger on wholesale rates, and
FirstEnergy's willingness to waive its OHIO POWER immunity when FirstEnergy
Corp. becomes a registered public utility holding company. Exhibit No. APP-100.
Bruce L. Levy, Senior Vice President and Chief Financial Officer of
GPU, Inc. describes the corporate structure of GPU, Inc. and its public utility
subsidiaries, the recent divestitures of substantially all of GPU, Inc.'s
generation assets, the operations of GPU, Inc.'s public utility subsidiaries,
and the effect of the Merger on wholesale rates. Exhibit No. APP-200.
Rodney Frame of Analysis Group/Economics provides testimony on the
competitive effects of the Merger, including a complete
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"Appendix A" screen in conformance with the Merger Policy Statement and relevant
Commission precedent. Exhibit Nos. APP-300 through APP-317.
B. Mitigation And Commitments
For ease of reference, the Applicants enumerate below all mitigation
measures and commitments that they offer in the Application in support of its
prompt approval without an evidentiary hearing.
COMPETITION AND RATES
(1) In the event that the Alliance fails to be approved by the Commission, ATSI
commits to file an application for approval to participate in another RTO that
complies with the RTO Final Rule. Application at 8; Testimony of Anthony J.
Alexander, Exhibit No. APP-100 at 10.
(2) The Applicants will hold any and all wholesale requirements customers
harmless from any Merger-related costs in excess of Merger savings. Application
at 29-30.
(3) The Applicants will hold any and all transmission customers harmless from
any Merger-related costs in excess of Merger savings. ID.
(4) The FirstEnergy Companies will not assert native load preference for
transmission service into PJM. Exhibit No. APP-100 at 11.
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REGULATION
(5) The Applicants waive their OHIO POWER immunity. Application at 31.
IV. THE APPLICANTS
A. FirstEnergy
FirstEnergy Corp. was formed on November 8, 1997 when the merger of OE
and Centerior Energy Corporation, which owned CEI and TE, became effective.(7)
FirstEnergy Corp. is a diversified energy services holding company headquartered
in Akron, Ohio. Its traditional public utility operating companies, i.e., OE,
CEI, TE and PP, along with ATSI, comprise the nation's tenth largest
investor-owned electric system, serving 2.2 million customers within 13,200
square miles of northern and central Ohio and western Pennsylvania.
OE, CEI, TE and PP are all public utilities under the FPA, and they
have received authorization to sell power at market-based rates.(8) The
FirstEnergy Companies currently own and operate 16 power plants that produce
approximately 12,500 megawatts of power. Approximately 30 percent of the
FirstEnergy Companies'
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(7) OHIO EDISON COMPANY, ET AL., 81 FERC (Paragraph) 61,110 (1997),
REHEARING DENIED, 85 FERC (Paragraph) 61,203 (1998).
(8) MEP INVESTMENTS, LLC, 87 FERC (Paragraph) 61,209 (1999) (a basket
order). FETS (formerly Market Responsive Energy, Inc.) also has
market-based rate authority. SEE CLEVELAND ELECTRIC ILLUMINATING
COMPANY, 76 FERC (Paragraph) 61,346 (1996).
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capacity is nuclear, which produces 40 percent of the energy generated by its
plants. The FirstEnergy Companies' nuclear generating stations (Beaver Valley,
Davis-Besse and Perry) are operated on a consolidated basis by the FirstEnergy
Nuclear Operating Company. The FirstEnergy Companies provide wholesale electric
capacity, energy, or transmission services to 37 municipal electric systems in
Ohio and five boroughs in Pennsylvania; and transmission service to 11 rural
electric cooperatives who are members of Buckeye Rural Electric Cooperative,
Inc. FirstEnergy Corp. also indirectly owns an interest in gas transport and
production facilities. Exhibit No. APP-100 at 5.
The FirstEnergy Companies are in the process of increasing the amount
of their capacity from approximately 12,500 MW to approximately 13,000 MW by
upgrading the Perry Station from 1248 MW to 1265 MW and installing up to 425 MW
of capacity at West Lorain. SEE Exhibit No. APP-101. They also plan to add
another 340 megawatts of capacity by the end of 2002.
On September 1, 2000, the FirstEnergy Companies transferred ownership
and operation of their high voltage transmission facilities in Ohio and
Pennsylvania to ATSI.(9) ATSI now owns and
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(9) SEE FIRSTENERGY OPERATING COMPANIES AND AMERICAN TRANSMISSION SYSTEMS,
INC., 89 FERC (Paragraph) 61,090 (October 27, 1999). Since September 1,
2000, ATSI has owned, operated
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controls a transmission system of 7,100 circuit miles of transmission lines with
voltages of 69 kilovolts and higher and 120 transmission substations with 37
interconnections with six other utilities, including its portion of a 345
kilovolt tie line with PJM (Penelec). ATSI provides non-discriminatory open
access transmission services under the terms of its OATT, ATSI FERC Electric
Tariff, Second Revised Volume No. 1.
In Ohio, the FirstEnergy Companies, in accordance with an approved
transition-to-retail competition plan, have agreed to (a) freeze their base
distribution electric rates through December 31, 2007, and (b) lower their
unbundled residential tariff rates during a five-year "market development
period" to reflect a five percent reduction in the generation component of such
rates.
In addition, the FirstEnergy Companies in Ohio have agreed to other
procompetitive measures during the market development period, including (a) the
release of up to 1,120 MW of generating capacity during the market development
period to retail marketers and brokers at a guaranteed price, plus customer
generation shopping credits which, coupled with the guaranteed prices for the
released capacity, will provide margins for subscribers of the released
capacity. In addition,
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(continued...)
and controlled the high voltage transmission system
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OE, CEI and TE are at risk for up to $500 million in nonrecovery of transition
costs if the emerging retail market in Ohio does not meet the state's targeted
effective level of competition, i.e., a 20 percent customer switching rate.(10)
SEE Exhibit No. APP-100 at 7-9.
As part of this approved transition to retail competition plan,
FirstEnergy Corp. will be dividing its current operations in Ohio into separate
business units.(11) To the extent this state-directed restructuring requires
Commission authorization to implement, the FirstEnergy Companies will make
appropriate filings under Sections 203 and 205 of the Federal Power Act in other
dockets.
FirstEnergy Services ("Services"), another wholly owned subsidiary of
FirstEnergy Corp., sells gas at wholesale and electricity at retail.(12)
Services is certified to sell
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(continued...)
formerly owned by the FirstEnergy Companies.
(10) The latter commitment aligns FirstEnergy's financial interests with
Ohio's public interest in realizing retail competition.
(11) The plan has been approved by the Public Utilities Commission Of Ohio
("PUCO"). IN THE MATTER OF FIRSTENERGY CORP., Case Nos. 99-1212-EL-ETP,
et. seq., 2000 Ohio PUC LEXIS 676 (July 19, 2000).
(12) FETS is the FirstEnergy subsidiary which currently has authority to
sell power at market-based rates. Its proposed merger into Services is
pending before the Commission in Docket No. EC01-3-000. Upon approval
of
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electricity in retail markets in Delaware, Maryland, New Jersey, Pennsylvania,
and Ohio, and following the Merger will be the corporate entity that competes
for electric sales in states allowing retail competition.
Under a restructuring settlement approved by the Pennsylvania Public
Utility Commission ("PPUC") in June 1999, PP's retail customers are protected
from an increase in generation rates until January 1, 2006. On that date a five
percent generation rate increase will be in effect until January 1, 2007, when
the generation rate cap will expire for PP's retail customers. Exhibit No.
APP-100 at 8-9.
B. FirstEnergy RTO Compliance Plan
By letter dated June 13, 2000, the Alliance Companies(13) officially
notified the Commission and all parties of record that:
The Alliance Companies are eager to establish the Alliance Regional
Transmission Organization ("Alliance RTO") in order that the benefits
of the Alliance Transco may be brought to the marketplace as soon as
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(continued...)
the proposed merger in Docket No. EC01-3-000, Services will be a public
utility under the Federal Power Act.
(13) The Alliance Companies are American Electric Power Service Corporation
(on behalf of its public utility subsidiaries, Appalachian Power
Company, Indiana Michigan Power Company, Kentucky Power Company,
Kingsport Power Company, Ohio Power Company and Wheeling Power
Company), Consumers Energy Company, The Detroit Edison Company,
FirstEnergy Corp. (on behalf of ATSI) and Virginia Electric and Power
Company.
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possible. The overriding goals of the Alliance Companies are first to
enable the independent provision of transmission service to become a
viable business that can attract investment and improve transmission
systems; and, second to be participating in an operating RTO on or
before December 15, 2001.
The Applicants are in the process of preparing a further compliance
filing and plan to submit the completed filing as soon as feasible.
This letter identifies modifications that the Applicants intend to make
to their proposal in compliance with the Commission's directives.
Thereafter, on September 15, 2000 the original Alliance Companies made
the Alliance Compliance Filing. The Alliance Companies believe that their
proposed RTO meets all of the minimum RTO characteristics and functions of the
RTO Final Rule. The Filing states, however, that the Alliance Companies are
continuing to develop proposals that will, in some respects, exceed the minimum
standards, such as the development of a market-based approach to congestion
management that can be implemented on "Day 1" of the Alliance RTO operations.
Thus, the Alliance Companies do not view the Alliance Compliance Filing as being
their ultimate compliance filing under the RTO Final Rule; such filing will be
made on or before January 15, 2001.
Under FirstEnergy's RTO compliance plan, ATSI will become a member of
the Alliance RTO.(14) Pending the effective date of
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(14) This Application refers to filings and commitments made by the Alliance
in order to explain why the Merger does
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Alliance RTO operations, ATSI will continue to offer
nondiscriminatory open access transmission service under the terms and
conditions of ATSI's OATT in full compliance with FERC Open Access Policy. Under
this approach, the FirstEnergy Companies other than ATSI, i.e., OE, TE, CEI and
PP, receive network integration service from ATSI under the same terms and
conditions that are available to all other network customers.
In view of these circumstances and the RTO commitment included herein
(Application at 8), there is no room for any concern that the Merger will create
an entity that can exercise transmission market power.
C. The GPU Companies
GPU, Inc. is, through its subsidiaries, an international provider of
energy-related infrastructure and services. Domestically, GPU's three public
utility subsidiaries, doing
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(continued...)
not present market power issues concerning the combination of
generation and transmission assets. However, any potential issues
regarding the Alliance's plans to comply with the RTO Final Rule should
be considered in the dockets established for Alliance-specific issues.
Accordingly, this proceeding should not be consolidated with the
Alliance proceedings in Docket Nos. ER99-3144, EC99-80, and sub-dockets
thereof. SEE COMMONWEALTH EDISON COMPANY, ET AL., 91 FERC (Paragraph)
61,036 at 61,135 (April 12, 2000) ("COMMONWEALTH EDISON") (Commission
need not address motion to consolidate merger proceeding with
proceeding involving proposal to form independent transmission company
with existing ISO structure and to achieve compliance with RTO Final
Rule).
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business as GPU Energy, serve 2.1 million customers in Pennsylvania and New
Jersey.
GPU Energy operates now primarily as a transmission and local
distribution system. GPU Energy retains only 285 MW of installed capacity
(hydroelectric and combustion turbines) and thus is in a net electrical short
position (demand generally exceeds supply).(15) Otherwise, it has contracts with
non-utility generators and has entered into agreements with other utilities to
purchase required capacity and related energy. These agreements include buyback
arrangements under which GPU Energy will purchase all of the capacity and energy
from (a) the Three Mile Island Unit 1 Nuclear Generating Station through
December 31, 2001, and (b) Oyster Creek through March 31, 2003.(16) GPU Energy
also has the right to call the capacity (but not the energy) of the Homer City
Station (in which Penelec sold its 50 percent interest to a subsidiary of Edison
Mission Energy in 1999) through May 31, 2001 and the capacity of the generating
stations sold to Sithe Energies and now owned by Reliant Energy through May 31,
2002. GPU Energy's remaining capacity and energy needs will be met by short to
intermediate-term
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(15) For background concerning the divestitures, see the testimony of Bruce
L. Levy, Exhibit No. APP-200 at 4-5 and decisions cited therein.
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commitments (one month to three years) during times of expected high energy
price volatility, and reliance on spot market purchases during other periods.
SEE Exhibit No. APP-300 at 9.
As to transmission, GPU Energy's system, as explained above, is under
the complete operational control of PJM/ISO. Under the PJM Transmission Tariff,
PJM/ISO offers pool-wide open access transmission service over the facilities of
the transmission owners in PJM. All transmission services are subject to a
single, non-pancaked rate based on the costs of the individual utility's
transmission system where the point of delivery is located. In general,
locational marginal pricing is used for calculating and recovering the costs of
transmission congestion. Moreover, it is expected that PJM/ISO will become an
RTO in compliance with the RTO Final Rule.
The Applicants propose that post-Merger, the GPU Companies will remain
in PJM while ATSI will become a part of the Alliance. The Applicants are
committed to resolution of inter-RTO seams issues and will work with both
organizations to further this objective.
Historically, GPU Energy had a number of wholesale requirements (full
or partial) customers. As a consequence of
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(continued...)
(16) Both of these nuclear power plants are owned by Amergen Energy Company
LLC.
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the divestiture program, however, GPU Energy (Penelec), has only two remaining
requirements customers, Allegheny Electric Cooperative, Inc. ("Allegheny"), and
West Penn Power Company ("West Penn"), that will take service beyond the end of
this year. (The Pennsylvania Boroughs of East Conemaugh and Summerhill will
terminate their service agreements with GPU Energy as of December 1, 2000.)(17)
Allegheny takes service from Penelec under a 1993 Wheeling and Supplemental
Power Agreement (WASP Agreement), which could expire as early as 2003.
Penelec provides service to West Penn under a 1973 service agreement
under Penelec's Tariff No. 1. This service allows West Penn to meet the
requirements of approximately four MW of isolated load in Clinton County,
Pennsylvania.
Both Penelec and MetEd are subject to generation rate caps applicable
to their retail customers until December 31, 2010. Both companies also
implemented rate decreases for their retail customers on January 1, 1999, 2.5
percent for MetEd customers and 3.0 percent for Penelec customers. Similarly, in
New Jersey JCP&L implemented a retail rate reduction on August 1, 1999. The
initial annual rate reduction was five percent; but between now and August 1,
2002, the annual reduction increases in steps until it
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(17) For more detail on the termination of GPU Energy's cost-based service
agreements, see Mr. Levy's testimony, Exhibit No. APP-200 at 7.
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reaches an annual rate of 11 percent, which continues through at least July 31,
2003.
GPU, Inc.'s merchant plant businesses own interests in and operate 14
projects in five countries, including the United States. On October 5, 2000,
however, Aquila Energy ("Aquila"), a subsidiary of UtiliCorp United, and
GPU,Inc., announced the execution of a definitive agreement under which Aquila
will purchase all of GPU's merchant plant interests in the United States (six
plants in New York, New Jersey, Georgia and Florida, representing about 500 MW
of capacity), plus GPU's one-half interest in a 715 MW project under development
in Mississippi.
GPU, Inc. sells competitive retail energy and related services in the
mid-Atlantic region of the United States through its subsidiary, GPU Advanced
Resources, Inc. In addition, GPU Electric, an affiliate company of GPU, Inc.,
develops, owns and operates transmission and distribution facilities outside the
United States (but not in Mexico or Canada).
V. THE MERGER
The Merger will occur in accordance with the Agreement and Plan of
Exchange and Merger, dated August 8, 2000 ("Merger Plan") (Exhibit H). Under the
Merger Plan, the separate existence of GPU, Inc. will cease, and it will be
merged with and into FirstEnergy Corp. with the latter continuing as the
surviving corporation. Each GPU shareholder (unless he or she
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has dissented) will have the opportunity to elect to receive cash for all of his
or her GPU shares, FirstEnergy shares for all of his or her GPU shares, or cash
for a portion, and FirstEnergy shares for the rest, of his or her GPU
shares.(18)
Shortly after all required regulatory authorizations are received, the
Merger will become effective upon the filings of articles of merger by GPU, Inc.
with the Department of State of the Commonwealth of Pennsylvania, and a
certificate of merger by FirstEnergy Corp. with the Secretary of State of the
State of Ohio.
Corporate headquarters will be in Akron, Ohio. FirstEnergy Corp. will
maintain offices and presence in Morristown, New Jersey and Reading,
Pennsylvania, subject to the authority of the Board of Directors.
If the Merger were completed today, FirstEnergy would be the sixth
largest investor-owned electric utility system in the U.S. based on customers
served. With assets of approximately $40 billion, a domestic customer base of
4.3 million, and a
__________________
(18) Under the Merger Plan, however, unless an adjustment is made as a
result of tax considerations, 50 percent of all issued and outstanding
shares of GPU common stock must be exchanged for cash and 50 percent
must be exchanged for FirstEnergy common stock. The elections of GPU
shareholders to receive cash or FirstEnergy common stock are subject to
proration because of this provision and also because of a possible
adjustment controlled by tax considerations.
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service area of 37,200 square miles, FirstEnergy will be one of the nation's
largest electric utility systems with more resources and opportunities to
provide high quality services to customers.
VI. MERGER ANALYSIS
A. Standard Of Review
The Merger is subject to approval under Section 203 of the FPA, which
provides:
No public utility shall sell, lease, or otherwise dispose of the whole
of its facilities subject to the jurisdiction of the Commission, or any
part thereof of a value in excess of $50,000, or by any means
whatsoever, directly or indirectly, merge or consolidate such
facilities or any part thereof with those of any other person, or
purchase, acquire, or take any security of any other public utility,
without first having secured an order of the Commission authorizing it
to do so.
16 U.S.C.ss.824b(a) (1994).
The Commission's approval of a merger under Section 203 requires a
finding that the proposed merger will be "consistent with the public interest."
ID.; COMMONWEALTH EDISON, SUPRA. Under the Merger Policy Statement, the
Commission determines whether a proposed merger is consistent with the public
interest by considering its effect on (1) competition, (2) rates, and (3)
regulation. The Commission should approve the Merger on the basis of this test.
23
<PAGE> 24
B. Effect On Competition
The Applicants requested Mr. Frame to perform quantitative and
qualitative studies of the Merger's effect on competition, including a delivered
price screen analysis described in Appendix A to the Merger Policy Statement. If
the screen analysis is passed, or if any failures are adequately mitigated,
there is generally no need for further analysis. Merger Policy Statement at
30,119-120. Mr. Frame's Appendix A analysis focuses on the market for electric
energy, specifically non-firm energy, with particular emphasis on the Economic
Capacity measure.(19) Mr. Frame analyzes the relevant product markets in 11 time
periods in 12 destination markets. Exhibit No. APP-300 at 7. He concludes that
the Merger will not adversely affect competition in any relevant market, nor
will it enable the Applicants to raise prices above non-merger levels. Exhibit
No. APP-300 at 11-15.
For Economic Capacity, in virtually all cases the Merger induced HHI
increases fall below the threshold levels included in Appendix A. The only
exceptions involve the FirstEnergy and Duquesne Light Company (DQE) destination
market where the HHI
_______________________
(19) Mr. Frame determines that no barriers exist to entry for long-term firm
capacity and, therefore, did not consider that product as a relevant
product market in his analysis. SEE ATLANTIC CITY ELECTRIC CO. AND
DELMARVA POWER & LIGHT CO., 80 FERC (Paragraph) 61,126 at 61,405
(1997).
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<PAGE> 25
increases in the off-peak periods exceed the Merger Guidelines' screening
threshold for all three seasons.
However, Mr. Frame concludes that these limited threshold violations do
not represent a real market power concern arising from the Merger. The reasons
include the difficulty in exercising market power during off-peak hours through
the withholding of capacity when such a high percentage of the capacity
operating then consists of baseload units (nuclear units and the minimum
operating levels for baseload coal units) that cannot be easily or economically
withheld.
Moreover, the predominant direction of energy flow between the East
Central Area Reliability Coordination Agreement(ECAR) region (where FirstEnergy
and DQE are located) and the PJM region (where GPU's generating assets are
located) is west to east, that is from FirstEnergy and other ECAR suppliers into
PJM. When the flows into PJM reach their limits, prices in PJM will rise above
prices in areas to the east. GPU's incentive is to seek to get the highest price
for the energy it sells and, therefore, it will sell its energy into PJM where
the prices are higher, and not in ECAR to the west where the prices are lower.
Thus, while the screening analysis might indicate that some of GPU Energy's
resources could be competitive in the FirstEnergy and DQE destination markets,
it is relatively rare for energy
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<PAGE> 26
actually to flow in the east to west direction that would allow this.
Mr. Frame also concludes that there are no HHI changes resulting from
the Merger when Available Economic Capacity is analyzed. Since GPU has divested
virtually all of its generation, it has no Available Economic Capacity at any
price level. Its combination with FirstEnergy therefore cannot possibly increase
concentration of Available Economic Capacity in any destination market.
In addition to these base case analyses, Mr. Frame analyzes several
alternative scenarios in which he assumes different transmission prices
(including those where proposed regional transmission tariffs are assumed to be
in place), transmission capacities, and market clearing prices. These scenarios
collectively bound a range of expectations about future market structure and
conditions. The results from these sensitivities reinforce Mr. Frame's
conclusion derived from the base case, which is that the Merger does not suggest
realistic concerns about the potential exercise of horizontal market power.
Mr. Frame also includes a sensitivity analysis that assumes FirstEnergy
may send 650 MW of energy into PJM during off-peak hours to help GPU Energy meet
its energy supply obligations to retail customers in its service territory. As
part of this scenario, Mr. Frame assumes that FirstEnergy acquires the
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<PAGE> 27
transmission capacity necessary to implement the energy transfer and that
transmission capability available to others is concomitantly reduced.
The HHI changes in these sensitivities contain the same limited, and
inconsequential, screen violations as the base case, but no additional ones. In
fact, in the sensitivity analysis where the 650 MW of energy is shipped from
FirstEnergy to PJM post-merger in off-peak hours, one effect is to reduce the
HHIs in the FirstEnergy destination market during off-peak periods and,
therefore, the minor base case screen threshold violations are eliminated.
It is also important to understand that an Appendix A-type screen
analysis will not capture the pro-competitive effects of retail customer choice
and the various restructuring initiatives that have been implemented in
Pennsylvania and New Jersey and that will begin on January 1, 2001 in Ohio.
These initiatives include the commitment to achieve timely compliance with the
RTO Final Rule.
C. Effect On Rates
Under the Merger Policy Statement, the Commission evaluates whether a
proposed merger will result in an increase in the merging utilities' cost-based
power or transmission rates.(20)
__________________________
(20) Although Applicants and their affiliates have market-based rate
authority, the Commission has made clear that
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<PAGE> 28
Merger Policy Statement at 30,123-124. In this case, the Merger will not affect
any cost-based rates.
GPU Energy's only remaining cost-based requirements service
arrangements are with West Penn, and with Allegheny under the WASP Agreement
which is at issue in Docket No. EL00-88-000. ALLEGHENY ELECTRIC COOPERATIVE,
INC. V. PENNSYLVANIA ELECTRIC COMPANY, 92 FERC (Paragraph) 61,206 (September 14,
2000).
Approval of the Merger should not be delayed by Allegheny's rate issues
with Penelec. Allegheny and West Penn already have declined to terminate their
wholesale purchase agreements on four separate occasions when the opportunity to
do so was offered in an "open season" associated with Penelec's applications
(all granted) for approval of its divestiture transactions; in each case,
Allegheny and West Penn were assured that they would not be responsible for any
stranded costs if they took advantage of the opportunity to terminate their
agreements. Further, Allegheny's rate disputes with Penelec in Docket No.
EL00-88-000 are not related to the Merger and should not be introduced into this
proceeding.
Otherwise, GPU Energy's only cost-based "rates" (GPU Energy is
allocated a portion of the revenues collected under the PJM
________________________
(continued...)
its ratepayer protection concerns do not apply to customers paying
market-based rates. ENRON CORP, ET AL., 78 FERC (Paragraph) 61,179
(1997).
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<PAGE> 29
OATT) are for the transmission services it provides under the PJM OATT.(21)
FirstEnergy sells small amounts of wholesale capacity and energy under
cost-based rates to certain municipal electric systems in Ohio, and one borough
in Pennsylvania.(22) The terms of FirstEnergy's existing sales arrangements
ensure that the customers will not be adversely affected by the Merger.
ATSI provides open access transmission services under its OATT at
cost-based rates. Because ATSI does not own or control generation, it will
initially satisfy its ancillary service requirements with power purchased from
FirstEnergy under FirstEnergy's Ancillary Services Tariff (FERC Electric Tariff,
Original Volume No. 3) at cost-based rates.(23) The ATSI OATT requires ATSI to
pass through the costs of this power to its customers without mark-up.
To ensure that there will be no legitimate ratepayer protection
concerns, the Applicants, including ATSI, hereby commit that they will hold
harmless from all Merger-related costs in excess of Merger-related savings all
of their wholesale
____________________
(21) SEE footnote 17 above.
(22) FirstEnergy sells imbalance energy to four boroughs in
Pennsylvania who receive transmission services from ATSI.
(23) FirstEnergy's Tariff and service agreement with ATSI were
filed on October 3, 2000 in Docket No. ER00-3771-000 with
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<PAGE> 30
customers, including Allegheny, who purchase either (a) requirements service at
cost-based rates, or (b) transmission and ancillary services at cost-based
rates. See Mr. Alexander's testimony (Exhibit No. APP-100 at 14-16) and Mr.
Levy's testimony (Exhibit No. APP-200 at 10-11).
D. Non-Discriminatory Transmission
The Applicants realize that under certain circumstances, the Commission
has required merger applicants to file a single-system open access transmission
tariff ("OATT") for non-discriminatory transmission access over the merged
transmission system. However, as indicated above, ATSI, FirstEnergy's
wholly-owned transmission company, plans to transfer control of its transmission
facilities to the Alliance, and GPU Energy's transmission system will remain
under the operational control of the PJM/ISO. The Alliance, furthermore, plans
to become an RTO that will achieve full compliance with the RTO Final Rule no
later than the first day of the Rule's effectiveness; likewise, PJM/ISO plans to
achieve full compliance with the RTO Final Rule no later than the first day of
the Rule's effectiveness. Accordingly, the Applicants are not required to file a
single-system OATT. COMMONWEALTH EDISON, 91 FERC (Paragraph) 61,036 (April 12,
_____________________
(continued...)
a requested effective date of September 1, 2000, the date ATSI
commenced operations.
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<PAGE> 31
2000); and ENERGY EAST CORPORATION, ET AL., 91 FERC (Paragraph) 61,001 (April
3, 2000).
E. Effect On Regulation
In order to avoid a hearing on the effects of a merger on regulation,
the Applicants must demonstrate that the Merger will not affect federal and
state regulation of the Applicants. Merger Policy Statement at 30,125.
FirstEnergy Corp. intends to register as a holding company under the Public
Utility Holding Company Act of 1935 ("PUHCA"). The Applicants, accordingly, will
waive OHIO POWER immunity from Commission regulation of non-power affiliate
sales.(24) Exhibit No. APP-100 at 13-14. Further, the Merger will not adversely
affect state regulation. FirstEnergy (OE, CEI, TE, and PP), and GPU Energy
(JCP&L, MetEd and Penelec) will remain subject to effective state regulation
following the Merger's closing.
VII. AFFILIATED SALES
Consistent with Commission policy, FirstEnergy commits not to sell
power to GPU Energy, and vice versa, unless the Commission authorizes such
sales. Further, the public utility affiliates of these companies will not sell
non-power goods and services to each other except under conditions the
Commission
___________________
(24) Merger Policy Statement at 30,124-125; OHIO POWER CO. V. FERC,
954 F.2d 779, 782-86 (D.C. Cir.), CERT. DENIED, 506 U.S. 981
(1992).
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<PAGE> 32
imposes on similar transactions between utilities and their affiliated power
marketers.
VIII. ACCOUNTING
In the Merger Policy Statement, the Commission stated that it would no
longer consider the proposed accounting treatment as a separate factor but
instead ruled that "proper accounting treatment is simply a requirement for all
mergers." Merger Policy Statement at 30,126. The Merger will be accounted for
under the purchase method in accordance with generally accepted accounting
principles. Exhibit No. APP-100 at 9-10.
IX. ATTACHMENTS, STANDARDS OF CONDUCT, AND CONFIDENTIAL TREATMENT
A. Application
The following information is included in the Application:
- Direct Testimony of Anthony J. Alexander (Exhibit No. APP-100)
and associated exhibits;
- Direct Testimony of Bruce L. Levy (Exhibit No. APP-200);
- Direct Testimony of Rodney Frame (Exhibit No. APP-300) and
associated exhibits;
Also attached are the Exhibits A through I as required by Section 33.3
of the Commission's regulations. To the extent necessary, the Applicants request
waiver of the Commission's
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<PAGE> 33
regulations to permit acceptance of the attached Exhibits in the form filed.
B. Standards Of Conduct
The Applicants hereby commit that, effective as of the date of this
filing, they will, for purposes of FERC Open Access Policy, treat each other as
if they were already affiliated companies. Therefore, ATSI's transmission
function personnel will treat GPU Energy's merchant function personnel in the
same manner that ATSI's transmission function personnel treat FirstEnergy's
merchant function personnel. GPU Energy's transmission function personnel will
treat FirstEnergy's merchant function personnel in the same manner that GPU
Energy's transmission function personnel treat GPU Energy's merchant function
personnel. Upon consummation of the Merger, Applicants will file a combined
Standards of Conduct in conformance with FERC Open Access Policy.
C. Confidential Treatment
The computer model underlying Mr. Frame's study is being submitted on a
confidential basis pursuant to 18 C.F.R. section 388.112 (2000). The model is
proprietary to Analysis Group/Economics and was developed at great cost to
Analysis Group/Economics. The disclosure of the model to the public without
limit will adversely impact Analysis Group/Economics. One copy of the model is
included with the original copy of the Application in a
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<PAGE> 34
sealed envelope. All other copies of the Application contain a statement that
the information has been removed. However, parties may obtain a copy of Mr.
Frame's model after executing a Confidentiality Agreement. Arrangements for a
copy of the model must be made by contacting Rodney Frame at Analysis
Group/Economics at telephone number (202) 785-6300.(25)
X. INFORMATION REQUIRED BY SECTION 33.2 OF THE COMMISSION'S REGULATIONS
A. Names and Addresses of Principal Business Offices
First Energy Corp. GPU, Inc.
76 South Main Street, 300 Madison Avenue
Akron, Ohio 443078 P.O. Box 1957
Morristown, New Jersey 07963
Names And Addresses Of Persons Authorized To Receive Notices And
Communications With Respect To The Application
Robert S. Waters Michael R. Beiting
Jones, Day, Reavis & Pogue Associate General Counsel
51 Louisiana Avenue, N.W. FirstEnergy Corp.
Washington, D.C. 20001 76 South Main Street
Akron, Ohio 44308
Kenneth G. Jaffe
Richard P. Sparling
Swidler, Berlin, Shereff
Friedman, LLP.
3000 K Street, N.W.
Suite 300 Washington, D.C. 20007-5116
_______________________
(25) Pursuant to 18 C.F.R.ss.388.112(b)(iv), inquiries regarding
this request should be directed to Robert S. Waters; Jones,
Day, Reavis & Pogue; 51 Louisiana Avenue, N.W.; Washington,
D.C. 20001; phone (202) 879-3687; fax (202) 626-1700.
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<PAGE> 35
B. Designation of Territories Served, by Counties And States
The FirstEnergy Companies provide electric service in northern Ohio and
western Pennsylvania, in all or portions of the following counties:
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY (OHIO)
Ashtabula Lorain
Cuyahoga Medina
Geauga Trumbull
Lake
OHIO EDISON COMPANY (OHIO)
Ashland Madison
Ashtabula Mahoning
Carroll Marion
Champaign Medina
Clark Morrow
Columbiana Ottawa
Crawford Portage
Cuyahoga Richland
Delaware Sandusky
Erie Seneca
Fayette Stark
Franklin Summit
Geauga Trumbull
Greene Tuscarawas
Holmes Union
Huron Wayne
Knox Wyandot
Lorain
PENNSYLVANIA POWER COMPANY (PENNSYLVANIA)
Allegheny Crawford
Beaver Lawrence
Butler Mercer
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<PAGE> 36
THE TOLEDO EDISON COMPANY (OHIO)
Defiance Putnam
Fulton Sandusky
Henry Seneca
Lucas Williams
Ottawa Wood
FirstEnergy also has affiliates engaged in unregulated sales of natural gas and
electricity in Delaware, Illinois, Indiana, Kentucky, Michigan, New Jersey,
North Carolina, Ohio, Pennsylvania, Texas, Virginia, and West Virginia.
As for GPU Energy, JCP&L provides retail service in northern, western
and east central New Jersey, having an estimated population of approximately 2.5
million. MetEd provides retail electric service in all or portions of fourteen
counties, in eastern and south central Pennsylvania, having a population of
approximately 1 million. Penelec provides retail and wholesale electric service
within a territory located in western, northern and south central Pennsylvania
extending from the Maryland state line northerly to the New York state line,
with a population of approximately 1.5 million. Penelec, as lessee of the
property of the Waverly Electric Light & Power Company, also serves a population
of approximately 13,700 in Waverly, New York and vicinity.
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<PAGE> 37
C. Description Of Facilities Owned Or Operated For Transmission
Of Electric Energy Or The Sale Of Electric Energy At Wholesale
In Interstate Commerce
As of December 31, 1999, the FirstEnergy Companies owned approximately
7,100 circuit miles of high voltage transmission lines that are 69 kV and above.
As of December 31, 1999, JCP&L owned approximately 2,047 circuit miles of
transmission lines, MetEd owned approximately 1,236 circuit miles of
transmission lines and Penelec owned approximately 2,739 circuit miles of
transmission lines. See Section IV of this Application for a description of the
Applicants' generation facilities.
D. Description Of Transaction And Statement As To Consideration
The Merger is described in Section V of this Application. The
consideration for the Merger is inherent in the exchange of shares (or receipt
of cash in whole or part by shareholders of GPU, Inc.) at closing, as negotiated
at arms-length between the parties and as described in the Merger Plan. Exhibit
H. The terms of the Merger have been approved by the Boards of Directors. The
Applicants were assisted by their own outside investment bankers in the
negotiation process. The Merger is voluntary and must be approved by voting
shareholders.
E. Description Of Facilities Involved In The Transaction
The jurisdictional facilities of the Applicants are described herein.
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<PAGE> 38
F. Statement Of The Cost Of The Facilities Involved In The
Transaction
See Exhibit C.
G. Statement As To The Effect Of The Merger Upon Contracts For
The Purchase, Sale, Or Interchange Of Electric Energy
The Merger will not have a material impact on any contract for the
purchase, sale, or interchange of electric energy. The Applicants' commitment to
ratepayers is described in Section VI.C of this Application.
H. Statement Of Other Federal And State Regulatory Requirements
FirstEnergy Corp. is currently a holding company exempt from most
provisions of PUHCA. GPU, Inc. is a registered holding company under PUHCA but
will cease to exist upon the Merger's closing. FirstEnergy Corp. is required to
obtain approval from the Securities and Exchange Commission ("SEC") under
Section 9(a)(2) of the PUHCA in connection with the Merger. Section 9(a)(2) of
the PUHCA provides that it is unlawful for any person to acquire any security of
any public utility company if that person owned, or by virtue of that
transaction will come to own, five percent or more of the voting securities of
the public utility company and of any other public utility company, without the
prior approval of the SEC. An application for approval of the Merger under PUHCA
will be filed by FirstEnergy Corp.
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<PAGE> 39
FirstEnergy Corp. will be required to be registered under Section 5 of
PUHCA when the Merger is completed. At that time, FirstEnergy Corp. will become
subject to the restrictions that PUHCA imposes on registered holding company
systems.
FirstEnergy Corp. believes that the approval of the Merger by the PUCO
is not required. However, under the law of the Commonwealth of Pennsylvania, any
public utility must obtain a certificate of public convenience from the PPUC
before it (or any affiliate) may acquire from, or transfer to, another entity
the title to, or the possession or use of, any property used or useful in the
public service. In addition, under the PPUC's policy, a merger that results in
the change in control of an existing Pennsylvania public utility (which includes
a change in the controlling interest of the utility's parent) requires the
issuance of a certificate of public convenience by the PPUC.
Additionally, the transfer of the ownership or control of GPU, Inc., as
the parent company of JCP&L, and various related matters, are subject to the
jurisdiction of the New Jersey Board Of Public Utilities ("BPU"). Pursuant to
the law of New Jersey, no person may acquire or seek to acquire control of a
public utility directly or indirectly through the medium of an affiliated or
parent corporation without first requesting and receiving approval of the BPU.
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<PAGE> 40
OE and PP each holds a license under the Atomic Energy Act ("NRC
license") from the Nuclear Regulatory Commission ("NRC") authorizing them to
hold ownership or leasehold interests in the Beaver Valley Unit 1 Nuclear Unit
and (along with OES Nuclear Inc., which is a wholly-owned subsidiary of OE) the
Perry Unit 1 Nuclear Unit. OE also holds an NRC license authorizing it to hold
an ownership or a leasehold interest in Beaver Valley Unit 2. Each of CEI and TE
holds an NRC license authorizing them to hold ownership or leasehold interests
in Perry Unit 1, Beaver Valley Unit 2 and the David-Besse Nuclear Units. The
Davis-Besse facility also includes a generally licensed independent spent fuel
storage installation. FirstEnergy Nuclear Operating Company holds NRC licenses
authorizing it to operate these FirstEnergy nuclear power plants.
GPU Nuclear, Inc. ("GPU Nuclear"), MetEd, JCP&L and Penelec each holds
an NRC license authorizing it to possess TMI-2. The Saxton Nuclear Experimental
Corporation, also an indirect, wholly-owned subsidiary of GPU, Inc. is licensed
to possess the Saxton Nuclear Facility, and GPU Nuclear is licensed to possess,
manage, use and maintain such facility.
On September 14, 2000, FirstEnergy formally informed the NRC, in a
docketed filing, that completion of the Merger will not result in a direct or
indirect transfer of control of the operating licenses for Perry Nuclear Power
Plant, the Davis-
40
<PAGE> 41
Besse Nuclear Power Station and the Beaver Valley Power Station Units 1 and 2.
The Merger will result in an indirect transfer of control over the
possession-only licenses for the two plants owned by GPU and its subsidiaries,
i.e., TMI-2, which is being decommissioned, and the Saxton Nuclear Facility. On
September 26, 2000, GPU Nuclear and FirstEnergy Corp. requested NRC consent to
the indirect transfer of control of the possession-only licenses for TMI-2 and
Saxton.
The Hart-Scott-Rodino Antitrust Improvements Act ("HSR Act") and the
rules and regulations thereunder provide that certain transactions (including
the Merger) may not be consummated until certain information has been submitted
to the Department of Justice ("DOJ") and the Federal Trade Commission ("FTC")
and the specified HSR Act waiting period requirements have been satisfied. The
expiration or termination of the HSR Act waiting period would not preclude the
DOJ or the FTC from challenging the Merger on antitrust grounds. If the Merger
is not consummated within twelve months after the expiration or termination of
the HSR Act waiting period, new pre-merger notifications would need to be
submitted to the DOJ and the FTC and a new HSR Act waiting period would have to
expire or be terminated before the Merger could be consummated. FirstEnergy
Corp. and GPU, Inc. will comply with the provisions of the HSR Act.
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<PAGE> 42
Finally, the Federal Communications Commission must approve the
transfer of certain licenses from GPU entities to FirstEnergy Corp.
I. Facts Showing That The Merger Is Consistent With The Public
Interest
The facts relied upon to show that the Merger is consistent with the
public interest are set forth in this Application. The Merger will not adversely
affect competition, rates or regulation. The Merger will enhance competition and
the ability of the Applicants to promote further competitive developments. The
Applicants have implemented or are about to implement pro-competitive retail
access and restructuring in their respective states. Likewise, they support the
Commission's independent transmission system initiatives, and the Applicants
will continue to provide leadership in the development of the Alliance RTO and
the enhancement of PJM in compliance with the RTO Final Rule, and other
competition enhancing initiatives while this Application is under review and
after the Merger is closed.
The Merger will combine two public utility systems with compatible
business and strategic goals into a financially stronger energy system better
suited to operate in the evolving energy markets. The combined system will have
the resources, experience and talent to provide its customers with high quality
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<PAGE> 43
and cost-efficient services, all subject to regulation intended to protect the
public interest.
J. Brief Statement Of Franchises Held
See Attachment 1 to this Application.
K. Form Of Notice
The Application includes a form of notice, in both hard copy and on
diskette, suitable for publication in the Federal Register.
XI. CONCLUSION
For the reasons set forth herein, including the accompanying testimony
and exhibits, the Applicants request that on or before March 31, 2001 the
Commission:
1. find that the Merger will not have an adverse effect on
competition, rates or regulation, that it is consistent with
the public interest, and that the Application satisfies all
requirements for authorization of the Merger under Section 203
of the FPA and Part 33 of the Commission's regulations;
2. approve the Merger and grant any and all other authorizations
or approvals incidental thereto that may be required;
3. issue such approvals and related authorizations without an
evidentiary hearing based on the information set forth in this
Application and
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<PAGE> 44
accompanying exhibits; or indicate any conditions that, if
agreeable to the Applicants, would result in conditional
approval of the Merger without an evidentiary hearing; and
4. waive any filing requirements or other regulations as the
Commission may find necessary or appropriate to allow this
Application to be accepted for filing and granted.
Respectfully submitted,
THE FIRSTENERGY COMPANIES
THE GPU COMPANIES
By: /s/ Robert S. Waters
---------------------------------
Leila L. Vespoli
Vice President and
General Counsel
Michael R. Beiting
Associate General Counsel
FirstEnergy Corp.
76 South Main Street
Akron, Ohio 44308
330-384-5795 - voice
330-384-3875 - fax
44
<PAGE> 45
By: /s/ Robert S. Waters
---------------------------------
Paul T. Ruxin
Robert S. Waters
Jones, Day Reavis & Pogue
51 Louisiana Avenue, N.W.
Washington, D.C. 20001
202-879-3939 - voice
202-626-1700 - fax
By: /s/ Robert S. Waters
---------------------------------
Ira H. Jolles
GPU, Inc.
300 Madison Avenue
P.O. Box 1957
Morristown, New Jersey 07963
206-389-4276 - voice
206-447-0849 - fax
By: /s/ Robert S. Waters
---------------------------------
Kenneth G. Jaffe
Richard P. Sparling
Swidler, Berlin, Shereff,
Friedman, LLP
3000 K Street, N.W.
Suite 300
Washington, D.C. 20007-5116
202-424-7563 - voice
202-424-7643 - fax
Dated: November 9, 2000
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<PAGE> 46
Attachment 1
Brief Statement of Franchises Held
and Dates of Expiration, if Not Perpetual
Operating Company Municipality Franchise Expiration
PENN POWER
Clark Perpetual
Bessemer Perpetual
Bradford Woods 2010
Callery Perpetual
Conneaut Lake 2007
Connoquenessing Perpetual
Ellwood City Perpetual
Enon Valley Perpetual
Evans City 2015
Fredonia Perpetual
Harmony 2035
Homewood Perpetual
Jackson Center Perpetual
Jamestown Perpetual
Koppel 2020
Mars Perpetual
Mercer Perpetual
New Castle Perpetual
New Galilee 2003
New Lebanon Perpetual
New Wilmington 2016
Salem 2021
Sandy Lake Perpetual
Sharon Perpetual
Sharpsville Perpetual
Sheakleyville Perpetual
SNPJ 2027
South New Castle Perpetual
Stoneboro Perpetual
Valencia Perpetual
Volant 2027
Wampum 2021
West Middlesex 2022
Wheatland Perpetual
Zelienople Perpetual
Page 1
<PAGE> 47
Attachment 1
OHIO EDISON
Akron Perpetual
Alliance Perpetual
Andover 2020
Ashland Perpetual
Ashley (Delaware County) Perpetual
Ashtabula Perpetual
Barberton Perpetual
Bay View Perpetual
Bellvue Perpetual
Beloit Perpetual
Berlin Heights Perpetual
Boston Heights 2000
Butler 2008
Caledonia Perpetual
Callery Perpetual
Campbell 2017
Canal Fulton Perpetual
Canfield 2020
Cardington (Morrow County) Perpetual
Castilia Indeterminate
Catawba Perpetual
Chippewa on the Lake no exp. Date
Clark Perpetual
Conneaut Indeterminate
Conneaut Lake 2007
Craig Beach Perpetual
Creston Perpetual
Cuyahoga Falls Perpetual
Dalton Perpetual
Delaware Perpetual
Dublin 2000
East Palestine 2000
Edison (Morrow County) 2005
Enon Perpetual
Garrettsville 2020
Girard 2011
Gloria Glens Perpetual
Green Camp 2003
Green Unspecified
Hanoverton 2020
Hayesville 2018
Kipton 2008
Leetonia 2020
Limaville Perpetual
Lisbon Perpetual
London 2007
Lorain Perpetual
Lordstown 2005
Loudonville Perpetual
Lowellville 2001
Magnetic Springs (Union County) Perpetual
Page 2
<PAGE> 48
Attachment 1
Mansfield Perpetual
Mantua 2021
Massillon 2014
McDonald 2018
Medina 2001
Medway Perpetual
Mifflin 2002
Monroeville 2010
North Ridgeville 2012
Navarre Perpetual
New Middletown 2020
New Waterford 2020
North Fairfield Indeterminate
North Ridgeville 2012
Norwalk 2022
Ontario 2009
Orangeville 2020
Orville Perpetual
Orwell Perpetual
Perrysville Perpetual
Plain City (Madison County) 2006
Poland 2020
Polk 2008
Port Clinton Indeterminate
Ravenna Perpetual
Reminderville Perpetual
Richwood (Union County) Perpetual
Rittman Perpetual
Roaming Shores Perpetual
Rogers 2020
South Amherst Indeterminate
Salem 2021
Sebring Perpetual
Seville Indeterminate
Sharon Township Perpetual
Shawnee Hills (Delaware County) Perpetual
Sheffield Lake Perpetual
Sheffield Township Perpetual
Sheffield Perpetual
Shippingport Perpetual
Silver Lake 2005
Slovene Nat'l Benefit Society 2027
South Amherst Perpetual
South Vienna 2000
Stoneboro Perpetual
Struthers 2014
Stow 2018
Streetsboro 1994
Vermillion Perpetual
Wadsworth Perpetual
Wakeman Perpetual
Wellington Perpetual
Page 3
<PAGE> 49
Attachment 1
Windham Township Unspecified
Wooster 2016
Youngstown 2003
Page 4
<PAGE> 50
Attachment 1
TOLEDO EDISON
Alvordton 2021
Archbold 2025
Bay View 2022
Berkey 2019
Blakeslee 2006
Bradner 2015
Burgoon 2008
Clay Center 2023
Defiance Perpetual
Delta 2000
Edgerton 2005
Fayette Perpetual
Freeport Perpetual
Gibsonburg 2024
Grand Rapids 2020
Green Springs Perpetual
Hamler 2019
Harbor View 2030
Haskins 2016
Helena 2026
Holgate 2019
Holland 2016
Jerry City Perpetual
Liberty Center 1999/2022
Lindsey 2026
Luckey 2017
Lyons 2015
Marblehead Perpetual
Maumee Perpetual
McClure 2019
Metamora 2011
Millbury 2027
Milton Center 2013
Montpelier 2016
New Bavaria 2016
Ney 2016
Northwood 2013
Oak Harbor (partial school) 2015
Oregon 2008
Ottowa Hills Perpetual
Permberville 2003
Perrysburg 2003
Port Clinton Perpetual
Providence
Put-In-Bay Perpetual
Risingsun 2002
Rocky Ridge Perpetual
Rossford 2021
Stryker 2013/2014
Swanton 2020
Sylvania Perpetual
Page 5
<PAGE> 51
Attachment 1
Toledo 2000
Tonogany 2024
Walbridge 2016
Wauseon Perpetual
Wayne Perpetual
West Unity 2020
Weston 2012
Whitehouse 2022
Page 6
<PAGE> 52
Attachment 1
<TABLE>
<CAPTION>
CEI
<S> <C>
Acquilla Perpetual
Ashtabula Not for longer than provided for in the Charter of the City
Avon Perpetual
Avon Lake Perpetual
Bay Village Perpetual
Beachwood Perpetual
Bedford Perpetual
Bentlyville Perpetual
Berea Perpetual
Bratenahl Perpetual
Brecksville Perpetual
Broadview Heights Perpetual
Brook Park Perpetual
Brooklyn Perpetual
Brooklyn Heights Perpetual
Burton Perpetual
Chagrin Falls Perpetual
Cleveland Perpetual
Cleveland Heights Perpetual
Conneaut Perpetual
Corlett Perpetual
Cuyahoga Heights Perpetual
Dover Perpetual
East Cleveland Perpetual
East View Perpetual
Eastlake Perpetual
Euclid Perpetual
Fairport Perpetual
Fairview Perpetual
Garfield Heights Perpetual
Gates Mills Perpetual
All townships in Perpetual
Geauga County Perpetual
Geneva Perpetual
Geneva-on-the-Lake Perpetual
Glenville Perpetual
Glenwillow Perpetual
Highland Heights Perpetual
Hunting Valley Perpetual
Idlewild Perpetual
Independence Perpetual
Jefferson Perpetual
Kirtland Hills Perpetual
Lake County Perpetual
Lakeline Perpetual
Lakeville Perpetual
Lakewood Perpetual
Linndale Perpetual
Lyndhurst Perpetual
Madison Perpetual
Maple Heights Perpetual
</TABLE>
Page 7
<PAGE> 53
Attachment 1
Mayfield Perpetual
Mayfield Heights Perpetual
Mentor Perpetual
Mentor-on-the-Lake Perpetual
Middleburg Heights Perpetual
Middlefield Perpetual
Miles Heights Perpetual
Moreland Hills Perpetual
Newburgh Perpetual
Newburgh Heights Perpetual
North Kingsville Perpetual
North Olmstead Perpetual
North Perry Perpetual
North Randall Perpetual
North Royalton Perpetual
Nottingham Perpetual
Olmstead Falls Perpetual
Orange Perpetual
Painesville Perpetual
Parkview Perpetual
Parma Perpetual
Parma Heights Perpetual
Pepper Pike Perpetual
Perry Perpetual
Richmond Perpetual
Richmond Heights Perpetual
Rock Creek Perpetual
Rocky River Perpetual
Seven Hills Perpetual
Shaker Heights Perpetual
Solon Perpetual
South Euclid Perpetual
South Newburgh Perpetual
South Russell Perpetual
Strongsville Perpetual
Timberlake Perpetual
University Heights Perpetual
Valley View Perpetual
Waite Hill Perpetual
Warrensville Heights Perpetual
West Clarendon - Granted to the Perpetual
West Clarendon Light &
Power Co.
West Park Perpetual
West View (formerly Dover) Perpetual
Westlake Perpetual
Wickliffe Perpetual
Willoughby Perpetual
Willowick Perpetual
Woodmere Perpetual
Page 8
<PAGE> 54
Attachment 1
GPU Energy has the necessary franchise rights to furnish electric
service in the various municipalities or territories in which it currently
provides such service. Those electric franchise rights consist generally of: (i)
charter rights; and (ii) certificates of public convenience issued by the PaPUC
or the BPU.
<PAGE> 55
EXHIBITS A - I
<PAGE> 56
EXHIBIT A
Copies of all resolutions of directors authorizing the proposed merger, and, if
approval of stockholders has been obtained, copies of the resolutions of the
stockholders.
Applicants request waiver of 18 C.F.R. Sec. 33.3 to permit Applicants to file
this Application without Exhibit A. In Revised Filing Requirements Under Part 33
of the Commission's Regulations, FERC Statutes and Regulations Paragraph 32,528
(1998), the Commission indicated that the information required in Exhibit A is
not necessary.
<PAGE> 57
EXHIBIT B
A statement of the measure of control or ownership exercised by or over
Applicants by any public utility, or bank, trust company, banking association,
or firm that is authorized by law to underwrite or participate in the marketing
of securities or a public utility, or any company supplying electric equipment
to such party.
<PAGE> 58
EXHIBIT B
STATEMENT OF MEASURE AND CONTROL OR OWNERSHIP
No public utility, bank, trust company, banking association, or firm
authorized to underwrite or participate in the marketing of securities of a
public utility, or any company supplying electric equipment to any of the
Applicants exercises any control by or over any of the Applicants, except that
Ohio Edison Company, a public utility, is the sole owner of Pennsylvania Power
Company, also a public utility. Neither FirstEnergy Corp., nor any of its
subsidiaries, have any officers or directors in common with GPU, Inc., or any
of its subsidiaries.
<PAGE> 59
EXHIBIT C
Balance sheets and supporting plant schedules for the most recent 12 month
period only, on an actual and on a pro forma basis in the form prescribed for
Statement A and B of FERC Form No. 1.
<PAGE> 60
FIRSTENERGY CORP / GPU, INC.
PRO FORMA COMBINED BALANCE SHEET
AS OF DECEMBER 31, 1999
(UNAUDITED)
<TABLE>
<CAPTION>
CLEVELAND JERSEY
PENNSYLVANIA ELECTRIC TOLEDO CENTRAL METROPOLITAN
OHIO EDISON POWER ILLUMINATING EDISON POWER & LIGHT EDISON
COMPANY COMPANY COMPANY COMPANY COMPANY COMPANY
----------- ------------ ------------ ------- ------------- ------------
<S> <C> <C> <C> <C> <C> <C>
ASSETS AND OTHER DEBITS
-----------------------
UTILITY PLANT
SUBTOTAL-UTILITY PLANT
(ELECTRIC) $7,472,804,691 $1,167,216,173 $4,359,898,509 $1,756,239,657 $4,282,312,803 $1,520,681,171
LESS ACCUMULATED PROVISIONS
FOR DEPRECIATION AND
AMORTIZATION 3,373,616,555 767,521,106 1,399,720,269 596,332,265 2,456,966,652 455,205,770
-------------- -------------- -------------- -------------- -------------- --------------
NET UTILITY PLANT (ELECTRIC) 4,099,188,136 399,695,067 2,960,178,220 1,159,907,392 1,825,346,151 1,065,475,401
NET NUCLEAR FUEL 55,333,981 31,511,503 68,353,741 42,000,544 (621,290) 46,189
-------------- -------------- -------------- -------------- -------------- --------------
NET UTILITY PLANT 4,154,522,117 431,206,570 3,028,531,961 1,201,907,936 1,824,724,861 1,065,521,590
OTHER PROPERTY AND INVESTMENTS 1,517,005,165 130,077,791 884,191,865 469,224,559 413,157,834 180,024,455
CURRENT AND ACCRUED ASSETS 538,031,758 128,413,756 220,444,876 119,362,277 541,047,478 260,737,108
DEFERRED DEBITS 2,122,123,557 368,839,038 3,106,287,160 1,450,617,122 3,146,633,735 2,367,456,931
-------------- -------------- -------------- -------------- -------------- --------------
TOTAL ASSETS AND OTHER DEBITS $8,331,682,597 $1,058,537,155 $7,219,455,861 $3,241,311,894 $5,925,563,908 $3,873,740,084
============== ============== ============== ============== ============== ==============
LIABILITIES AND OTHER CREDITS
-----------------------------
PROPRIETARY CAPITAL $2,795,389,515 $253,711,910 $1,354,651,501 $761,704,367 $1,482,015,854 $501,444,282
LONG-TERM DEBT 2,230,074,447 282,175,097 2,810,811,850 1,031,546,526 1,450,648,041 683,430,508
OTHER NONCURRENT LIABILITIES 202,356,480 62,465,666 245,137,658 146,971,049 153,539,575 10,337,873
CURRENT AND ACCRUED LIABILITIES 605,436,563 110,583,249 577,024,506 252,317,255 273,782,087 229,850,744
DEFERRED CREDITS 2,408,425,592 349,601,233 2,231,830,344 1,048,772,697 2,565,578,351 2,448,876,677
-------------- -------------- -------------- -------------- -------------- --------------
TOTAL LIABILITIES AND OTHER
CREDITS $8,331,682,597 $1,058,537,155 $7,219,455,861 $3,241,311,894 $5,925,563,908 $3,873,740,084
============== ============== ============== ============== ============== ==============
</TABLE>
<TABLE>
<CAPTION>
CURRENT
PENNSYLVANIA FIRST ENERGY MERGER FIRSTENERGY
ELECTRIC YORK HAVEN OTHER & GPU PRO FORMA PRO FORMA
COMPANY POWER COMPANY SUBSIDIARIES ELIMINATIONS ADJUSTMENTS COMBINED
------------ ------------- ------------ ------------ ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
ASSETS AND OTHER DEBITS
-----------------------
UTILITY PLANT $1,765,403,888 $27,344,118 $4,944,935,898 $0 ($450,000,000) $26,846,836,906
SUBTOTAL-UTILITY PLANT
(ELECTRIC) 522,449,183 7,503,064 1,042,715,260 0 (12,150,000) 10,639,880,144
-------------- ----------- --------------- ---------------- -------------- ---------------
LESS ACCUMULATED PROVISIONS
FOR DEPRECIATION AND
AMORTIZATION 1,212,954,703 19,841,054 3,902,220,638 0 (437,850,000) 16,206,956,762
NET UTILITY PLANT (ELECTRIC) 0 0 86,845,484 0 0 283,470,152
-------------- ----------- --------------- ---------------- -------------- ---------------
NET NUCLEAR FUEL 1,212,954,703 19,841,054 3,989,066,122 0 (437,850,000) 16,490,426,914
NET UTILITY PLANT 379,291,683 0 10,078,580,461 (9,021,532,910) 880,000,000 5,890,000,0090
OTHER PROPERTY AND INVESTMENTS 202,099,242 13,365,220 2,522,626,996 (1,669,774,352) 0 2,876,354,359
CURRENT AND ACCRUED ASSETS 2,510,468,560 374,519 4,020,579,647 (351,555,958) 1,073,764,211 19,815,788,722
-------------- ----------- --------------- ----------------- -------------- ---------------
DEFERRED DEBITS $4,304,614,188 $33,580,793 $20,610,853,426 ($11,042,663,220) $1,515,914,211 $45,072,590,897
============== =========== =============== ================= ============== ===============
TOTAL ASSETS AND OTHER DEBITS
LIABILITIES AND OTHER CREDITS
-----------------------------
PROPRIETARY CAPITAL $461,182,233 $19,134,855 $10,528,819,301 ($8,634,058,472) ($988,465,382) $8,535,529,964
LONG-TERM DEBT 544,463,592 0 4,928,482,393 (741,606,713) 2,215,422,250 15,523,447,991
OTHER NONCURRENT LIABILITIES 11,246,732 0 57,924,493 0 0 889,979,526
CURRENT AND ACCRUED LIABILITIES 298,186,649 13,931,265 4,004,625,917 (1,667,198,343) 151,757,343 4,850,297,545
DEFERRED CREDITS 2,989,734,982 514,673 1,093,001,322 0 137,200,000 15,273,335,871
-------------- ----------- --------------- ----------------- -------------- ---------------
TOTAL LIABILITIES AND OTHER
CREDITS $4,304,814,188 $33,580,793 $20,610,853,426 ($11,042,863,220) $1,515,914,211 $45,072,590,897
============== =========== =============== ================= ============== ===============
</TABLE>
<PAGE> 61
EXHIBIT D
A statement of all known contingent liabilities except minor items such as
damage claims and similar items involving relatively small amounts, as of the
date of the application.
<PAGE> 62
EXHIBIT D
STATEMENTS OF CONTINGENT LIABILITIES
<PAGE> 63
The consolidated financial statements include FirstEnergy Corp.
(Company) and its principal electric utility operating subsidiaries, Ohio Edison
Company (OE), The Cleveland Electric Illuminating Company (CEI), Pennsylvania
Power Company (Penn) and The Toledo Edison Company (TE). The Company and its
utility subsidiaries are referred to throughout as "Companies." The Company's
1997 results of operations include the results of CEI and TE for the period
November 8, 1997 through December 31, 1997. The consolidated financial
statements also include the Company's other principal subsidiaries: FirstEnergy
Facilities Services Group, LLC. (FE Facilities); FirstEnergy Trading Services,
Inc. (FETS); and MARBEL Energy Corporation (MARBEL). FE Facilities is the parent
company of several heating, ventilating, air conditioning and energy management
companies. FETS markets and trades electricity and natural gas in unregulated
markets. MARBEL is a fully integrated natural gas company. Significant
intercompany transactions have been eliminated. The Companies follow the
accounting policies and practices prescribed by the Public Utilities Commission
of Ohio (PUCO), the Pennsylvania Public Utility Commission (PPUC) and the
Federal Energy Regulatory Commission (FERC). The preparation of financial
statements in conformity with generally accepted accounting principles requires
management to make periodic estimates and assumptions that affect the reported
amounts of assets, liabilities, revenues and expenses. Certain prior year
amounts have been reclassified to conform with the current year presentation.
Revenues -- The Companies' principal business is providing electric
service to customers in central and northern Ohio and western Pennsylvania. The
Companies' retail customers are metered on a cycle basis. Revenue is recognized
for unbilled electric service through the end of the year.
Receivables from customers include sales to residential, commercial and
industrial customers located in the Companies' service area and sales to
wholesale customers. There was no material concentration of receivables at
December 31, 1999 or 1998, with respect to any particular segment of the
Companies' customers.
CEI and TE sell substantially all of their retail customer accounts
receivable to Centerior Funding Corp. under an asset-backed securitization
agreement which expires in 2001. Centerior Funding completed a public sale of
$150 million of receivables-backed investor certificates in 1996 in a
transaction that qualified for sale accounting treatment.
Regulatory Plans -- The PUCO approved OE's Rate Reduction and Economic
Development Plan in 1995 and FirstEnergy's Rate Reduction and Economic
Development Plan for CEI and TE in January 1997. These regulatory plans were to
maintain current base electric rates for OE, CEI and TE through December 31,
2005. At the end of the regulatory plan periods, OE base rates were to be
reduced by $300 million (approximately 20 percent below current levels) and CEI
and TE base rates were to be reduced by a combined $310 million (approximately
15 percent below current levels). The plans also revised the Companies' fuel
cost recovery methods. The Companies formerly recovered fuel-related costs not
otherwise included in base rates from retail customers through separate energy
rates. In accordance with the respective regulatory plans, OE's, CEI's and TE's
fuel rates would be frozen through the regulatory plan period, subject to
limited periodic adjustments. As part of OE's and FirstEnergy's regulatory
plans, transition rate credits were implemented for customers, which are
expected to reduce operating revenues for OE by approximately $600 million and
CEI and TE by approximately $391 million during the regulatory plan period.
In July 1999, Ohio's new electric utility restructuring legislation
which will allow Ohio electric customers to select their generation suppliers
beginning January 1, 2001, was signed into law. Among other things, the new law
provides for a five percent reduction on the generation portion of residential
customers' bills and the opportunity to recover transition costs, including
regulatory assets, from January 1, 2001 through December 31, 2005. The period
for the recovery of regulatory assets only can be extended up to December 31,
2010. The PUCO was authorized to determine the level of transition cost
recovery, as well as the recovery period for the regulatory assets portion of
those costs, in considering each Ohio electric utility's transition plan
application.
<PAGE> 64
The Company, on behalf of its Ohio electric utility operating
companies - - OE, CEI and TE - - on December 22, 1999 refiled its transition
plan under Ohio's new electric utility restructuring law. The plan was
originally filed with the PUCO on October 4, 1999, but was refiled to conform to
PUCO rules established on November 30, 1999. The new filing also included
additional information on FirstEnergy's plans to turn over control, and perhaps
ownership, of its transmission assets to the Alliance Regional Transmission
Organization. The PUCO indicated that it will endeavor to issue its order in the
Company's case within 275 days of the initial October filing date.
The transition plan itemizes, or unbundles, the current price of
electricity into its component elements - including generation, transmission,
distribution and transition charges. As required by the PUCO's rules, the
Company's filing also included its proposals on corporate separation of its
regulated and unregulated operations, operational and technical support changes
needed to accommodate customer choice, an education program to inform customers
of their options under the new law, and how the Company's transmission system
will be operated to ensure access to all users. Under the plan, customers who
remain with OE, CEI, or TE as their generation provider will continue to receive
savings under the Company's rate plans, expected to total $759 million between
2000 and 2005. In addition, customers will save $358 million through reduced
charges for taxes and a five percent reduction in the price of generation for
residential customers beginning January 1, 2001. Customer prices are expected to
be frozen through a five-year market development period (2001-2005), except for
certain limited statutory exceptions including the five percent reduction in the
price of generation for residential customers. The plan proposes recovery of
generation-related transition costs of approximately $4.5 billion ($4.0 billion,
net of deferred income taxes) over the market development period; transition
costs related to regulatory assets aggregating approximately $4.2 billion ($2.9
billion, net of deferred income taxes) will be recovered over the period of 2001
through early 2004 for OE; 2001 through 2007 for TE; and 2001 through 2010 for
CEI.
In June 1998, the PPUC authorized a rate restructuring plan for Penn
which essentially resulted in the deregulation of Penn's generation business as
of June 30, 1998. Penn was required to remove from its balance sheet all
regulatory assets and liabilities related to its generation business and assess
all other assets for impairment. The Securities and Exchange Commission (SEC)
issued interpretive guidance regarding asset impairment measurement which
concluded that any supplemental regulated cash flows such as a competitive
transition charge (CTC) should be excluded from the cash flows of assets in a
portion of the business not subject to regulatory accounting practices. If those
assets are impaired, a regulatory asset should be established if the costs are
recoverable through regulatory cash flows. Consistent with the SEC guidance,
Penn reduced its nuclear generating unit investments by approximately $305
million, of which approximately $227 million was recognized as a regulatory
asset to be recovered through a CTC over a seven-year transition period; the
remaining net amount of $78 million was written off. The charge of $51.7 million
($30.5 million after income taxes) for discontinuing the application of
Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the
Effects of Certain Types of Regulation" (SFAS 71), to Penn's generation business
was recorded as a 1998 extraordinary item on the Consolidated Statement of
Income.
All of the Companies' regulatory assets are being recovered under
provisions of the regulatory plans. In addition, the PUCO has authorized OE to
recognize additional capital recovery related to its generating assets (which is
reflected as additional depreciation expense) and additional amortization of
regulatory assets during the regulatory plan period of at least $2 billion, and
the PPUC had authorized Penn to accelerate at least $358 million, more than the
amounts that would have been recognized if the regulatory plans were not in
effect. These additional amounts are being recovered through current rates. As
of December 31, 1999, OE's and Penn's cumulative additional capital recovery and
regulatory asset amortization amounted to $1.048 billion (including Penn's
impairment discussed above and CTC recovery). CEI and TE recognized a fair value
purchase accounting adjustment of $2.55 billion in connection with the
FirstEnergy
<PAGE> 65
merger; that fair value adjustment recognized for financial reporting purposes
will ultimately satisfy the $2 billion asset reduction commitment contained in
the CEI and TE regulatory plan. For regulatory purposes, CEI and TE will
recognize the accelerated amortization over the period that their rate plan is
in effect.
Application of SFAS 71 was discontinued in 1997 with respect to CEI 's
and TE's nuclear operations (see "Regulatory Assets" below) and in 1998 with
respect to Penn's generation operations (as described above). The following
summarizes net assets included in property, plant and equipment relating to
operations for which the application of SFAS 71 was discontinued, compared with
the respective company's total assets at December 31, 1999.
SFAS 71
Discontinued
Net Assets Total Assets
(In millions)
CEI $977 $6,209
TE 530 2,667
Penn 76 1,016
Property, Plant and Equipment -- Property, plant and equipment reflects
original cost (except for CEI's, TE's and Penn's nuclear generating units which
were adjusted to fair value), including payroll and related costs such as taxes,
employee benefits, administrative and general costs, and interest costs.
The Companies provide for depreciation on a straight-line basis at
various rates over the estimated lives of property included in plant in service.
The annual composite rate for OE's electric plant was approximately 3.0% in
1999, 1998 and 1997. The annual composite rate for Penn's electric plant was
approximately 2.5% in 1999 and 3.0% in 1998 and 1997. CEI's and TE's composite
rates were both approximately 3.4% in 1999 and 1998. In addition to the
straight-line depreciation recognized in 1999, 1998 and 1997, OE and Penn
recognized additional capital recovery of $95 million, $141 million (excluding
Penn's impairment) and $172 million, respectively, as additional depreciation
expense in accordance with their regulatory plans. Such additional charges in
the accumulated provision for depreciation were $517 million and $422 million as
of December 31, 1999 and 1998, respectively.
Annual depreciation expense in 1999 included approximately $31.0
million for future decommissioning costs applicable to the Companies' ownership
and leasehold interests in four nuclear generating units. The Companies' future
decommissioning costs reflect the increase in their ownership interests related
to the asset transfer with Duquesne Light Company (Duquesne) discussed below in
"Common Ownership of Generating Facilities." The Companies' share of the future
obligation to decommission these units is approximately $1.8 billion in current
dollars and (using a 4.0% escalation rate) approximately $4.5 billion in future
dollars. The estimated obligation and the escalation rate were developed based
on site specific studies. Payments for decommissioning are expected to begin in
2016, when actual decommissioning work begins. The Companies have recovered
approximately $315 million for decommissioning through their electric rates from
customers through December 31, 1999. If the actual costs of decommissioning the
units exceed the funds accumulated from investing amounts recovered from
customers, the Companies expect that additional amount to be recoverable from
their customers. The Companies have approximately $543.7 million invested in
external decommissioning trust funds as of December 31, 1999. This includes
additions to the trust funds and the corresponding liability of $123 million as
a result of the asset transfer. Earnings on these funds are reinvested with a
corresponding increase to the decommissioning liability. The Companies have also
recognized an estimated liability of approximately $36.7 million related to
decontamination and decommissioning of nuclear enrichment facilities operated by
the United States Department of Energy (DOE), as required by the Energy Policy
Act of 1992.
The Financial Accounting Standards Board (FASB) issued a proposed
accounting standard for nuclear decommissioning costs in 1996. If the standard
is adopted as proposed: (1) annual provisions for decommissioning could
increase; (2) the net present value of estimated decommissioning costs could be
recorded as a liability; and (3) income from the external decommissioning trusts
could be reported as investment income. The FASB subsequently expanded the scope
of the proposed standard to include other closure and removal obligations
related to long-lived assets. A revised proposal may be issued by the FASB in
the first quarter of 2000.
<PAGE> 66
Common Ownership of Generating Facilities -- The Companies and Duquesne
constituted the Central Area Power Coordination Group (CAPCO). The CAPCO
companies formerly owned and/or leased, as tenants in common, various power
generating facilities. Each of the companies is obligated to pay a share of the
costs associated with any jointly owned facility in the same proportion as its
interest. The companies' portions of operating expenses associated with jointly
owned facilities are included in the corresponding operating expenses on the
Consolidated Statements of Income.
On March 26, 1999, FirstEnergy completed its agreements with Duquesne
to exchange certain generating assets. All regulatory approvals were received by
October 1999. In December 1999, Duquesne transferred 1,436 megawatts owned by
Duquesne at eight CAPCO generating units in exchange for 1,328 megawatts at
three non-CAPCO power plants owned by the Companies. The agreements for the
exchange of assets, which was structured as a like-kind exchange for tax
purposes, provides the Companies with exclusive ownership and operating control
of all CAPCO generating units. The three FirstEnergy plants transferred are
being sold by Duquesne to a wholly owned subsidiary of Orion Power Holdings,
Inc. (Orion). The Companies will continue to operate those plants until the
assets are transferred to the new owners. Duquesne funded decommissioning costs
equal to its percentage interest in the three nuclear generating units that were
transferred to FirstEnergy. The Duquesne asset transfer to the Orion subsidiary
could take place by the middle of 2000. Under the agreements, Duquesne is no
longer a participant in the CAPCO arrangements after the exchange.
Nuclear Fuel - OE's and Penn's nuclear fuel is recorded at original
cost, which includes material, enrichment, fabrication and interest costs
incurred prior to reactor load. CEI and TE severally lease their respective
portions of nuclear fuel and pay for the fuel as it is consumed (see Note 2).
The Companies amortize the cost of nuclear fuel based on the rate of
consumption. The Companies' electric rates include amounts for the future
disposal of spent nuclear fuel based upon the formula used to compute payments
to the DOE.
Income Taxes - Details of the total provision for income taxes are
shown on the Consolidated Statements of Taxes. Deferred income taxes result from
timing differences in the recognition of revenues and expenses for tax and
accounting purposes. Investment tax credits, which were deferred when utilized,
are being amortized over the recovery period of the related property. The
liability method is used to account for deferred income taxes. Deferred income
tax liabilities related to tax and accounting basis differences are recognized
at the statutory income tax rates in effect when the liabilities are expected to
be paid. Alternative minimum tax credits of $101 million, which may be carried
forward indefinitely, are available to reduce future federal income taxes.
Retirement Benefits - The Companies' trusteed, noncontributory defined
benefit pension plan covers almost all full-time employees. Upon retirement,
employees receive a monthly pension based on length of service and compensation.
In 1998, the Centerior Energy Corporation (Centerior) pension plan was merged
into the FirstEnergy pension plan. The Companies use the projected unit credit
method for funding purposes and were not required to make pension contributions
during the three years ended December 31, 1999. The assets of the pension plan
consist primarily of common stocks, United States government bonds and corporate
bonds.
The Companies provide a minimum amount of noncontributory life
insurance to retired employees in addition to optional contributory insurance.
Health care benefits, which include certain employee deductibles and copayments,
are also available to retired employees, their dependents and, under certain
circumstances, their survivors. The Companies pay insurance premiums to cover a
portion of these benefits in excess of set limits; all amounts up to the limits
are paid by the Companies. The Companies recognize the expected cost of
providing other postretirement benefits to employees and their beneficiaries and
covered dependents from the time employees are hired until they become eligible
to receive those benefits.
<PAGE> 67
The following sets forth the funded status of the plans and amounts
recognized on the Consolidated Balance Sheets as of December 31:
<TABLE>
<CAPTION>
Other
Pension Benefits Postretirement Benefits
(In millions)
Change in benefit obligation:
<S> <C> <C> <C> <C>
Benefit obligation as of January 1 $ 1,500.1 $ 1,327.5 $ 601.3 $ 534.1
Service cost 28.3 25.0 9.3 7.5
Interest cost 102.0 92.5 40.7 37.6
Plan amendments -- 44.3 -- 40.1
Actuarial loss (gain) (155.6) 101.6 (17.6) 10.7
Net increase from asset swap 14.8 -- 12.5 --
Benefits paid (95.5) (90.8) (37.8) (28.7)
Benefit obligation as of December 31 1,394.1 1,500.1 608.4 601.3
Change in plan assets:
Fair value of plan assets as of January 1 1,683.0 1,542.5 3.9 2.8
Actual return on plan assets 220.0 231.3 0.6 0.7
Company contribution -- -- 0.4 0.4
Benefits paid (95.5) (90.8) -- --
Fair value of plan assets as of December 31 1,807.5 1,683.0 4.9 3.9
Funded status of plan 413.4 182.9 (603.5) (597.4)
Unrecognized actuarial loss (gain) (303.5) (110.8) 24.9 30.6
Unrecognized prior service cost 57.3 63.0 24.1 27.4
Unrecognized net transition obligation (asset) (10.1) (18.0) 120.1 129.3
Prepaid (accrued) benefit cost $ 157.1 $ 117.1 $ (434.4) $ (410.1)
Assumptions used as of December 31:
Discount rate 7.75% 7.00% 7.75% 7.00%
Expected long-term return on plan assets 10.25% 10.25% 10.25% 10.25%
Rate of compensation increase 4.00% 4.00% 4.00% 4.00%
</TABLE>
Net pension and other postretirement benefit costs for the three years
ended December 31, 1999 were computed as follows:
<TABLE>
<CAPTION>
Other
Pension Benefits Postretirement Benefits
(In millions)
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 28.3 $ 25.0 $ 15.2 $ 9.3 $ 7.5 $ 4.6
Interest cost 102.0 93.5 55.9 40.7 37.6 20.4
Expected return on plan assets (168.1) (152.7) (99.7) (0.4) (0.3) (0.2)
Amortization of transition obligation (asset) (7.9) (8.0) (8.0) 9.2 9.2 8.2
Amortization of prior service cost 5.7 2.3 2.1 3.3 (0.8) 0.3
Recognized net actuarial loss (gain) -- (2.6) (0.9) -- -- --
Voluntary early retirement program expense -- -- 54.5 -- -- 1.9
Net benefit cost $ (40.0) $ (43.5) $ 19.1 $ 62.1 $ 53.2 $ 35.2
</TABLE>
The health care trend rate assumption is 5.3% in 2000, 5.2% in 2001 and
5.0% for 2002 and later years. Assumed health care cost trend rates have a
significant effect on the amounts reported for the health care plan. An increase
in the health care trend rate assumption by one percentage point would increase
the total service and interest cost components by $4.5 million and the
postretirement benefit obligation by $72.0 million. A decrease in the same
assumption by one percentage point would decrease the total service and interest
cost components by $3.5 million and the postretirement benefit obligation by
$58.2 million.
Supplemental Cash Flows Information -- All temporary cash investments
purchased with an initial maturity of three months or less are reported as cash
equivalents on the Consolidated Balance Sheets. At December 31, 1999 and 1998,
cash and cash equivalents included $83 million and $26 million, respectively, to
be used for the redemption of long-term debt in the first quarter of 2000 and in
1999, respectively. The Companies reflect temporary cash investments at cost,
which approximates their fair market value. Noncash financing and investing
activities included capital lease transactions amounting to $36.2 million, $61.8
million and $3.0 million for the years 1999, 1998 and 1997, respectively.
Commercial paper transactions of OES Fuel, Incorporated (OES Fuel) (a wholly
owned subsidiary of OE) that have initial maturity periods of three months or
less are reported net within financing activities under long-term debt and are
reflected as long-term debt on the Consolidated Balance Sheets (see Note 3H).
<PAGE> 68
All borrowings with initial maturities of less than one year are
defined as financial instruments under generally accepted accounting principles
and are reported on the Consolidated Balance Sheets at cost, which approximates
their fair market value. The following sets forth the approximate fair value
and related carrying amounts of all other long-term debt, preferred stock
subject to mandatory redemption and investments other than cash and cash
equivalents as of December 31:
<TABLE>
<CAPTION>
Carrying Fair Carrying Fair
Value Value Value Value
(In millions)
<S> <C> <C> <C> <C>
Long-term debt $6,381 $6,331 $6,783 $7,247
Preferred stock $ 295 $ 280 $ 335 $ 340
Investments other than cash and cash equivalents:
Debt securities
-Maturity (5-10 years) $ 475 $ 476 $ 481 $ 520
-Maturity (more than (0 years) 1,068 1,013 1,109 1,139
Equity securities 17 17 17 17
All other 852 874 520 533
$2,412 $2,380 $2,127 $2,209
</TABLE>
The fair values of long-term debt and preferred stock reflect the
present value of the cash outflows relating to those securities based on the
current call price, the yield to maturity or the yield to call, as deemed
appropriate at the end of each respective year. The yields assumed were based on
securities with similar characteristics offered by a corporation with credit
ratings similar to the Companies' ratings.
The fair value of investments other than cash and cash equivalents
represent cost (which approximates fair value) or the present value of the cash
inflows based on the yield to maturity. The yields assumed were based on
financial instruments with similar characteristics and terms. Investments other
than cash and cash equivalents include decommissioning trust investments.
Unrealized gains and losses applicable to the decommissioning trusts have been
recognized in the trust investment with a corresponding change to the
decommissioning liability. The debt and equity securities referred to above are
in the held-to-maturity category, The Companies have no securities held for
trading purposes.
Effective December 31, 1998, the Company began accounting for its
commodity price derivatives, entered into specifically for trading purposes, on
a mark-to-market basis in accordance with Emerging Issues Task Force Issue
98-10, "Accounting for Energy Trading arid Risk Management Activities," with
gains and losses recognized currently in the Consolidated Statements of Income.
The contracts that were marked to market are included in the Consolidated
Balance Sheets as Deferred Charges and Deferred Credits at their fair values.
The impact on the consolidated financial statements was immaterial.
Regulatory Assets - The Companies recognize, as regulatory assets,
costs which the FERC, PUCO and PPUC have authorized for recovery from customers
in future periods. Without such authorization, the costs would have been charged
to income as incurred. All regulatory assets are being recovered from customers
under the Companies' respective regulatory plans. Based on those regulatory
plans, at this time, the Companies are continuing to bill and collect cost-based
rates relating to all of OE's operations, CEI's and TE's nonnuclear operations,
and Penn's nongeneration operations and they continue the application of SFAS 71
to those respective operations. OE and Penn recognized additional cost recovery
of $257 million, $50 million and $39 million in 1999, 1998 and 1997,
respectively, as additional regulatory asset amortization in accordance with
their regulatory plans. FirstEnergy's regulatory plan does not provide for full
recovery of CEI's and TE's nuclear operations. As a result, in October 1997,
CEI and TE discontinued application of SFAS 71 for their nuclear operations and
decreased their regulatory assets of customer receivables for future income
taxes related to the nuclear assets by $794 million.
The PUCO indicated that it will endeavor to issue its order related to
the Company's transition plan by mid-2000. The application of SFAS 71 to OE's
generation business and the nonnuclear generation businesses of CEI and TE will
be discontinued at that time. If the transition plans ultimately approved by the
PUCO for OE, CEI and TE do not provide adequate recovery of their nuclear
generating unit investments and regulatory assets, there would be a charge to
earnings which could have a material adverse effect on the results of operations
and financial condition for the Company, OE, CEI and TE. The Companies will
continue to bill and collect cost-based rates for their transmission and
distribution services, which will remain regulated; accordingly, it is
appropriate that the Companies continue the application of SFAS 71 to those
respective operations after December 31, 2000.
<PAGE> 69
Net regulatory assets on the Consolidated Balance Sheets are comprised
of the following:
<TABLE>
<CAPTION>
(In millions)
<S> <C> <C>
Nuclear unit expenses $ 1,123.0 $ 1,164.8
Customer receivables for future income taxes 444.3 444.0
Rate stabilization program deferrals 420.1 440.1
Sale and leaseback costs 17.8 218.7
Competitive transition charge 280.4 331.0
Loss on reacquired debt 173.9 183.5
Employee postretirement benefit costs 24.8 28.9
DOE decommissioning and decontamination costs 29.5 32.9
Other 29.6 43.5
Total $ 2,543.4 $ 2,887.4
</TABLE>
The Companies lease certain generating facilities, nuclear fuel, office
space and other property and equipment under cancelable arid noncancelable
leases.
OE sold portions of its ownership interests in Perry Unit 1 and Beaver
Valley Unit 2 and entered into operating leases on the portions sold for basic
lease terms of approximately 29 years. CEI and TE also sold portions of their
ownership interests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3
and entered into similar operating leases for lease terms of approximately 30
years. During the terms of their respective leases, OE, CEI and TE continue to
be responsible, to the extent of their individual combined ownership and
leasehold interests, for costs associated with the units including construction
expenditures, operation and maintenance expenses, insurance, nuclear fuel,
property taxes and decommissioning. They have the right, at the end of the
respective basic lease terms, to renew their respective leases. They also have
the right to purchase the facilities at the expiration of the basic lease term
or renewal term (if elected) at a price equal to the fair market value of the
facilities. The basic rental payments are adjusted when applicable federal tax
law changes.
OES Finance, Incorporated (OES Finance), a wholly owned subsidiary of
OE, maintains deposits pledged as collateral to secure reimbursement obligations
relating to certain letters of credit supporting OE's obligations to lessors
under the Beaver Valley Unit 2 sale and leaseback arrangements. The deposits
pledged to the financial institution providing those letters of credit are the
sole property of OES Finance. In the event of liquidation, OES Finance, as a
separate corporate entity, would have to satisfy its obligations to creditors
before any of its assets could be made available to OE as sole owner of OES
Finance common stock.
Nuclear fuel is currently financed for CEI and TE through leases with a
special-purpose corporation. As of December 31,1999, $116 million of nuclear
fuel was financed under a lease financing arrangement totaling $145 million
($30 million of intermediate-term notes arid $115 million from bank credit
arrangements). The notes mature in August 2000 and the bank credit arrangements
expire in September 2000. Lease rates are based on intermediate-term note rates,
bank rates and commercial paper rates.
Consistent with the regulatory treatment, the rentals for capital and
operating leases are charged to operating expenses on the Consolidated
Statements of Income. Such costs for the three years ended December 31, 1999,
are summarized as follows:
(In millions)
Operating leases
Interest element $ 208.6 $ 201.2 $ 149.9
Other 110.3 147.8 45.2
Capital leases
Interest element 17.5 17.6 6.1
Other 76.1 66.3 6.0
Total rentals $ 412.5 $ 432.9 $ 207.2
The future minimum lease payments as of December 31, 1999, are:
<TABLE>
<CAPTION>
Operating Leases
Capital Lease Capital
Leases Payments Trusts Net
(in millions)
<C> <C> <C> <C> <C>
2000 $ 75.4 $ 296.5 $ 150.6 $ 145.9
2001 45.2 307.5 146.1 161.4
2002 29.7 312.7 169.5 143.2
2003 16.0 326.6 176.5 150.1
2004 12.1 291.8 110.7 181.1
Years thereafter 71.6 3,645.8 1,364.3 2,281.5
Total minimum lease payments 250.0 $ 5,180.9 $ 2,117.7 $ 3,063.2
Executory costs 26.9
Net minimum lease payments 223.1
Interest portion 64.8
Present value of net minimum
lease payments 158.3
Less current portion 55.2
Noncurrent portion $103.1
</TABLE>
<PAGE> 70
OE invested in the PNBV Capital Trust, which was established to
purchase a portion of the lease obligation bonds issued on behalf of lessors in
OE's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. CEI
and TE established the Shippingport Capital Trust to purchase the lease
obligation bonds issued on behalf of lessors in their Bruce Mansfield Units 1, 2
and 3 sale and leaseback transactions. The PNBV and Shippingport capital trust
arrangements effectively reduce lease costs related to those transactions.
(A) Retained Earnings - There are no restrictions on retained
earnings for payment of cash dividends on the Company's common stock.
(B) Employee Stock Ownership Plan - The Companies fund the matching
contribution for their 401(k) savings plan through an ESOP Trust. All full-time
employees eligible for participation in the 401(k) savings plan are covered by
the ESOP. The ESOP borrowed $200 million from OE and acquired 10,654,114 shares
of OE's common stock through market purchases; the shares were converted into
the Company's common stock in connection with the merger. Dividends on ESOP
shares are used to service the debt. Shares are released from the ESOP on a pro
rata basis as debt service payments are made. In 1999, 1998 and 1997, 627,427
shares, 423,206 shares and 429,515 shares, respectively, were allocated to
employees with the corresponding expense recognized based on the shares
allocated method. The fair value of 6,778,905 shares unallocated as of December
31, 1999, was approximately $153.8 million. Total ESOP-related compensation
expense was calculated as follows:
(In millions)
Base compensation $ 18.3 $ 13.5 $ 9.9
Dividends on common stock
held by the ESOP and
used to service debt (4.5) (3.9) (3.4)
Net expense $ 13.8 $ 9.6 $ 6.5
(C) Stock Compensation Plans -- Under the Centerior Equity Compensation
Plan (Centerior Plan) adopted in 1994, common stock options were granted to
management employees. Upon consummation of the merger, outstanding options
became exercisable for the Company's common stock with option prices and the
number of shares adjusted to reflect the merger conversion ratio. All options
under the Centerior Plan expire on or before February 25, 2007.
On April 30,1998, the Company adopted the Executive and Director
Incentive Compensation Plan (FE Plan). The FE Plan permits awards to be made to
key employees in the form of restricted stock, stock options, stock appreciation
rights, performance shares or cash. Common stock granted under the FE Plan may
not exceed 7.5 million shares. No stock appreciation rights or performance
shares have been issued under the FE Plan. A total of 20,000 shares of
restricted stock were granted in 1998, with a per share market price of $30.78.
Restrictions on the restricted stock lapse in 25% annual increments beginning in
the fourth year from date of grant. Dividends on the 1998 grant are not
restricted. An additional 8,000 shares of restricted stock were granted in 1999,
in five separate awards with a weighted average market price per share of $30.89
and weighted average cliff vesting period of 5.8 years. Dividends on the 1999
grants are being restricted. Options were granted in 1998 arid 1999, and are
exercisable after four years from the date of grant with some acceleration of
vesting possible based on performance. Stock option activity for the converted
Centerior Plan stock options and FE Plan stock options was as follows:
Weighted
Average
Number of Exercise
Options Price
Stock Option Activity
Balance at December 31, 1996 -- $ --
Options granted (at merger) 743,086 23.85
Options exercised 222,023 22.13
Options forfeited 3,675 22.75
Balance at December 31, 1997 517,388 24.59
(517,388 options exercisable)
Options granted 189,491 29.82
Options exercised 335,058 24.67
Options forfeited 7,535 29.82
Balance at December 31, 1998 364,286 27.13
(182,330 options exercisable)
Options granted 1,811,658 24.90
Options exercised 22,575 21.42
Balance at December 31,1999 2,153,369 25.32
(159,755 options exercisable)
<PAGE> 71
As of December 31, 1999, the weighted average remaining contractual
life of outstanding stock options was 6.2 years.
Under the Executive Deferred Compensation Plan, adopted January 1,
1999, employees can direct a portion of their Annual Incentive Award and/or Long
Term Incentive Award into an unfunded FirstEnergy Stock Account to receive
vested stock units. An additional 20% premium is received in the form of stock
units based on the amount allocated to the FirstEnergy Stock Account. Dividends
are calculated quarterly on stock units outstanding and are paid in the form of
additional stock units. Upon withdrawal, stock units are converted to
FirstEnergy shares. Payout occurs three years from the date of deferral. As of
December 31, 1999, there were 61,465.81 stock units outstanding.
The Company continues to apply APB Opinion 25, "Accounting for Stock
Issued to Employees." As required by SFAS 123, ""Accounting for Stock-Based
Compensation," the Company has determined pro forma earnings as though the
Company had accounted for employee stock options under the fair value method.
The weighted average assumptions used in valuing the options and their
resulting fair values are as follows:
Valuation assumptions:
Expected option term (years) 6.4 10 8
Expected volatility 20.03% 15.50% 16.00%
Expected dividend yield 5.97% 5.68% 5.80%
Risk-free interest rate 5.97% 5.65% 5.94%
Fair value per option $ 3.42 $ 3.25 $ 2.92
The pro forma effects of applying fair value accounting to the
Company's stock options would be to reduce net income and earnings per share.
The following table summarizes the pro forma effect.
Net Income (000)
As Reported $568,299 $410,874
Pro Forms $567,876 $410,839
Earnings Per Share
of Common Stock -
Basic and Diluted
As Reported $2.50 $1.82
Pro Forma $2.50 $1.82
(D) Comprehensive Income - In 1998, the Company adopted SFAS 130,
"Reporting Comprehensive Income," and applied the standard to all periods
presented in the Consolidated Statements of Common Stockholders' Equity.
Comprehensive income includes net income as reported on the Consolidated
Statements of Income and all other changes in common stockholders' equity except
those resulting from transactions with common stockholders.
(E) Preferred and Preference Stock - Penn's 7.75% series of preferred
stock has a restriction which prevents early redemption prior to July 2003. OE's
8.45% series of preferred stock has no optional redemption provision. CEI's
$88.00 Series R preferred stock is not redeemable before December 2001 and its
$90.00 Series S has no optional redemption provision. All other preferred stock
may be redeemed by the Companies in whole, or in part, with 30-90 days' notice.
Preference stock authorized for the Companies are 8 million shares
without par value for OE; 3 million shares without par value for CEI; and 5
million shares, $25 par value for TE. No preference shares are currently
outstanding.
(F) Preferred Stock Subject to Mandatory Redemption - Annual sinking
fund provisions for the Companies' preferred stock are as follows:
Redemption
Price Per
Series Shares Share Date Beginning
OE 8.45% 50,000 $ 100 (i)
CEI $ 7.35 C 10,000 100 (i)
88.00 E 3,000 1,000 (i)
91.50 Q 10,714 1,000 (i)
90.00 S 18,750 1,000 (i)
88.00 R 50,000 1,000 December 1 2001
Penn 7.625 % 7,500 100 October 1 2002
(i) Sinking fund provisions are in effect.
Annual sinking fund requirements for the next five years are $38
million in 2000, $85 million in 2001, $19 million in 2002, $2 million in 2003
and $2 million in 2004. A liability of$19 million was included in the net assets
acquired from CEI and TE for preferred dividends declared attributable to the
post-merger period. Accordingly, no accruals for CEI and TE preferred dividends
are included in the Company's Consolidated Statement of Income for the period
November 8,1997 through December 31, 1997.
<PAGE> 72
(G) Ohio Edison Obligated Mandatorily Redeemable Preferred Securities
of Subsidiary Trust Holding Solely Ohio Edison Subordinated Debentures - Ohio
Edison Financing Trust, a wholly owned subsidiary of OE, has issued $120 million
of 9% Cumulative Trust Preferred Capital Securities. GE purchased all of the
Trust's Common Securities and simultaneously issued to the Trust $123.7 million
principal amount of 9% Junior Subordinated Debentures due 2025 in exchange for
the proceeds that the Trust received from its sale of Preferred and Common
Securities. The sole assets of the Trust are the Subordinated Debentures whose
interest and other payment dates coincide with the distribution and other
payment dates on the Trust Securities. Under certain circumstances, the
Subordinated Debentures could be distributed to the holders of the outstanding
Trust Securities in the event the Trust is liquidated. The Subordinated
Debentures may be optionally redeemed by GE beginning December 31, 2000, at a
redemption price of $25 per Subordinated Debenture plus accrued interest, in
which event the Trust Securities will be redeemed on a pro rata basis at $25 per
share plus accumulated distributions. OE's obligations under the Subordinated
Debentures along with the related Indenture, amended and restated Trust
Agreement, Guarantee Agreement and the Agreement for expenses and liabilities,
constitute a full and unconditional guarantee by GE of payments due on the
Preferred Securities.
(H) Long-Term Debt - The first mortgage indentures and their
supplements, which secure all of the Companies' first mortgage bonds, serve as
direct first mortgage liens on substantially all property and franchises,
other than specifically excepted property, owned by the Companies.
Based on the amount of bonds authenticated by the Trustees through
December 31,1999, OE's, TE's and Penn's annual sinking and improvement fund
requirements for all bonds issued under the mortgage amounts to $31 million. OE,
TE and Penn expect to deposit funds in 2000 that will be withdrawn upon the
surrender for cancellation of a like principal amount of bonds, which are
specifically authenticated for such purposes against unfunded property
additions or against previously retired bonds. This method can result in minor
increases in the amount of the annual sinking fund requirement.
Sinking fund requirements for first mortgage bonds and maturing
long-term debt (excluding capital leases) for the next five years are:
(In millions)
2000 $668.8
2001 375.7
2002 945.8
2003 459.0
2004 833.3
The Companies' obligations to repay certain pollution control revenue
bonds are secured by several series of first mortgage bonds and, in some cases,
by subordinate liens on the related pollution control facilities. Certain
pollution control revenue bonds are entitled to the benefit of irrevocable bank
letters of credit of $397.3 million. To the extent that drawings are made under
those letters of credit to pay principal of, or interest on, the pollution
control revenue bonds, OE, Penn and/or CEI are entitled to a credit against
their obligation to repay those bonds. The Companies pay annual fees of 0.43% to
1.10% of the amounts of the letters of credit to the issuing banks and are
obligated to reimburse the banks for any drawings thereunder.
<PAGE> 73
OE had unsecured borrowings of$190 million at December 31, 1999,
supported by a $250 million long-term revolving credit facility agreement which
expires November 18, 2002. OE must pay an annual facility fee of 0.20% on the
total credit facility amount. In addition, the credit agreement provides that
OE maintain unused first mortgage bond capability for the full credit agreement
amount under OE's indenture as potential security for the unsecured borrowings.
CEI and TE have letters of credit of approximately $222 million in
connection with the sale and leaseback of Beaver Valley Unit 2 that expire in
May 2002. The letters of credit are secured by first mortgage bonds of CEI and
TE in the proportion of 40% and 60%, respectively (see Note 2).
OE's and Penn's nuclear fuel purchases are financed through the
issuance of OES Fuel commercial paper and loans, both of which are supported by
a $180.5 million long-term bank credit agreement which expires March 31, 2001.
Accordingly, the commercial paper and loans are reflected as long-term debt on
the Consolidated Balance Sheets. OES Fuel must pay an annual facility fee of
0.20% on the total line of credit and an annual commitment fee of 0.0625% on any
unused amount.
Short-term borrowings outstanding at December 31, 1999, consisted of
$257.8 million of bank borrowings and $160.0 million of OES Capital,
Incorporated (OES Capital) commercial paper. OES Capital is a wholly owned sub-
sidiary of OE whose borrowings are secured by customer accounts receivable. OES
Capital can borrow up to $170 million under a receivables financing agreement at
rates based on certain bank commercial paper and is required to pay an annual
fee of 0.20% on the amount of the entire finance limit. The receivables
financing agreement expires in 2002.
The Companies have various credit facilities with domestic banks that
provide for borrowings of up to $205 million under various interest rate
options. OE's short-term borrowings may be made under its lines of credit on
its unsecured notes. To assure the availability of these lines, the Companies
are required to pay annual commitment fees that vary from 0.125% to 0.50%. These
lines expire at various times during 2000. The weighted average interest rates
on short-term borrowings outstanding at December 31, 1999 and 1998, were 6.51%
and 5.67%, respectively.
Capital Expenditures - The Companies' current forecasts reflect
expenditures of approximately $3.0 billion for property additions and
improvements from 2000-2004, of which approximately $650 million is applicable
to 2000. Investments for additional nuclear fuel during the 2000-2004 period are
estimated to be approximately $497 million, of which approximately $159 million
applies to 2000. During the same periods, the Companies' nuclear fuel
investments are expected to be reduced by approximately $480 million and $106
million, respectively, as the nuclear fuel is consumed.
Stock Repurchase Program - On November 17, 1998, the Board of Directors
authorized the repurchase of up to 15 million shares of the Company's common
stock over a three-year period beginning in 1999. Repurchases are made on the
open market, at prevailing prices, and are funded primarily through the use of
operating cash flows. During 1999, the Company repurchased and retired 4.6
million shares of its common stock at an average price of $28.08 per share. The
Company also entered into a forward contract with Credit Suisse First Boston
Corporation for the purchase of 1.4 million shares of the Company's common stock
at an average price of $24.22 per share to be settled on November 3, 2000. The
contract may be settled through gross physical settlement, net share settlement
or net cash settlement at the Company's election.
<PAGE> 74
Nuc]ear Insurance - The Price-Anderson Act limits the public liability
relative to a single incident at a nuclear power plant to $9.5 billion. The
amount is covered by a combination of private insurance and an industry
retrospective rating plan. The Companies' maximum potential assessment under the
industry retrospective rating plan would be $352.4 million per incident but not
more than $40 million in any one year for each incident.
The Companies are also insured under policies for each nuclear plant.
Under these policies, up to $2.75 billion is provided for property damage and
decontamination and decommissioning costs. The Companies have also obtained
approximately $1.43 billion of insurance coverage for replacement power costs.
Under these policies, the Companies can be assessed a maximum of approximately
$44 million for incidents at any covered nuclear facility occurring during a
policy year which are in excess of accumulated funds available to the insurer
for paying losses.
The Companies intend to maintain insurance against nuclear risks as
described above as long as it is available. To the extent that replacement
power, property damage, decontamination, decommissioning, repair and replacement
costs and other such costs arising from a nuclear incident at any of the
Companies' plants exceed the policy limits of the insurance in effect with
respect to that plant, to the extent a nuclear incident is determined not to be
covered by the Companies' insurance policies, or to the extent such insurance
becomes unavailable in the future, the Companies would remain at risk for such
costs.
Environmental Matters - Various federal, state and local authorities
regulate the Companies with regard to air and water quality and other
environmental matters. The Companies estimate additional capital expenditures
for environmental compliance of approximately $292 million, which is included in
the construction forecast provided under "Capital Expenditures" for 2000 through
2004.
The Companies are in compliance with the current sulfur dioxide (SO
(subscript 2)) and nitrogen oxides (NOx) reduction requirements under the Clean
Air Act Amendments of 1990. SO(subscript 2) reductions are being achieved by
burning lower-sulfur fuel, generating more electricity from lower-emitting
plants, and/or purchasing emission allowances. NOx reductions are being achieved
through combustion controls and generating more electricity from lower-emitting
plants. In September 1998, the Environmental Protection Agency (EPA) finalized
regulations requiring additional NOx reductions from the Companies' Ohio and
Pennsylvania facilities by May 2003. The EPA's NOx Transport Rule imposes
uniform reductions of NOx emissions across a region of twenty-two states and the
District of Columbia, including Ohio and Pennsylvania, based on a conclusion
that such NOx emissions are contributing significantly to ozone pollution in the
eastern United States. In May 1999, the U.S. Court of Appeals for the D.C.
Circuit issued a stay which delays implementation of EPA's NOx Transport Rule
until the Court has ruled on the merits of various appeals. Under the NOx
Transport Rule, each of the twenty-two states are required to submit revised
State Implementation Plans (SIP) which comply with individual state NOx budgets
established by the EPA contemplating an approximate 85% reduction in utility
plant NOx emissions from projected 2007 emissions. A proposed Federal
Implementation Plan accompanied the NOx Transport Rule and may be implemented by
the EPA in states which fail to revise their SIP. In another separate but
related action, eight states filed petitions with the EPA under Section 126 of
the Clean Air Act seeking reductions of NOx emissions which are alleged to
contribute to ozone pollution in the eight petitioning states. The EPA suggests
that the Section 126 petitions will be adequately addressed by the NOx Transport
Program, but a December 17, 1999 rulemaking established an alternative program
which would require nearly identical 85% NOx reductions at 392 utility plants,
including the Companies' Ohio and Pennsylvania plants, by May 2003, in the event
implementation of the NOx Transport Rule is delayed. New Section 126 petitions
were filed by New Jersey, Maryland, Delaware and the District of Columbia in
mid-1999 and are still under evaluation by the EPA. The Companies continue to
evaluate their compliance plans and other compliance options.
<PAGE> 75
The Companies are required to meet federally approved SO(subscript 2)
regulations. Violations of such regulations can result in shutdown of the
generating unit involved and/or civil or criminal penalties of up to $27,500
for each day the unit is in violation. The EPA has an interim enforcement
policy for $02 regulations in Ohio that allows for compliance based on a 30-day
averaging period. The Companies cannot predict what action the EPA may take in
the future with respect to the interim enforcement policy.
In July 1997, the EPA promulgated changes in the National Ambient Air
Quality Standard (NAAQS) for ozone and proposed a new NAAQS for previously
unregulated ultra-fine particulate matter. In May 1999, the U.S. Court of
Appeals for the D.C. Circuit remanded both standards back to the EPA finding
constitutional and other defects in the new NAAQS rules. The D.C. Circuit Court,
on October 29, 1999, denied an EPA petition for rehearing. The Companies cannot
predict the EPA's action in response to the Court's remand order. The cost of
compliance with these regulations, if they are reinstated, may be substantial
and depends on the manner in which they are ultimately implemented, if at all,
by the states in which the Companies operate affected facilities.
In September 1999, FirstEnergy received, and subsequently in October
1999, OE and Penn received, a citizen suit notification letter from the New York
Attorney General's office alleging Clean Air Act violations at the W. H. Sammis
Plant. In November 1999, OE and Penn received a citizen suit notification letter
from the Connecticut Attorney General's office alleging Clean Air Act violations
at the Sammis Plant. On November 3, 1999, the EPA issued Notices of Violation
(NOV) or a Compliance Order to eight utilities covering 32 power plants,
including the Sammis Plant. In addition, the U.S. Department of Justice filed
seven civil complaints against various investor-owned utilities, which included
a complaint against OE and Penn in the U.S. District Court for the Southern
District of Ohio. The NOV and complaint allege violations of the Clean Air Act
based on operation and maintenance of the Sammis Plant dating back to 1984. The
complaint requests permanent injunctive relief to require the installation of
"best available control technology" and civil penalties of up to $27,500 per day
of violation. Although unable to predict the outcome of this litigation, the
Company believes the Sammis Plant is in full compliance with the Clean Air Act
and the NOV and complaint are without merit. Penalties could be imposed if the
Sammis Plant continues to operate without correcting the alleged violations and
a court determines that the allegations are valid. It is anticipated at this
time that the Sammis Plant will continue to operate while the matter is being
decided.
CEI and TE have been named as "potentially responsible parties" (PRPs)
at waste disposal sites which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved,
are often unsubstantiated and subject to dispute. Federal law provides that all
PRPs for a particular site be held liable on a joint and several basis. CEI and
TE have accrued liabilities totaling $5.4 million as of December 31, 1999, based
on estimates of the costs of cleanup and the proportionate responsibility of
other PRPs for such costs. CEI and TE believe that waste disposal costs will not
have a material adverse effect on their financial condition, cash flows or
results of operations.
The Company's primary segment is its Electric Utility Operating
Companies which includes four regulated electric utility operating companies
that provide electric service in Ohio and Pennsylvania. Its other material
business segment is FETS which markets and trades electricity in nonregulated
markets. Financial data for these business segments and products and services
are as shown on the following page:
<PAGE> 76
<TABLE>
<CAPTION>
Electric FE Trading All Reconciling
Utilities Services Other Eliminations Totals
(In millions)
1999
<S> <C> <C> <C> <C> <C>
External revenues $ 5,421 $ 191 $ 708 $ -- $ 6,320
Intersegment revenues 32 60 102 (194) --
Total revenues 5,453 251 810 (194) 6,320
Depreciation and amortization 913 -- 25 -- 938
Net interest charges 549 6 66 (49) 572
Income taxes 377 (5) 23 -- 395
Net income/Earnings on common stock 545 (8) 35 (4) 568
Total assets 17,105 181 1,864 (926) 18,224
Property additions 417 -- 130 -- 547
Acquisitions -- 25 53 -- 78
1998
External revenues $ 5,215 $ 411 $ 249 $ -- $ 5,875
Intersegment revenues 32 26 97 (155) --
Total revenues 5,247 437 346 (155) 5,875
Depreciation and amortization 748 -- 11 -- 759
Net interest charges 590 2 69 (60) 601
Income taxes 320 (35) (2) -- 283
Extraordinary item:
Pennsylvania restructuring (31) -- -- -- (31)
Net income/Earnings on common stock 478 (52) 1 (16) 411
Total assets 18,316 54 1,742 (1,920) 18,192
Property additions 304 -- 64 -- 368
Acquisitions -- -- 285 -- 285
1997
External revenues $ 2,844 $ 43 $ 74 $ -- $ 2,961
Intersegment revenues 33 -- 106 (139) --
Total revenues 2,877 43 180 (139) 2,961
Depreciation and amortization 470 -- 5 -- 475
Net interest charges 300 -- 60 (51) 309
Income taxes 206 -- 3 -- 209
Net income/Earnings on common stock 335 (1) 4 (32) 306
Total assets 18,700 32 1,209 (1,680) 18,261
Property additions 166 -- 38 -- 204
Acquisitions -- -- 1,582 -- 1,582
</TABLE>
Oil & Gas Energy Related
Electricity Sales and Sales and
Sales Production Services
(In millions)
Year
1999 $5,253 $ 203 $ 503
1998 4,980 26 198
1997 2,775 -- --
<PAGE> 77
The following summarizes certain consolidated operating results by
quarter for 1999 and 1998.
<TABLE>
<CAPTION>
Three Months Ended
March 31, June 30, September 30, December 31,
1999 1999 1999 1999
(In millions, except per share amounts)
<S> <C> <C> <C> <C>
Revenues $ 1,417.4 $ 1,523.9 $ 1,732.4 $ 1,645.9
Expenses 1,041.7 1,149.8 1,291.0 1,301.7
Income Before Interest
and Income Taxes 375.7 374.1 441.4 344.2
Net Interest Charges 146.1 147.4 141.3 137.5
Income Taxes 92.9 101.4 114.3 86.2
Net Income $ 136.7 $ 125.3 $ 185.8 $ 120.5
Earnings per Share of
Common Stock $.60 $.55 $.82 $.53
<CAPTION>
March 31, June 30, September 30, December 31,
Three Months Ended 1998 1998 1998 1998
(In millions, except per share amounts)
<S> <C> <C> <C> <C>
Revenues $ 1,367.1 $ 1,464.0 $ 1,722.0 $ 1,321.8
Expenses 1,016.8 1,197.1 1,294.0 1,020.8
Income Before Interest
and Income Taxes 350.3 266.9 428.0 301.0
Net Interest Charges 143.6 154.7 153.3 149.4
Income Taxes 83.0 52.2 111.7 56.9
Income Before Extraordinary Item 123.7 60.0 163.0 94.7
Extraordinary Item
(Net of Income Taxes)
(Note 1) -- (30.5) -- --
Net Income $ 123.7 $ 29.5 $ 163.0 $ 94.7
Earnings per Share of
Common Stock
Before Extraordinary Item $.56 $.27 $.71 $.41
Extraordinary Item
(Net of Income Taxes)
(Note 1) -- (.14) -- --
Earnings per Share of
Common Stock $.56 $.13 $.71 $.41
</TABLE>
The Company was formed on November 8,1997 by the merger of OE and
Centerior. The merger was accounted for as a purchase of Centerior's net assets
with 77,637,704 shares of FirstEnergy Common Stock through the conversion of
each outstanding Centerior Common Stock share into 0.525 of a share of
FirstEnergy Common Stock (fractional shares were paid in cash). Based on an
imputed value of $20.125 per share, the purchase price was approximately $1.582
billion, which also included approximately $20 million of merger related
costs. Goodwill of approximately $2.0 billion was recognized (to be amortized on
a straight-line basis over forty years), which represented the excess of the
purchase price over Centerior's net assets after fair value adjustments.
Accumulated amortization of goodwill was approximately $109 million as
of December 31, 1999. The merger purchase accounting adjustments, which were
recorded in the records of Centerior's direct subsidiaries, included recognizing
estimated severance and other compensation liabilities ($80 million). The amount
charged against the liability in 1998 relating to the costs of involuntary
employee separation was $41 million. In addition, the liability was reduced to
approximately $9 million as of December 31, 1998 to represent potential costs
associated with the separation of 493 CEI employees. The liability adjustment
was offset by a corresponding reduction to goodwill recognized in connection
with the Centerior acquisition.
The following pro forma statement of income of FirstEnergy gives effect
to the OE/Centerior merger as if it had been consummated on January 1, 1997,
with the purchase accounting adjustments actually recognized in the business
combination.
Year Ended
December 31,
1997
(In millions, except per share amounts)
Revenues $5,206
Expenses 3,800
Income Before Interest and Income Taxes 1,406
Net Interest Charges 643
Income Taxes 336
Net Income $ 427
Earnings per Share of Common Stock $ 1.92
Pro forma adjustments reflected above include: (1) adjusting CEI and TE
nuclear generating units to fair value based upon independent appraisals and
estimated discounted future cash flows based on management's estimate of cost
recovery; (2) goodwill recognized representing the excess of the purchase price
over Centerior's adjusted net assets; (3) elimination of revenue and expense
transactions between OE and Centerior; (4) amortization of the fair value
adjustment for long-term debt; and (5) adjustments for estimated tax effects on
the above adjustments.
<PAGE> 78
PART I. FINANCIAL INFORMATION
-----------------------------
FIRSTENERGY CORP. AND SUBSIDIARIES
OHIO EDISON COMPANY AND SUBSIDIARIES
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY AND SUBSIDIARY
THE TOLEDO EDISON COMPANY AND SUBSIDIARY
PENNSYLVANIA POWER COMPANY
NOTES TO FINANCIAL STATEMENTS
(Unaudited)
1 - FINANCIAL STATEMENTS:
The principal business of FirstEnergy Corp. (FirstEnergy) is the
holding, directly or indirectly, of all of the outstanding common stock of its
four principal electric utility operating subsidiaries, Ohio Edison Company
(OE), The Cleveland Electric Illuminating Company (CEI), The Toledo Edison
Company (TE) and Pennsylvania Power Company (Penn). These utility subsidiaries
are referred to throughout as "Companies." Penn is a wholly owned subsidiary of
OE.
The condensed unaudited financial statements of FirstEnergy and each of
the Companies reflect all normal recurring adjustments that, in the opinion of
management, are necessary to fairly present results of operations for the
interim periods. These statements should be read in connection with the
financial statements and notes included in the combined Annual Report on Form
10-K for the year ended December 31, 1999 for FirstEnergy and the Companies.
Significant intercompany transactions have been eliminated. The preparation of
financial statements in conformity with accounting principles generally accepted
in the United States requires management to make periodic estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses. Actual results could differ from those estimates. The reported
results of operations are not indicative of results of operations for any future
period. Certain prior year amounts have been reclassified to conform with the
current year presentation.
Penn's results of operations for the 1999 interim periods include Penn
and its wholly owned subsidiary, Penn Power Energy, Inc. (PPE). Penn's interest
in PPE was transferred to FirstEnergy Services Corp. (FE Services), an
affiliate, effective December 31, 1999.
The sole assets of the subsidiary trust that is the obligor on the
preferred securities included in FirstEnergy's and OE's capitalization are
$123,711,350 principal amount of 9% Junior Subordinated Debentures of OE due
December 31, 2025.
2 - COMMITMENTS, GUARANTEES AND CONTINGENCIES:
CAPITAL EXPENDITURES-
FirstEnergy's current forecast reflects expenditures of approximately
$3.0 billion (OE-$766 million, CEI-$529 million, TE-$259 million, Penn-$234
million and unregulated subsidiaries-$1.212 billion) for property additions and
improvements from 2000-2004, of which approximately $670 million (OE-$213
million, CEI-$109 million, TE-$99 million, Penn-$29 million and unregulated
subsidiaries-$220 million) is applicable to 2000. Investments for additional
nuclear fuel during the 2000-2004 period are estimated to be approximately $462
million (OE-$113 million, CEI-$157 million, TE-$108 million and Penn-$84
million), of which approximately $152 million (OE-$33 million, CEI-$56 million,
TE-$39 million and Penn-$24 million) applies to 2000.
STOCK REPURCHASE PROGRAM-
On November 17, 1998, the Board of Directors authorized the repurchase
of up to 15 million shares of FirstEnergy's common stock over a three-year
period beginning in 1999. Repurchases are made on the open market, at prevailing
prices, and are funded primarily through the use of operating cash flows. During
the second quarter of 2000 and the first six months of 2000, FirstEnergy
repurchased and retired 1.7 million shares (average price of $24.29 per share)
and 3.2 million shares (average price of $22.71 per share) of its common stock,
respectively. In 1999, FirstEnergy also entered into a forward contract with
Credit Suisse First Boston Corporation for the purchase of 1.4
1
<PAGE> 79
million shares of FirstEnergy's common stock at an average price of $24.22 per
share to be settled on November 3, 2000. The contract may be settled through
gross physical settlement, net share settlement or net cash settlement at
FirstEnergy's election.
ENVIRONMENTAL MATTERS-
Various federal, state and local authorities regulate the Companies
with regard to air and water quality and other environmental matters. The
Companies estimate capital expenditures for environmental compliance of
approximately $292 million (OE-$144 million, CEI-$84 million, TE-$33 million and
Penn-$31 million), which is included in the construction estimate given under
"Capital Expenditures" for 2000 through 2004.
The Companies are required to meet federally approved sulfur dioxide
(SO2) regulations. Violations of such regulations can result in shutdown of the
generating unit involved and/or civil or criminal penalties of up to $27,500 for
each day the unit is in violation. The Environmental Protection Agency (EPA) has
an interim enforcement policy for SO2 regulations in Ohio that allows for
compliance based on a 30-day averaging period. The Companies cannot predict what
action the EPA may take in the future with respect to the interim enforcement
policy.
The Companies are in compliance with the current SO2 and nitrogen
oxides (NOx) reduction requirements under the Clean Air Act Amendments of 1990.
SO2 reductions are being achieved by burning lower-sulfur fuel, generating more
electricity from lower-emitting plants, and/or purchasing emission allowances.
NOx reductions are being achieved through combustion controls and the generation
of more electricity at lower-emitting plants. In September 1998, the EPA
finalized regulations requiring additional NOx reductions from the Companies'
Ohio and Pennsylvania facilities by May 2003. The EPA's NOx Transport Rule
imposes uniform reductions of NOx emissions across a region of twenty-two states
and the District of Columbia, including Ohio and Pennsylvania, based on a
conclusion that such NOx emissions are contributing significantly to ozone
pollution in the eastern United States. In March 2000, the U.S. Court of Appeals
for the D.C. Circuit upheld EPA's NOx Transport Rule except as applied to the
State of Wisconsin and portions of Georgia and Missouri. By October 2000, states
are to submit revised State Implementation Plans (SIP) which Comply with
individual state NOx budgets established by the EPA contemplating an approximate
85% reduction in utility plant NOx emissions from projected 2007 emissions. A
proposed Federal Implementation Plan accompanied the NOx Transport Rule and may
be implemented by the EPA in states which fail to revise their SIP. In another
separate but related action, eight states filed petitions with the EPA under
Section 126 of the Clean Air Act seeking reductions of NOx emissions which are
alleged to contribute to ozone pollution in the eight petitioning states. The
EPA position is that the Section 126 petitions will be adequately addressed by
the NOx Transport Program, but a December 17, 1999 rulemaking established an
alternative program which would require nearly identical 85% NOx reductions at
392 utility plants, including the Companies' Ohio and Pennsylvania plants, by
May 2003, in the event implementation of the NOx Transport Rule is delayed.
Additional Section 126 petitions were filed by New Jersey, Maryland, Delaware
and the District of Columbia in mid-1999 and are still under evaluation by the
EPA. The Companies continue to evaluate their compliance plans and other
compliance options.
In July 1997, EPA promulgated changes in the National Ambient Air
Quality Standard (NAAQS) for ozone and proposed a new NAAQS for previously
unregulated ultra-fine particulate matter. In May 1999, the U.S. Court of
Appeals for the D.C. Circuit remanded both standards to the EPA, having found
constitutional and other defects in the new NAAQS rules. The D.C. Circuit Court,
on October 29, 1999, denied an EPA petition for rehearing. The U.S. Supreme
Court, on May 22, 2000, agreed to hear appeals of both EPA and industry
petitioners regarding the new NAAQS rules and a decision is expected in 2001.
The cost of compliance with these regulations, if they are reinstated, may be
substantial and will depend on the manner in which they are ultimately
implemented, if at all, by the states in which the Companies operate affected
facilities.
In September 1999, FirstEnergy received, and subsequently in October
1999, OE and Penn received, a citizen suit notification letter from the New York
Attorney General's office alleging Clean Air Act violations at the W. H. Sammis
Plant. In November 1999, OE and Penn received a citizen suit notification letter
from the Connecticut Attorney General's office alleging Clean Air Act violations
at the Sammis Plant. In November 1999 and March 2000, the EPA issued Notices of
Violation (NOV) or a Compliance Order to eight utilities covering 36 power
plants, including the Sammis Plant. In addition, the U.S. Department of Justice
filed seven civil complaints against various investor-owned utilities, which
included a complaint against OE and Penn in the U.S. District Court for the
Southern District of Ohio. The NOV and complaint allege violations of the Clean
Air Act based on operation and maintenance of the Sammis Plant dating back to
1984. The complaint requests permanent injunctive relief to require the
installation of "best available control technology" and civil penalties of up to
$27,500 per day of violation. Although unable to predict the outcome of these
proceedings, FirstEnergy believes the Sammis Plant is in full compliance with
the Clean Air Act and
2
<PAGE> 80
the NOV and complaint are without merit. Penalties could be imposed if the
Sammis Plant continues to operate without correcting the alleged violations and
a court determines that the allegations are valid. It is anticipated at this
time that the Sammis Plant will continue to operate until these proceedings are
concluded.
3
<PAGE> 81
As a result of the Resource Conservation and Recovery Act of 1976, as
amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous, waste
disposal requirements pending EPA's evaluation of the need for future
regulation. EPA has issued its final regulatory determination that regulation of
coal ash as a hazardous waste is unnecessary. On April 25, 2000, EPA announced
that it will develop national standards regulating disposal of coal ash under
its authority to regulate nonhazardous waste.
CEI and TE have been named as "potentially responsible parties" (PRPs)
at waste disposal sites which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved,
are often unsubstantiated and subject to dispute. Federal law provides that all
PRPs for a particular site be held liable on a joint and several basis. CEI and
TE have accrued liabilities of $4.4 million and $0.6 million, respectively, as
of June 30, 2000, based on estimates of the costs of cleanup and the
proportionate responsibility of other PRPs for such costs. CEI and TE believe
that waste disposal costs will not have a material adverse effect on their
financial condition, cash flows or results of operations.
MERGER AGREEMENT-
On August 8, 2000, FirstEnergy and GPU, Inc. (GPU), a Pennsylvania
corporation, entered into an Agreement and Plan of Merger. Under the merger
agreement, FirstEnergy would acquire all of the outstanding shares of GPU's
common stock for approximately $4.5 billion in cash and FirstEnergy common
stock. FirstEnergy would also assume approximately $7.4 billion of GPU's debt
and preferred stock. The transaction would be accounted for by the purchase
method. The combined company's principal electric utility operating companies
would include OE, CEI, TE and Penn, as well as GPU's electric utility operating
companies - Jersey Central Power & Light Company, Metropolitan Edison Company,
and Pennsylvania Electric Company, which serve customers in Pennsylvania and New
Jersey.
Under the agreement, GPU shareholders would receive the equivalent of
$36.50 for each share of GPU common stock they own, payable in cash or in
FirstEnergy common stock, as long as FirstEnergy's common stock price is between
$24.24 and $29.63. Each GPU shareholder would be able to elect the form of
consideration they wish to receive, subject to proration so that the aggregate
consideration to all GPU shareholders will be 50 percent cash and 50 percent
FirstEnergy common stock. Each GPU share converted into FirstEnergy common stock
would receive not less than 1.2318 and not more than 1.5055 shares of
FirstEnergy common stock, depending on the average closing price of FirstEnergy
stock during the 20-day trading period ending on the sixth trading date prior to
the merger closing. The stock portion of the consideration is expected to be
tax-free to GPU shareholders.
The Merger has been approved by the respective Boards of Directors of
the Company and GPU and is expected to close promptly after all of the
conditions to the consummation of the Merger, including shareholder approval and
the receipt of all necessary regulatory approvals, are fulfilled or waived. The
receipt of all necessary regulatory approvals, including, the Federal Energy
Regulatory Commission, the Nuclear Regulatory Commission, the Federal
Communications Commission, and the Securities and Exchange Commission, are
expected to take approximately one year.
3- REGULATORY ACCOUNTING:
On July 19, 2000, the Public Utilities Commission of Ohio (PUCO)
approved FirstEnergy's transition plan by adopting the agreement with major
parties to the transition plan it had filed in 1999, on behalf of OE, CEI and TE
under Ohio's electric utility restructuring law. Major parties to the agreement
included the PUCO staff, the Ohio Consumers' Counsel, the Industrial Energy
Users-Ohio, certain power marketers and others.
Major provisions of the agreement consisted of approval of the
transition plan as filed, including recovery of transition costs through no
later than 2006 for CE, mid-2007 for TE and 2008 for CEI, except Where a longer
period of recovery is provided for in the agreement. The total transition cost
amounts to be recovered are as filed in the transition plan. FirstEnergy will
also allow preferred access over FirstEnergy's subsidiaries to non-affiliated
marketers, brokers and aggregators to 1,120 megawatts of generation capacity
through 2005 at established prices for sales to the Ohio operating companies'
retail customers. The base electric rates for distribution service for OE, CEI
and TE under their prior respective regulatory plans will be extended from
December 31, 2005 through December 31, 2007.
4
<PAGE> 82
The transition rate credits for customers under their prior regulatory plans
will also be extended through the Companies' respective transition cost recovery
periods.
5
<PAGE> 83
Beginning January 1, 2001 when Ohio electric customers have the choice
to select their generation suppliers under the Ohio restructuring law, the
agreement provides to FirstEnergy's Ohio customers electing alternative
suppliers, an additional incentive applied to the shopping credit of 45% for
residential customers, 30% for commercial customers and 15% for industrial
customers as reductions from their bills, when they select alternative energy
providers (the credits exceed the price FirstEnergy will be offering to
electricity suppliers relating to the 1,120 megawatts described on the previous
page). The amount of the incentive will serve to reduce the amortization of
transition costs during the market development period (January 1, 2001 through
December 31, 2005) and will be recovered over the remaining transition cost
recovery periods. If the customer shopping goals established in the agreement
are not achieved by the end of 2005, the transition cost recovery periods could
be shortened for OE, CEI and TE to reduce recovery by as much as $500 million
(OE-$250 million, CEI-$170 million and TE-$80 million), but any such adjustment
would be computed on a class-by-class and pro-rata basis.
The application of Statement of Financial Accounting Standards (SFAS)
No. 71 "Accounting for the Effect of Certain Types of Regulation" (SFAS 71) to
OE's generation business and the nonnuclear generation businesses of CEI and TE
was discontinued effective with the issuance of the PUCO order. The June 30,
2000 balance sheets reflect the effect of such discontinuance with the reduction
of plant investment and the corresponding recognition of regulatory assets
recoverable through future regulatory cash flows for generating assets that were
impaired in the amount of $1.6 billion ($1.2 billion, $304 million and $53
million for OE, CEI and TE, respectively). The Companies continue to bill and
collect cost-based rates for their transmission and distribution services, which
remain regulated; accordingly, it is appropriate that the Companies continue the
application of SFAS 71 to those respective operations.
4 - NEW ACCOUNTING STANDARD:
In June 2000, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 138 (SFAS 138), "Accounting for
Certain Derivative Instruments and Certain Hedging Activities - an amendment of
FASB Statement No. 133." SFAS 138 modifies Statement No. 133 (SFAS 133) in
several ways. The most significant impact of the amendment for FirstEnergy is
expansion of the "normal purchases and normal sales" exception in SFAS 133 to
include contracts that implicitly or explicitly permit net settlement. As a
consequence, a number of contracts entered into in the normal course of business
which were previously required to be accounted for as derivative instruments
under SFAS 133 will now be excluded from those provisions, reducing SFAS 133's
potential for volatility on earnings and other comprehensive income. The
amendment also modifies certain hedging requirements of SFAS 133. FirstEnergy
anticipates adopting SFAS 138 on its effective date of January 1, 2001.
FirstEnergy is in the process of quantifying the impacts on its financial
statements of adopting this new standard.
6
<PAGE> 84
5. SEGMENT INFORMATION:
FirstEnergy's primary segment is its Electric Utility Operating
Companies which include four electric utilities that provide electric service in
Ohio and Pennsylvania. Its other material business segment consists of the
subsidiaries that operate unregulated businesses. Financial data for these
business segments are as follows:
<TABLE>
<CAPTION>
Segment Financial Information
-----------------------------
Electric Unregulated Reconciling
Three Months Ended: Utilities Businesses Eliminations Totals
------------------- --------- ---------- ------------ ------
(In millions)
<S> <C> <C> <C> <C>
June 30, 2000
-------------
External revenues .................................. $ 1,342 $ 360 $ -- $ 1,702
Intersegment revenues .............................. 29 40 (69) --
Total revenues .................................... 1,371 400 (69) 1,702
Depreciation and amortization ...................... 220 5 -- 225
Net interest charges ............................... 128 17 (11) 134
Income taxes ....................................... 99 (4) -- 95
Net income/Earnings on common stock ................ 141 (4) (2) 135
Total assets ....................................... 17,169 2,092 (1,160) 18,101
Property additions ................................. 102 22 -- 124
Acquisitions ....................................... -- -- -- --
June 30, 1999
-------------
External revenues .................................. $ 1,335 $ 184 $ -- $ 1,519
Intersegment revenues .............................. 8 45 (53) --
Total revenues .................................... 1,343 229 (53) 1,519
Depreciation and amortization ...................... 208 9 -- 217
Net interest charges ............................... 143 16 (12) 147
Income taxes ....................................... 101 -- -- 101
Net income/Earnings on common stock ................ 125 3 (3) 125
Total assets ....................................... 17,393 1,924 (934) 18,383
Property additions ................................. 69 24 -- 93
Acquisitions ....................................... -- -- -- --
<CAPTION>
Electric Unregulated Reconciling
Six Months Ended: Utilities Businesses Eliminations Totals
----------------- --------- ---------- ------------ ------
(In millions)
<S> <C> <C> <C> <C>
June 30, 2000
-------------
External revenues .................................. $ 2,617 $ 693 $ -- $ 3,310
Intersegment revenues .............................. 57 66 (123) --
Total revenues .................................... 2,674 759 (123) 3,310
Depreciation and amortization ...................... 417 10 -- 427
Net interest charges ............................... 259 35 (25) 269
Income taxes ....................................... 196 (3) -- 193
Net income/Earnings on common stock ................ 282 (2) (4) 276
Total assets ....................................... 17,169 2,092 (1,160) 18,101
Property additions ................................. 219 57 -- 276
Acquisitions ....................................... -- -- -- --
June 30, 1999
-------------
External revenues .................................. $ 2,612 $ 329 $ -- $ 2,941
Intersegment revenues .............................. 16 68 (84) --
Total revenues .................................... 2,628 397 (84) 2,941
Depreciation and amortization ...................... 394 14 -- 408
Net interest charges ............................... 285 32 (24) 293
Income taxes ....................................... 197 (3) -- 194
Net income/Earnings on common stock ................ 268 (2) (4) 262
Total assets ....................................... 17,393 1,924 (934) 18,383
Property additions 121 54 -- 175
Acquisitions -- 9 -- 9
</TABLE>
7
<PAGE> 85
Notes to Consolidated Financial Statements
GPU, Inc. owns all the outstanding common stock of three domestic electric
utilities-Jersey Central Power & Light Company (JCP&L), Metropolitan Edison
Company (Met-Ed) and Pennsylvania Electric Company (Penelec). The customer
service function, transmission and distribution operations and the operations of
the remaining non-nuclear generating facilities of these electric utilities are
conducting business under the name GPU Energy. JCP&L, Met-Ed and Penelec
considered together are referred to as the "GPU Energy companies." The nuclear
generation operations of GPU Energy are conducted by GPU Nuclear, Inc. (GPUN).
GPU Capital, Inc. and GPU Electric, Inc. and their subsidiaries own, operate and
fund the acquisition of electric and gas transmission and distribution systems
in foreign countries, and are referred to as "GPU Electric." GPU International,
Inc. and GPU Power, Inc. and their subsidiaries develop, own and operate
generation facilities in the United States and foreign countries and are
referred to as the "GPUI Group." Other subsidiaries of GPU, Inc. include GPU
Advanced Resources, Inc. (GPU AR), which is involved in retail energy sales; GPU
Telcom Services, Inc. (GPU Telcom), which is engaged in
telecommunications-related businesses; and GPU Service, Inc. (GPUS), which
provides legal, accounting, financial and other services to the GPU companies.
All of these companies considered together are referred to as "GPU."
1. Summary of Significant Accounting Policies
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities, the disclosure of
contingent assets and liabilities at the date of the financial statements, and
revenues and expenses during the reporting period. Actual results could differ
from those estimates.
System of Accounts: Certain reclassifications of prior years' data have been
made to conform with the current presentation. The GPU Energy companies'
accounting records are maintained in accordance with the Uniform System of
Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and
adopted by the Pennsylvania Public Utility Commission (PaPUC) and the New Jersey
Board of Public Utilities (NJBPU). GPU's accounting records also comply with the
Securities and Exchange Commission's (SEC) rules and regulations.
Consolidation: The GPU consolidated financial statements include the accounts of
its wholly-owned subsidiaries and any affiliates in which it has a controlling
financial interest (generally evidenced by a greater than 50% ownership
interest). All significant intercompany transactions and accounts are eliminated
in consolidation. GPU also uses the equity method of accounting for investments
in affiliates in which it has the ability to exercise significant influence.
Effective in the third quarter of 1999, GPU began accounting for its Midlands
Electricity plc (Midlands) investment as a consolidated entity due to GPU's
purchase from Cinergy Corp. (Cinergy) of the remaining 50% ownership interest in
Midlands which GPU did not own. As a result of this change, GPU's remaining
equity investments are no longer presented in the Notes to Consolidated
Financial Statements since these investments as of December 31, 1999 are
considered immaterial to GPU's results of operations and financial condition.
Regulatory Accounting: Statement of Financial Accounting Standards No.71 (FAS
71), "Accounting for the Effects of Certain Types of Regulation," applies to
regulated utilities that have the ability to recover their costs through rates
established by regulators and charged to customers. The GPU Energy companies'
transmission and distribution operations are currently accounted for under the
provisions of FAS 71. In accordance with FAS 71, GPU has deferred certain costs
pursuant to actions of the NJBPU and PaPUC and is recovering or expects to
recover such costs in regulated rates charged to customers. Regulatory assets
and liabilities are reflected net in the Deferred Debits and Other Assets
section of the Consolidated Balance Sheets. For additional information about
regulatory assets and liabilities, see Note 12, Commitments and Contingencies.
With the receipt of the NJBPU Summary Restructuring Order (Summary Order) in
1999 and the PaPUC Restructuring Orders (Restructuring Orders) in 1998, GPU
determined that the GPU Energy companies' electric generation operations no
longer met the criteria for the continued application of FAS 71, and therefore
adopted, for that portion of its business, the provisions of Statement of
Financial Accounting Standards No. 101 (FAS 101), "Regulated
Enterprises-Accounting for the Discontinuation of Application of FASB Statement
No.71" and Emerging Issues Task Force Issue 97-4 (EITF) (Issue 97-4),
Deregulation of the Pricing of Electricity -- Issues Related to the Application
of FASB Statement No.71 "Accounting for the Effects of Certain Types of
Regulation" and No. 101 "Regulated Enterprises -- Accounting for the
Discontinuation of Application of FASB Statement No. 71."
Currency Translation: In accordance with Statement of Financial Accounting
Standards No. 52 (FAS 52), "Foreign Currency Translation," balance sheet
accounts of foreign operations are translated from foreign currencies into US
dollars at year-end rates, while income statement accounts are translated at the
average month-end exchange rates for the relevant period. The resulting
translation adjustments are included in Accumulated other comprehensive
income/(loss), net of deferred taxes, on the Consolidated Balance Sheets. Gains
and losses resulting from foreign currency transactions are included in Net
Income.
26 GPU 1999 FINANCIAL REPORT
<PAGE> 86
Revenues: GPU recognizes operating revenues for services rendered to the end of
the relevant accounting period. GPU Electric and the GPU Energy companies'
electric operating revenues also include an estimate for unbilled revenues.
Deferred Costs: JCP&L recovers its prudently incurred generation-related costs
through a Market Transition Charge (MTC) and Basic Generation Service (BGS)
charge, and defers any differences between actual costs and amounts recovered
from customers through rates. Met-Ed and Penelec use deferred accounting for
the above-market portion of nonutility generation (NUG) costs which are
collected through the Competitive Transition Charge (CTC).
Utility Plant: At December 31, 1999 and 1998, the GPU Energy companies'
generation plants are valued at the lower of cost or market. All other utility
plant and additions are valued at cost. The assets of acquired companies are
carried at their fair value as of the acquisition date, less accumulated
depreciation.
Depreciation: GPU generally provides for depreciation at annual rates determined
and revised periodically, on the basis of studies, to be sufficient to
depreciate the original cost of depreciable property over estimated remaining
service lives, which are generally longer than those employed for tax purposes.
These rates, on an aggregate composite basis, resulted in annual rates of 2.96%,
3.43% and 3.34% for the years 1999, 1998 and 1997, respectively. GPU GasNet
uses the volumetric depreciation method to amortize the cost of its gas
pipeline.
AMORTIZATION POLICIES:
Accounting for TMI-2 and Forked River Investments At December 31, 1999, $61
million is included in Regulatory assets, net on the Consolidated Balance Sheets
for JCP&L's investment in Three Mile Island Unit 2 (TMI-2). JCP&L is collecting
annual revenues for the amortization of TMI-2 of $9.6 million. This level of
revenue will be sufficient to recover the remaining investment by 2008. Met-Ed
and Penelec have collected all of their TMI-2 investment attributable to retail
customers. At December 31, 1999, $56 million is included in Regulatory assets,
net on the Consolidated Balance Sheets for JCP&L's Forked River project. JCP&L
is collecting annual revenues for the amortization of this project of $11.2
million, which will be sufficient to recover its remaining investment by 2006.
Because JCP&L has not been provided revenues for a return on the unamortized
balances of the damaged TMI-2 facility and the cancelled Forked River project,
these investments are being carried at their discounted present values.
Nuclear Fuel The GPU Energy companies amortize nuclear fuel on a
unit-of-production basis. Rates are determined and periodically revised to
amortize the cost of the fuel over its useful life.
At December 31, 1999 and 1998, the liability of the GPU Energy companies for
future contributions to the Federal Decontamination and Decommissioning Fund for
the cleanup of uranium enrichment plants operated by the Federal Government
amounted to $25 million and $28 million, respectively, and was primarily
reflected in Deferred Credits and Other Liabilities-Other. Annual contributions,
which began in 1993, are being made over a 15-year period. JCP&L is recovering
these costs from customers through its BGS and MTC rates while Met-Ed and
Penelec anticipate recovery in Phase II of their restructuring proceedings which
are expected to begin in early 2000.
Goodwill Goodwill, resulting from GPU's purchase of various businesses, is
recorded on the Consolidated Balance Sheets and amortized to expense, on a
straight-line basis, over its useful life not to exceed 40 years. Goodwill
amortization expense amounted to $51.6 million, $14 million and $2.8 million for
the years ended December 31, 1999, 1998 and 1997, respectively. In addition,
GPU's investments accounted for under the equity method or cost method include
goodwill (net of amortization) totaling $21 million and $18.5 million as of
December 31, 1999 and 1998, respectively, which is amortized on a straight-line
basis over 20 years. Amortization expense on this goodwill (which is reflected
on the Consolidated Statements of Income in Other Income and Deductions)
amounted to $1.9 million, $1.6 million and $3.6 million for the years ended
December 31, 1999, 1998 and 1997, respectively. GPU periodically reviews
undiscounted projections of future cash flows from operations to assess whether
any potential intangible impairment exists on its goodwill. For additional
information of goodwill resulting from acquisitions, see Note 7, Acquisitions.
Nuclear Fuel Disposal Fee: The GPU Energy companies are providing for estimated
future disposal costs for spent nuclear fuel at the Oyster Creek nuclear
generating station (Oyster Creek) and Three Mile Island Unit 1 (TMI-1) in
accordance with the Nuclear Waste Policy Act of 1982. The GPU Energy companies
entered into contracts in 1983 with the US Department of Energy (DOE) for the
disposal of spent nuclear fuel. The total liability under these contracts,
including interest, at December 31, 1999, all of which relates to spent nuclear
fuel from nuclear generation through April 1983, amounted to $198 million, and
is reflected in Deferred Credits and Other Liabilities-Other. As the actual
liability is substantially in excess of the amount recovered to date from
ratepayers, the GPU Energy companies have reflected such excess in Regulatory
assets, net. The distribution rates presently charged to customers provide for
the collection of these costs, plus interest, over a remaining period of seven
years for JCP&L. Met-Ed and Penelec are recovering these costs through their
respective CTC.
27 GPU 1999 FINANCIAL REPORT
<PAGE> 87
The GPU Energy companies' current rates provide for the recovery of costs for
spent nuclear fuel disposal costs resulting from nuclear generation subsequent
to April 1983. The GPU Energy companies are making quarterly payments to the DOE
based on one mill per kilowatt-hour. These remittances hove ceased for TMI-1 and
will cease for Oyster Creek when that facility is sold. For a discussion of the
DOE's current inability to begin acceptance of spent nuclear fuel from the GPU
Energy companies and other standard contract holders, see Note 12, Commitments
and Contingencies.
Income Taxes: GPU files a consolidated federal income tax return. All
participants are jointly and severally liable for the full amount of any tax,
including penalties and interest, which may be assessed against the group.
Deferred income taxes, which result primarily from purchase accounting
adjustments, liberalized depreciation methods, deferred costs, decommissioning
funds and discounted Forked River and TMI-2 investments, reflect the impact of
temporary differences between the amounts of assets and liabilities recognized
for financial reporting purposes and the amounts recognized for tax purposes.
Investment tax credits (ITC) are amortized over the estimated service lives of
the related facilities.
Carrying Amounts of Financial Instruments: The carrying amounts of Temporary
cash investments, Special deposits, Securities due within one year and Notes
payable on the Consolidated Balance Sheets approximate fair value due to the
short period to maturity. The carrying amounts of the Nuclear decommissioning
trusts and Nuclear fuel disposal trust, whose assets are invested in cash
equivalents and debt and equity securities, also approximate fair value.
DERIVATIVE INSTRUMENTS:
CPU's use of derivative instruments is intended primarily to manage the risk of
interest rate, foreign currency and commodity price fluctuations. GPU does not
intend to hold or issue derivative instruments for trading purposes.
Commodity Derivatives The GPU Energy companies use futures contracts to manage
the risk of fluctuations in the market price of electricity and natural gas.
These contracts qualify for hedge accounting treatment under current accounting
rules since price movements of the commodity derivatives are highly correlated
with the underlying hedged commodities and the transactions are designated as
hedges at inception. Accordingly, under the deferral method of accounting, gains
and losses related to commodity derivatives are recognized in Power purchased
and interchanged in the Consolidated Statements of Income when the hedged
transaction closes or if the commodity derivative is no longer sufficiently
correlated. Prior to income or loss recognition, deferred gains and losses
relating to these transactions are recorded in Current Assets or Current
Liabilities in the Consolidated Balance Sheets.
Interest Rote Swap Agreements GPU Electric uses interest rate swap agreements to
manage the risk of increases in variable interest rates. At December 31, 1999,
these agreements covered approximately $1.3 billion of debt, including
commercial paper, and were scheduled to expire on various dates through November
2007. Differences between amounts paid and received under interest rate swaps
are recorded as adjustments to the interest expense of the underlying debt since
the swaps are related to specific assets, liabilities or anticipated
transactions. All of the agreements effectively convert variable rate debt,
including commercial paper, to fixed rate debt. For the year ended December 31,
1999, fixed rate interest expense incurred in connection with the swap
agreements exceeded the variable rate interest expense that would have been
incurred had the swaps not been in place by approximately $20.7 million.
Currency Swap Agreements GPU Electric uses currency swap agreements to manage
currency risk caused by fluctuations in the US dollar exchange rate related to
debt issued in the US by Avon Energy Partners Holdings (Avon). These swap
agreements effectively convert principal and interest payments on this US dollar
debt to fixed sterling principal and interest payments, and expire on the
maturity dates of the bonds. Interest expense is recorded based on the fixed
sterling interest rate. At December 31, 1999, these currency swap agreements
covered (pound sterling)517 million (US $850 million) of debt. Interest expense
would have been (pound sterling)16.6 million (US $26.9 million) as compared to
(pound sterling)18.2 million (US $29.5 million) for the year ended December 31,
1999 had these agreements not been in place.
Indexed Swap Agreement As part of an amended power purchase agreement with
Niagara Mohawk Power Corporation (NIMO), Onondaga Cogeneration L.P (Onondaga), a
GPU International subsidiary, entered into a 10-year indexed swap agreement in
1998 which is intended to provide Onondaga a fixed revenue stream. At December
31, 1999 and 1998, the indexed swap agreement is valued at $55.1 million and
$62.4 million, respectively and is included in Other-Deferred Debits and Other
Assets on the Consolidated Balance Sheets. This valuation was derived using the
discounted estimated cash flows related to payments expected to be received by
Onondaga. The indexed swap is being amortized to expense over the life of the
swap agreement. As a result of the anticipated expiration of a related power put
agreement between Onondaga and NIMO, GPU International expects to recognize in
income the unamortized balance of the indexed swap agreement, mostly offset by a
plant impairment, resulting in a slight gain in 2000.
28 GPU 1999 FINANCIAL REPORT
<PAGE> 88
Environmental Liabilities: GPU may be subject to loss contingencies resulting
from environmental laws and regulations, which include obligations to mitigate
the effects on the environment of the disposal or release of certain hazardous
wastes and substances at various sites. GPU records liabilities (on an
undiscounted basis) for hazardous waste sites where it is probable that a loss
has been incurred and the amount of the loss can be reasonably estimated and
adjusts these liabilities as required to reflect changes in circumstances.
Statements of Cash Flows: For the purpose of the consolidated statements of cash
flows, temporary investments include all unrestricted liquid assets, such as
cash deposits and debt securities, with maturities generally of three months or
less. Cash flows are reported using the US dollar equivalent of the functional
currencies in effect at the time of the cash transaction. The effect of exchange
rate changes on cash balances held in foreign currencies are reported as a
separate line item on the Consolidated Statements of Cash Flows.
Avon and Midlands have a formal agreement with a United Kingdom bank, under
which they maintain available cash balances in a number of subsidiary bank
accounts and an overdraft in the main Midlands operating account. The overdraft
balance was $224.6 million as of December 31, 1999, while total cash at Midlands
was $274.6 million. Since Midlands manages the overdraft balance in such a way
that it does not exceed the available cash balances in the other associated
accounts, no interest or fees are paid under this arrangement. In effect,
Midlands uses the overdraft facility to utilize the available cash in the other
bank accounts. The overdraft position and the offsetting cash balances subject
to this arrangement are shown on the Consolidated Balance Sheets in Bank
overdraft and Cash and temporary cash investments, respectively.
2. SHORT-TERM BORROWING ARRANGEMENTS At December 31, 1999 and 1998, short-term
debt outstanding consisted of $1.2 billion and $369 million, respectively. GPU's
weighted average interest rate on the short-term borrowings was 6.5% and 6.4% at
December 31, 1999 and 1998, respectively.
GPU has various credit facilities in place, the most significant of which are
discussed below. These credit facilities generally provide GPU bank loans at
negotiable market rates. In addition, commitment fees or facility fees are
determined by market rates at the time the facility is put in place, and can
change based on the borrower's current bond rating.
GPU, Inc. and GPU Energy companies: GPU, Inc. and the GPU Energy companies have
available $450 million of short-term borrowing facilities, which includes a $250
million revolving credit agreement and various bank lines of credit. In
addition, GPU, Inc., JCP&L, Met-Ed and Penelec can issue commercial paper in
amounts of up to $100 million, $150 million, $75 million, and $100 million,
respectively. From these sources, GPU, Inc. has regulatory authority to have
$250 million outstanding at any one time. JCP&L, Met-Ed and Penelec are limited
by their charters or SEC authorization to $265 million, $150 million and $150
million, respectively, of short-term debt outstanding at any one time. As of
December 31, 1999, GPU, Inc. and the GPU Energy companies had $123.5 million and
$53.6 million, respectively, of short-term debt outstanding.
GPU Electric: GPU Capital has a $1 billion 364-day senior revolving credit
agreement due in December 2000 supporting the issuance of commercial paper for
its $1 billion commercial paper program established to fund GPU Electric
acquisitions. GPU, Inc. has guaranteed GPU Capital's obligations under this
program. At December 31, 1999, $768 million was outstanding under the commercial
paper program, of which $370 million is included in long-term debt on the
Consolidated Balance Sheets since it is management's intent to reissue this
amount of the commercial paper on a long-term basis. For additional information,
see Note 3 Long-Term Debt.
GPU Australia Holdings, Inc. has $270 million available under its senior
revolving credit facility due in November 2002. This facility, in combination
with other GPU, Inc. credit facilities, serves as credit support for GPU
Australia Holdings' $350 million commercial paper program. GPU, Inc. has
guaranteed GPU Australia Holdings' obligations under this program. At December
31, 1999, $182 million was outstanding under the commercial paper program.
Austran Holdings, Inc. (Austran), a wholly-owned indirect subsidiary of GPU
Electric, has a A$500 million (approximately US $328 million) commercial paper
program to refinance the maturing portion of the senior debt credit facility
used to finance the PowerNet Victoria (GPU PowerNet) acquisition. GPU PowerNet
has guaranteed Austran's obligations under this program. At December 31, 1999,
A$420 million (approximately US $275 million) was outstanding under this
program.
Midlands maintains a (pound sterling)200 million (approximately US $323 million)
syndicated revolving credit facility with a bank for working capital purposes,
which matures May 2001. At December 31, 1999, (pound sterling)87 million
(approximately US $140 million) was outstanding under this facility.
GPUI Group: GPU International has a revolving credit agreement providing for
borrowings through December 2000 of up to $30 million outstanding at any one
time, of which up to $15 million may be utilized to provide letters of credit.
GPU, Inc. has guaranteed GPU International's obligations under this agreement.
At December 31, 1999, no borrowings or letters of credit were outstanding under
this facility.
29 GPU 1999 FINANCIAL REPORT
<PAGE> 89
3. Long.term Debt
At December 31, 1999, long-term debt outstanding consisted of the
following:
<TABLE>
<CAPTION>
DUE
INTEREST TOTAL DEBT WITHIN
(IN MILLIONS) MATURITIES RATES OUTSTANDING ONE YEAR
----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
GPU Energy companies & GPUS:
First mortgage bonds 2000-2027 5.35-9.48% $ 1,783(1) $ 90
Senior notes 2004-2019 5.75-6.63% 350 --
Other long-term debt 2000-2039 6.76-7.69% 34 --
GPU Electric:
Bank loans 2000-2014 4.16-13% 2,483 475
Bonds 2002-2008 7.38.7.46% 1,092 --
Commercial paper/Medium term notes 2000-2002 6.3-7.65% 633(2) --
GPUI Group 2000-2022 4.5-7% 46 5
----------------------------------------------------------------------------------------------------------
Total $ 6,421 $570
----------------------------------------------------------------------------------------------------------
</TABLE>
(1) Amount is less unamortized net discount of $4.6 million.
(2) Amount includes $370 million of commercial paper, which is included in
long-term debt on the Consolidated Balance Sheets since it is
management's intent to reissue this amount on a long-term basis.
For the years 2000, 2001, 2002, 2003 and 2004, GPU has long-term debt
maturities of $570 million, $1.1 billion, $1.2 billion, $260 million and $343
million, respectively. Substantially all of the utility plant owned by the GPU
Energy companies is subject to the liens of their respective mortgages.
The fair value of long-term debt is estimated based on the quoted market prices
for the same or similar issues or on the current rates offered to GPU for debt
of the same remaining maturities and credit qualities. The estimated fair value
of GPU's long-term debt, including amounts due within one year, as of December
31, 1999 and 1998 is as follows:
CARRYING FAIR
(IN MILLIONS) AMOUNT VALUE
---------------------------------------------------
1999 $6,421 $6,312
1998 $4,387 $4,455
At December 31, 1999, GPU Electric had long-term debt outstanding of
approximately $470 million, which was guaranteed by GPU, Inc. The guaranteed
amount consisted of $370 million under the GPU Capital $1 billion commercial
paper program and up to $100 million under the (pound sterling)245 million
credit facility used to partially fund GPU's acquisition of Cinergy's 50%
interest in Midlands.
4. Preferred Securities
Cumulative Preferred Stock: At December 31, 1999, JCP&L had the
following cumulative preferred stock outstanding:
STATED VALUE SHARES STATED VALUE
SERIES PER SHARE OUTSTANDING (IN THOUSANDS)
----------------------------------------------------------------------------
With mandatory redemption:
7.52% $100 340,000 $34,000
8.65% $100 500,000 50,000
----------------------------------------------------------------------------
Total 840,000 84,000
=======
Amounts due within one year (10,833)
----------------------------------------------------------------------------
Total $73,167
=======
Without mandatory redemption:
4% $100 125,000 $12,500
=======
Premium 149
----------------------------------------------------------------------------
Total $12,649
============================================================================
30 GPU 1999 FINANCIAL REPORT
<PAGE> 90
The fair value of the preferred stock with mandatory redemption, including
amounts due within one year at December 31, 1999 and 1998, was $86.5 million and
$94.7 million, respectively. The 7.52% and 8.65% Series are callable at various
prices above their stated values beginning in 2002 and 2000, respectively. The
7.52% Series is to be redeemed ratably over twenty years, beginning in 1998. The
8.65% Series is to be redeemed ratably over six years beginning in 2000. The
shares with mandatory redemption have redemption requirements of $10.8 million
for each year of the next five years.
The 4% Series is callable at a price above its stated value. At December 31,
1999, JCP&L could call this series for $13.3 million.
In 1999, Met-Ed and Penelec redeemed all of their outstanding shares of
cumulative preferred stock for $12.5 million and $17.4 million, respectively. As
a result, a reacquisition loss of $1.3 million was charged to income.
During 1999, JCP&L redeemed all of its outstanding shares of 7.88% cumulative
preferred stock with a stated value of $25 million and $5 million stated value
of its 7.52% cumulative preferred stock pursuant to mandatory and optional
sinking fund provisions. As a result, a reacquisition loss of $0.8 million was
charged to income. During 1998, JCP&L redeemed $5 million stated value of its
7.52% cumulative preferred stock and $10 million stated value of its 8.48%
cumulative preferred stock pursuant to mandatory and optional sinking fund
provisions. JCP&L's total redemption cost for 1999 and 1998 was $30.9 million
and $15 million, respectively.
Subsidiary-Obligated Mandatorily Redeemable Preferred Securities: JCP&L Capital,
LP., Met-Ed Capital, L.P. and Penelec Capital, L.P. are special-purpose
partnerships in which a subsidiary of JCP&L, Met-Ed and Penelec, respectively,
is the sole general partner. In 1995, JCP&L Capital, L.P. issued $125 million at
8.56% (5 million shares at $25 per share) of mandatorily redeemable preferred
securities (MIPS) and in 1994, Met-Ed Capital, L.P. and Penelec Capital, L.P.
issued $100 million at 9% (4 million shares at $25.0 per shore) and $105 million
at 8.75% (4.2 million shares at $25 per share), respectively, of MIPS. The
proceeds were loaned to JCP&L, Met-Ed and Penelec, respectively, which, in turn,
issued their deferrable interest subordinated debentures to the partnerships. In
1999, Met-Ed and Penelec redeemed all of their outstanding shares of MIPS for
$100 million and $105 million, respectively. At December 31, 1999, JCP&L's
outstanding shares of MIPS had a fair value of $120.6 million.
The MIPS of JCP&L Capital, L.P. mature in 2044 and are redeemable at the option
of JCP&L beginning in May of 2000 at 100% of their principal amount, or earlier
under certain limited circumstances, including the loss of the federal tax
deduction for interest paid on the subordinated debentures. JCP&L has fully and
unconditionally guaranteed payment of distributions, to the extent there is
sufficient cash on hand to permit such payments and legally available funds, and
payments on liquidation or redemption of its Preferred Securities. Distributions
on the MIPS (and interest on the subordinated debentures) may be deferred for up
to 60 months, but JCP&L, may not pay dividends on, or redeem or acquire, any of
its cumulative preferred or common stock until deferred payments on its
subordinated debentures are paid in full.
Trust Preferred Securities: In 1999, $100 million of trust preferred securities
were issued on behalf of each of Met-Ed and Penelec at 7.35% and 7.34%,
respectively. The trust preferred securities were issued by Met-Ed Capital Trust
and Penelec Capital Trust and represent a beneficial interest in the trust equal
to a cumulative preferred limited partnership interest in Met-Ed Capital II,
L.P. and Penelec Capital II, L.P. The preferred securities are the sole assets
of the trust and the only revenues of the trust will be distributions on the
trust preferred securities. Each trust security has entitled the holder to
receive quarterly cash distributions. Met-Ed and Penelec unconditionally
guaranteed the payments by Met-Ed Capital II, L.P. and Penelec Capital II,
L.P., respectively.
The fair value of the Met-Ed and Penelec trust preferred securities at December
31, 1999 was $81 million and $80.8 million, respectively.
5. Stockholders' Equity
-------------------------------------------------------------------------------
The following table presents information relating to the common stock
($2.50 par value) of GPU, Inc.:
<TABLE>
<CAPTION>
1999 1998 1997
-----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Authorized shares 350,000,000 350,000,000 350,000,000
Issued shares 132,783,338 132,783,338 125,783,338
Reacquired shares 10,977,798 4,787,657 4,950,727
Outstanding shares 121,805,540 127,995,681 120,832,611
Outstanding restricted units 283,602 268,360 247,955
Outstanding stock options 394,750 335,950 --
</TABLE>
31 GPU 1999 FINANCIAL REPORT
<PAGE> 91
In 1999, GPU, Inc. reacquired 6.4 million shares of common stock at a total cost
of $225.8 million.
Pursuant to the 1990 Employee Stock Plan (as restated to reflect amendments
through June 3, 1999), awards may be granted in the form of incentive stock
options, nonqualified stock options, restricted shares of common stock,
restricted units and stock appreciation rights, which may accompany options. In
1999, 1998 and 1997, GPU, Inc. issued restricted units to officers representing
rights to receive shares of common stock, on a one-for-one basis, at the end of
the restriction period. The number of shares eventually issued will depend upon
the degree to which GPU's performance goals have been met for the restriction
period and could range from 0% to 200% of the originally awarded units plus
additional units resulting from reinvested dividend equivalents. In 1999, GPU,
Inc. granted stock options to its officers to purchase 90,600, 1,000 and 1,000
shares at $42.9375, $34.50 and $34.6875 per share, respectively. In 1998, GPU,
Inc. granted stock options to its officers to purchase 305,950 and 30,000 shares
at $36.625 per share and $44.25 per share, respectively. All options have an
exercise price equal to the fair market value of GPU, Inc. common stock on the
grant date. Options are exercisable in accordance with the terms set forth in
the Stock Option Agreement. In 1999 and 1998, no options were exercised.
Since 1997, pursuant to the Deferred Stock Unit Plan for Outside Directors,
restricted units were issued to outside directors representing rights to receive
shares of GPU, Inc. common stock, on a one-for-one basis. All restricted units
are considered common stock equivalents and, accordingly, are reflected in the
computation of diluted earnings per share shown on the Consolidated Statements
of Income. The restricted units accrue dividend equivalents on a quarterly
basis, which are reinvested in additional restricted units.
In 1999, 1998 and 1997, through the above-mentioned plans, officers and outside
directors were awarded 56,994, 53,260 and 64,941 restricted units, respectively.
In 1999, 1998 and 1997, also through those plans, GPU, Inc. issued a total of
20,215, 20,611 and 54,491 shares of common stock, respectively, from previously
reacquired shares.
In 1996, GPU adopted the disclosure requirements of Statement of Financial
Accounting Standards No. 123 (FAS 123), "Accounting for Stock-Based
Compensation," which establishes a fair value-based method of accounting for
employee stock-based compensation. As permitted by FAS 123 GPU continues to
follow the intrinsic value method set forth in APB Opinion No. 25, "Accounting
for Stock Issued to Employees" and disclose the pro forma effects on net income
(loss) had the fair value of the options been expensed. The pro forma effects on
net income resulting from the application of the fair value-based method of
accounting defined in FAS 123 are immaterial.
Accumulated Other Comprehensive Income/(Loss): in 1997, GPU adopted Statement of
Financial Accounting Standards No. 130, "Reporting Comprehensive Income.' At
December 31, 1999 and 1998, GPU had on the Consolidated Balance Sheets the
following amounts in Accumulated other comprehensive income/(loss):
(IN THOUSANDS) 1999 1998
--------------------------------------------------------------------------------
Net unrealized gains on investments $ 34,183 $ 28,345
Foreign currency translation (40,518) (54,377)
Minimum pension liability (6) (5,272)
--------------------------------------------------------------------------------
Accumulated other comprehensive income/(loss) $ (6.341) $(31,304)
--------------------------------------------------------------------------------
32 GPU 1999 FINANCIAL REPORT
<PAGE> 92
The components of the change in accumulated other comprehensive income/(loss),
and the related tax effects, for the years 1999, 1998 and 1997 are as follows:
<TABLE>
<CAPTION>
AMOUNT INCOME TAX AMOUNT
BEFORE (EXPENSE) NET OF
(IN THOUSANDS) TAXES BENEFIT TAXES
===================================================================================================================================
<S> <C> <C> <C>
1999
Net unrealized gains on investments $ 12,516 $ (4,680) $ 7,836
Adjustment for amounts included in income (1,998) -- (1,998)
-----------------------------------------------------------------------------------------------------------------------------------
Net change in accumulated other comprehensive income 10,518 (4,680) 5,838
-----------------------------------------------------------------------------------------------------------------------------------
Foreign currency translation adjustments 19,735 (6,907) 12,828
Adjustment for amounts included in income 1,586 (555) 1,031
-----------------------------------------------------------------------------------------------------------------------------------
Net change in accumulated other comprehensive income 21,321 (7,462) 13,859
-----------------------------------------------------------------------------------------------------------------------------------
Minimum pension liability 8,957 (3,691) 5,266
-----------------------------------------------------------------------------------------------------------------------------------
Total change in accumulated other comprehensive income/(loss) $40,796 $ (15,833) $ 24,963
====================================================================================================================================
1998
Net unrealized gains on investments $ 13,235 $ (4,248) $ 8,987
-----------------------------------------------------------------------------------------------------------------------------------
Foreign currency translation adjustments (23,295) 8,233 (15,062)
Adjustment for amounts included in income 8,737 (3,136) 5,601
-----------------------------------------------------------------------------------------------------------------------------------
Net change in accumulated other comprehensive income (14,558) 5,097 (9,461)
-----------------------------------------------------------------------------------------------------------------------------------
Minimum pension liability (2,605) 1,071 (1,534)
-----------------------------------------------------------------------------------------------------------------------------------
Total change in accumulated other comprehensive income/(loss) $ (3,928) $ 1,920 $ (2,008)
====================================================================================================================================
1997
Net unrealized gains on investments $ 10,895 $ (4,521) $ 6,374
Foreign currency translation adjustments (73,115) 24,186 (48,929)
Minimum pension liability (2,541) 1,046 (1,495)
-----------------------------------------------------------------------------------------------------------------------------------
Total change in accumulated other comprehensive income/(loss) $ (64,761) $ 20,711 $ (44,050)
====================================================================================================================================
</TABLE>
6. Accounting For Extraordinary And Non-Recurring Items
JCP&L Restructuring Write-off: In 1999, the NJBPU issued a Summary Order
regarding JCP&L's unbundling, stranded cost and restructuring filings.
Accordingly, in 1999 JCP&L discontinued the application of FAS 71 and adopted
the provisions of FAS 101 and EITF 97-4 with respect to its electric generation
operations. The transmission and distribution operations of JCP&L continue to be
subject to the provisions of FAS 71.
In 1999, JCP&L recorded a reduction in operating revenues of $115 million
relating to the Summary Order which resulted in an after-tax charge to earnings
of $68 million, or $0.54 per share. This reduction reflects JCP&L's obligation
to refund to customers 5% from rates in effect as of April 30, 1997. The refund
will be made to customers from August 1, 2002 through July 31, 2003.
Since JCP&L is no longer subject to FAS 71 for the generation portion of its
business, GPU performed an impairment test on Oyster Creek in accordance with
Statement of Financial Accounting Standards No. 121 (FAS 121) "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of." This test determined that JCP&L's net investment in Oyster Creek, including
plant, nuclear fuel and materials and supplies inventories, was impaired. This
investment was written down by a total of $678 million (pre-tax) in 1999 to
reflect the plant's fair market value. This impairment, which was recorded as an
extraordinary deduction, was reversed and reestablished as a regulatory asset
since the Summary Order provides for rate recovery.
Generation Asset Divestiture: As discussed below, in 1999, the GPU Energy
companies completed the sales of TMI-1 and substantially all of their
fossil-fuel and hydroelectric stations.
The GPU Energy companies sold TMI-1 to AmerGen Energy Company, LLC (AmerGen), a
joint venture of PECO Energy and British Energy, for a total purchase price of
approximately $100 million. The sale did not have a significant impact on 1999
earnings since TMI-1 had been written down to its fair market value in 1998. The
majority of the amount written down and the majority of the remaining loss from
the sale resulted
33 GPU 1999 FINANCIAL REPORT
<PAGE> 93
in the deferral of $528.3 million as a regulatory asset pending separate and
further reviews by the NJBPU and the PaPUC (Phase II of the Pennsylvania
restructuring proceedings).
The GPU Energy companies completed the sales of substantially all their fossil
fuel and hydroelectric generating facilities to Sithe Energies (Sithe) for
approximately $1.6 billion (JCP&L's 50% interest in Yards Creek was not included
in the sale and the sales of the 66 MW Forked River combustion turbines an
19 MW York Haven hydroelectric station were postponed). The sale resulted in the
recording of an after-tax gain of $13.4 million in 1999 for the portion of the
gain related to wholesale operations and the deferral of the remaining pre-tax
gain of $706.5 million as a regulatory liability pending separate and further
reviews by the NJBPU and the PaPUC.
Penelec sold its 20% interest in the Seneca Pumped Storage Hydroelectric
Generating Station to The Cleveland Electric Illuminating Company for $43
million. The sale resulted in the recording of an after-tax gain of $1.2 million
in 1999 for the portion of the gain related to wholesale operations and the
deferral of the remaining pre-tax gain of $30.2 million as a regulatory
liability pending further review by the PaPUC.
Penelec sold its 50% interest in the Homer City Station to a subsidiary of
Edison Mission Energy for approximately $900 million. As a result, Penelec
recorded an after-tax gain of $22.6 million in 1999 for the portion of the gain
related to wholesale operations and deferred as a regulatory liability the
remaining pre-tax gain of $590.7 million pending further review by the PaPUC.
Midlands sold its electric supply business to National Power plc for
approximately $300 million. As a result, in 1999 GPU recorded an after-tax gain
on the sale of $6.8 million.
For information on JCP&L's pending sale of Oyster Creek, see Note 12,
Commitments and Contingencies.
Pennsylvania Restructuring Write-offs: In 1998, Met-Ed and Penelec received
PaPUC Restructuring Orders which, among other things, essentially removed from
regulation the costs associated with providing electric generation service to
Pennsylvania consumers, effective January 1, 1999. Accordingly, in 1998 Met-Ed
and Penelec discontinued the application of FAS 71 and adopted the provisions of
FAS 101 and EITF Issue 97-4 with respect to their electric generation
operations. The transmission and distribution operations of Met-Ed and Penelec
continue to be subject to the provisions of FAS 71.
As a result of the Restructuring Orders, Met-Ed and Penelec recorded an
extraordinary charge of $25.8 million (after-tax) or $0.20 per share and a
non-recurring charge of $40 million (after-tax), or $0.32 per share, for
customer refunds of 1998 revenues and for the establishment of a sustainable
energy fund.
In accordance with FAS 121, impairment tests were performed and determined that
the net investment in TMI-1 was impaired at December 31, 1998, resulting in a
write-down of $518 million (pre-tax) to reflect TMI-1's fair market value. Of
the amount written down for TMI-1, $508 million was reestablished as a
regulatory asset because management believes it is probable of recovery in the
restructuring process and $10 million (the FERC jurisdictional portion) was
charged to expense as an extraordinary item in 1998.
Windfall Profits Tax Write-off: In 1997, the Government of the United Kingdom
imposed a windfall profits tax on privatized utilities, including Midlands. As a
result, a one-time charge to income of $109.3 million, or $0.90 per share, was
taken in 1997.
34 GPU 1999 FINANCIAL REPORT
<PAGE> 94
7. Acquisitions
Empresa Distribuidora Electrica Regional, S.A.: in March 1999, GPU Electric
acquired Empresa Distribuidora Electrica Regional, S.A. (Emdersa) for US $375
million. The fair value of the assets acquired totaled approximately $320
million and the amount of liabilities assumed totaled approximately $153
million, including debt of $76 million. Emdersa owns three electric distribution
companies that serve three provinces in northwest Argentina.
The acquisition was financed through the issuance of commercial paper by GPU
Capital, guaranteed by GPU, Inc., and a $50 million capital contribution from
GPU, Inc.
The acquisition has been accounted for under the purchase method of accounting.
The total acquisition cost exceeded the estimated value of net assets by
approximately $208 million. This excess is considered goodwill and is being
amortized on a straight-line basis over 40 years.
Transmission Pipelines Australia: In June 1999, GPU Electric acquired
Transmission Pipelines Australia (TPA), a natural gas transmission business,
from the State of Victoria, Australia for A$1.025 billion (approximately US $675
million). TPA has been renamed GPU GasNet. The fair value of the assets acquired
totaled approximately US $704 million and the amount of liabilities assumed
totaled approximately US $116 million.
The acquisition was financed through: (1) an A$750 million (approximately US
$495 million) senior credit facility, which is non-recourse to GPU, Inc.; and
(2) an equity contribution from GPU Capital of A$275 million (approximately US
$180 million) provided through the issuance of commercial paper guaranteed by
GPU, Inc.
The acquisition has been accounted for under the purchase method. The total
acquisition cost exceeded the estimated value of net assets acquired by
approximately $88 million. This excess is considered goodwill and is being
amortized on a straight-line basis over 40 years.
Midlands Electricity plc: In July 1999, GPU Electric acquired Cinergy's 50%
ownership interest in Avon, which owns Midlands, for (pound sterling) 452.5
million (approximately US $714 million). GPU and Cinergy had jointly formed
Avon in 1996 to acquire Midlands. The fair value of the assets acquired totaled
approximately US $2.1 billion and the liabilities totaled approximately
US$1.5 billion, including debt of US $1 billion.
GPU Electric financed the acquisition through a combination of equity and debt.
The equity was funded from: (1) a US $250 million contribution from GPU, Inc.,
and (2) the issuance of US $50 million of commercial paper by GPU Capital, which
is guaranteed by GPU, Inc. The debt has been provided through a two-year
(pound sterling) 245 million (approximately US $382 million) credit agreement
entered into by EI UK Holdings, of which GPU, Inc. has guaranteed approximately
US $100 million.
As a result of GPU's purchase of Cinergy's 50% ownership in Midlands, effective
in the third quarter of 1999, GPU began accounting for Midlands as a
consolidated entity, rather than under the equity method of accounting as was
previously the practice. Consequently, Goodwill, net on the Consolidated Balance
Sheet increased by approximately $1.8 billion in the third quarter of 1999. Of
this amount, $1.7 billion relates to the previous 1996 acquisition of Midlands
by GPU and Cinergy and approximately $119 million represents goodwill resulting
from GPU's purchase of Cinergy's 50% share of Midlands. The goodwill is being
amortized on a straight-line basis over 40 years.
Concurrent with GPU's July 1999 acquisition of the 50% of Midlands which it did
not already own, GPU began to evaluate existing restructuring plans and
formulate additional plans to reduce operating expenses and achieve ongoing cost
reductions. As of December 31, 1999, GPU had identified and approved a cost
reduction plan. At the acquisition date, Midlands had recorded a liability of
$28.6 million related to previous cost reduction plans. GPU retained $25.7
million of this liability, related to contractual termination and other
severance benefits for 276 employees identified in a 1999 business process
reengineering project. GPU identified an additional 355 employees (234 in
Engineering Services, 38 in metering, 21 in Network Services and 62 from other
specific functions) to be terminated as part of the plan and recorded an
additional liability of $39.3 million. A net charge of $18.2 million for GPU's
50% share of these adjustments is included in expense and the other 50% was
recorded as a purchase accounting adjustment.
As of December 31, 1999, $7.2 million of severance benefits had been paid to 172
of these employees. The remaining severance liability of $29.5 million for the
remaining 459 employees is included in Other current liabilities, and $28.3
million to be funded out of pension plan assets is included as a pension
liability. Management expects the plan will be substantially completed by June
2000.
35 GPU 1999 FINANCIAL REPORT
<PAGE> 95
The following unaudited pro forma consolidated results of operations for the
years 1999 and 1998 presents information assuming Emdersa, GPU GasNet and the
50% of Midlands GPU did not already own were acquired January 1, 1998. The pro
forma amounts include certain adjustments, primarily to recognize interest
expense, amortization of goodwill and depreciation of assets having stepped-up
bases, and are not necessarily indicative of the actual results that would have
been realized had the acquisitions occurred on the assumed date of January 1,
1998, nor are they necessarily indicative of future results. The pro forma
operating results are for information purposes only and are as follows:
<TABLE>
<CAPTION>
1999 1998
--------------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS, EXCEPT PER SHARE DATA) AS REPORTED PRO FORMA* AS REPORTED PRO FORMA*
--------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Revenues $4,757,124 $6,030,514 $4,248,792 $6,901,012
Income before extraordinary item $ 459,014 $ 493,449 $ 385,881 $ 441,776
Net income $ 459,014 $ 493,449 $ 360,126 $ 416,021
Basic and Diluted earnings per share before extraordinary item $ 3.66 $ 3.94 $ 3.03 $ 3.47
Basic and Diluted earnings per share $ 3.66 $ 3.94 $ 2.83 $ 3.27
--------------------------------------------------------------------------------------------------------------------------
</TABLE>
*Unaudited
GPU PowerNet: In 1997, GPU Electric acquired the business of GPU PowerNet from
the State of Victoria, Australia for A$2.6 billion (approximately US $1.9
billion). The fair value of the assets acquired totaled approximately US $2
billion and the amount of liabilities assumed totaled approximately US $142.9
million. GPU PowerNet owns and operates the high-voltage electricity
transmission system in the State of Victoria serving an area of approximately
87,900 square miles and a population of approximately 4.5 million.
The acquisition was financed through: (1) a senior debt credit facility of A$1.9
billion (approximately US $1.4 billion), which is non-recourse to GPU, Inc.; (2)
a five-year US $450 million bank credit agreement which is guaranteed by GPU,
Inc.; and (3) an equity contribution from GPU, Inc. of US $50 million.
The acquisition was accounted for under the purchase method of accounting. The
total acquisition costs exceeded the estimated value of net assets by A$877
million (approximately US $537 million). This excess is considered goodwill and
is being amortized on a straight-line basis over 40 years.
GPU PowerNet has been included in GPU's consolidated financial statements since
its purchase on November 6, 1997. The unaudited consolidated pro forma
information for 1997, assuming debt financing and an acquisition date of January
1, 1997, is as follows: operating revenues of $4.32 billion; net income of $327
million; basic comings per share of $2.71 and; diluted earnings per share of
$2.70. The pro forma results, which are for information purposes only, are not
necessarily indicative of the actual results that would have been realized had
the acquisition occurred on the assumed date of January 1,1997, nor are they
necessarily indicative of future results.
Planned Acquisition of MYR Group Inc.: In December 1999, GPU, Inc., and MYR
Group Inc. (MYR) entered into an agreement under which GPU has agreed to acquire
the utility infrastructure construction firm for $215 million cash, or $30.10
per share of MYR common stock. Following the acquisition, MYR would become a
wholly-owned subsidiary of GPU, Inc. The acquisition, which is subject to
approval by the SEC and other conditions, is expected to be completed in the
first quarter of 2000. The acquisition will be initially financed through
short-term debt and will be accounted for under the purchase method of
accounting.
36 GPU 1999 FINANCIAL REPORT
<PAGE> 96
8. Income Taxes
As of December 31, 1999 and 1998, Regulatory assets, net, on the Consolidated
Balance Sheets reflected $296 million and $450 million, respectively, of Income
taxes recoverable through future rates (primarily related to liberalized
depreciation), and Income taxes refundable through future rates of $28 million
and $53 million, respectively (related to unamortized ITC). These net regulatory
assets are substantially due to the recognition of amounts not previously
recorded with the adoption of Statement of Financial Accounting Standards No.
109, "Accounting for Income Taxes," in 1993.
A summary of the components of deferred taxes as of December 31, 1999 and 1998
follows:
<TABLE>
<CAPTION>
(IN MILLIONS)
DEFERRED TAX ASSETS
--------------------------------------------------------------------------------------------
1999 1998
--------------------------------------------------------------------------------------------
Current:
<S> <C> <C>
Unbilled revenue $ 12 $ 31
Deferred energy -- --
Other 60 16
--------------------------------------------------------------------------------------------
Total $ 72 $ 47
============================================================================================
Noncurrent:
Unamortized ITC $ 36 $ 70
Decommissioning 77 151
Contributions in aid of construction 28 26
Cumulative translation adjustment 22 29
Above-market NUGs 798 748
Customer transition charge 533 534
Revenue subject to refund 47 23
Generation revenue requirements 47 44
Net gain on generation asset sales 499 --
Other 441 379
--------------------------------------------------------------------------------------------
Total $2,528 $2,004
============================================================================================
<CAPTION>
DEFERRED TAX LIABILITIES
-------------------------------------------------------------------------------------------
1999 1998
-------------------------------------------------------------------------------------------
<S> <C> <C>
Current:
Revenue taxes $ 5 $ 8
Deferred energy 3 4
-------------------------------------------------------------------------------------------
Total $ 8 $ 12
===========================================================================================
Noncurrent:
Liberalized Depreciation:
Previously flowed through $ 222 $ 202
Future revenue requirements 147 155
-------------------------------------------------------------------------------------------
Subtotal 369 357
Liberalized depreciation 659 719
Customer transition charge 1,451 1,684
Net loss on generation asset sales 218 --
Other 866 285
-------------------------------------------------------------------------------------------
Total $3,563 $3,045
===========================================================================================
</TABLE>
The reconciliations of net income to book income subject to tax and of the
federal statutory rate to combined federal and state effective tax rates are as
follows:
<TABLE>
<CAPTION>
(IN MILLIONS) 1999 1998 1997
----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Net income $ 459 $ 360 $ 335
Preferred stock dividends 9 11 13
Loss on preferred stock reacquisition 2 -- --
Income tax expense 294 250 234
----------------------------------------------------------------------------------------------
Book income subject to tax $ 764* $ 621* $ 582*
==============================================================================================
Federal statutory rate 35% 35% 35%
State tax, net of federal benefit 5 5 4
Amortization of ITC (6) (1) (2)
Other, net 4 1 3
----------------------------------------------------------------------------------------------
Effective income tax rate 38% 40% 40%
==============================================================================================
</TABLE>
* Includes pre-tax foreign operations income of $331 million, $238
million and $34 million, of which $85 million, $88 million and $20
million, respectively for 1999, 1998 and 1997, are included in Equity
in undistributed earnings/(loss) of affiliates in the Consolidated
Statements of Income.
37 GPU 1999 FINANCIAL REPORT
<PAGE> 97
Federal and state income tax expense is comprised of the following:
<TABLE>
<CAPTION>
(IN MILLIONS) 1999 1998 1997
-----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Provisions for taxes currently payable:
Domestic $ 775 $ 290 $ 206
Foreign 60 22 40
-----------------------------------------------------------------------------------------------------------------------------------
Total provision for taxes $ 835 $ 312 $ 246
Deferred income taxes:
Liberalized depreciation $(252) $ 2 $ 14
Foreign deferred taxes 80 31 4
Unbilled revenues 19 -- (8)
Gain/(Loss) on sole of properly (406) -- --
Decommissioning 87 (19) (5)
PA Restructuring (FAS 71) 61 (15) --
Global Settlement 2 (8) --
Pension expense/Voluntary Enhanced Retirement Programs (1) (8) (10)
Nonutility generation contract buyout costs (14) (11) 5
Provision for rote refunds (47) (10) --
OPEBs 2 (12) 5
Other (25) (3) (7)
-----------------------------------------------------------------------------------------------------------------------------------
Deferred income taxes, net (494) (53) (2)
-----------------------------------------------------------------------------------------------------------------------------------
Amortization of ITC, net (47) (9) (10)
-----------------------------------------------------------------------------------------------------------------------------------
Income tax expense $ 294 $ 250 $ 234
-----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
The foreign taxes in the above table for 1999, 1998 and 1997, include $53
million ($16 million Current; $37 million Deferred), $27 million ($10 million
Current; $17 million Deferred) and $41 million ($37 million Current; $4 million
Deferred) in foreign tax expense which is netted in Equity in undistributed
earnings/(loss) of affiliates in the Consolidated Statements of Income. Included
in the ITC Amortization is the recognition of $36 million of ITC benefit
resulting from the sale of generation plants.
The Internal Revenue Service (IRS) has completed its examinations of GPU's
federal income tax returns through 1995.
9. Supplementary Income Statement Information
Maintenance expense and other taxes charged to operating expenses consisted of
the following:
<TABLE>
<CAPTION>
(IN MILLIONS) 1999 1998 1997
----------------------------------------------------------------------------------------------------------------------------------
MAINTENANCE $210 $202 $216
----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Other taxes:
New Jersey Transitional Energy Facility Assessment $ 59 $ 67 --
New Jersey unit tax -- -- $211
Pennsylvania state gross receipts 54 79 81
Real estate and personal property 39 23 27
Value Added and Stamp taxes (U.K.) 6 -- --
Other 33 50 39
----------------------------------------------------------------------------------------------------------------------------------
Total $191 $219 $358
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
38 GPU 1999 FINANCIAL REPORT
<PAGE> 98
10. Employee Benefits
Pension Plans and Other Postretirement Benefits: GPU maintains defined benefit
pension plans covering substantially all employees. GPU also provides certain
retiree health care and life insurance benefits for substantially all US
employees who reach retirement age while working for GPU. The following tables
provide a reconciliation of the changes in the plans' benefit obligation and
fair value of assets for the years ended December 31, 1999 and 1998, a statement
of the funded status of the plans, the amounts recognized in the Consolidated
Balance Sheets as of December 31, 1999 and 1998 and the weighted average
assumptions used in the measurement of the benefit obligation. The pension
benefit disclosure amounts for the year 1999 reflect the acquisition of the
remaining 50% of Midlands stock by GPU in July of that year. Accordingly, the
July 1999 benefit obligation and fair value of plan assets balances for Midlands
are shown next to the line items entitled "Acquisitions" and the
post-acquisition amounts occurring in the second half of 1999 are included in
the tables.
<TABLE>
<CAPTION>
OTHER POSTRETIREMENT
(IN MILLIONS) PENSION BENEFITS BENEFITS
------------------------------------------------------------------------------------------------- -------------------------
1999 1998 1999 1998
------------------------------------------------------------------------------------------------- -------------------------
<S> <C> <C> <C> <C>
Change in benefit obligation:
Benefit obligation at January 1: $ 1,897.0 $ 1,791.7 $ 790.5 $ 798.0
Acquisitions 1,502.5 -- -- --
Service cost 46.2 36.1 15.9 16.4
Interest cost 158.0 121.6 52.2 54.4
Plan amendments 2.5 9.6 -- (6.0)
Actuarial (gain)/loss and other items (182.8) 26.2 (36.9) (55.7)
Currency exchange (4.0) -- -- --
Benefits paid (171.0) (123.9) (39.8) (30.2)
Curtailments and settlements (139.4) 6.8 (44.8) 12.5
Termination benefits 48.8 28.9 -- 1.1
-------------------------------------------------------------------------------------------------------------------------------
Benefit obligation at December 31: $ 3,157.8 $ 1,897.0 $ 737.1 $ 790.5
-------------------------------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at January 1: $ 2,258.8 $ 2,033.3 $ 507.1 $ 403.0
Acquisitions 1,710.2 -- -- --
Actual return on plan assets 579.4 342.9 61.0 78.9
Employer contributions 1.8 6.5 15.0 55.4
Benefits paid (171.0) (123.9) (39.8) (30.2)
Currency exchange (5.8) -- -- --
Settlement and other items (30.0) -- -- --
-------------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at December 31: $ 4,343.4 $ 2,258.8 $ 543.3 $ 507.1
-------------------------------------------------------------------------------------------------------------------------------
Funded Status:
Funded status at December 31: $ 1,185.6 $ 361.8 $ (193.8) $ (283.4)
Unrecognized net actuarial (gain)/loss (953.0) (439.5) (54.2) (37.8)
Unrecognized prior service cost 21.5 27.6 2.9 4.3
Unrecognized net transition (asset)/obligation (1.4) (1.9) 143.3 210.7
-------------------------------------------------------------------------------------------------------------------------------
Net amount recognized $ 252.7 $ (52.0) $ (101.8) $ (106.2)
-------------------------------------------------------------------------------------------------------------------------------
Amounts recognized in the Consolidated Balance Sheet
at December 31:
Prepaid benefit cost $ 297.2 $ 42.0 $ 24.2 $ 43.8
Accrued benefit liability (45.3) (103.0) (126.0) (150.0)
Intangible asset 0.8 -- -- --
Accumulated other comprehensive income -- 5.3 -- --
Deferred income taxes -- 3.7 -- --
-------------------------------------------------------------------------------------------------------------------------------
Net amount recognized $ 252.7 $ (52.0) $ (101.8) $ (106.2)
-------------------------------------------------------------------------------------------------------------------------------
Weighted average assumptions as of December 31:
Discount rate 7.0% 6.75% 7.5% 6.75%
Expected return on plan assets 8.1% 8.5% 8.5% 8.5%
Rate of compensation increase 4.7% 4.5% -- --
</TABLE>
39 GPU 1999 FINANCIAL REPORT
<PAGE> 99
The following tables provide the components of net periodic pension and other
postretirement benefit costs. As previously discussed, the 1999 net periodic
pension cost reflects post-acquisition amounts related to Midlands for the
second half of the year.
<TABLE>
<CAPTION>
PENSION PLANS
(IN MILLIONS) 1999 1998 1997
-----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost $ 46.2 $ 36.1 $ 31.1
Interest cost 158.0 121.6 122.2
Expected return on plan assets (198.0) (140.1) (131.5)
Amortization of transition (asset)/obligation (0.5) (0.5) (0.5)
Other amortization 2.1 1.1 0.2
------------------------------------------------------------------------------------------------------------------------------
Net periodic pension cost $ 7.8 $ 18.2 $ 21.5
------------------------------------------------------------------------------------------------------------------------------
</TABLE>
In 1999, the effect of increasing the discount rate assumption for the US
pension plans from 6.75% to 7.5% resulted in a $162 million decrease in the
benefit obligation as of December 31, 1999. In 1998, the effect of decreasing
the discount rate assumption from 7% to 6.75% was partially offset by the effect
of decreasing the salary scale assumption from 5% to 4.5% and resulted in a $35
million increase in the benefit obligation as of December 31, 1998.
The above net periodic pension cost amount for 1999 excludes pre-tax credits of
$31 million, of which $30 million was deferred for return to customers,
resulting from employee terminations related to generation asset divestiture.
The above net periodic pension cost amount for 1998 excludes pre.tax charges of
$3O million, of which $22 million was deferred pending future rate recovery,
resulting from early retirement programs in 1998.
<TABLE>
<CAPTION>
OTHER POSTRETIREMENT BENEFITS
(IN MILLIONS) 1999 1998 1997
----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost $ 15.9 $ 16.4 $ 10.7
Interest cost 52.2 54.4 51.7
Expected return on plan assets (37.5) (29.5) (23.7)
Amortization of transition (asset)/obligation 14.6 15.8 16.8
Other amortization 1.6 5.0 2.3
----------------------------------------------------------------------------------------------------------------------------------
Net periodic postretirement benefit cost 46.8 62.1 57.8
Deferred for future recovery -- -- (13.0)
----------------------------------------------------------------------------------------------------------------------------------
Postretirement benefit cost, net of deferrals $ 46.8 $ 62.1 $ 44.8
----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
In 1999, the effect of increasing the assumption associated with medical
inflation rates was partially offset by the effect of increasing the discount
rate assumption from 6.75% to 73% and resulted in a$45 million increase in the
benefit obligation as of December 31, 1999. In 1998, the effect of decreasing
the assumption relating to the long-term medical cost of managed care plans was
partially offset by the effect of decreasing the discount rate assumption from
7% to 6.75% and resulted in a $40 million decrease in the benefit obligation as
of December 31, 1998. The benefit obligation was determined by application of
the terms of the medical and life insurance plans, including the effects of
established maximums on covered costs, together with relevant actuarial
assumptions and health-care cost trend rates of 10% for those not eligible for
Medicare and 11% for those eligible for Medicare, then decreasing gradually to
6% in 2010 and thereafter. These costs also reflect the implementation of an
annual cost-cap of 6% for individuals who retire after December 31, 1995 and
reach age 65. The effect of a 1% change in these assumed cost trend rates would
increase or decrease the benefit obligation by $39.2 million or $36.9 million,
respectively. In addition, such a 1% change would increase or decrease the
aggregate service and interest cost components of net periodic postretirement
health-care cost by $3.5 million or $3.4 million, respectively.
The above net periodic postretirement benefit cost amount for 1999 excludes
pre-tax charges of $3 million, which was deferred pending future rate recovery,
resulting from employee terminations related to generation asset divestiture.
The above net periodic postretirement benefit cost amount for 1998 excludes
pre-tax charges of $20 million, of which $12 million was deferred pending future
rate recovery, resulting from early retirement programs in 1998.
In JCP&L's 1993 base rate proceeding, the NJBPU allowed JCP&L to collect $3
million annually for incremental postretirement benefit costs, charged to
expense, and recognized as a result of FAS 106. Based on the final order, and in
accordance with EITF Issue 92-12, "Accounting for OPEB Costs by Rate-Regulated
Enterprises," JCP&L has deferred the amounts above that level. A 1997
Stipulation of Final Settlement (Final
40 GPU 1999 FINANCIAL REPORT
<PAGE> 100
Settlement) allows JCP&L to recover and amortize the deferred balance at
December 31, 1997 over a fifteen-year period. In addition, the Final Settlement
allows JCP&L to recover current amounts accrued pursuant to FAS 106, including
amortization of the transition obligation. Met-Ed has deferred the incremental
postretirement benefit costs associated with the adoption of FAS 106 and in
accordance with EITF Issue 92-12, as authorized by the PaPUC in its 1993 base
rate order. In accordance with EITF Issue 92-12, effective January 1998, Met-Ed
has ceased deferring these costs. The approximately one-third generation-related
portion of the deferred balance at December 31, 1997 is to be recovered in rates
over a twelve-year period pursuant to the PaPUC's Restructuring Orders. The
remaining two-thirds for the transmission and distribution-related portion is to
be amortized over a fourteen-year period beginning January 1999, pursuant to the
Restructuring Orders. In 1994, Penelec determined that its FAS 106 costs,
including costs deferred since January 1993, were not probable of recovery and
charged those deferred costs to expense.
Savings Plans: GPU also maintains savings plans for substantially all US
employees. These plans provide for employee contributions up to specified limits
and various levels of employer matching contributions. The matching
contributions for GPU for 1999, 1998 and 1997 were $14 million, $13.6 million
and $12.6 million, respectively.
11. Leases
GPU Energy companies: The GPU Energy companies' capital leases consist primarily
of leases for nuclear fuel. Nuclear fuel capital lease obligations at December
31, 1999 and 1998 totaled $48 million and $126 million, respectively.
Prior to the sale of TMI-1 to AmerGen in December 1999, the GPU Energy companies
had nuclear fuel lease agreements with nonaffiliated fuel trusts for the plant.
Upon the sale of TMI-1, the related fuel leases were terminated and all
outstanding amounts due under the related credit facility were paid. The Oyster
Creek fuel lease agreement will be terminated upon the sale of Oyster Creek to
AmerGen. Lease expense consists of an amount designed to amortize the cost of
the nuclear fuel as consumed plus interest costs. For the years ended December
31, 1999, 1998 and 1997, these amounts were $53 million, $54 million and $49
million, respectively.
Met-Ed and JCP&L have sold and leased back a portion of their respective
ownership interests in the Merrill Creek Reservoir project. The annual minimum
lease payments under these operating leases, which have remaining terms of 33
years, range from approximately $3.6 million to $6.7 million over the next five
years, net of reimbursements from sublessees. Met-Ed believes that its Merrill
Creek lease payments will be a recoverable stranded cost in Phase II rate
proceedings pending before the PaPUC. JCP&L is recovering its Merrill Creek
lease payments, net of reimbursements, through distribution rates.
GPUI Group: A subsidiary of GPU International sold and leased back an electric
cogeneration facility for on initial term of eleven years (facility lease) for
which GPU, Inc. has guaranteed payments of up to $8.1 million. In addition, a
20-year site lease was entered into commencing in 1993. The leases are accounted
for as operating leases and rent expense is recorded on a straight-line basis
over the initial 11-year term of the facility lease. Rent expense at December
31, 1999 and 1998 totaled $12.3 million and $11.3 million, respectively. The
minimum lease payments for 2000, 2001, 2002, 2003 and 2004 are $13.4 million,
$14.1 million, $14.8 million, $15.8 million and $12 million, respectively.
12. Commitments and Contingencies
Competition and the Changing Regulatory Environment:
Generation Asset Divestiture: In 1999, the GPU Energy companies completed the
sales of TMI-1 and substantially all of their fossil and hydroelectric
generating stations. For additional information on the completed sales, see Note
6, Accounting for Extraordinary and Non-recurring Items.
In October 1999, JCP&L agreed to sell Oyster Creek to AmerGen for $10 million
and reimbursement of the cost (estimated at $88 million) of the next scheduled
refueling outage. This transaction is subject to the receipt of various federal
and state regulatory approvals.
JCP&L and Public Service Electric & Gas Company (PSE&G) each hold a 50%
undivided ownership interest in Yards Creek Pumped Storage Facility (Yards
Creek). In December 1998, JCP&L filed a petition with the NJBPU seeking a
declaratory order that PSE&G's right of first refusal to purchase JCP&L's
ownership interest at its current book value under a 1964 agreement between the
companies is void and unenforceable. Management believes that the fair market
value of JCP&L's ownership interest in Yards Creek is substantially in excess of
its December 31, 1999 book value of $22 million. There can be no assurance as to
the outcome of this matter.
41 GPU 1999 FINANCIAL REPORT
<PAGE> 101
Stranded Costs and Regulatory Restructuring Orders: With the current market
price of electricity being below the cost of some utility-owned generation and
power purchase commitments, and the ability of customers to choose their energy
suppliers, certain costs, which generally would be recoverable in a regulated
environment, may not be recoverable in a competitive environment. These costs
are generally referred to as stranded costs.
In 1998, the PaPUC issued Restructuring Orders to Met-Ed and Penelec which,
among other things, provide for Met-Ed and Penelec's recovery of a substantial
portion of what otherwise would have become stranded costs, and provide for a
Phase II proceeding following the completion of their generation divestitures to
make a final determination of the extent of that stranded cost recovery. An
appeal by one intervenor in the restructuring proceedings is pending before the
Pennsylvania Supreme Court. There can be no assurance as to the outcome of this
appeal.
In April 1999, JCP&L entered into a settlement agreement with several parties to
its stranded cost and rate unbundling proceedings, pending before the NJBPU. In
May 1999, the NJBPU issued a Summary Order, approving the settlement with
certain modifications. Among other things, the Summary Order provides for full
recovery of JCP&L's stranded costs. The Summary Order did not address the
pending sale of Oyster Creek, because at the time the Summary Order was issued,
it was uncertain whether the plant would be sold or retired early. As a result
of the NJBPU's actions, in the second quarter of 1999, JCP&L recorded a
reduction in operating revenues of $115 million reflecting JCP&L's obligation to
make refunds to customers. JCP&L is awaiting a final order from the NJBPU. For
additional information, see Note 6, Accounting for Extraordinary and
Non-recurring Items.
Under the NJBPU and the PaPUC restructuring orders, the GPU Energy companies are
required to provide generation service to customers who do not choose an
alternate supplier. As noted above, the GPU Energy companies have sold or agreed
to sell substantially all of their generation assets. Consequently, there will
be increased market risks associated with providing generation service since the
GPU Energy companies will have to supply energy almost entirely from contracted
and open market purchases. Under the Summary Order, JCP&L is permitted to
recover reasonable and prudently incurred costs associated with providing basic
generation service and to defer the portion of these costs that cannot be
recovered currently. The PaPUC's Restructuring Orders, however, generally do not
allow Met-Ed and Penelec to recover their costs, including their energy costs in
excess of established rate caps. An inability of the GPU Energy companies to
supply electricity to customers who do not choose an alternate supplier at a
cost recoverable under their capped rates, would have an adverse effect, which
may be material, on GPU's results of operations.
Generation Agreements: The emerging competitive generation market has created
uncertainty regarding the forecasting of the GPU Energy companies' energy supply
needs, which has caused the GPU Energy companies to seek shorter-term agreements
offering more flexibility. The GPU Energy companies' supply plan focuses on
short- to intermediate-term commitments (one month to three years) covering
times of expected high energy price volatility (that is, peak demand periods)
and reliance on spot market purchases during other periods.
As of December 31, 1999, the GPU Energy companies have entered into agreements
with third party suppliers to purchase capacity and energy. Payments pursuant to
these agreements, which include firm commitments as well ascertain assumptions
regarding, among other things, call/put arrangements and the timing of the
pending Oyster Creek sale, are estimated to be $709 million in 2000, $565
million in 2001, $328 million in 2002, $144 million in 2003 and $44 million in
2004.
Pursuant to the mandates of the federal Public Utility Regulatory Policies Act
and state regulatory directives, the GPU Energy companies have been required to
enter into power purchase agreements with NUGs for the purchase of energy and
capacity which have remaining terms of up to 21 years. The rates under virtually
all of the GPU Energy companies' NUG agreements are substantially in excess of
current and projected prices from alternative sources. The projected cost of
energy from new generation supply sources has also decreased due to improvements
in power plant technologies and lower forecasted fuel prices. The following
table shows actual payments from 1997 through December 31, 1999, and estimated
payments thereafter through 2004.
PAYMENTS UNDER NUG AGREEMENTS
(IN MILLIONS) TOTAL JCP&L MET-ED PENELEC
------------------------------------------------------------
1997 759 384 172 203
1998 788 403 174 211
1999 774 388 167 219
2000 794 405 157 232
2001 778 410 154 214
2002 799 422 158 219
2003 802 413 163 226
2004 808 407 168 233
42 GPU 1999 FINANCIAL REPORT
<PAGE> 102
The NJBPU Summary Order and PaPUC Restructuring Orders provide the GPU Energy
companies assurance of full recovery of their NUG costs (including above-market
NUG costs and certain buyout costs). Accordingly, the GPU Energy companies have
recorded, on a present value basis, a liability for above-market NUG costs of
$3.2 billion on the Consolidated Balance Sheets which is fully offset by
Regulatory assets, net. In addition, JCP&L recorded a liability of $64 million
for above-market utility power purchase agreements with a corresponding offset
to Regulatory assets, net, since there is also assurance of full recovery of
these costs. The GPU Energy companies are continuing efforts to reduce the
above-market costs of these agreements and will, where beneficial, attempt to
renegotiate the prices of the agreements, offer contract buyouts and attempt to
convert must-run agreements to dispatchable agreements. There can be no
assurance as to the extent to which these efforts will be successful.
In 1997, the NJBPU approved a Stipulation of Final Settlement which, among other
things, provided for the recovery of costs associated with the buyout of the
Freehold Cogeneration power purchase agreement (Freehold buyout). The NJBPU
approved the cost recovery of up to $135 million, over a seven-year period, on
an interim basis subject to refund. The NJBPU's Summary Order provides for the
continued recovery of the Freehold buyout in the MTC, but has not altered the
interim nature of such recovery, pending a final decision by the NJBPU. There
can be no assurance as to the outcome of this matter.
Accounting Matters: JCP&L, in 1999, and Met-Ed and Penelec in 1998, discontinued
the application of FAS 71, and adopted the provisions of FAS 101, and EITF Issue
97-4 with respect to their electric generation operations. The transmission and
distribution portion of the GPU Energy companies' operations continue to be
subject to the provisions of FAS 71.
Regulatory assets, net as reflected in the December 31, 1999 and December 31,
1998 Consolidated Balance Sheets in accordance with the provisions of FAS 71 and
EITF Issue 97-4 were as follows:
<TABLE>
<CAPTION>
(IN THOUSANDS) 1999 1998
-------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Market transition charge (MTC)/basic generation service (NJ) $ 2,358,844 $ --
Competitive transition charge (CTC) (PA) 803,064 1,023,815
Reserve for generation divestiture 536,904 1,527,985
Power purchase contract loss not in CTC (PA) 369,290 369,290
Costs recoverable through distribution rates (NJ) 296,841 --
Income taxes recoverable through future rates, net 280,268 396,937
Three Mile Island Unit 2 (TMI-2) decommissioning costs 100,794 119,571
Societal benefits charge (NJ) 116,941 --
Other postretirement benefits 25,335 73,770
Nonutility generation contract buyout costs -- 123,208
Unamortized property losses (NJ) -- 80,287
Net investment in TMI-2 (NJ) -- 65,787
Environmental remediation (NJ) -- 50,214
Above market NUC deferral costs (252,348) (16,067)
Other, net 76,721 126,032
-------------------------------------------------------------------------------------------------------------
Total regulatory assets, net $ 4,712,654 $ 3,940,829
-------------------------------------------------------------------------------------------------------------
</TABLE>
Statement of Financial Accounting Standards No. 133 (FAS 133), "Accounting for
Derivative Instruments and Hedging Activities," establishes accounting and
reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities. FAS 133
requires that companies recognize all derivatives as either assets or
liabilities on the balance sheet and measure those instruments at fair value.
GPU will be required to include its derivative transactions on its balance sheet
at fair value, and recognize the subsequent changes in fair value as either
gains or losses in earnings or report them as a component of other comprehensive
income, depending upon the intended use and designation of the derivative as a
hedge. FAS 133 is effective for all fiscal quarters of fiscal years beginning
after June 15, 2000. GPU will adopt FAS 133 in the first quarter of 2001 and is
in the process of evaluating the impact of the implementation of this statement.
GPU's use of derivative instruments is intended to manage the risk of interest
rate, foreign currency and commodity price fluctuations and may include such
transactions as electricity and natural gas forward and futures contracts,
foreign currency swaps, interest rate swaps and options. GPU does not intend to
hold or issue derivative instruments for trading purposes.
43 GPU 1999 FINANCIAL REPORT
<PAGE> 103
Nuclear Facilities:
Investments: In December 1999, the GPU Energy companies sold TMI-1 to AmerGen
for approximately $100 million. In addition, JCP&L has agreed to sell Oyster
Creek to AmerGen for $10 million and reimbursement of the cost (estimated at $88
million) of the next refueling outage. TMI-2, which was damaged during a 1979
accident, is jointly owned by JCP&L, Met-Ed and Penelec in the percentages of
25%, 50% and 25%. JCP&L's net investment in TMI-2 at December 31, 1999 and 1998
was $61 million and $66 million, respectively. JCP&L is collecting revenues for
TMI-2 on a basis which provides for the recovery of its remaining investment in
the plant by 2008. Met-Ed and Penelec's remaining investments in TMI-2 were
written off in 1998 after receiving the PaPUC's Restructuring Orders.
Costs associated with the operation, maintenance and retirement of nuclear
plants have continued to be significant and less predictable than costs
associated with other sources of generation, in large part due to changing
regulatory requirements, safety standards, availability of nuclear waste
disposal facilities and experience gained in the construction and operation of
nuclear facilities. Also, not all risks associated with the ownership or
operation of nuclear facilities may be adequately insured or insurable.
Consequently, the recovery of costs associated with nuclear projects, including
replacement power, any unamortized investment at the end of each plant's useful
life (whether scheduled or premature), the carrying costs of that investment and
retirement costs, is not assured.
TMI-2: As a result of the 1979 TMI-2 accident, individual claims for alleged
personal injury (including claims for punitive damages), which are material in
amount, were asserted against GPU, Inc. and the GPU Energy companies.
Approximately 2,100 of such claims were filed in the US District Court for the
Middle District of Pennsylvania. Some of the claims also seek recovery for
injuries from alleged emissions of radioactivity before and after the accident.
At the time of the TMI-2 accident, as provided for in the Price-Anderson Act,
the GPU Energy companies had (a) primary financial protection in the form of
insurance policies with groups of insurance companies providing an aggregate of
$140 million of primary coverage, (b) secondary financial protection in the form
of private liability insurance under an industry retrospective rating plan
providing for up to an aggregate of $335 million in premium charges under such
plan, and (c) an indemnity agreement with the Nuclear Regulatory Commission
(NRC) for up to $85 million, bringing their total financial protection up to an
aggregate of $560 million. Under the secondary level, the GPU Energy companies
are subject to a retrospective premium charge of up to $5 million per reactor,
or a total of $15 million.
In 1995, the US Court of Appeals for the Third Circuit ruled that the
Price-Anderson Act provides coverage under its primary and secondary levels for
punitive as well as compensatory damages, but that punitive damages could not be
recovered against the Federal Government under the third level of financial
protection. In so doing, the Court of Appeals referred to the "finite fund" (the
$560 million of financial protection under the Price-Anderson Act) to which
plaintiffs must resort to get compensatory as well as punitive damages.
The Court of Appeals also ruled that the standard of care owed by the defendants
to a plaintiff was determined by the specific level of radiation which was
released into the environment, as measured at the site boundary, rather than as
measured at the specific site where the plaintiff was located at the time of the
accident (as the defendants proposed). The Court of Appeals also held that each
plaintiff still must demonstrate exposure to radiation released during the TMI-2
accident and that such exposure had resulted in injuries. In 1996, the US
Supreme Court denied petitions filed by GPU, Inc. and the GPU Energy companies
to review the Court of Appeals' rulings.
In 1996, the District Court granted a motion for summary judgment filed by GPU,
Inc. and the GPU Energy companies, and dismissed the ten initial "test cases,"
which had been selected for a test case trial as well as all of the remaining
2,100 pending claims. The Court ruled that there was no evidence which created a
genuine issue of material fact warranting submission of plaintiffs' claims to a
jury. The plaintiffs appealed the District Court's ruling to the Court of
Appeals for the Third Circuit. In November 1999, the Third Circuit affirmed the
District Court's dismissal of the ten "test cases," but set aside the dismissal
of the additional pending claims, remanding them to the District Court for
further proceedings. In remanding these claims, the Third Circuit held that the
District Court had erred in extending its summary judgment decision to the other
plaintiffs and imposing on these plaintiffs the District Court's finding that
radiation exposures below 10 rems were too speculative to establish a causal
link to cancer. The Court of Appeals stated that the non-test case plaintiffs
should be permitted to present their own individual evidence that exposure to
radiation from the accident caused their cancers.
GPU, Inc. and the GPU Energy companies believe that the Third Circuit has
misinterpreted the record before the District Court as it applies to the
non-test case plaintiffs, and in November 1999, filed petitions seeking a
rehearing and reconsideration of the Court's decision regarding the remaining
claims. The "test case" plaintiffs also requested a rehearing of the Court's
decision upholding the dismissal of their claims. In January 2000, the Court of
Appeals denied both petitions. The "test case" plaintiffs have stated that they
intend to seek, and GPU, Inc. and the GPU Energy companies are considering
whether to seek, Supreme Court review of the District Court's decision. There
can be no assurance as to the outcome of this litigation.
44 GPU 1999 FINANCIAL REPORT
<PAGE> 104
GPU, Inc. and the GPU Energy companies believe that any liability to which they
might be subject by reason of the TMI-2 accident will not exceed their financial
protection under the Price-Anderson Act.
Nuclear Plant Retirement Costs: Retirement costs for nuclear plants include
decommissioning the radiological portions of the plants and the cast of removal
of nonradiological structures and materials. The disposal of spent nuclear fuel
is covered separately by contracts with the DOE.
In 1995,a consultant to GPUN performed site-specific studies of TMI-2 and Oyster
Creek (updated in 1998), that considered various decommissioning methods and
estimated the cost of decommissioning the radiological portions and the cost of
removal of the nonradiological portions of each plant, using the prompt
removal/dismantlement method. GPUN management has reviewed the methodology and
assumptions used in these studies, is in agreement with them, and believes the
results are reasonable. Under NRC regulations, JCP&L is making periodic payments
to complete the funding for Oyster Creek retirement costs by the end of the
plant's license term of 2009. The TMI-2 funding completion date is 2014,
consistent with TMI-2's remaining in long-term storage. The NRC may require an
acceleration of the decommissioning funding for Oyster Creek if the pending sale
is not completed and the plant is retired early. The retirement cost estimates
under the 1995 site-specific studies, assuming decommissioning of TMI-2 and
Oyster Creek in 2014 and 2009, respectively, areas follows (in 1999 dollars):
OYSTER
(IN MILLIONS) TMI-2 CREEK
---------------------------------------------------------------
Radiological decommissioning $435 $591
Nonradiological cost of removal 34* 32
---------------------------------------------------------------
Total $469 $623
---------------------------------------------------------------
* Net of $12.6 million spent as of December 31, 1999.
Each of the GPU Energy companies is responsible for retirement costs in
proportion to its respective ownership percentage. The ultimate cost of retiring
the GPU Energy companies' nuclear facilities may be different from the cost
estimates contained in these site-specific studies. Also, the cost estimates
contained in these site-specific studies are significantly greater than the
decommissioning funding targets established by the NRC.
The 1995 Oyster Creek site-specific study was updated in 1998 in response to the
previously announced potential early closure of the plant in 2000. An early
shutdown would increase the retirement costs shown above to $632 million ($600
million for radiological decommissioning and $32 million for nonradiological
cost of removal). Both estimates include substantial spending for an on-site dry
storage facility for spent nuclear fuel and significant costs for storing the
fuel until the DOE complies with the Nuclear Waste Policy Act of 1982. For
additional information, see OTHER COMMITMENTS AND CONTINGENCIES section.
Upon the sale of TMI-1, AmerGen assumed all TMI-1 decommissioning liabilities
and the GPU Energy companies transferred $320 million to AmerGen for
decommissioning.
The agreements to sell Oyster Creek to AmerGen provide, among other things, that
upon financial closing, JCP&L will transfer $430 million in decommissioning
trust funds to AmerGen, which will assume all liability for decommissioning
Oyster Creek.
The GPU Energy companies charge to depreciation expense and accrue retirement
costs based on amounts being collected from customers. Customer collections are
contributed to external trust funds. These deposits, including the related
earnings, are classified as Nuclear decommissioning trusts, at market on the
Consolidated Balance Sheets.
The NJBPU has granted JCP&L annual revenues for Oyster Creek retirement costs of
$223 million based on the 1995 site-specific study. In August 2000, the recovery
of Oyster Creek retirement cost escalates to $34.4 million annually if the plant
is retired in 2000.
In the Restructuring Orders, the PaPUC granted Met-Ed and Penelec recovery of
TMI-1 decommissioning costs of $103.4 million and $67.8 million, respectively,
as part of the CTC. These amounts, which are computed on a present value basis,
ore based on the 1 995 site-specific study and will be adjusted in Phase Il of
Met-Ed and Penelec's restructuring proceedings, once the net proceeds from the
generation asset divestiture are determined.
In the event JCP&L does not complete the pending sole of Oyster Creek,
management believes that any retirement costs, in excess of those currently
recognized for ratemaking purposes, should be recoverable from customers.
45 GPU 1999 FINANCIAL REPORT
<PAGE> 105
The estimated liabilities for TMI-2 future retirement costs (reflected as Three
Mile Island Unit 2 future costs on the Consolidated Balance Sheets) as of
December 31, 1999 and December 31, 1998 are $497 million and $484 million,
respectively. These amounts are based upon the 1995 site-specific study
estimates (in 1999 and 1998 dollars, respectively) discussed above and an
estimate for remaining incremental monitored storage costs of $27 million as of
December 31, 1999 and $29 million as of December 31, 1998, as a result of
TMI-2's entering long-term monitored storage in 1993. The GPU Energy companies
are incurring annual incremental monitored storage costs of approximately $1.8
million.
Offsetting the $497 million liability at December 31, 1999 is $193 million
which management believes is probable of recovery from customers and included in
Regulatory assets, net on the Consolidated Balance Sheets, and $355 million in
trust funds for TMI-2 and included in Nuclear decommissioning trusts, at market
on the Consolidated Balance Sheets. Earnings on trust fund deposits are included
in amounts shown on the Consolidated Balance Sheets under Regulatory assets,
net. TMI-2 decommissioning costs charged to depreciation expense in 1999
amounted to $14.3 million.
The NJBPU has granted JCP&L revenues for TMI-2 retirement costs based on the
1995 site-specific estimates. In addition, JCP&L is recovering its share of
TMI-2 incremental monitored storage costs. The PaPUC Restructuring Orders
granted Met-Ed and Penelec recovery of TMI-2 decommissioning costs as part of
the CTC, but also allowed Met-Ed and Penelec to defer as a regulatory asset
those amounts that are above the level provided for in the CTC.
At December 31, 1999, the accident-related portion of TMI-2 radiological
decommissioning costs is considered to be $77 million, which is based on the
1995 site-specific study estimate (in 1999 dollars). In connection with rate
case resolutions at the time, JCP&L, Met-Ed and Penelec have made contributions
to irrevocable external trusts relating to their shares of the accident-related
portions of the decommissioning liability in the amounts of $15 million, $40
million and $20 million, respectively. These contributions were not recoverable
from customers and have been expensed. The GPU Energy companies will not pursue
recovery from customers for any amounts contributed in excess of the $77 million
accident-related portion referred to above.
JCP&L intends to seek recovery far any increases in TMI-2 retirement costs, and
Met-Ed and Penelec intend to seek recovery for any increases in the
nonaccident-related portion of such costs, but recognize that recovery cannot be
assured.
Insurance:
GPU has insurance (subject to retentions and deductibles) for its
operations and facilities including coverage for property damage, liability to
employees and third parties, and loss of use and occupancy (primarily
incremental replacement power costs). There is no assurance that GPU will
maintain all existing insurance coverages. Losses or liabilities that are not
completely insured, unless allowed to be recovered through ratemaking, could
have a material adverse effect on the financial position of GPU.
The decontamination liability, premature decommissioning and property damage
insurance coverage for Oyster Creek totals $2.75 billion. In addition, GPU has
purchased property and decontamination insurance coverage for TMI-2 totaling
$150 million. In accordance with NRC regulations, these insurance policies
generally require that proceeds first be used for stabilization of the reactors
and then to pay for decontamination and debris removal expenses. Any remaining
amounts available under the policies may then be used for repair and restoration
costs and decommissioning costs. Consequently, there can be no assurance that in
the event of a nuclear incident, property damage insurance proceeds would be
available for the repair and restoration of that station.
The Price-Anderson Act limits GPU's liability to third parties for a nuclear
incident at Oyster Creek to approximately $9.5 billion. Coverage for the first
$200 million of such liability is provided by private insurance. The remaining
coverage, or secondary financial protection, is provided by retrospective
premiums payable by all nuclear reactor owners. Under secondary financial
protection, a nuclear incident at any licensed nuclear power reactor in the
country, including Oyster Creek, could result in an assessment of up to $88
million per incident, subject to an annual maximum payment of $10 million per
incident per reactor. Although TMI-2 is exempt from this assessment, the plant
is still covered by the provisions of the Price-Anderson Act. In addition to the
retrospective premiums payable under the Price-Anderson Act, the GPU Energy
companies are also subject to retrospective premium assessments of up to $10.5
million for insurance policies currently in effect applicable to nuclear
operations and facilities. The GPU Energy companies are also subject to other
retrospective premium assessments related to policies applicable to TMI-1 prior
to the sale of the plant to AmerGen.
JCP&L has insurance coverage for incremental replacement power costs should an
accident-related outage at Oyster Creek occur. Coverage would commence after a
12-week waiting period at $2.1 million per week for 52 weeks, decreasing to 80%
of such amount for the next 110 weeks.
Environmental Matters:
As a result of existing and proposed legislation and regulations, and ongoing
legal proceedings dealing with environmental matters, including but not limited
to acid rain, water quality, ambient air quality, global warming,
electromagnetic fields, and storage and disposal of hazardous
46 GPU 1999 FINANCIAL REPORT
<PAGE> 106
and/or toxic wastes, GPU may be required to incur substantial additional costs
to construct new equipment, modify or replace existing and proposed equipment,
remediate, decommission or cleanup waste disposal and other sites currently or
formerly used by it, including formerly owned manufactured gas plants (MGP),
coal mine refuse piles and generation facilities.
GPU has been formally notified by the EPA and state environmental authorities
that it is among the potentially responsible parties (PRPs) who may be jointly
and severally liable to pay for the costs associated with the investigation and
remediation at 11 hazardous and/or toxic waste sites.
In addition, certain of the GPU companies have been requested to participate in
the remediation or supply information to the EPA and state environmental
authorities on several other sites for which they hove not been formally named
as PRPs, although the EPA and state authorities may nevertheless consider them
as PRPs. Certain of the GPU companies have also been named in lawsuits
requesting damages (which are material in amount) for hazardous and/or toxic
substances allegedly released into the environment. The ultimate cost of
remediation will depend upon changing circumstances as site investigations
continue, including (a) the existing technology required for site cleanup, (b)
the remedial action plan chosen and (c) the extent of site contamination and the
portion attributed to the GPU companies involved.
In 1997, the EPA filed a complaint against GPU, Inc. in the US District Court
for the District of Delaware for enforcement of its Unilateral Order (Order)
issued against GPU, Inc. to clean up the former Dover Gas Light Company (Dover)
manufactured gas production site (Site) in Dover, Delaware. Dover was part of
the AGECO/AGECORP group of companies from 1929 until 1942; GPU, Inc. emerged
from the AGECO/AGECORP reorganization proceedings in 1946. All of Dover's common
stock, which was sold in 1942 to an unaffiliated entity, was subsequently
acquired by Chesapeake, which merged with Dover in 1960. Chesapeake is currently
performing the cleanup at the Site. According to the complaint, the EPA is
seeking (1) enforcement of the Order against GPU; (2) recovery of its past
response costs, (3) a declaratory judgment that GPU is liable for any remaining
cleanup costs of the Site and (4) statutory penalties for noncompliance with the
Order. The EPA has stated that it has incurred approximately $1 million of past
response costs as of December 31, 1999. The EPA estimates the total Site cleanup
costs at approximately $4.2 million. Consultants to Chesapeake have estimated
the remaining remediation groundwater costs at approximately $10.5 million. In
accordance with its penalty policy, and in discussions with GPU, the EPA has
demanded penalties calculated at daily rate of $8,800, rather than the statutory
maximum of $27,500 per day. At December 31,1999, if the statutory maximum is
applied, the total amount of penalties would be approximately $34 million. GPU
believes that it has meritorious defenses as to why no penalty should be
assessed or if a penalty is assessed, why it should be at a lower daily rate.
Chesapeake has also sued GPU, Inc. for contribution to the cleanup of the Dover
Site. The US District Court for the District of Delaware has consolidated the
case filed by Chesapeake with the case filed by the EPA and discovery is
proceeding. There can be no assurance as to the outcome of these proceedings.
In connection with the sale of its Seward Generation Station to Sithe, Penelec
has assumed up to $6 million of remediation costs associated with certain coal
mine refuse piles which are the subject of an earlier consent decree with the
Pennsylvania Department of Environmental Protection. Penelec expects recovery of
these remediation costs in Phase II of its restructuring proceeding and has
recorded a corresponding regulatory asset of approximately $6 million at
December 31, 1999.
JCP&L has entered into agreements with the New Jersey Department of
Environmental Protection for the investigation and remediation of 17 formerly
owned MGP sites. JCP&L has also entered into various cost-sharing agreements
with other utilities for most of the sites. As of December 31, 1999, JCP&L has
spent approximately $36 million in connection with the cleanup of these sites.
In addition, JCP&L has recorded on estimated environmental liability of $52
million relating to expected future costs of these sites (as well as two other
properties). This estimated liability is based upon ongoing site investigations
and remediation efforts, which generally involve capping the sites and pumping
and treatment of ground water. Moreover, the cost to clean up these sites could
be materially in excess of $52 million due to significant uncertainties,
including changes in acceptable remediation methods and technologies. In
addition, federal and state law provides for payment by responsible parties for
damage to natural resources.
In 1997, the NJBPU approved JCP&L's request to establish a Remediation
Adjustment Clause for the recovery of MGP remediation costs. As a result of the
NJBPU's Summary Order, effective August 1, 1999, the recovery of these costs was
transferred to the Societal Benefits Charge. At December 31, 1999, JCP&L had
recorded on its Consolidated Balance Sheet a regulatory asset of $44 million.
JCP&L is continuing to pursue reimbursement from its insurance carriers for
remediation costs already spent and for future estimated costs. In 1994, JCP&L
commenced litigation in the New Jersey Superior Court against several of its
insurance carriers, relative to these MGP sites, and has settled with all but
one of those insurance companies.
47 GPU 1999 FINANCIAL REPORT
<PAGE> 107
Other Commitments and Contingencies:
Class Action Litigation:
GPU Energy: In July 1999, New Jersey experienced a severe heat storm that
resulted in major power outages and temporary service interruptions including in
JCP&L's service territory. As a result, the NJBPU has initiated an investigation
into the reliability of the transmission and distribution systems of all New
Jersey utilities and their response to power outages. In addition, two class
action lawsuits have been commenced in New Jersey Superior Court against GPU,
Inc. and the GPU Energy companies, seeking both compensatory and punitive
damages for alleged losses suffered due to service interruptions. The GPU
defendants originally requested the Court to stay or dismiss the litigation in
deference to the NJBPU's primary jurisdiction. The Court denied the motion, but
in January 2000 the Appellate Division agreed to review the Court's decision. In
response to GPU's demand for a statement of damages, the plaintiffs have stated
that they are seeking damages of $700 million, subject to the results of
pre-trial discovery. GPU has notified its insurance carriers who have reserved
their rights to contest coverage under GPU's insurance policies for losses which
GPU may incur. There can be no assurance as to the outcome of these matters.
GPU Electric: As a result of the fire and explosion in September 1998, at the
Longford natural gas plant in Victoria, Australia, three class actions have been
brought in Australian Federal Court against Esso Australia Limited and its
affiliate (Esso), the owner and operator of the plant, for losses suffered due
to the lack of natural gas supply and related damages. Plaintiffs claim that
Esso was, among other things, negligent in designing, maintaining and operating
the Longford plant and also assert claims under various Australian fair trade
practices laws.
Esso has joined as third party defendants the State of Victoria (State) and
various State-owned entities which operated the Victorian gas industry prior to
its privatization, including TPA and its affiliate Transmission Pipelines
(Assets) Australia (TPAA). GPU, Inc. through GPU GasNet acquired the assets of
TPA and the shares of TPAA from the State in June 1999. Esso has also named GPU
GasNet as a third party defendant. Under the acquisition agreement with the
State, GPU GasNet has indemnified TPA and the State against third party claims.
Esso is seeking contribution and indemnity from the third party defendants for
any damages for which Esso maybe found liable. In addition, Esso has asserted
several separate claims against the State and the farmer State-owned entities
for damages, and contends that GPU GasNet assumed TPA's liabilities as part of
the State's privatization process.
GPU GasNet and TPAA have filed answers denying liability, which could be
material and have moved to dismiss portions of Esso's claims. GPU GasNet and
TPAA have also notified their insurance carriers of this action. The insurers
have reserved their rights to deny coverage. There can be no assurance as to the
outcome of this master.
Investments and Guarantees:
GPU, Inc.: GPU, Inc. has made significant investments in foreign businesses and
facilities through its subsidiaries, GPU Electric and the GPUI Group. At
December 31, 1999, GPU, Inc.'s investment in GPU Electric and the GPUI Group was
$1.06 billion and $232 million, respectively. As of that date, GPU, Inc. has
also guaranteed an additional $1.04 billion and $29.9 million (including $8.7
million of guarantees related to domestic operations) of GPU Electric and GPUI
Group outstanding obligations, respectively. Although management attempts to
mitigate the risks of investing in certain foreign countries by, among other
things, securing political risk insurance, GPU faces additional risks inherent
to operating in such locations, including foreign currency fluctuations.
GPU Electric: Midlands has a 40% ownership interest in a 586 MW power project in
Pakistan (the Uch Power Project), which was originally scheduled to begin
commercial operation in late 1998, but testing and commercial operation have
been delayed.
In June 1999, certain Project lenders issued notices of default to the Project
sponsors (including Midlands) for, among other things, failure to pay principal
and interest under various loon agreements. In November 1999, the Project
sponsors and lenders reached an agreement under which repayment of the
construction loan will be extended, principal and interest payments deferred,
and the sponsors will fund the completion of the plant through the remaining
equity contribution commitments. Midlands' investment in the Uch Power Project
at December 31, 1999 was approximately $43 million, and its share of the
projected completion costs represents an additional $8 million commitment.
Cinergy has agreed to fund up to an aggregate of $20 million of the required
capital contributions and/or certain future "cash losses" which could be
incurred on the Uch Power Project. Cinergy has reimbursed Midlands $3 million of
capital contributions as of December 31, 1999, leaving a remaining commitment of
up to $17 million. Testing of the plant has begun and the start of commercial
operations is now anticipated in 2000. There can be no assurance as to the
outcome of this master.
As part of the sale of the Midlands' supply business and the purchase of the 50%
of Midlands GPU did not already own, certain long-term obligations under natural
gas supply contracts were retained. Most of these contracts were at fixed prices
in excess of the market price of gas as of December 31, 1999. A liability was
previously established far the estimated loss under such contracts, which extend
to September 2005. The estimated liability at December 31, 1999 was $55.1
million.
48 GPU 1999 FINANCIAL REPORT
<PAGE> 108
GPUI Group: On July 9, 1999, DIAN (the Columbian national tax authority) issued
a "Special Requirement" on the Termobarranquilla S.A., Empresa de Servicios
Publicos (TEBSA, an investment in which GPU Power has a 29% interest) 1996
income tax return which challenges the exclusion from taxable income of an
inflation adjustment related to the value of assets used for power generation.
The failure to give notice of this Special Requirement to the US Export Import
Bank may be asserted as a technical event of default under the loan agreement.
An event of default would entitle TEBSA's lenders to accelerate the payment of
outstanding loans of TEBSA and require payment of certain standby equity
commitments by TEBSA's shareholders and equity guarantors, which include a
subsidiary of GPU Power and GPU, Inc. respectively. The lenders have not
asserted that an event of default has occurred or indicated whether they will
pursue remedies under the project financing documents.
As of December 31, 1999, GPU Power has an investment of approximately $79
million in TEBSA and GPU, Inc. has guaranteed $21.3 million in standby equity
commitments. There can be no assurance as to the outcome of these matters.
Other:
GPU AR has entered into contracts to supply electricity to retail customers
through May 2001. In connection with meeting its supply obligations, GPU AR has
entered into firm purchase commitments for energy and capacity with payment
obligations totaling approximately $27 million as of December 31, 1999. GPU,
Inc. has guaranteed up to $19 million of these payments.
In accordance with the Nuclear Waste Policy Act of 1982 (NWPA), the GPU Energy
companies hove entered into contracts with, and have been paying fees to, the
DOE for the future disposal of spent nuclear fuel in a repository or interim
storage facility. AmerGen has assumed all liability for disposal costs related
to spent fuel generated after its purchase of TMI-1 and has agreed to assume
this liability for Oyster Creek following its purchase of that plant. In 1996,
the DOE notified the GPU Energy companies and other standard contract holders
that it will be unable to begin acceptance of spent nuclear fuel for disposal by
1998, as mandated by the NWPA. The DOE requested recommendations from contract
holders for handling the delay. The DOE's inability to accept spent nuclear fuel
could have a material impact on GPU's results of operations, as additional costs
may be incurred to build and maintain interim on-site storage at Oyster Creek.
In June 1997, a consortium of electric utilities, including GPUN, filed a
license application with the NRC seeking permission to build on interim
above-ground disposal facility for spent nuclear fuel in Utah. There can be no
assurance as to the outcome of these matters.
GPU, Inc. and consolidated affiliates have approximately 10,800 employees
worldwide, of which 6,100 are employed in the US and 3,700 are employed in the
United Kingdom. The majority of the US workforce is employed by the GPU Energy
companies, of which approximately 4,000 are represented by unions for collective
bargaining purposes. In the United Kingdom, approximately 2,800 Midlands
employees are represented by unions; terms and conditions of the various
bargaining agreements are generally reviewed annually, on April 1. JCP&L, Met-Ed
and Penelec's collective bargaining agreements with the International
Brotherhood of Electrical Workers expire on October 31,2002, April 30, 2000 and
May 14, 2002, respectively. Penelec's collective bargaining agreement with the
Utility Workers Union of America expires on June 30,2001.
During the normal course of the operation of its businesses, in addition to the
matters described above, GPU is from time to time involved in disputes, claims
and, in some cases, as a defendant in litigation in which compensatory and
punitive damages are sought by the public, customers, contractors, vendors and
other suppliers of equipment and services and by employees alleging unlawful
employment practices. While management does not expect that the outcome of these
matters will have a material effect on GPU's financial position or results of
operations, there can be no assurance that this will continue to be the case.
13. Segment Information
The following is presented in accordance with Statement of Financial Accounting
Standards No. 131, "Disclosures about Segments of an Enterprise and Related
Information."
GPU's reportable segments are strategic business units that are managed
separately due to their different operating and regulatory environments. GPU's
management evaluates the performance of its business units based upon income
before extraordinary and non-recurring items. For the purpose of providing
segment information, domestic electric utility operations (GPU Energy) is
comprised of the three electric utility operating companies serving customers in
New Jersey and Pennsylvania, as well as GPU Generation, Inc. (sold in late
1999), GPUN, GPU Telcom and GPUS. For additional information on GPU's
organizational structure and businesses, see preface to the Notes to
Consolidated Financial Statements.
49 GPU 1999 FINANCIAL REPORT
<PAGE> 109
Business Segment Data
<TABLE>
<CAPTION>
DEPRECIATION INTEREST CHARGES INCOME TAX
OPERATING AND AND PREFERRED EXPENSE/
(IN THOUSANDS) REVENUES AMORTIZATION DIVIDENDS (BENEFIT)(a)
------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1999
Domestic Segments:
Electric Utility Operations (GPU Energy) $3,685,821 $409,345 $209,769 $238,591
Independ Power Prod (GPU International) 83,434 9,401 1,044 9.478
Electric Retail Energy Sales (GPU AR) 84.681 - - (2,393)
------------------------------------------------------------------------------------------------------------------------
Subtotal 3,853,936 418,746 210,813 245,676
------------------------------------------------------------------------------------------------------------------------
Foreign Segments:
Electric/Gas Utility Operations: (GPU Electric)
Electric Distribution-United Kingdom 504,826 52,847 91,433 21,208
Electric Distribution-Argentina 135,938 15,273 23,414 (960)
Electric Transmission-Australia 193,366 42,850 110,059 (1,171)
Gas Transmission-Australia 31,326 6,933 28,821 (12,156)
Independent Power Prod-S. America (GPU Power) 37,732 6,290 3,560 5,152
------------------------------------------------------------------------------------------------------------------------
Subtotal 903,188 124,193 257,287 12,073
------------------------------------------------------------------------------------------------------------------------
Corporate and Eliminations - - 14,397 -
------------------------------------------------------------------------------------------------------------------------
Consolidated Total $4,757,124 $542,939 $482,497 $257,749
========================================================================================================================
1998
Domestic Segments:
Electric Utility Operations (GPU Energy) $3,953,254 $469,623 $241,886 $271,336
Independ Power Prod (GPU International) 72,256 4,560 748 9,103
Electric Retail Energy Sales (GPU AR) 10,938 - - (1,201)
------------------------------------------------------------------------------------------------------------------------
Subtotal 4,036,448 474,183 242,634 279,238
------------------------------------------------------------------------------------------------------------------------
Foreign Segments:
Electric/Gas Utility Operations: (GPU Electric)
Electric Distribution-United Kingdom 944 1,226 30,859 (6,489)
Electric Transmission-Australia 181,059 40,841 108,227 11,421
Independ Power Prod-S. America (GPU Power) 33,136 5,844 4,219 719
------------------------------------------------------------------------------------------------------------------------
Subtotal 215,139 47,911 143,305 5,651
------------------------------------------------------------------------------------------------------------------------
Corporate and Eliminations (2,795) - 3,293 -
------------------------------------------------------------------------------------------------------------------------
Consolidated Total $4,248,792 $522,094 $389,232 $284,889
========================================================================================================================
1997
Domestic Segments:
Electric Utility Operations (GPU Energy) $4,045,233 $451,009 $249,015 $249,184
Independ Power Prod (GPU International) 38,727 778 713 (3,115)
Electric Retail Energy Sales (GPU AR) 1,339 - - (2,576)
------------------------------------------------------------------------------------------------------------------------
Subtotal 4,085,299 451,787 249,728 243,493
------------------------------------------------------------------------------------------------------------------------
Foreign Segments:
Electric/Gas Utility Operations: (GPU Electric)
Electric Distribution-United Kingdom - 354 39,312 (44,438)
Electric Transmission & Distribution-
Australia 30,339 9,412 23,397 (5,184)
Independ Power Prod-S. America (GPU Power) 29,174 6,161 3,202 (335)
------------------------------------------------------------------------------------------------------------------------
Subtotal 59,513 15,927 65,911 (49,957)
------------------------------------------------------------------------------------------------------------------------
Corporate and Eliminations (1,433) - 3,682 -
------------------------------------------------------------------------------------------------------------------------
Consolidated Total $4,143,379 $467,714 $319,321 $193,536
========================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
INCOME BEFORE
EXTRAORDINARY AND INVESTMENTS
NON-RECURRING TOTAL AND CAPITAL
(IN THOUSANDS) ITEMS ASSETS EXPENDITURES(b)
----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
1999
Domestic Segments:
Electric Utility Operations (GPU Energy) $440,983 $13,244,301 $291,391
Independ Power Prod (GPU International) 11,337 359,374 1,225
Electric Retail Energy Sales (GPU AR) (4,558) 24,630 -
----------------------------------------------------------------------------------------------------------
Subtotal 447,762 13,628,305 292,616
----------------------------------------------------------------------------------------------------------
Foreign Segments:
Electric/Gas Utility Operations: (GPU Electric)
Electric Distribution-United Kingdom 54,836(c) 4,687,476 727,793
Electric Distribution-Argentina (1,778) 579,907 407,225
Electric Transmission-Australia (6,715) 1,824,309 19,889
Gas Transmission-Australia (39) 795,527 653,747
Independent Power Prod-S. America (GPU Power) 8,116 238,644 30,421
----------------------------------------------------------------------------------------------------------
Subtotal 54,420 8,125,863 1,839,075
----------------------------------------------------------------------------------------------------------
Corporate and Eliminations (18,068) (36,086) -
----------------------------------------------------------------------------------------------------------
Consolidated Total $484,114 $21,718,082 $2,131,691
========================================================================================================================
1998
Domestic Segments:
Electric Utility Operations (GPU Energy) $369,752 $13,298,257 $ 328,418
Independ Power Prod (GPU International) 11,622 397,523 21,375
Electric Retail Energy Sales (GPU AR) (2,231) 2,651 34
----------------------------------------------------------------------------------------------------------
Subtotal 379,143 13,698,431 349,827
----------------------------------------------------------------------------------------------------------
Foreign Segments:
Electric/Gas Utility Operations: (GPU Electric)
Electric Distribution-United Kingdom 37,249(d) 617,737 -
Electric Transmission-Australia 18,885 1,788,877 58,549
Independ Power Prod-S. America (GPU Power) 2,499 237,162 59,847
----------------------------------------------------------------------------------------------------------
Subtotal 58,633 2,643,776 118,396
----------------------------------------------------------------------------------------------------------
Corporate and Eliminations (11,818) (54,098) -
----------------------------------------------------------------------------------------------------------
Consolidated Total $425,958 $16,288,109 $ 468,223
========================================================================================================================
1997
Domestic Segments:
Electric Utility Operations (GPU Energy) $388,030 $ 9,850,784 $ 356,416
Independ Power Prod (GPU International) (13,362) 318,592 111,700
Electric Retail Energy Sales (GPU AR) (4,782) 5,122 -
----------------------------------------------------------------------------------------------------------
Subtotal 369,886 10,174,498 468,116
----------------------------------------------------------------------------------------------------------
Foreign Segments:
Electric/Gas Utility Operations: (GPU Electric)
Electric Distribution-United Kingdom 78,463(d) 568,997 449
Electric Transmission & Distribution-
Australia 12,631 1,967,946 1,800,072
Independ Power Prod-S. America (GPU Power) (2,301) 145,859 -
----------------------------------------------------------------------------------------------------------
Subtotal 88,793 2,682,802 1,800,521
----------------------------------------------------------------------------------------------------------
Corporate and Eliminations (14,278) (34,366) -
----------------------------------------------------------------------------------------------------------
Consolidated Total $444,401 $12,822,934 $2,268,637
========================================================================================================================
</TABLE>
(a) Represents income lazes on income before extraordinary and
non-recurring items.
(b) Includes acquisitions, net of cash acquired of $1,671 million in 1999
(Midlands $653 million; Emdersa $369 million; GPU GasNet $649 million)
and $1,798 million in 1997 (GPU PowerNet).
(c) Includes equity in net income of investee accounted for under the
equity method of $74 million, for the period prior to the consolidation
of Midlands.
(d) Includes equity in net income of investee accounted for under the
equity method of $62 million in 1998 and $74 million in 1997.
50 GPU 1999 FINANCIAL REPORT
<PAGE> 110
GPU, Inc. and Subsidiary Companies
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
GPU, Inc. owns all the outstanding common stock of three domestic
electric utilities -- Jersey Central Power & Light Company (JCP&L), Metropolitan
Edison Company (Met-Ed) and Pennsylvania Electric Company (Penelec). The
customer service function, transmission and distribution operations and the
operations of the remaining non-nuclear generating facilities of these electric
utilities are conducting business under the name GPU Energy. JCP&L, Met-Ed and
Penelec considered together are referred to as the "GPU Energy companies." The
nuclear generation operations of GPU Energy are conducted by GPU Nuclear, Inc.
(GPUN). GPU Capital, Inc. and GPU Electric, Inc. and their subsidiaries own,
operate and fund the acquisition of electric distribution and gas transmission
systems in foreign countries, and are referred to as "GPU Electric." GPU
International, Inc. and GPU Power, Inc. and their subsidiaries develop, own and
operate generation facilities in the United States (US) and foreign countries
and are referred to as the "GPUI Group." Other subsidiaries of GPU, Inc. include
G?U Advanced Resources, Inc. (GPU AR), which is involved in retail energy sales;
GPU Telcom Services, Inc. (GPU Telcom), which is engaged in
telecommunications-related businesses; MYR Group Inc. (MYR), which is a utility
infrastructure construction services company; and GPU Service, Inc. (GPUS),
which provides legal, accounting, financial and other services to the GPU
companies. All of these companies considered together are referred to as "GPU."
These notes should be read in conjunction with the notes to
consolidated financial statements included in the 1999 Annual Report on Form
10-K. The December 31, 1999 balance sheet data contained in the attached
financial statements was derived from audited financial statements. For
disclosures required by accounting principles generally accepted in the US, see
the 1999 Annual Report on Form 10-K.
1. COMMITMENTS AND CONTINGENCIES
COMPETITION AND THE CHANGING REGULATORY ENVIRONMENT
Stranded Costs and Regulatory Restructuring Orders:
---------------------------------------------------
With the current market price of electricity being below the cost of
some utility-owned generation and power purchase commitments, and the ability of
customers to choose their energy suppliers, certain costs, which generally would
be recoverable in a regulated environment, may not be recoverable in a
competitive environment. These costs are generally referred to as stranded
costs.
In 1998, the Pennsylvania Public Utility Commission (PaPUC) issued
Restructuring Orders to Met-Ed and Penelec which, among other things, provide
for Met-Ed and Penelec's recovery of a substantial portion of what otherwise
would have become stranded costs, and provide for a Phase II proceeding
following the completion of their generation divestitures to make a final
determination of the extent of that stranded cost recovery. The Pennsylvania
Supreme Court has denied an appeal filed by one intervenor in the proceeding.
GPU Energy does not know whether the intervenor will seek review by the US
Supreme Court.
40
<PAGE> 111
On January 31, 2000, Met-Ed and Penelec submitted Phase II Reports to
the PaPUC addressing actual net divestiture proceeds and reconciliation of
stranded costs pursuant to the 1998 Restructuring Orders. The PaPUC and other
parties, which participated in the 1998 Restructuring Orders, are currently
reviewing the Reports. There can be no assurance as to the outcome of this
matter.
In May 1999, the NJBPU issued a Summary Order with respect to JCP&L's
rate unbundling, stranded cost and restructuring filings. The Summary Order
provides for, among other things, customer choice of electric generation
supplier beginning August 1, 1999 and full recovery of stranded costs. The
Summary Order did not address the pending sale of Oyster Creek, because at the
time the Summary Order was issued, it was uncertain whether the plant would be
sold or retired early. JCP&L is awaiting a final order from the NJBPU.
During 1999, the NJBPU issued final electric restructuring and
generation-related securitization orders to Public Service Electric and Gas
Company (PSE&G), a non-affiliated utility. Several parties appealed these orders
on a variety of grounds, including the use of deferred accounting associated
with above market NUG costs and the Societal Benefit Charge, which includes
recovery of nuclear decommissioning costs. In April 2000, the Appellate Division
of the New Jersey Superior Court affirmed the orders. The Appellate Division's
decision has been appealed to the New Jersey Supreme Court which is not expected
to issue a decision before January 2001. While JCP&L's Summary Order has not
been appealed, JCP&L is unable to determine the impact, if any, the appeals to
PSE&G's orders will have on its restructuring order and petition for
securitization or its use of deferred accounting.
As a result of the NJBPU and the PaPUC restructuring decisions, the GPU
Energy companies are required to supply electricity to customers who do not
choose an alternate supplier. Given that the GPU Energy companies have
essentially divested their generation business, there will be increased market
risks associated with supplying that electricity, since the GPU Energy companies
will have to supply electricity to non-shopping customers entirely from
contracted and open market purchases. While JCP&L is permitted to recover
reasonable and prudently incurred costs associated with providing basic
generation service to non-shopping customers, Met-Ed and Penelec are generally
unable to recover their energy costs in excess of established rate caps.
Management has implemented an energy risk management program, but there can be
no assurance that the GPU Energy companies will be able to fully recover the
costs to supply electricity to customers who do not choose an alternate
supplier.
Generation Agreements:
----------------------
The evolving competitive generation market has created uncertainty
regarding the forecasting of the GPU Energy companies' energy supply needs,
which has caused the GPU Energy companies to seek shorter-term agreements
offering more flexibility. The GPU Energy companies' supply plan focuses on
short- to intermediate-term commitments (one month to three years) covering
times of expected high energy price volatility (that is, peak demand periods)
and reliance on spot market purchases during other periods.
41
<PAGE> 112
The GPU Energy companies have entered into agreements with third party
suppliers to purchase capacity and energy. Payments pursuant to these
agreements, which include firm commitments as well as certain assumptions
regarding, among other things, call/put arrangements and the timing of the
pending Oyster Creek sale, are estimated to be $650 million in 2000, $651
million in 2001, $323 million in 2002, $138 million in 2003 and $44 million in
2004.
Pursuant to the mandates of the federal Public Utility Regulatory
Policies Act and state regulatory directives, the GPU Energy companies have been
required to enter into power purchase agreements with non-utility generators
(NUGs) for the purchase of energy and capacity, which agreements have remaining
terms of up to 20 years. The rates under virtually all of the GPU Energy
companies' NUG agreements are substantially in excess of current and projected
prices from alternative sources. The following table shows actual payments from
1998 through June 30, 2000, and estimated payments thereafter through 2005:
Payments Under NUG Agreements
(in millions)
Total JCP&L Met-Ed Penelec
1998 788 403 174 211
1999 774 388 167 219
2000 741 385 141 215
2001 733 392 138 203
2002 736 394 141 201
2003 752 400 145 207
2004 767 404 150 213
2005 751 392 153 206
The NJBPU Summary Order provides JCP&L assurance of full recovery of
its NUG costs (including above-market NUG costs and certain buyout costs),
whereas the PaPUC Restructuring Orders provide Met-Ed and Penelec assurance of
full recovery of their above-market NUG costs and certain NUG buyout costs. The
GPU Energy companies have recorded, on a present value basis, a total liability
of $3.1 billion (JCP&L $1.5 billion; Met-Ed $0.7 billion; Penelec $0.9 billion)
on the Consolidated Balance Sheets for above-market NUG costs which is offset by
a corresponding regulatory asset. The GPU Energy companies are continuing
efforts to reduce the above-market costs of these agreements. There can be no
assurance as to the extent to which these efforts will be successful.
In 1997, the NJBPU approved a Stipulation of Final Settlement which,
among other things, provided for the recovery of costs associated with the
buyout of the Freehold Cogeneration power purchase agreement (Freehold buyout).
The NJBPU approved the cost recovery of up to $135 million, over a seven-year
period, on an interim basis subject to refund. The NJBPU's Summary Order
provides for the continued recovery of the Freehold buyout in the Market
Transition Charge (MTC), but has not altered the interim nature of such
recovery, pending a final decision by the NJBPU. There can be no assurance as to
the outcome of this matter.
ACCOUNTING MATTERS
JCP&L, in 1999, and Met-Ed and Penelec in 1998, discontinued the
application of Statement of Financial Accounting Standards No. 71 (FAS 71),
42
<PAGE> 113
"Accounting for the Effects of Certain Types of Regulation," and adopted the
provisions of Statement of Financial Accounting Standards No. 101, "Regulated
Enterprises - Accounting for the Discontinuation of Application of FASB
Statement No. 71," and Emerging Issues Task Force (EITF) Issue 97-4,
"Deregulation of the Pricing of Electricity - Issues Related to the Application
of FAS 71 and FAS 101", with respect to their electric generation operations.
The transmission and distribution portion of the GPU Energy companies'
operations continue to be subject to the provisions of FAS 71. Regulatory
assets, net as reflected in the June 30, 2000 and December 31, 1999 Consolidated
Balance Sheets in accordance with the provisions of FAS 71 and EITF Issue 97-4
were as follows:
GPU, Inc. and Subsidiary Companies
<TABLE>
<CAPTION>
(in thousands)
-----------------------------
June 30, December 31,
------------ -------------
<S> <C> <C>
Market transition charge (MTC) / basic
generation service $2,287,449 $2,359,529
Competitive transition charge (CTC) 756,406 803,064
Reserve for generation divestiture 530,912 536,904
Power purchase contract loss not in CTC 369,290 369,290
Income taxes recoverable through future rates, net 283,636 280,268
Costs recoverable through distribution rates 281,363 296,842
Three Mile Island Unit 2 (TMI-2)
decommissioning costs 100,869 100,794
Societal benefits charge 100,643 116,941
Net divestiture proceeds recoverable through MTC 58,077 37,542
Above-market deferred NUG costs (196,276) (252,348)
Other, net 67,584 67,420
---------- ----------
Total regulatory assets, net $4,639,953 $4,716,246
========== ==========
JCP&L
MTC-basic generation service $2,287,449 $2,359,529
Costs recoverable through distribution rates 281,363 296,842
Societal benefits charge 100,643 116,941
Net divestiture proceeds recoverable through MTC 58,077 37,542
---------- ----------
Total regulatory assets, net $2,727,532 $2,810,854
========== ==========
Met-Ed
CTC $ 583,441 $ 591,316
Power purchase contract loss not in CTC 271,270 271,270
Reserve for generation divestiture 142,179 137,037
Income taxes recoverable through future rates, net 122,955 115,713
TMI-2 decommissioning costs 64,608 65,455
Other, net 67,711 52,074
---------- ----------
Total regulatory assets, net $1,252,164 $1,232,865
========== ==========
Penelec
Reserve for generation divestiture $ 388,733 $ 399,867
Above-market deferred NUG costs (213,312) (252,893)
CTC 172,965 211,748
Income taxes recoverable through future rates, net 160,681 164,555
Power purchase contract loss not in CTC 98,020 98,020
Other, net 53,170 51,230
---------- ----------
Total regulatory assets, net $ 660,257 $ 672,527
========== ==========
</TABLE>
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Statement of Financial Accounting Standards 133, "Accounting for
Derivative Instruments and Hedging Activities", as amended by FAS 137,
"Accounting for Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of FASB Statement No. 133" and FAS 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities - An Amendment of FASB
Statement No. 133" (collectively, FAS 133), establishes accounting and reporting
standards for derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities. In general, FAS 133
requires that companies recognize all derivatives as either assets or
liabilities on the balance sheet and measure those instruments at fair value.
FAS 133 (as amended) excludes from its scope certain contracts that qualify as
normal purchases and sales. To qualify for this exclusion, it must be probable
that the contract will result in physical delivery.
GPU's use of derivative instruments is intended to manage the risks of
commodity price, interest rate and foreign currency fluctuations, and may
include such transactions as electricity and natural gas forwards and futures
contracts, foreign currency swaps, interest rate swaps and options. GPU does not
intend to hold or issue derivative instruments for trading purposes. To the
extent that GPU's energy-related contracts fall within the scope of FAS 133, GPU
will be required to include them on its balance sheet at fair value, and
recognize the subsequent changes in fair value as either gains or losses in
earnings or report them as a component of other comprehensive income, depending
upon their intended use and designation as a hedge. GPU will adopt this
statement on January 1, 2001 and is currently in the process of evaluating the
impact of its implementation.
NUCLEAR FACILITIES
Investments:
------------
In December 1999, the GPU Energy companies sold TMI-1 to AmerGen for
approximately $100 million. In addition, in October 1999, JCP&L agreed to sell
Oyster Creek to AmerGen for $10 million and reimbursement of the cost (estimated
at $88 million) of the next refueling outage. JCP&L's net investment, including
nuclear fuel, in Oyster Creek as of June 30, 2000 and December 31, 1999 was $10
million, reflecting the impairment write-down from the pending sale. JCP&L,
Met-Ed and Penelec jointly own TMI-2, which was damaged during a 1979 accident,
in the percentages of 25%, 50% and 25%. JCP&L's net investment in TMI-2 as of
June 30, 2000 and December 31, 1999 was $58 million and $61 million,
respectively. JCP&L is collecting revenues for TMI-2 on a basis which provides
for the recovery of its remaining investment in the plant by 2008. Met-Ed and
Penelec's remaining investments in TMI-2 were written off in 1998 after
receiving the PaPUC's Restructuring Orders.
TMI-2:
------
As a result of the 1979 TMI-2 accident, individual claims for alleged
personal injury (including claims for punitive damages), which are material in
amount, were asserted against GPU, Inc. and the GPU Energy companies.
Approximately 2,100 of such claims were filed in the US District Court for the
Middle District of Pennsylvania. Some of the claims also seek recovery for
injuries from alleged emissions of radioactivity before and after the accident.
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At the time of the TMI-2 accident, as provided for in the
Price-Anderson Act, the GPU Energy companies had (a) primary financial
protection in the form of insurance policies with groups of insurance companies
providing an aggregate of $140 million of primary coverage, (b) secondary
financial protection in the form of private liability insurance under an
industry retrospective rating plan providing for up to an aggregate of $335
million in premium charges under such plan and (c) an indemnity agreement with
the Nuclear Regulatory Commission (NRC) for up to $85 million, bringing their
total financial protection up to an aggregate of $560 million. Under the
secondary level, the GPU Energy companies are subject to a retrospective premium
charge of up to $5 million per reactor, or a total of $15 million.
In 1995, the US Court of Appeals for the Third Circuit ruled that the
Price-Anderson Act provides coverage under its primary and secondary levels for
punitive as well as compensatory damages, but that punitive damages could not be
recovered against the Federal Government under the third level of financial
protection. In so doing, the Court of Appeals referred to the "finite fund" (the
$560 million of financial protection under the Price-Anderson Act) to which
plaintiffs must resort to get compensatory as well as punitive damages.
The Court of Appeals also ruled that the standard of care owed by the
defendants to a plaintiff was determined by the specific level of radiation
which was released into the environment, as measured at the site boundary,
rather than as measured at the specific site where the plaintiff was located at
the time of the accident (as the defendants proposed). The Court of Appeals also
held that each plaintiff still must demonstrate exposure to radiation released
during the TMI-2 accident and that such exposure had resulted in injuries. In
1996, the US Supreme Court denied petitions filed by GPU, Inc. and the GPU
Energy companies to review the Court of Appeals' rulings.
In 1996, the District Court granted a motion for summary judgment filed
by GPU, Inc. and the GPU Energy companies, and dismissed the ten initial "test
cases," which had been selected for a test case trial as well as all of the
remaining 2,100 pending claims. The Court ruled that there was no evidence which
created a genuine issue of material fact warranting submission of plaintiffs'
claims to a jury. The plaintiffs appealed the District Court's ruling to the
Court of Appeals for the Third Circuit. In November 1999, the Third Circuit
affirmed the District Court's dismissal of the ten "test cases," but set aside
the dismissal of the additional pending claims, remanding them to the District
Court for further proceedings. In remanding these claims, the Third Circuit held
that the District Court had erred in extending its summary judgment decision to
the other plaintiffs and imposing on these plaintiffs the District Court's
finding that radiation exposures below 10 rems were too speculative to establish
a causal link to cancer. The Court of Appeals stated that the non-test case
plaintiffs should be permitted to present their own individual evidence that
exposure to radiation from the accident caused their cancers. In June 2000, the
US Supreme Court denied petitions by GPU, Inc., the GPU Energy companies and the
plaintiffs.
GPU, Inc. and the GPU Energy companies believe that any liability to
which they might be subject by reason of the TMI-2 accident will not exceed
their financial protection under the Price-Anderson Act.
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NUCLEAR PLANT RETIREMENT COSTS
Retirement costs for nuclear plants include decommissioning the
radiological portions of the plants and the cost of removal of nonradiological
structures and materials. The disposal of spent nuclear fuel is covered
separately by contracts with the US Department of Energy (DOE).
In 1995, a consultant to GPUN performed site-specific studies of TMI-2
and Oyster Creek (updated in 1998), that considered various decommissioning
methods and estimated the cost of decommissioning the radiological portions and
the cost of removal of the nonradiological portions of each plant, using the
prompt removal/dismantlement method. GPUN management has reviewed the
methodology and assumptions used in these studies, is in agreement with them,
and believes the results are reasonable. Under NRC regulations, JCP&L is making
periodic payments to complete the funding for Oyster Creek retirement costs by
the end of the plant's license term of 2009. The TMI-2 funding completion date
is 2014, consistent with TMI-2 remaining in long-term storage. The NRC may
require an acceleration of the decommissioning funding for Oyster Creek if the
pending sale is not completed and the plant is retired early. The retirement
cost estimates under the 1995 site-specific studies, assuming decommissioning of
TMI-2 and Oyster Creek in 2014 and 2009, respectively, are $443 million and $601
million for radiological decommissioning and $35 million and $33 million for
non-radiological removal costs (net of $12.6 million spent as of June 30, 2000)
(in 2000 dollars)
Each of the GPU Energy companies is responsible for retirement costs in
proportion to its respective ownership percentage. The ultimate cost of retiring
the GPU Energy companies' nuclear facilities may be different from the cost
estimates contained in these site-specific studies. Also, the cost estimates
contained in these site-specific studies are significantly greater than the
decommissioning funding targets established by the NRC.
The 1995 Oyster Creek site-specific study was updated in 1998 in
response to the previously announced potential early closure of the plant in
2000. An early shutdown would increase the retirement costs shown above to $643
million ($610 million for radiological decommissioning and $33 million for
nonradiological cost of removal). Both estimates include substantial spending
for an on-site dry storage facility for spent nuclear fuel and significant costs
for storing the fuel until the DOE complies with the Nuclear Waste Policy Act of
1982. For additional information, see OTHER COMMITMENTS AND CONTINGENCIES
section.
The agreements to sell Oyster Creek to AmerGen provide, among other
things, that upon financial closing, JCP&L will transfer $430 million in
decommissioning trust funds to AmerGen, which will assume all liability for
decommissioning Oyster Creek. .
The NJBPU has granted JCP&L annual revenues for Oyster Creek retirement
costs of $22.5 million based on the 1995 site-specific study. In August 2000,
the recovery of Oyster Creek retirement costs escalates to $34.4 million
annually if the plant is retired in 2000.
In the event JCP&L does not complete the pending sale of Oyster Creek,
management believes that any retirement costs, in excess of those currently
recognized for ratemaking purposes, should be recoverable from customers.
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The estimated liabilities for TMI-2 future retirement costs (reflected
as Three Mile Island Unit 2 future costs on the Consolidated Balance Sheets) as
of June 30, 2000 and December 31, 1999 are $504 million (JCP&L $126 million;
Met-Ed $252 million; Penelec $126 million) and $497 million (JCP&L $124 million;
Met-Ed $249 million; Penelec $124 million), respectively. These amounts are
based upon the 1995 site-specific study estimates (in 2000 and 1999 dollars,
respectively) discussed above and an estimate for remaining incremental
monitored storage costs of $27 million (JCP&L $7 million; Met-Ed $13 million;
Penelec $7 million) as of June 30, 2000 and December 31, 1999, as a result of
TMI-2 entering long-term monitored storage in 1993.
Offsetting the $504 million liability as of June 30, 2000 is $182
million (JCP&L $13 million; Met-Ed $133 million; Penelec $36 million), which
management believes is probable of recovery from customers and included in
Regulatory assets, net on the Consolidated Balance Sheets, and $366 million
(JCP&L $116 million; Met-Ed $151 million; Penelec $99 million) in trust funds
for TMI-2 and included in Nuclear decommissioning trusts, at market on the
Consolidated Balance Sheets.
The NJBPU has granted JCP&L revenues for TMI-2 retirement costs based
on the 1995 site-specific estimates. In addition, JCP&L is recovering its share
of TMI-2 incremental monitored storage costs. The PaPUC Restructuring Orders
granted Met-Ed and Penelec recovery of TMI-2 decommissioning costs as part of
the CTC, but also allowed Met-Ed and Penelec to defer as a regulatory asset
those amounts that are above the level provided for in the CTC.
As of June 30, 2000, the accident-related portion of TMI-2 radiological
decommissioning costs is considered to be $78 million (JCP&L $19.5 million;
Met-Ed $39 million; Penelec $19.5 million), which is based on the 1995
site-specific study estimates (in 2000 dollars).
JCP&L intends to seek recovery for any increases in TMI-2 retirement
costs, and Met-Ed and Penelec intend to seek recovery for any increases in the
nonaccident-related portion of such costs, but recognize that recovery cannot be
assured.
INSURANCE
GPU has insurance (subject to retentions and deductibles) for its
operations and facilities including coverage for property damage, liability to
employees and third parties, and loss, of use and occupancy (primarily
incremental replacement power costs). There is no assurance that GPU will
maintain all existing insurance coverages. Losses or liabilities that are not
completely insured, unless allowed to be recovered through ratemaking, could
have a material adverse effect on the financial position of GPU.
The decontamination liability, premature decommissioning and property
damage insurance coverage for Oyster Creek totals $2.75 billion. In addition,
GPU has purchased property and decontamination insurance coverage for TMI-2
totaling $150 million. In accordance with NRC regulations, these insurance
policies generally require that proceeds first be used for stabilization of the
reactors and then to pay for decontamination and debris removal expenses. Any
remaining amounts available under the policies may then be used for repair and
restoration costs and decommissioning costs. Consequently, there can be no
assurance that in the event of a nuclear
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incident, property damage insurance proceeds would be available for the repair
and restoration of that station.
The Price-Anderson Act limits GPU's liability to third parties for a
nuclear incident at Oyster Creek to approximately $9.5 billion. Coverage for the
first $200 million of such liability is provided by private insurance. The
remaining coverage, or secondary financial protection, is provided by
retrospective premiums payable by all nuclear reactor owners. Under secondary
financial protection, a nuclear incident at any licensed nuclear power reactor
in the country, including Oyster Creek, could result in an assessment of up to
$88 million per incident, subject to an annual maximum payment of $10 million
per incident per reactor. Although TMI-2 is exempt from this assessment, the
plant is still covered by the provisions of the Price-Anderson Act. In addition
to the retrospective premiums payable under the Price-Anderson Act, the GPU
Energy companies are also subject to retrospective premium assessments of up to
$9.5 million for insurance policies currently in effect applicable to nuclear
operations and facilities. The GPU Energy companies are also subject to other
retrospective premium assessments related to policies applicable to TMI-1 and
Oyster Creek (GPU anticipates the sale of Oyster Creek to be completed in August
2000) prior to their sales to AmerGen.
JCP&L has insurance coverage for incremental replacement power costs
should an accident-related outage at Oyster Creek occur. Coverage would commence
after a 12-week waiting period at $2.1 million per week for 52 weeks, decreasing
to 80% of such amount for the next 110 weeks.
ENVIRONMENTAL MATTERS
As a result of existing and proposed legislation and regulations, and
ongoing legal proceedings dealing with environmental matters, including but not
limited to acid rain, water quality, ambient air quality, global warming,
electromagnetic fields, and storage and disposal of hazardous and/or toxic
wastes, GPU may be required to incur substantial additional costs to construct
new equipment, modify or replace existing and proposed equipment, remediate,
decommission or cleanup waste disposal and other sites currently or formerly
used by it, including formerly owned manufactured gas plants (MGP), coal mine
refuse piles and generation facilities. In addition, federal and state law
provides for payment by responsible parties for damage to natural resources.
GPU has been formally notified by the Environmental Protection Agency
(EPA) and state environmental authorities that it is among the potentially
responsible parties (PRPs) who may be jointly and severally liable to pay for
the costs associated with the investigation and remediation at hazardous and/or
toxic waste sites in the following number of instances (in some cases, more than
one company is named for a given site):
JCP&L MET-ED PENELEC GPUN GPU, INC. TOTAL
----- ------ ------- ---- --------- -----
6 4 2 1 1 11
In addition, certain of the GPU companies have been requested to
participate in the remediation or supply information to the EPA and state
environmental authorities on several other sites for which they have not been
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formally named as PRPs, although the EPA and/or state authorities may
nevertheless consider them as PRPs. Certain of the GPU companies have also been
named in lawsuits requesting damages (which are material in amount) for
hazardous and/or toxic substances allegedly released into the environment. As of
June 30, 2000, a liability of approximately $6 million was recorded for nine PRP
sites where it is probable that a loss has been incurred and the amount could be
reasonably estimated.
The ultimate cost of remediation of all these and other hazardous waste
sites will depend upon changing circumstances as site investigations continue,
including (a) the existing technology required for site cleanup, (b) the
remedial action plan chosen and (c) the extent of site contamination and the
portion attributed to the GPU companies involved.
In 1997, the EPA filed a complaint against GPU, Inc. in the US District
Court for the District of Delaware for enforcement of its Unilateral Order
(Order) issued against GPU, Inc. to clean up the former Dover Gas Light Company
(Dover) manufactured gas production site (Site) in Dover, Delaware. Dover was
part of the AGECO/AGECORP group of companies from 1929 until 1942; GPU, Inc.
emerged from the AGECO/AGECORP reorganization proceedings in 1946. All of
Dover's common stock, which was sold in 1942 to an unaffiliated entity, was
subsequently acquired by Chesapeake Utilities Corporation (Chesapeake), which
merged with Dover in 1960. Chesapeake is currently performing the cleanup at the
Site. According to the complaint, the EPA is seeking (1) enforcement of the
Order against GPU; (2) recovery of its past response costs; (3) a declaratory
judgment that GPU is liable for any remaining cleanup costs of the Site; and (4)
statutory penalties for noncompliance with the Order. The EPA has stated that it
has incurred approximately $1 million of past response costs as of December 31,
1999. The EPA estimates the total Site cleanup costs at approximately $4.2
million. Consultants to Chesapeake have estimated the remaining remediation
ground water costs to be approximately $11.3 million to $19 million. In
accordance with its penalty policy, and in discussions with GPU, the EPA has
demanded penalties calculated at a daily rate of $8,800, rather than the
statutory maximum of $27,500 per day. As of June 30, 2000, if the statutory
maximum were applied, the total amount of penalties would be approximately $39
million. GPU believes that it has meritorious defenses to the imposition of
penalties, or that if a penalty is assessed, it should be at a lower daily rate.
Chesapeake has also sued GPU, Inc. for contribution to the cleanup of the Dover
Site. The US District Court for the District of Delaware has consolidated the
case filed by Chesapeake with the case filed by the EPA and discovery is
proceeding. There can be no assurance as to the outcome of these proceedings.
In connection with the 1999 sale of its Seward Generation Station to
Sithe Energies, Penelec has assumed up to $6 million of remediation costs
associated with certain coal mine refuse piles which are the subject of an
earlier consent decree with the Pennsylvania Department of Environmental
Protection. Penelec expects recovery of these remediation costs in Phase II of
its restructuring proceeding and has recorded a corresponding regulatory asset.
JCP&L has entered into agreements with the NJDEP for the investigation
and remediation of 17 formerly owned MGP sites. JCP&L has also entered into
various cost-sharing agreements with other utilities for most of the sites. As
of June 30, 2000, JCP&L has spent approximately $38 million in connection
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with the cleanup of these sites. In addition, JCP&L has recorded an estimated
environmental liability of $54 million relating to expected future costs of
these sites (as well as two other properties) . This estimated liability is
based upon ongoing site investigations and remediation efforts, which generally
involve capping the sites and pumping and treatment of ground water. Moreover,
the cost to clean up these sites could be materially in excess of the $54
million due to significant uncertainties, including changes in acceptable
remediation methods and technologies.
In 1997, the NJBPU approved JCP&L's request to establish a Remediation
Adjustment Clause for the recovery of MGP remediation costs. As a result of the
NJBPU's Summary Order, effective August 1, 1999, the recovery of these costs was
transferred to the Societal Benefits Charge. As of June 30, 2000, JCP&L had
recorded on its Consolidated Balance Sheet a regulatory asset of $46 million.
JCP&L is continuing to pursue reimbursement from its insurance carriers for
remediation costs already spent and for future estimated costs. In 1994, JCP&L
filed a complaint with the Superior Court of New Jersey against several of its
insurance carriers, relative to these MGP sites, and has settled with all but
one of those insurance carriers.
OTHER COMMITMENTS AND CONTINGENCIES
Class Action Litigation:
------------------------
GPU Energy
In July 1999, New Jersey experienced a severe heat storm that resulted
in major power outages and temporary service interruptions, which affected
JCP&L's service territory. As a result, the NJBPU initiated an investigation
into the reliability of the transmission and distribution systems of all New
Jersey utilities and their response to power outages. This investigation was
completed in April 2000, resulting in Phase I and Phase II Reports. Both Reports
contain, among other things, recommendations as to certain actions that should
be undertaken by JCP&L, and were adopted by NJBPU orders requiring JCP&L to act
on the recommendations and to report back on such implementation. JCP&L has
begun to act on these recommendations. The NJBPU order adopting the Phase II
Report stated that there is not a prima facie case demonstrating that overall
JCP&L provided unsafe, inadequate or improper service to its customers. In
addition, two class action lawsuits were commenced in New Jersey Superior Court
in July 1999 against GPU, Inc. and JCP&L, seeking both compensatory and punitive
damages for alleged losses suffered due to service interruptions. The GPU
defendants originally requested the Court to stay or dismiss the litigation in
deference to the NJBPU's primary jurisdiction. The Court denied the motion,
consolidated the two actions, and certified them as class actions on behalf of a
class that includes JCP&L customers as well as "all dependents, tenants,
employees, and other intended beneficiaries of customers who suffered damages as
a result" of the outages. In January 2000, the Appellate Division agreed to
review the trial court's decision on primary jurisdiction. In June 2000, the
Appellate Division affirmed the trial court's decision recognizing, however,
that future developments in the case may require a reference of certain issues
to the NJBPU. The Appellate Division also stated that the NJBPU's findings could
be probative but not determinative of at least some issues in the
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litigation. In response to GPU's demand for a statement of damages, the
plaintiffs have stated that they are seeking damages of $700 million, subject to
the results of pre-trial discovery. GPU has notified its insurance carriers of
the plaintiffs' allegations. The primary insurance carrier has stated that while
the substance of the plaintiffs' allegations are covered under GPU's policy, it
is reserving its rights concerning coverage as circumstances develop. There can
be no assurance as to the outcome of these matters.
GPU Electric
As a result of the September 1998 fire and explosion at the Longford
natural gas plant in Victoria, Australia, Victorian gas users (plaintiffs) have
brought a class action in the Australian Federal Court against Esso Australia
Limited and its affiliate (Esso), the owner and operator of the plant, for
losses suffered due to the lack of natural gas supply and related damages. The
plaintiffs claim that Esso was, among other things, negligent in designing,
maintaining and operating the Longford plant and also assert claims under
Australian fair trade practices law.
Esso has joined as third party defendants the State of Victoria (State)
and various State-owned entities which operated the Victorian gas industry prior
to its privatization, including Transmission Pipelines Australia (TPA) and its
affiliate Transmission Pipelines (Assets) Australia (TPAA) . GPU, Inc., through
GPU GasNet, acquired the assets of TPA and the shares of TPAA from the State in
June 1999. Esso asserts that the State and the gas industry were negligent in
that, among other things, they failed to ensure that the gas system would
provide a secure supply of gas to users and also asserts claims under the
Australian fair trade practices law. In addition, GPU GasNet and other private
entities (Buyers) that purchased the Victorian gas assets from the State have
joined Esso as third party defendants. Esso asserts that if the gas industry is
liable as alleged, that liability has been transferred to the Buyers as part of
the State's privatization process.
Under the acquisition agreement with the State, GPU GasNet has
indemnified TPA and the State against third party claims arising out of, among
other things, the operation of TPA'S business. TPA and the State have commenced
proceedings against GPU GasNet to enforce the indemnity in respect of any
liability that may flow to TPA as a result of Esso's claim.
GPU GasNet and TPAA have filed answers denying liability to Esso, the
State and TPA, which could be material. GPU GasNet and TPAA have notified their
insurance carriers of this action. The insurers have reserved their rights to
deny coverage. There can be no assurance as to the outcome of this matter.
Investments and Guarantees:
---------------------------
GPU, Inc.
GPU, Inc. has made significant investments in foreign businesses and
facilities through its subsidiaries, GPU Electric and the GPUI Group. As of June
30, 2000, GPU, Inc. `s investment in GPU Electric and the GPUI Group was $569
million and $252 million, respectively. As of that date, GPU, Inc. has also
guaranteed an additional $998 million and $30 million (including $9
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million of guarantees related to domestic operations) of GPU Electric and GPUI
Group outstanding obligations, respectively. Although management attempts to
mitigate the risks of investing in certain foreign countries by, among other
things, securing political risk insurance, GPU faces additional risks inherent
to operating in such locations, including foreign currency fluctuations.
GPU Electric
In June 2000, GPU sold GPU PowerNet for A$2.1 billion (US$1.26
billion). For further information, see Note 2, Acquisitions and Dispositions.
GPU had previously announced its intention to sell all, or at least 50%, of the
Australian companies, for which it paid approximately US $1.9 billion (GPU
PowerNet) and US $675 million (GPU GasNet) in 1997 and 1999, respectively. GPU
is still considering the possible sale of GPU GasNet.
On June 2, 2000, repayment of approximately $218 million of maturing
GPU GasNet bank debt was extended to September 2, 2000. GPU GasNet may further
extend this loan to October 2, 2000. GPU GasNet is in the process of
establishing a commercial paper program and a medium term note program to
refinance this debt. GPU, Inc. has agreed to guarantee this loan, under certain
conditions, if it is not repaid by August 25, 2000.
Midlands Electricity plc (Midlands) (conducting business under the name
GPU Power UK) has a 40% equity interest in a 586 MW power project in Pakistan
(the Uch Power Project), which was originally scheduled to begin commercial
operation in late 1998. In June 1999, certain Project lenders for the Uch Power
Project issued notices of default to the Project sponsors (including Midlands
for, among other things, failure to pay principal and interest under various
loan agreements. In November 1999, the Project sponsors and lenders reached an
agreement under which repayment of the construction loan will be extended,
principal and interest payments deferred, and the sponsors will fund the
completion of the plant through the remaining equity contribution commitments.
Testing of the plant has begun, but the start of commercial operations has been
further delayed pending the resolution of certain technical problems, which are
being addressed.
Uch has renegotiated several of the project agreements with the
Government of Pakistan and its agencies. In April 2000, Uch signed a Memorandum
of Understanding with Pakistani authorities, in which it agreed, among other
things, to accept a reduction in the power purchase tariff averaging
approximately 8% over the project term. The agreement includes options to extend
the term of the project from 23 to 30 years. Commercial operations are now
planned to commence by the end of August, 2000. There remains a risk that
project revenues may be delayed due to the poor economic situation in Pakistan.
GPU's investment in the Uch Power Project as of June 30, 2000 was
approximately $37.1 million, plus a guarantee letter of credit of $5.2 million,
and its share of the projected completion costs represents an additional $3.9
million commitment. Cinergy Corp. has agreed to fund up to an aggregate of $20
million of the required capital contributions and/or certain future "cash
losses," which could be incurred on the Uch Power Project. Cinergy has
reimbursed GPU Electric for $4.9 million of capital contributions through June
30, 2000, leaving a remaining commitment of up to $15.1 million. There can be no
assurance as to the outcome of this matter.
As part of the 1999 sale of the GPU Power UK supply business and the
purchase of the 50% of GPU Power UK that GPU did not already own, certain
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long-term purchase obligations under natural gas supply contracts were retained.
Most of these contracts, which extend to September 2005, were at fixed prices in
excess of the market price of gas, and a liability was established for the
estimated loss under such contracts. However, as a result of increasing gas
prices during the second quarter of 2000, GPU Power UK was able to enter into
matching forward sale contracts for the majority of the gas purchases, resulting
in a reduction in the estimated liability and a credit to income of $15.9
million pre-tax. The estimated liability as of June 30, 2000 was $25 million, of
which approximately $19 million was "locked-in" under new forward sale
contracts. GPU Power UK was still exposed to future price risk on the remaining
$6 million of liabilities as of June 30, 2000.
In a recent English court decision involving two unaffiliated utilities
(National Grid and National Power), the court held that utilities improperly
used a pension plan surplus in the UK Electricity Supply Pension Scheme to
eliminate scheduled payments in respect of early retirement costs and employer
contributions. The Court found that, in the case of National Grid and National
Power, procedures had not been strictly followed, and as such, a liability may
now exist. At a subsequent hearing, the Court refused to consider the validity
or effectiveness of retrospective amendments to the plan. National Grid and
National Power have appealed the Court's decision to the House of Lords. Pending
the outcome of the Appeal, the requirement for any payments has been stayed. If
a similar complaint were to be made against GPU Power UK, GPU Power UK's
potential liability is estimated to be a maximum of British pound 63 million
(US$96 million), exclusive of any applicable interest charges or penalties. The
GPU Power UK section of the Electricity Supply Pension Scheme remains in
substantial surplus and any payment to the plan that might ultimately prove to
be necessary would be accounted for as an increase in pension assets, and would
not have an immediate impact on income. However, any related penalties or
interest (which could be assessed, though none are currently proposed) would
adversely affect income. There can be no assurance as to the outcome of this
matter.
Emdersa's operating companies are subject to a number of government
claims related to Value-added tax liabilities and to Social Security taxes
collected in their electric rates, which aggregate approximately $22 million.
The claims are generally related to transitional issues surrounding the
privatization of Argentina's electricity industry. There can be no assurance as
to the outcome of these matters.
GPUI Group
On July 9, 1999, DIAN (the Colombian national tax authority) issued a
"Special Requirement" on the Termobarranquilla S.A., Empresa de Servicios
Publicos (TEBSA) 1996 income tax return, which challenges the exclusion from
taxable income of an inflation adjustment related to the value of assets used
for power generation (EI Barranquilla, a wholly owned subsidiary of GPU Power,
ABB Barranquilla, Corporacion Electrica de la Costa Atlantica and Distral Group
have a 28.7%, 28.7%, 42.5% and 0.1% interest in TEBSA, respectively). The
failure to give notice of this Special Requirement to the US Export Import Bank
(EXIM Bank) is an event of default under the loan agreement. GPU Power also
believes that other events of default exist under the loan agreements with
project lenders including the Overseas Private Investments Corporation (OPIC)
and a commercial bank syndicate. As a result, certain required certifications
have not been delivered to EXIM Bank, OPIC and the other project lenders, which
failure is, itself, an event of default
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<PAGE> 124
under the loan agreements. These issues are currently being discussed with EXIM
Bank and the other project lenders. GPU Power also expects that it will be
necessary to address these issues with the Government of Colombia, as well as
the other partners in the TEBSA project. As of June 30, 2000, GPU Power has an
investment of approximately $84.4 million in TEBSA and is committed to make
additional standby equity contributions of $21.3 million, which GPU, Inc. has
guaranteed. The total outstanding senior debt of the TEBSA project is $399
million and, in addition, GPU International has guaranteed the obligations of
the operators of the TEBSA project, up to a maximum of $5 million, under the
project's operations and maintenance agreement. There can be no assurance as to
the outcome of these matters.
GPU Telcom
In March 2000, GPU, Inc. announced its participation in America's Fiber
Network LLC (AFN), of which GPU, Inc. anticipates owning 25%. AFN is a
high-speed fiber optics company with a network of more than 7,000 route miles,
or 140,000 fiber miles, connecting major markets in the eastern US to secondary
markets with a growing need for broadband access. GPU, Inc. anticipates
investing approximately $40 million (of which $1.9 million has been invested as
of June 30, 2000) in AFN through GPU Telcom, which includes existing and new
fiber routes and electronic equipment.
In April 2000, GPU, Inc. announced the formation of Telergy
Mid-Atlantic (TMA), a joint venture between GPU Telcom and Telergy, Inc. TMA
combines established telecommunication services and marketing expertise with
utilities' existing fiber networks and natural positioning in serving retail
markets. GPU, Inc. has invested $20 million in Telergy, Inc. through GPU Telcom.
Other:
------
JCP&L and Public Service Electric & Gas Company (PSE&G) each hold a 50%
undivided ownership interest in Yards Creek Pumped Storage Facility (Yards
Creek). In December 1998, JCP&L filed a petition with the New Jersey Board of
Public Utilities (NJBPU) seeking a declaratory order that PSE&G's right of first
refusal to purchase JCP&L's ownership interest at its current book value under a
1964 agreement between the companies is void and unenforceable. Management
believes that the fair market value of JCP&L's ownership interest in Yards Creek
is substantially in excess of its June 30, 2000 book value of $22 million. There
can be no assurance as to the outcome of this matter.
Concurrent with GPU's July 1999 acquisition of the 50% of GPU Power UK
which it did not already own, GPU began to evaluate existing restructuring plans
and formulate additional plans to reduce operating expenses and achieve ongoing
cost reductions. As of December 31, 1999, GPU had identified and approved a cost
reduction plan. At the acquisition date, GPU Power UK had recorded a liability
of $28.6 million related to previous cost reduction plans. GPU retained $25.7
million of this liability, related to contractual termination and other
severance benefits for 276 employees identified in a 1999 business process
reengineering project. GPU identified an additional 355 employees (234 in
Engineering Services, 38 in metering, 21 in Network Services and 62 from other
specific functions) to be terminated as part of the plan and recorded an
additional liability of $39.3 million. A net charge of $18.2 million for GPU's
50% share of these adjustments was included in expense in 1999 and the other 50%
was recorded in Goodwill as a purchase accounting adjustment.
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<PAGE> 125
In 2000, a change in the investment return assumptions, due to better
than expected investment performance, resulted in a reduction of approximately
$6.9 million to $22.6 million in the estimated liability for the
remaining 459 employees at December 31, 1999. Consequently, goodwill was
credited for $3.4 million (50% of the change in estimate) and $3.5 million was
credited to income. Also in 2000, $14.2 million was paid to 338 employees. The
remaining severance liability of $7.5 million at June 30, 2000 reflects the
above transactions as well as currency translation adjustments and the impact of
five employees who were retained and is included in Other current liabilities on
the Consolidated Balance Sheets. Management expects the plan will be
substantially completed by September 2000.
GPU AR has entered into contracts to supply electricity to retail
customers through June 2002. In connection with meeting its supply obligations,
GPU AR has entered into purchase commitments for energy and capacity with
payment obligations totaling approximately $22.5 million as of June 30, 2000.
GPU, Inc. has guaranteed up to $19.1 million of these payments.
In accordance with the Nuclear Waste Policy Act of 1982 (NWPA), the GPU
Energy companies have entered into contracts with, and have been paying fees to,
the DOE for the future disposal of spent nuclear fuel in a repository or interim
storage facility. AmerGen has assumed all liability for disposal costs related
to spent fuel generated after its purchase of TMI-1 and has agreed to assume
this liability for Oyster Creek following its purchase of that plant. In 1996,
the DOE notified the GPU Energy companies and other standard contract holders
that it would be unable to begin acceptance of spent nuclear fuel for disposal
by 1998, as mandated by the NWPA. The DOE requested recommendations from
contract holders for handling the delay. The DOE's inability to accept spent
nuclear fuel could have a material impact on GPU's results of operations, as
additional costs may be incurred to build and maintain interim on-site storage
at Oyster Creek. In June 1997, a consortium of electric utilities, including
GPUN, filed a license application with the NRC seeking permission to build an
interim above-ground disposal facility for spent nuclear fuel in Utah. There can
be no assurance as to the outcome of these matters.
GPU, Inc. and consolidated affiliates have approximately 15,500
employees worldwide, of whom 11,500 are employed in the US, 3,500 are in the
United Kingdom (UK) and the remaining 500 are in South America and Australia.
The majority of the US workforce is employed by the GPU Energy companies (5,600)
and MYR (5,500), of which approximately 3,300 and 4,800, respectively, are
represented by unions for collective bargaining purposes. In the UK,
approximately 3,100 GPU Power UK employees are represented by unions, and the
terms and conditions of various bargaining agreements are generally reviewed
annually, on April 1. JCP&L, Met-Ed and Penelec's collective bargaining
agreements with the International Brotherhood of Electrical Workers expire on
October 31, 2002, May 1, 2003 and May 14, 2002, respectively. Penelec's
collective bargaining agreement with the Utility Workers Union of America
expires on June 30, 2001.
During the normal course of the operation of its businesses, in
addition to the matters described above, GPU is from time to time involved in
disputes, claims and, in some cases, as a defendant in litigation in which
compensatory and punitive damages are sought by the public, customers,
contractors, vendors and other suppliers of equipment and services and by
employees alleging unlawful employment practices. While management does not
expect that the outcome of these matters will have a material effect on GPU's
55
<PAGE> 126
financial position or results of operations, there can be no assurance that this
will continue to be the case.
2. ACQUISITIONS AND DISPOSITIONS
MYR Group Inc. Acquisition
In April 2000, GPU, Inc. completed its acquisition of MYR Group Inc.
(MYR) for approximately $217.5 million. The fair value of the assets acquired
totaled approximately $154.7 million and the amount of liabilities assumed
totaled approximately $99.7 million.
MYR, a suburban Chicago-based infrastructure construction services
company, is the fifth largest specialty contractor in the US. MYR provides a
complete range of power line and commercial/industrial electrical construction
services for electric utilities, telecommunications providers, commercial and
industrial facilities and government agencies across the US. MYR also builds
cellular towers for the wireless communications market.
The acquisition was partially financed through the issuance of GPU,
Inc. short-term debt and was accounted for under the purchase method of
accounting. The total acquisition cost exceeded the estimated value of net
assets by $162.5 million. This excess is considered goodwill and is being
amortized on a straight-line basis over 40 years.
The following is a summary of significant accounting policies for MYR's
construction services business:
Revenue Recognition
-------------------
MYR recognizes revenue on construction contracts using the
percentage-of-completion accounting method determined in each case by the ratio
of cost incurred to date on the contract (excluding uninstalled direct
materials) to management's estimate of the contract's total cost. Contract cost
includes all direct material, subcontract and labor costs and those indirect
costs related to contract performance, such as supplies, tool repairs and
depreciation. MYR charges selling, general, and administrative costs, including
indirect costs associated with maintaining district offices, to expense as
incurred.
Provisions for estimated losses on uncompleted contracts are recorded
in the period in which such losses are determined. Changes in estimated revenues
and costs are recognized in the periods in which such estimates are revised.
Significant claims are included in revenue in accordance with industry practice.
The asset, "Costs and estimated earnings in excess of billings on
uncompleted contracts," represents revenues recognized in excess of amounts
billed. The liability, "Billings in excess of costs and estimated earnings on
uncompleted contracts," represents amounts billed in excess of revenues
recognized.
Classification of Current Assets and Current Liabilities
--------------------------------------------------------
The length of MYR's contracts vary, with some larger contracts
exceeding one year. In accordance with industry practice, MYR includes in
current assets and current liabilities amounts realizable and payable under
contracts which may extend beyond one year.
56
<PAGE> 127
GPU PowerNet Sale
On June 30, 2000, GPU, Inc. sold GPU PowerNet to Singapore Power
International (SPI) for A$2.1 billion (approximately US $1.26 billion). As part
of the sales price, SPI assumed liability for A$230 million (US$137.8 million)
of medium term notes. GPU applied the net proceeds from the sale as follows:
A$1,288 million (US$772 million) was used to repay debt; and $A579 million
(US$347 million) was placed in a trust (which is included in Special deposits on
the Consolidated Balance Sheets) to provide for the repayment of the remaining
medium term notes (A$174 million/US$104 million) and outstanding commercial
paper (A$405 million/US$243 million) at maturity. As a result of the sale, GPU
recorded in Operating expenses on the Consolidated Statements of Income, a
pre-tax loss in the quarter ended June 30, 2000 of $372 million($295 million
after-tax, or $2.43 per share), including a $94 million foreign currency loss.
Pending Sale of Oyster Creek
In 1999, the GPU Energy companies sold Three Mile Island Unit 1 (TMI-1)
nuclear generating station and substantially all of their fossil and
hydroelectric generating stations. In October 1999, JCP&L agreed to sell Oyster
Creek to AmerGen Energy Company, LLC (AmerGen), a joint venture of PECO Energy
and British Energy, for $10 million and reimbursement of the cost (estimated at
$88 million) of the next scheduled refueling outage. The Oyster Creek plant was
written down to its fair market value in 1999, consistent with its sale price.
The write-down of the plant asset was deferred as a regulatory asset pending
separate and further review by the NJBPU.
3. ACCOUNTING FOR DERIVATIVE INSTRUMENTS
GPU's use of derivative instruments is intended primarily to manage the
risk of interest rate, foreign currency and commodity price fluctuations. GPU
does not intend to hold or issue derivative instruments for trading purposes.
Commodity Derivatives:
----------------------
The GPU Energy companies use futures contracts to manage the risk of
fluctuations in the market price of electricity and natural gas. These contracts
qualify for hedge accounting treatment under current accounting rules since
price movements of the commodity derivatives are highly correlated with the
underlying hedged commodities and the transactions are designated as hedges at
inception. Accordingly, under the deferral method of accounting, gains and
losses related to commodity derivatives are recognized in Power purchased and
interchanged in the Consolidated Statements of Income when the hedged
transaction closes or if the commodity derivative is no longer sufficiently
correlated. Prior to income or loss recognition, deferred gains and losses
relating to these transactions are recorded in Current Assets or Current
Liabilities in the Consolidated Balance Sheets.
Interest Rate Swap Agreements:
------------------------------
GPU Electric uses interest rate swap agreements to manage the risk of
increases in variable interest rates. As of June 30, 2000, these agreements
covered approximately $549 million of debt, including commercial paper, and were
scheduled to expire on various dates through November 2007. Differences
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<PAGE> 128
between amounts paid and received under interest rate swaps are recorded as
adjustments to the interest expense of the underlying debt since the swaps are
related to specific assets, liabilities or anticipated transactions. All of the
agreements effectively convert variable rate debt, including commercial paper,
to fixed rate debt. For the quarter ended June 30, 2000, fixed rate interest
expense incurred in connection with the swap agreements exceeded the variable
rate interest expense that would have been incurred had the swaps not been in
place by approximately $380 thousand.
Due to the sale of GPU PowerNet, the amount of debt subject to interest
rate swaps at GPU Electric declined from $1,299 million at March 31, 2000 to
$549 million at June 30, 2000. Swap positions associated with the retired debt
were closed out, and swap breakage costs of $2.1 million pre-tax were included
as part of the loss on the sale of GPU PowerNet.
In April 2000, Penelec issued a total of $50 million of variable rate
senior notes as unsecured medium-term notes. These variable rate securities were
converted to fixed rate obligations through interest rate swap agreements.
Currency Swap Agreements:
-------------------------
GPU Electric uses currency swap agreements to manage currency risk
caused by fluctuations in the US dollar exchange rate related to debt issued in
the US by Avon Energy Partners Holdings (Avon). These swap agreements
effectively convert principal and interest payments on this US dollar debt to
fixed sterling principal and interest payments, and expire on the maturity dates
of the bonds. Interest expense is recorded based on the fixed sterling interest
rate. As of June 30, 2000, these currency swap agreements covered British pound
561 million (US $850 million) of debt. Interest expense would have been British
pound 9.4 million (US $14.3 million) as compared to British pound 9.8 million
(US $14.9 million) for the quarter ended June 30, 2000 had these agreements not
been in place.
Gain on Forward Foreign Exchange Contracts:
-------------------------------------------
In connection with its previously announced intention to sell its
Australian assets, GPU Electric entered into forward foreign exchange contracts
in order to lock in the then-current A$/US$ exchange rate on the projected
remittance of Australian dollar proceeds arising from the expected sale of GPU
PowerNet and GPU GasNet. On May 24, 2000, GPU announced that it had declined all
bids submitted in connection with the sale process. Consequently, GPU Electric
closed out its forward foreign exchange positions, and recognized a pre-tax
gain of $4.5 million in the second quarter of 2000.
Indexed Swap Agreement:
-----------------------
In June 1998, Onondaga Cogeneration L.P. (Onondaga), a GPU
International, Inc. subsidiary, and Niagara Mohawk Power Corporation (NIMO)
renegotiated their existing power purchase agreement and entered into a 10-year
power put indexed swap agreement.
The power put agreement gives Onondaga the right, but not the
obligation, to sell energy and capacity to NIMO at a proxy market price up to
the specified contract quantity.
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<PAGE> 129
Under the indexed swap agreement, Onondaga pays NIMO the market price
of energy and capacity and NIMO pays Onondaga a contract price which is fixed
for the first two years and then adjusted monthly, according to an indexing
formula, for the remaining term. As of June 30, 2000, the unamortized balance of
the swap contract was valued at $51.7 million, and was included in Other -
Deferred Debits and Other Assets on the Consolidated Balance Sheets. This
valuation was derived using the discounted estimated cash flows related to
payments expected to be received by Onondaga. A corresponding amount was
recorded in deferred revenue (which is included in Other - Current Liabilities
on the Consolidated Balance Sheets) and will be recognized to income over a
period not to exceed 10 years.
Concurrent with the establishment of a competitive market for
electricity in New York (Power Exchange) and meeting specific trading volume
criteria, certain rights between Onondaga and NIMO expire under the power put
agreement. As a result, in 2000, GPU International, Inc. expects to recognize in
income all unamortized deferred revenue, including that from the indexed swap
agreement, which will be largely offset by an impairment of the Onondaga
facility and a provision for out-of-market gas transportation costs.
4. SEGMENT INFORMATION
The following is presented in accordance with Statement of Financial
Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and
Related Information."
GPU's reportable segments are strategic business units that are managed
separately due to their different operating and regulatory environments. GPU's
management evaluates the performance of its business units based upon income
before extraordinary and non-recurring items. For the purpose of providing
segment information, domestic electric utility operations (GPU Energy) is
comprised of the three electric utility operating companies serving customers in
New Jersey and Pennsylvania, as well as GPU Generation, Inc. (sold in late
1999), GPUN, GPU Telcom and GPUS. For additional information on GPU's
organizational structure and businesses, see preface to the Notes to
Consolidated Financial Statements.
59
<PAGE> 130
<TABLE>
<CAPTION>
Business Segment Data (in thousands)
Interest
Depreciation Charges and Income Tax
Operating and Preferred Expense/
Revenues Amortization Dividends (Benefit)
-------- ------------ --------- -----------
<S> <C> <C> <C> <C>
For the six months ended
June 30, 2000
Domestic Segments:
Electric Utility Operations
(GPU Energy) $ 1,730,089 $ 169,356 $ 102,847 $ 102,722
Independ Power Prod
(GPU International) 43,692 4,700 416 73
Electric Retail Energy Sales
(GPU AR) 39,874 - - 848
Construction Services
(MYR) (e) 99,532 1,311 2,389 1,147
----------- ---------- ---------- ---------
Subtotal 1,913,187 175,367 105,652 104,790
----------- ---------- ---------- ---------
Foreign Segments:
Electric/Gas Utility Operations: (GPU Electric)
Electric Distribution -
United Kingdom 325,106 52,376 91,451 29,795
Electric Distribution -
Argentina 81,614 7,663 12,749 6,881
Electric Transmission -
Australia (d) 90,007 19,947 46,822 (10,921)
Gas Transmission -
Australia 27,183 5,520 21,114 (6,675)
Independ Power Prod -
S. America (GPU Power) 21,082 3,154 2,183 2,408
----------- ---------- ---------- ---------
Subtotal 544,992 88,660 174,319 21,488
----------- ---------- ---------- ---------
Corporate and Eliminations (1,361) - 4,805 -
----------- ---------- ---------- ---------
Consolidated Total $ 2,456,818 $ 264,027 $ 284,776 $ 126,278
=========== ========== ========== =========
For the six months ended June 30, 1999
Domestic Segments:
Electric Utility Operations
(GPU Energy) $ 1,712,716 $ 206,963 $ 114,519 $ 163,060
Independ Power Prod
(GPU International) 42,197 4,649 619 182
Electric Retail Energy
Sales (GPU AR) 37,521 - - 1,032
----------- ---------- ---------- ---------
Subtotal 1,792,434 211,612 115,138 164,274
----------- ---------- ---------- ---------
Foreign Segments:
Electric/Gas Utility Operations: (GPU Electric)
Electric Distribution -
United Kingdom 603 - 9,835 2,171
Electric Distribution -
Argentina 48,999 6,190 8,008 1,986
Electric Transmission -
Australia (d) 95,912 21,367 52,526 4,462
Gas Transmission -
Australia 5,721 1,227 3,589 422
Independ Power Prod -
S. America (GPU Power) 17,734 2,699 1,363 2,272
----------- ---------- ---------- ---------
Subtotal 168,969 31,483 75,321 11,313
----------- ---------- ---------- ---------
Corporate and Eliminations - - 481 -
----------- ---------- ---------- ---------
Consolidated Total $ 1,961,403 $ 243,095 $ 190,940 $ 175,587
=========== ========== ========== =========
</TABLE>
(a) Represents income taxes on income before extraordinary and
non-recurring items.
(b) The comparative 1999 Total Assets is as of December 31, 1999.
(c) Includes equity in net income of investee accounted for under the
equity method of $73.5 million, for the period prior to the
consolidation of GPU Power UK.
(d) Represents GPU PowerNet, which was sold in June 2000.
(e) MYR was acquired in May 2000.
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<PAGE> 131
5. COMPREHENSIVE INCOME
For the six months ended June 30, 2000 and 1999, comprehensive income
is summarized below.
<TABLE>
<CAPTION>
(in thousands)
Six months
Ended June 30,
GPU, Inc. and Subsidiary Companies 2000 1999
---------------------------------- ---- ----
<S> <C> <C>
Net income/(loss) $ (79,815) $ 237,981
---------- ----------
Other comprehensive income/(loss), net of tax:
Net unrealized gains/(loss) on investments 13,028 (4,758)
Foreign currency translation (41,852) 8,169
---------- ----------
Total other comprehensive income/(loss) (28,824) 3,411
---------- ----------
Comprehensive income! (loss) $(108, 639) $ 241,392
========== ==========
JCP&L
Net income $ 90,004 $ 47,842
---------- ----------
Other comprehensive income/(loss), net of tax:
Net unrealized gains/(loss) on investments - -
---------- ----------
Comprehensive income $ 90,004 $ 47,842
========== ==========
Met-Ed
Net income $ 35,160 $ 51,974
---------- ----------
Other comprehensive income/(loss), net of tax:
Net unrealized gains/(loss) on investments (2,141) 2,816
---------- ----------
Comprehensive income $ 33,019 $ 54,790
========== ==========
Penelec
Net income $ 31,481 $ 85,435
---------- ----------
Other comprehensive income/(loss), net of tax:
Net unrealized gains/(loss) on investments (1,076) 1,337
---------- ----------
Comprehensive income $ 30,405 $ 86,772
========== ==========
</TABLE>
61
<PAGE> 132
PART II
ITEM 1 - LEGAL PROCEEDINGS
Information concerning the current status of certain legal
proceedings instituted against GPU, Inc. and the GPU Energy
companies discussed in Part I of this report in Combined Notes
to Consolidated Financial Statements is incorporated herein by
reference and made a part hereof.
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
(4) Instruments defining the rights of security
holders, including indentures
A - First Supplemental Indenture between Met-Ed and
United States Trust Company of New York, dated
August 1, 2000.
B - First Supplemental Indenture between Penelec and
United States Trust Company of New York, dated
August 1, 2000.
(12) Statements Showing Computation of Ratio of
Earnings to Fixed Charges and Ratio of Earnings to
Combined Fixed Charges and Preferred Stock Dividends
Based on SEC Regulation S-K, Item 503
A - JCP&L
B - Met-Ed
C - Penelec
(27) Financial Data Schedules
A - GPU, Inc. and Subsidiary Companies
B - JCP&L
C - Met-Ed
D - Penelec
(b) Reports on Form 8-K
GPU, Inc.:
----------
<PAGE> 133
EXHIBIT E
Income statement for the most recent 12 month period only, on an actual and on a
pro forma basis in the form prescribed for Statement C of FERC Form No. 1.
<PAGE> 134
FIRSTENERGY CORP./GPU INC.
PRO FORMA COMBINED INCOME STATEMENT
FOR THE YEAR ENDED DECEMBER 31, 1999
<TABLE>
<CAPTION>
OHIO CLEVELAND TOLEDO PENNSYLVANIA
EDISON ELECTRIC EDISON POWER
------ -------- ------ -----
<S> <C> <C> <C> <C>
Operating Revenues $2,365,964,220 $1,849,561,714 $921,158,988 $ 315,731,137
Operating Expenses 1,924,843,906 1,470,176,587 757,382,166 280,378,886
-------------- -------------- ------------ -------------
Net Operating Income 441,120,314 379,385,127 163,776,822 35,352,251
Net Other Income 44,098,260 23,306,399 12,737,848 (1,850,983)
-------------- -------------- ------------ -------------
Income Before Net Interest Charges 485,218,574 402,691,526 176,514,670 33,501,268
Net interest Charges 187,529,210 208,602,718 76,569,731 20,853,276
-------------- -------------- ------------ -------------
Net Income 297,689,364 194,088,808 99,944,939 12,647,992
Preferred Stock Dividend Requirements 0 0 0 0
-------------- -------------- ------------ -------------
Earnings on Common Stock $ 297,689,364 $ 194,088,808 $ 99,944,939 $ 12,647,992
============== ============== ============ =============
</TABLE>
<TABLE>
<CAPTION>
JERSEY
CENTRAL METROPOLITAN PENNSYLVANIA
POWER & LIGHT EDISON ELECTRIC YORK HAVEN
COMPANY COMPANY COMPANY POWER COMPANY
------- ------- ------- -------------
<S> <C> <C> <C> <C>
Operating Revenues $2,018,208,667 $902,697,284 $921,964,651 $ 5,201,850
Operating Expenses 1,740,204,057 730,544,562 774,460,913 3,738,108
-------------- ------------ ------------ -----------
Net Operating Income 278,004,610 172,152,722 147,503,738 l,463,742
Net Other Income 1,023,436 (14,569,687) 50,081,756 161,868
-------------- ------------ ------------ -----------
Income Before Net Interest Charges 279,028,046 157,583,035 197,585,494 1,625,610
Net interest Charges 106,648,828 62,459,768 45,093,993 3,227
-------------- ------------ ------------ -----------
Net Income 172,379,218 95,123,267 152,491,501 1,622,383
Preferred Stock Dividend Requirements 0 0 0 0
-------------- ------------ ------------ -----------
Earnings on Common Stock $ 172,379,218 $ 95,123,267 $152,491,501 $ 1,622,383
============== ============ ============ ===========
</TABLE>
<TABLE>
<CAPTION>
CURRENT
FIRSTENERGY MERGER FIRSTENERGY
OTHER & GPU PRO FORMA PRO FORMA
SUBSIDIARIES ELIMINATIONS ADJUSTMENTS COMBINED
------------ ------------ ----------- --------
<S> <C> <C> <C> <C>
Operating Revenues $3,657,808,770 ($2,923,012,328) $ 0 $10,035,284,953
Operating Expenses 2,948,196,047 (2,459,216,804) (94,475,000) 8,076,233,428
-------------- --------------- ------------- ---------------
Net Operating Income 709,612,723 (463,795,524) 94,475,000 1,959,051,525
Net Other Income 780,614,447 (701,099,558) 0 194,503,786
-------------- --------------- ------------- ---------------
Income Before Net Interest Charges 1,490,227,170 (1,164,895,082) 94,475,000 2,153,555,311
Net interest Charges 346,330,776 (24,441,171) 193,849,000 1,223,499,356
-------------- --------------- ------------- ---------------
Net Income 1,143,896,394 (1,140,453,911) (99,374,000) 930,055,955
Preferred Stock Dividend Requirements 0 0 0 0
-------------- --------------- ------------- ---------------
Earnings on Common Stock $1,143,896,394 ($1,140,453,911) ($99,374,000) $ 930,055,955
============== =============== ============= ===============
</TABLE>
<PAGE> 135
EXHIBIT F
An analysis of retained earnings for the period covered by the income statements
referred to in Exhibit E.
<PAGE> 136
FIRSTENERGY CORP./GPU, INC.
PRO FORMA COMBINED STATEMENT OF RETAINED EARNINGS
FOR THE YEAR ENDED DECEMBER 31, 1999
<TABLE>
<CAPTION>
MERGER FIRSTENERGY
FIRSTENERGY ELIMINATIONS PRO FORMA
CORP. GPU, INC. & ADJUSTMENTS COMBINED
--------------- -------------- --------------- -------------
<S> <C> <C> <C> <C>
Balance - Beginning of Year (1/1/99) $ 718,409,346 $2,189,947,916 ($2,189,947,916) (a) $ 718,409,346
Net Income 568,299,454 461,130,501 (99,374,000) (b) 930,055,955
--------------- -------------- --------------- -------------
1,286,708,800 2,651,078,417 (2,289,321,916) 1,648,465,301
Dividends Declared - Common Stock (341,468,277) (263,088,657) 263,088,657 (c) (464,830,277)
(123,362,000) (c)
Adjustments to Retained Earnings:
Loss on Reacquisition of Preferred Stock - (2,116,272) (2,116,272)
Net Unrealized Gain on Investments - 5,838,268 5,838,268
Foreign Currency Translation - 13,859,089 13,859,089
Minimum Pension Liability - 5,266,502 5,266,502
Other Adjustments - (1,194) (1,194)
--------------- -------------- --------------- -------------
Balance - End of Year (12/31/99) $ 945,240,523 $2,410,836,153 ($2,149,595,259) $1,206,481,417
=============== ============== =============== =============
NOTES: (a) Represents pro forma elimination of GPU, Inc. accumulated
retained earnings as of January 1, 1999.
(b) Represents pro forma net income adjustments.
(c) Represents adjustment to replace GPU 1999 common stock
dividends with pro forma annual dividend of $1.50 paid on
82,241,527 FirstEnergy common shares issued to GPU, Inc.
shareholders.
</TABLE>
<PAGE> 137
FIRST ENERGY CORP/GPU INC.
PRO FORMA COMBINED SUMMARY OF UTILITY PLANT AND
ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
AS OF DECEMBER 31, 1999
<TABLE>
<CAPTION>
OHIO CLEVELAND TOLEDO PENNSYLVANIA
EDISON ELECTRIC EDISON POWER
--------------- --------------- --------------- ---------------
UTILITY PLANT
IN SERVICE:
<S> <C> <C> <C> <C>
PLANT IN SERVICE (CLASSIFIED) $ 8,824,276,231 $ 3,791,020,858 $ 1,526,730,041 $ 1,008,632,099
PROPERTY UNDER CAPITAL LEASES 164,001,333 7,943,494 1,636,046 4,116,636
PLANT PURCHASED OR SOLD 63,118,344 184,410,076 0 40,567,280
COMPLETED CONSTRUCTION NOT CLASSIFIED 231,637,462 302,366,906 129,865,924 32,487,849
EXPERIMENTAL PLANT NOT CLASSIFIED 0 0 0 0
--------------- --------------- --------------- ---------------
TOTAL 7,273,823,370 4,285,443,333 1,657,832,010 1,145,783,904
LEASED TO OTHERS 0 0 0 983,057
HELD FOR FUTURE USE 11,867,916 19,453,151 2,453,748 1,871,382
CONSTRUCTION WORK IN PROGRESS 187,113,405 86,002,026 96,853,900 18,557,920
ACQUISITION ADJUSTMENTS 0 0 0 0
--------------- --------------- --------------- ---------------
TOTAL UTILITY PLANT 7,472,804,891 4,350,896,809 1,756,230,657 1,167,216,173
ACCUM PROV FOR DEPR, AMORT & DEPL 3,373,616,555 1,300,720,289 596,332,268 767,521,106
--------------- --------------- --------------- ---------------
NET UTILITY PLANT $ 4,099,196,136 $ 2,960,178,220 1,159,907,382 $ 300,005,067
=============== =============== =============== ===============
DETAIL OF ACCUMULATED PROVISIONS FOR
DEPRECIATION,AMORTIZATION AND DEPLETION
IN SERVICE:
DEPRECIATION $ 3,164,498,078 $ 1,311,227,017 $ 550,411,532 $ 727,141,223
AMORT. AND DEPL. OF PRODUCTING NATURAL
GAS LANDLAND RIGHTS 0 0 0 0
AMORT. OF UNDERGROUND STORAGE
LAND AND LAND RIGHTS 0 0 0 0
AMORT OF OTHER UTILITY PLANT 208,098,138 72,094,814 34,788,907 40,248,076
--------------- --------------- --------------- ---------------
TOTAL IN SERVICE 3,373,566,216 1,383,321,831 964,181,439 767,368,796
LEASED TO OTHERS:
DEPRECIATION 0 0 0 0
AMORTIZATION AND DEPLETION 0 0 0 0
--------------- --------------- --------------- ---------------
TOTAL LEASED TO OTHERS 0 0 0 0
HELD FOR FUTURE USE:
DEPRECIATION 30,330 16,396,456 2,150,826 131,808
AMORTIZATION 0 0 0 0
--------------- --------------- --------------- ---------------
TOTAL HELD FOR FUTURE USE 30,330 16,396,456 2,150,826 131,808
ABANDONMENT OF LEASES (NATURAL GAS)
AMORT OF PLANT ACQUISITION ADJ. 0 0 0 0
--------------- --------------- --------------- ---------------
TOTAL ACCUMULATED PROVISIONS $ 3,373,616,866 $ 1,303,720,200 $ 800,332,206 $ 787,821,108
=============== =============== =============== ===============
<CAPTION>
JERSEY METROPOLITAN PENNSYLVANIA YORK
CENTRAL EDISON ELECTRIC HAVEN
--------------- --------------- --------------- ---------------
UTILITY PLANT
IN SERVICE:
<S> <C> <C> <C> <C>
PLANT IN SERVICE (CLASSIFIED) $ 4,186,230,526 $ 1,499,028,875 $ 1,732,370,611 $ 23,231,721
PROPERTY UNDER CAPITAL LEASES 0 0 2,176,778 0
PLANT PURCHASED OR SOLD 0 (160,362) O O
COMPLETED CONSTRUCTION NOT CLASSIFIED 0 0 0 0
EXPERIMENTAL PLANT NOT CLASSIFIED 0 0 0 0
--------------- --------------- --------------- ---------------
TOTAL 4,186,230,526 1,490,000,613 1,734,547,589 23,231,721
LEASED TO OTHERS 0 0 0 0
HELD FOR FUTURE USE 15,402,271 806,326 527,551 0
CONSTRUCTION WORK IN PROGRESS 80,671,006 21,216,332 30,326,546 4,112,397
ACQUISITION ADJUSTMENTS 0 0 0 0
--------------- --------------- --------------- ---------------
TOTAL UTILITY PLANT 4,292,312,803 1,620,081,171 1,785,403,806 27,344,119
ACCUM PROV FOR DEPR, AMORT & DEPL 2,456,999,052 456,205,770 862,449,183 7,803,054
--------------- --------------- --------------- ---------------
NET UTILITY PLANT $ 1,826,346,151 $ 1,068,476,401 $ 1,212,954,703 $ 19,841,054
=============== =============== =============== ===============
DETAIL OF ACCUMULATED PROVISIONS FOR
DEPRECIATION,AMORTIZATION AND DEPLETION
IN SERVICE:
DEPRECIATION $ 2,456,966,852 $ 456,205,770 $ 552,449,183 $ 7,503,064
AMORT. AND DEPL. OF PRODUCTING NATURAL
GAS LANDLAND RIGHTS 0 0 0 0
AMORT. OF UNDERGROUND STORAGE
LAND AND LAND RIGHTS 0 0 0 0
AMORT OF OTHER UTILITY PLANT 0 0 0 0
--------------- --------------- --------------- ---------------
TOTAL IN SERVICE 2,456,966,852 455,205,770 552,449,183 7,503,064
LEASED TO OTHERS:
DEPRECIATION 0 0 0 0
AMORTIZATION AND DEPLETION 0 0 0 0
--------------- --------------- --------------- ---------------
TOTAL LEASED TO OTHERS 0 0 0 0
HELD FOR FUTURE USE:
DEPRECIATION 0 0 0 0
AMORTIZATION 0 0 0 0
--------------- --------------- --------------- ---------------
TOTAL HELD FOR FUTURE USE 0 0 0 0
ABANDONMENT OF LEASES (NATURAL GAS)
AMORT OF PLANT ACQUISITION ADJ. 0 0 0 0
--------------- --------------- --------------- ---------------
TOTAL ACCUMULATED PROVISIONS $ 2,456,906,052 $ 456,205,770 $ 582,449,183 $ 7,503,064
=============== =============== =============== ===============
<CAPTION>
CURRENT
FIRST ENERGY MERGER FIRST ENERGY
OTHER & GPU PRO FORMA PRO FORMA
SUBSIDIARIES ELIMINATIONS ADJUSTMENTS COMBINED
--------------- --------------- --------------- ---------------
UTILITY PLANT
IN SERVICE:
<S> <C> <C> <C> <C>
PLANT IN SERVICE (CLASSIFIED) $ 4,910,948,248 $ 0 ($ 450,000,000) $25,112,470,300
PROPERTY UNDER CAPITAL LEASES 0 0 0 180,364,296
PLANT PURCHASED OR SOLD 0 0 0 277,825,307
COMPLETED CONSTRUCTION NOT CLASSIFIED 0 0 0 800,060,141
EXPERIMENTAL PLANT NOT CLASSIFIED 0 0 0 0
--------------- --------------- --------------- ---------------
TOTAL 4,910,948,248 0 (450,000,000) 26,286,828,114
LEASED TO OTHERS 0 0 0 983,057
HELD FOR FUTURE USE 0 0 0 62,172,355
CONSTRUCTION WORK IN PROGRESS 33,967,050 0 0 526,843,380
ACQUISITION ADJUSTMENTS 0 0 0 0
--------------- --------------- --------------- ---------------
TOTAL UTILITY PLANT 4,944,935,098 0 (450,000,000) 26,848,838,806
ACCUM PROV FOR DEPR, AMORT & DEPL 1,042,716,280 0 0 10,052,030,144
--------------- --------------- --------------- ---------------
NET UTILITY PLANT $ 3,902,220,638 0 (450,000,000) $16,194.906,762
=============== =============== =============== ===============
DETAIL OF ACCUMULATED PROVISIONS FOR
DEPRECIATION,AMORTIZATION AND DEPLETION
IN SERVICE:
DEPRECIATION $ 1,042,715,280 $ 0 $ 0 $ 0
AMORT. AND DEPL. OF PRODUCTING NATURAL
GAS LANDLAND RIGHTS 0 0 0 0
AMORT. OF UNDERGROUND STORAGE
LAND AND LAND RIGHTS 0 0 0 0
AMORT OF OTHER UTILITY PLANT 0 0 0 356,210,834
--------------- --------------- --------------- ---------------
TOTAL IN SERVICE $ 1,042,715,280 0 0 356,210,834
LEASED TO OTHERS:
DEPRECIATION 0 0 0 0
AMORTIZATION AND DEPLETION 0 0 0 0
--------------- --------------- --------------- ---------------
TOTAL LEASED TO OTHERS 0 0 0 0
HELD FOR FUTURE USE:
DEPRECIATION 0 0 0 10,711,431
AMORTIZATION 0 0 0 0
--------------- --------------- --------------- ---------------
TOTAL HELD FOR FUTURE USE 0 0 0 10,711,431
ABANDONMENT OF LEASES (NATURAL GAS)
AMORT OF PLANT ACQUISITION ADJ. 0 0 0 0
--------------- --------------- --------------- ---------------
TOTAL ACCUMULATED PROVISIONS $ 1,042,715,280 $ 0 $ 0 $ 374,822,365
=============== =============== =============== ===============
<CAPTION>
FE GPU TOTAL
OTHER OTHER OTHER
SUBSIDIARIES SUBSIDIARIES SUBSIDIARIES
--------------- --------------- ---------------
UTILITY PLANT
IN SERVICE:
<S> <C> <C> <C>
IN SERVICE:
PLANT IN SERVICE (CLASSIFIED) $ 888,185 $ 4,910,280,063 $ 4,910,948,248
PROPERTY UNDER CAPITAL LEASES 0 0 0
PLANT PURCHASED OR SOLD 0 0 0
COMPLETED CONSTRUCTION NOT CLASSIFIED 0 0 0
EXPERIMENTAL PLANT NOT CLASSIFIED 0 0 0
--------------- --------------- ---------------
TOTAL 888,195 4,910,280,063 4,910,948,248
LEASED TO OTHERS 0 0 0
HELD FOR FUTURE USE 0 0 0
CONSTRUCTION WORK IN PROGRESS 0 33,987,850 33,967,050
ACQUISITION ADJUSTMENTS 0 0 0
--------------- --------------- ---------------
TOTAL UTILITY PLANT 888,185 4,944,267,713 4,944,935,896
ACCUM PROV FOR DEPR, AMORT & DEPL 333,124 1,042,382,136 1,042,718,260
--------------- --------------- ---------------
NET UTILITY PLANT $ 336,061 $ 3,901,996,577 $ 3,002,220,038
=============== =============== ===============
DETAIL OF ACCUMULATED PROVISIONS FOR
DEPRECIATION,AMORTIZATION AND DEPLETION
IN SERVICE:
DEPRECIATION $ 333,124 $ 1,042,382,138 $ 1,042,715,280
AMORT. AND DEPL. OF PRODUCTING NATURAL
GAS LANDLAND RIGHTS 0 0 0
AMORT. OF UNDERGROUND STORAGE
LAND AND LAND RIGHTS 0 0 0
AMORT OF OTHER UTILITY PLANT 0 0 0
--------------- --------------- ---------------
TOTAL IN SERVICE $ 333,124 $ 1,042,382,138 $ 1,042,715,280
LEASED TO OTHERS:
DEPRECIATION 0 0 0
AMORTIZATION AND DEPLETION 0 0 0
--------------- --------------- ---------------
TOTAL LEASED TO OTHERS 0 0 0
HELD FOR FUTURE USE:
DEPRECIATION 0 0 0
AMORTIZATION 0 0 0
--------------- --------------- ---------------
TOTAL HELD FOR FUTURE USE 0 0 0
ABANDONMENT OF LEASES (NATURAL GAS)
AMORT OF PLANT ACQUISITION ADJ. 0 0 0
--------------- --------------- ---------------
TOTAL ACCUMULATED PROVISIONS $ 333,124 $ 1,042,382,138 $ 1,042,715,280
=============== =============== ===============
</TABLE>
<PAGE> 138
EXHIBIT G
A copy of each application and Exhibit filed with any other Federal or State
regulatory body in connection with the proposed transaction, and if action has
been taken thereon, a certified copy of each order relating thereto.
<PAGE> 139
Copy of Application to the United States Nuclear
Regulatory Commission for Indirect Transfers of Control
Exhibit Intentionally Omitted.
<PAGE> 140
EXHIBIT H
A copy of all contracts in respect to the proposed transaction.
<PAGE> 141
Copy of Agreement and Plan of Merger Between
FirstEnergy Corp. and GPU, Inc. Dated as of
August 8, 2000.
Exhibit Intentionally Omitted.
<PAGE> 142
EXHIBIT I
Maps.
Exhibit Intentionally Omitted.
<PAGE> 143
VERIFICATIONS
<PAGE> 144
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Ohio Edison Company )
The Cleveland Eletric Illuminating )
Company, The Toledo Edison Company, ) Docket No. ECO1-____-000
Pennsylvania Power Company, American )
Transmission Systems, Inc. and their public )
utility affiliates )
)
and )
)
Jersey Central Power & Light Company, )
Metropolitan Edison Company, Pennsylvania )
Electric Company and their public utility affiliates )
VERIFICATION
------------
STATE OF OHIO )
)
COUNTY OF SUMMIT )
NOW, BEFORE ME, the undersigned authority, personally came and appeared,
H. Peter Burg, who, after being duly sworn by me, did depose and say:
That he is Chairman and Chief Executive Officer of FirstEnergy Corp.; that
he has the authority to verify the foregoing Application on behalf of
FirstEnergy Corp.; that he has read said Application and knows the contents
thereof; and that all of the statements contained in said Application are true
and correct to the best of his knowledge and belief.
/s/ H. Peter Burg
--------------------------------
H. Peter Burg
Chairman and Chief Executive Officer
FirstEnergy Corp.
SUBSCRIBED AND SWORN TO before me this 9th day of November, 2000
/s/ Michael R. Beiting
--------------------------------- [NOTARY SEAL]
Michael R. Beiting MICHAEL R. BEITING, Attorney at Law
Notary Public Notary Public -- State of Ohio
My Commission has no expiration date.
My Commission has no expiration date Section 147.03 R.C.
County of Residency: Summit
<PAGE> 145
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Ohio Edison Company, )
The Cleveland Electric Illuminating )
Company. The Toledo Edison Company, )
Pennsylvania Power Company, American )
Transmission Systems, Inc. and their public )
utility affiliates )
)
and ) Docket No. EC01-__-000
)
Jersey Central Power & Light Company, )
Metropolitan Edison Company, Pennsylvania )
Electric Company and their public )
utility affiliates )
VERIFICATION
TERRANCE HOWSON, being duly sworn upon oath, states that he is VICE
PRESIDENT, & Treasurer and has read the attached APPLICATION; that he knows the
contents thereof; that the statements made therein with respect to Jersey
Central Power & Light Company, Metropolitan Edison Company, Pennsylvania
Electric Company and their public utility affiliates are true and correct to
the best of his knowledge, information and belief; and that he has full power
and authority to sign this document on behalf of Jersey Central Power & Light
Company, Metropolitan Edison Company, Pennsylvania Electric Company and their
public utility affiliates
/s/ Terrance G. Howson
-----------------------------------
Name: Terrance G. Howson
Title: Vice President and Treasurer
Subscribed and sworn to before me this 2nd day of Nov., 2000
/s/ Barbara E. Jost
-------------------
Notary Public
[NOTARY SEAL]
My commission expires Barbara E. Jost
Notary Public of New Jersey
My Commission Expires August 12, 2004
<PAGE> 146
NOTICE OF FILING
<PAGE> 147
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Ohio Edison Company, )
The Cleveland Electric Illuminating )
Company, The Toledo Edison Company, ) Docket No. EC01-__-000
Pennsylvania Power Company, American )
Transmission Systems, Inc. and their public )
utility affiliates )
)
and )
)
Jersey Central Power & Light Company, )
Metropolitan Edison Company, Pennsylvania )
Electric Company and their public
utility affiliates )
NOTICE OF FILING
( )
Take notice that on November 9, 2000 Ohio Edison Company ("OE"), The
Cleveland Electric Illuminating Company ("CEI"), The Toledo Edison Company
("TE"), Pennsylvania Power Company ("PP"), American Transmission Systems, Inc.
("ATSI"), and their public utility affiliates (the "FirstEnergy Companies") and
Jersey Central Power & Light Company ("JCP&L"), Metropolitan Edison Company
("MetEd"), and Pennsylvania Electric Company ("Penelec"), and their public
utility affiliates (the "GPU Companies") (collectively, "Applicants"), tendered
for filing an application pursuant to Section 203 of the Federal Power Act and
Part 33 of the Commission's regulations, 18 C.F.R. Part 33 (2000), for an order
approving the proposed merger of the FirstEnergy Companies and the GPU Companies
("Application").
Applicants request all authorizations necessary to undertake the
proposed merger. Upon consummation of the merger, Applicants will form a
registered utility holding company system.
Applicants request that the Commission approve the merger on an
expedited basis and without an evidentiary hearing. Applicants state that they
have, by overnight mail, served a copy of the Application on the Ohio Public
Utility Commission, the Pennsylvania Public Utility Commission, the New Jersey
Board of Public Utilities and on all other interested entities.
Any person desiring to be heard or to protest said filing should file
a motion to intervene or protest with the Federal Energy Regulatory Commission,
888 First Street, N.E., Washington, D.C. 20426, in accordance with Rules 211
and 214 of the Commission's Rules of Practice and Procedure, 18 C.F.R. Sections
385.211 and 385.214 (2000). All such motions or protests should be
<PAGE> 148
2
filed on or before December __, 2000. Protests will be considered by the
Commission in determining the appropriate action to be taken, but will not
serve to make protestants parties to the proceeding. Any person wishing to
become a party must file a motion to intervene. Copies of this filing are on
file with the Commission and are available for public inspection. This filing
may also be viewed on the Internet at http://www.ferc.fed.us/online/rims/htm
(call 202-208-2222 for assistance).
David P. Boergers
Secretary
<PAGE> 149
TESTIMONY AND EXHIBITS
<PAGE> 150
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Ohio Edison Company, )
The Cleveland Electric Illuminating Company, )
The Toledo Edison Company, Pennsylvania )
Power Company, American Transmission ) Docket No. EC01- -000
Systems, Inc. and their public utility affiliates )
)
and )
)
Jersey Central Power & Light Company, )
Metropolitan Edison Company, )
Pennsylvania Electric Company and their )
public utility affiliates )
PREPARED DIRECT
TESTIMONY AND EXHIBITS OF
ANTHONY J. ALEXANDER
ON BEHALF OF APPLICANTS
<PAGE> 151
EXHIBIT NO. APP-100
PAGE 1 OF 16
Q. PLEASE STATE YOUR NAME, BUSINESS ADDRESS, AND TITLE.
A. Anthony J. Alexander. My business address is 76 South Main Street, Akron,
Ohio 44308. I am the President of FirstEnergy Corp.
Q. PLEASE DESCRIBE YOUR RECENT EMPLOYMENT HISTORY AND CURRENT RESPONSIBILITIES.
A. I was named Senior Vice president and General Counsel in 1991, and Executive
Vice President and General Counsel in 1997 of Ohio Edison Company. When
FirstEnergy was formed in November 1997, I was named Executive Vice
President and General Counsel of FirstEnergy and each of its utility
operating companies. I was named President of FirstEnergy Corp. effective
February 1, 2000. My responsibilities have included communications, legal,
governmental affairs, sales and marketing, business development, power
trading and wholesale transactions, and for a short period distribution
operations. I also have responsibility over our Heating, Ventilation, and
Air Conditioning (HVAC) and natural gas businesses.
Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
A. The purpose of my testimony is to provide the Federal Energy Regulatory
Commission ("Commission" or "FERC") with an overview of, and relevant
background concerning, the proposed merger involving Ohio Edison Company
("OE"), The Cleveland Electric Illuminating Company ("CEI"), The Toledo
Edison Company ("TE"), Pennsylvania Power Company ("PP"), and American
Transmission Systems, Inc. ("ATSI") on the one hand (hereinafter, the
"FirstEnergy Companies"), and Jersey Central Power & Light Company
("JCP&L"), Metropolitan Edison Company ("MetEd"), and Pennsylvania
<PAGE> 152
EXHIBIT NO. APP-100
PAGE 2 OF 16
Electric Company ("Penelec") on the other. The FirstEnergy Companies are
wholly-owned direct or indirect subsidiaries of FirstEnergy Corp., an exempt
public utility holding company. JCP&L, MetEd and Penelec are wholly-owned
direct or indirect subsidiaries of GPU, Inc., a registered public utility
holding company. I refer to the public utility subsidiaries of GPU, Inc.
(i.e., JCP&L, MetEd and Penelec) collectively as GPU Energy. For brevity,
I will not repeat all the information that is included in the application.
Q. PLEASE DESCRIBE THE FIRSTENERGY COMPANIES.
A. FirstEnergy Corp. was formed when the merger of OE and Centerior Energy
Corporation, which owned CEI and TE, became effective on November 8, 1997.
FirstEnergy Corp. is a diversified energy services holding company organized
and existing under the laws of the state of Ohio. FirstEnergy Corp. is
headquartered in Akron, Ohio. FirstEnergy's regulated public utility
subsidiaries include OE, CEI, TE, PP, ATSI and FirstEnergy Trading Services,
Inc. ("FETS"). An application is pending before the Commission in Docket No.
EC01-3-000 seeking authorization to merge FETS into FirstEnergy Services
Corp. ("FirstEnergy Services"), an affiliate currently providing retail gas
and electricity service in several states. FirstEnergy Corp. also wholly
owns other businesses including a regulated gas business and a number of
mechanical contractors located throughout the northeastern United States.
These enterprises collectively employ about 3,500 people. FirstEnergy also
owns 50% of a business engaged in gas exploration and production operations,
and pipeline operations.
<PAGE> 153
EXHIBIT NO. APP-100
PAGE 3 OF 16
OE, TE, CEI and PP provide regulated retail electric service to 2.2 million
customers within 13,200 square miles stretching from northern and central
Ohio into western Pennsylvania. OE, TE, CEI, PP and FETS are authorized to
sell wholesale power at market-based rates. Effective September 1, 2000, OE,
TE, CEI and PP transferred their high voltage transmission facilities to
ATSI. Thus, OE, TE, CEI and PP no longer provide transmission service in
interstate commerce, Those services are provided by ATSI under ATSI's open
access transmission service tariff on file with the Commission. OE, CEI and
TE are regulated by the Public Utilities Commission of Ohio ("PUCO"), and PP
is regulated by the Pennsylvania Public Utility Commission ("PPUC"). Ohio
and Pennsylvania have both restructured their electric utility markets to
permit retail competition. Effective January 1, 2001, retail customers in
Ohio will be entitled to select their own generation suppliers. In
Pennsylvania, retail choice for generation supply has been available in PP's
service area since January 1, 1999. In addition, FirstEnergy Services
competes for retail electric customers in other states, including New
Jersey, Maryland, Pennsylvania and Delaware. By the end of 1999, FirstEnergy
Services was already serving more than 20,000 new electric accounts,
including 800 federal governmental facilities in New Jersey, such as the
Statue of Liberty and Ellis Island.
Q. PLEASE DESCRIBE THE FIRSTENERGY COMPANIES' ELECTRIC GENERATING UNITS.
A. OE, TE, CEI and PP currently own and operate 16 power plants, which consist
of a mix of fossil and combustion turbine generators and nuclear generators,
with a total capacity
<PAGE> 154
EXHIBIT NO. APP-100
PAGE 4 OF 16
of approximately 12,500 MW. Approximately 30 percent of the capacity is
nuclear, and 40 percent of the energy generated by the system is from our
nuclear units. FirstEnergy is in the process of increasing the amount of its
capacity from 12,500 MW to approximately 13,000 MW by upgrading the Perry
station from 1248 MW to 1265 MW and installing up to 425 MW of capacity at
West Lorain. Attached as Exhibit No. APP-101 is a listing of the net
installed electric generating capacity of each of these plants. We also plan
to add another 340 MW of peaking capacity by the end of 2002.
Q. DO THE FIRSTENERGY COMPANIES CONTROL THE POTENTIAL SITES FOR NEW GENERATION
IN OHIO?
A. No. Several other large utility systems, including the AEP System, have
generating units located at numerous sites in Ohio. Additionally, merchant
plant developers are not finding it difficult to locate new generating
projects in Ohio. There are presently at least sixteen applications pending
before the Ohio Power Siting Board for new generation facilities in Ohio
between now and 2003 that are unaffiliated with the Applicants. These
proposed new generation facilities represent over 10,000 MW of capacity.
Also. a subsidiary of CME Energy announced plans to construct a new 2,200 MW
natural gas fired merchant plant in Lawrence County, Ohio. Although CME has
yet to file an application with either the Ohio Power Siting Board or the
state's environmental protection agency, CME indicated that it holds an
option to purchase 280 acres for the plant site and is in the process of
drafting the required state applications.
Q. DOES FIRSTENERGY CONTROL FUEL SUPPLIES OR TRANSPORTATION FACILITIES?
<PAGE> 155
EXHIBIT NO. APP-100
PAGE 5 OF 16
A. No. FirstEnergy does not own any coal mines or coal transportation
facilities, and it procures its coal supplies under a mix of long-term and
short-term spot purchase contracts from unaffiliated coal producers.
FirstEnergy indirectly owns gas reserves and production, intrastate
pipelines, and a small interstate pipeline through its subsidiary, Marbel
Energy Corporation ("Marbel"). Marbel owns a small LDC in Ohio (Northeast
Ohio Natural Gas Corp.) and Marbel HoldCo, Inc. ("HoldCo"). HoldCo and Range
Resources Corporation of Fort Worth, Texas are each fifty-percent owners of
Great Lakes Energy Partners, L.L.C. ("Great Lakes"), a joint venture between
HoldCo and Range Resources. Great Lakes owns gas reserves and production in
the Appalachian Basin. Great Lakes also owns an intrastate pipeline (Ohio
Intrastate Gas Transmission Co.) and an interstate pipeline (Gas Transport,
Inc.). The intrastate pipeline facilities are located in northeast Ohio. The
interstate pipeline, which has a tariff on file with the Commission, is an
approximately 100 mile pipeline running between Columbia Gas Transmission
Company in West Virginia and Washington County, Ohio. Columbia Gas, Tenneco,
Texas Eastern, CNG, and National Fuel dominate the interstate pipeline
system in the Appalachian Basin and numerous other parties own gas
production facilities in the region. In addition Gas Transport, Inc., Ohio
Intrastate Gas Transmission Co., and Northeast Ohio Natural Gas Corp., are
subject to open access service requirements. Mr. Frame explains that
FirstEnergy's interests in these natural gas production and transportation
facilities do not give it the ability to block those that might compete with
FirstEnergy in the development of new electric generation.
Q. PLEASE DESCRIBE FIRSTENERGY'S TRANSMISSION SYSTEM.
<PAGE> 156
EXHIBIT NO. APP-100
PAGE 6 OF 16
A. ATSI owns approximately 7,100 circuit miles of transmission lines of 69 kV
or above and 120 substations: 1,153 miles of 345 kV lines; 3,667 miles of
138 kV lines; and 2,279 of 69 kV lines. ATSI now provides open access
transmission service over its transmission facilities under a tariff on file
with the FERC. OE, CEI, TE and PP receive network integration service from
ATSI under the same terms and conditions that are available to all
non-affiliated network customers. ATSI has 37 interconnections with six
other electric systems, including an interconnection with PJM through
Penelec at the Ohio-Pennsylvania border. This interconnection with Penelec
is a 345 kV line, known as the Ashtabula-Erie West tie line, and crosses the
Ohio and Pennsylvania border. It is approximately 14.9 miles in length and
has a summer rating of 1643 MVA and a winter rating of 1781 MVA. OE, TE,
CEI, and PP also own approximately 57,000 miles of distribution facilities.
The FirstEnergy Companies have been active participants in the formation of
the Alliance Regional Transmission Organization ("Alliance"), which is
described in the Application and which is the subject of other proceedings
before the Commission. FirstEnergy plans to satisfy the Commission's Order
No.2000 requirements through participation in the Alliance.
Q. PLEASE EXPLAIN WHY FIRSTENERGY AND GPU HAVE DECIDED TO MERGE.
A. The merger represents a natural alliance of companies with adjoining service
areas and interconnected transmission systems and is a key strategic step in
preparing FirstEnergy to be a premier energy services provider in states
that have mandated industry
<PAGE> 157
EXHIBIT NO. APP-100
PAGE 7 OF 16
restructuring and retail customer choice, including Ohio, Pennsylvania and
New Jersey. The advent of retail competition introduces significant new
risks and challenges to companies that were until recently service providers
in franchised areas. The merger is intended in large part to enhance the
Applicants' combined abilities to meet these challenges. Following the
merger, FirstEnergy will serve approximately 2 million customers in Ohio,
1.3 million customers in Pennsylvania, and slightly less than 1 million
customers in New Jersey. The combined service territories will be more
diverse than the individual service territories, reducing exposure to
adverse changes in any sector's economic and competitive conditions.
Q. PLEASE SUMMARIZE THE STATUS OF RETAIL ELECTRIC COMPETITION IN OHIO AND
PENNSYLVANIA.
A. In July 1999, the Ohio General Assembly enacted Senate Bill 3, which
requires customer choice effective January 1, 2001. In late 1999, OE, TE,
and CEI filed retail transition plans with the PUCO as required by Senate
Bill 3. In April 2000, the parties to those PUCO proceedings agreed to a
Stipulation under which OE, TE, and CEI would implement open access
consistent with Senate Bill 3. PUCO approved the Stipulation on July 19,
2000. Beginning January 1, 2001, OE, TE and CEI will provide retail utility
service on an unbundled basis and retail customers will have an opportunity
to choose among energy suppliers. Also effective January 1, 2001, OE, TE and
CEI will freeze their base distribution electric rates through December 31,
2007 and will also lower their unbundled
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residential tariff rates during a five-year market development period. To
ensure the development of a competitive power market, from January 1, 2001
through December 31, 2005, OE, TE, and CEI collectively will make 1,120 MW
of power available exclusively for marketers and aggregators to sell to the
Companies' retail customers. In addition, OE, TE and CEI will reimburse
marketers for certain transmission costs, which will further broaden the
market. Further, the Stipulation requires each Company to actively work with
the Alliance, the MISO, and other RTO/ISOs and transmission-level customers
in the region to develop and implement proposals to address reciprocity and
RTO interface/seams issues. The Stipulation also includes "shopping credits"
to provide retail customers with an incentive to obtain their power supplies
from alternative sources. Senate Bill 3 envisions that at least 20 percent
of each company's retail customers will obtain their power supplies from
alternative providers. Failure to achieve the 20 per cent threshold level
will limit the Companies' recovery of their transition costs. The
Stipulation also shortens the period in which the OE, TE and CEI may recover
transition costs to December 31, 2006 for OE, June 30, 2007 for TE, and
December 31, 2008 for CEI, although these dates are subject to modification
in limited circumstances. In December of 1996, the Pennsylvania legislature
passed the Electricity Generation, Customer Choice and Competition Act to
deregulate the electric industry in Pennsylvania. The Act requires the
unbundling of electric services into separate generation, transmission, and
distribution services, with open retail competition for generation services.
Mr. Bruce Levy, Senior Vice President of GPU, Inc. describes the
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Pennsylvania restructuring program in more detail. Exhibit No. APP-200 at 8.
In sum, the Competition Act required utilities to submit restructuring plans
with the PPUC that included an assessment of stranded costs resulting from
retail competition. In September 1997, PP filed a comprehensive
restructuring plan with the PPUC. In June 1998, the PPUC accepted PP's plan.
Under PP's restructuring plan, PP's retail customers are protected from an
increase in generation rates until January 1, 2006. On that date, the
generation rate will increase by five percent and will remain in effect
until January 1, 2007. At that point, PP's retail customers will no longer
be subject to a generation rate cap.
Q. PLEASE DESCRIBE THE MERGER TRANSACTION,
A. Under the Agreement and Plan of Merger, dated August 8, 2000, CPU, Inc. will
be merged with and into FirstEnergy Corp., which will be the surviving
corporation. Under the Merger Agreement, holders of GPU common stock will be
able to choose to receive (i) $36.50 in cash for each share of GPU common
stock, or (ii) FirstEnergy common stock, the amount to be determined by an
exchange ratio set forth in the Merger Agreement. Under the Merger
Agreement, however, unless an adjustment is made as a result of tax
considerations, 50 percent of all issued and outstanding shares of GPU
common stock must be exchanged for cash and 50 percent must be exchanged for
FirstEnergy common stock. The elections of GPU shareholders to receive cash
or FirstEnergy common stock are subject to proration because of this
provision and also because of a possible adjustment controlled by tax
considerations. The merger will be
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accounted for on a "purchase" accounting basis in accordance with generally
accepted accounting principles.
Q. PLEASE DESCRIBE THE STRUCTURE OF THE MERGED COMPANY.
A. Upon closing of the merger, the GPU Companies will become wholly owned
subsidiaries of FirstEnergy Corp. JCP&L, MetEd, and Penelec will continue to
operate as separate electric utility operating companies as will OE, CEI, TE
and PP. ATSI also will remain a separate subsidiary company of FirstEnergy
Corp. With respect to distribution operations, the FirstEnergy utilities
will continue to provide service to customers in their respective service
territories. Our headquarters will remain in Akron, Ohio. We will maintain
offices and presence in Morristown, New Jersey and Reading, Pennsylvania,
subject to the authority of the Board of Directors. Attached as Exhibit No.
APP-102 is an organizational chart reflecting the anticipated corporate
structure of the merged company.
Q. ARE THE APPLICANTS MAKING ANY COMMITMENTS TO FACILITATE APPROVAL OF THE
MERGER BY THE COMMISSION?
A. Yes. I note that these commitments are also described in Section III.B of
the Application. The commitments are offered in support of the merger's
prompt approval by the Commission without an evidentiary hearing. As to
competition and rates, our commitments are: (1) In the event that the
Alliance fails to be approved by the Commission, ATSI commits to file an
application for approval to participate in another RTO that complies with
the RTO Final Rule.
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(2) The Applicants will hold any and all wholesale requirements customers
harmless from any merger-related costs in excess of merger savings. (3) ATSI
and GPU Energy will hold any and all transmission customers harmless from
any merger-related costs in excess of merger savings. (4) The FirstEnergy
Companies will not seek to assert native load preference into PJM as a means
to preempt transmission capacity reserved by others. As to regulation, the
Applicants waive their OHIO POWER immunity as I explain later in my
testimony. These commitments have no adverse impact on the merger
commitments the FirstEnergy Companies have agreed to in prior FERC merger
proceedings.
Q. IS THE MERGER CONSISTENT WITH THE COMMISSION'S GOALS OF OPENING WHOLESALE
ELECTRIC MARKETS TO COMPETITION?
A. Yes. FirstEnergy and GPU have been supporting the efforts of the FERC to
introduce competition to the electric industry. The FirstEnergy Companies
are charter members of the Alliance RTO. Likewise, the GPU Companies have
been active members of the PJM Interconnection, L.L.C. The prior divestiture
by GPU Energy of all but 285 MW of installed generating capacity in
combination with the merger significantly advances the Commission's goals
because these actions will result in a stronger, larger, more diverse
utility company, better able to respond to competition in the restructured
utility market, but without raising generation or transmission market power
issues.
Q. DO THE FIRSTENERGY COMPANIES PLAN TO SELL POWER TO GPU ENERGY AFTER THE
MERGER CLOSES TO SERVE ITS LOAD REQUIREMENTS?
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A. While our plans have not been finalized, it may make economic sense and be
possible for us to sell energy to GPU Energy (Penelec, JCP&L and MedEd)
during certain off-peak periods. Only off-peak sales are envisioned because
FirstEnergy has no capacity to sell on-peak, and even if it did, has no firm
transmission reserved to PJM. As I mentioned previously, following
completion of the merger, FirstEnergy will compete for firm transmission
service into PJM on the same basis as other transmission customers, and will
not seek to invoke native load obligations as a means to preempt
transmission capacity reserved by other transmission customers. In
calculating the competitive effect of the proposed merger, we have asked Mr.
Frame to analyze scenarios in which no energy sales are made, and in which
off-peak energy sales equivalent to 650 MW during off-peak hours will be
made to serve GPU Energy's loads.
Q. PLEASE DESCRIBE HOW THE FIRSTENERGY COMPANIES PLAN TO SATISFY THE
REQUIREMENTS OF THE FERC'S RTO FINAL RULE.
A. As I have mentioned, OE, CEI, TE and PP have already transferred the
ownership of their high-voltage transmission facilities to ATSI. ATSI has
committed to join the Alliance RTO. On December 20, 1999, the Alliance
companies received conditional approval from the Commission to transfer
ownership and/or functional control of their jurisdictional transmission
facilities to the Alliance RTO subject to acceptance of a later compliance
filing. The Alliance companies made a compliance filing on September 15,
2000 to address issues identified by the Commission in its previous orders
on the Alliance RTO. The Alliance plans to become an RTO that will achieve
full compliance with the RTO Final Rule.
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Q. ARE THE FIRSTENERGY COMPANIES PLANNING TO RESTRUCTURE THEIR INTERNAL
OPERATIONS?
A. Yes. Senate Bill 3 requires the FirstEnergy Companies to restructure their
operations in Ohio into separate business units. In Pennsylvania, the
Competition Act also requires a restructuring of PP's operations. Effective
January 1, 2001, the FirstEnergy Companies in Ohio will separate their
corporate structures into three units: a Competitive Services Unit, a
Corporate Support Services Unit, and a Utility Services Unit. The
Competitive Services Unit will hold the companies' generation facilities and
all other competitive assets. The Corporate Support Services Unit will
provide centralized and common services to the other units, such as
accounting, legal, auditing, finance, and human resources. The Utility
Services Unit will hold the transmission and distribution facilities. To
avoid incurring additional transition costs, the FirstEnergy Ohio Companies
are allowed to transfer their generating assets to the Competitive Services
Unit on a phased basis. This internal restructuring will be the subject of
separate FERC filings to the extent FERC authorization is required.
Q. WILL FIRSTENERGY CORP. BECOME A REGISTERED HOLDING COMPANY?
A. Yes. FirstEnergy Corp. will become a registered holding company system under
the Public Utility Holding Company Act, which is enforced by the Securities
and Exchange Commission ("SEC").
Q. ARE YOU AWARE OF THE OHIO POWER DOCTRINE AND THE FERC'S MERGER POLICY
WITH RESPECT TO THE PRICING OF NON-POWER
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GOODS AND SERVICES AMONG AFFILIATES OF A REGISTERED PUBLIC UTILITY HOLDING
COMPANY?
A. Yes. As to registered holding company systems, the SEC has jurisdiction over
non-power intra-affiliate transactions and contracts. Under the OHIO POWER
doctrine, in certain instances as to registered holding company systems,
FERC cannot disallow the recovery in FERC-jurisdictional rates of any
payments made in accordance with SEC-approved transactions.
Q. AS A CONDITION OF APPROVAL OF THE MERGER, WILL THE APPLICANTS WAIVE THEIR
OHIO POWER IMMUNITY?
A. Yes. For rate making purposes, the Applicants agree to follow FERC policy
regarding sales of non-power goods and services under contracts between
public utility affiliates in a holding company system. The Applicants hereby
waive their OHIO POWER immunity.
Q. DO THE FIRSTENERGY COMPANIES HAVE ANY RATEPAYERS ENTITLED TO PROTECTION
UNDER THE COMMISSION'S MERGER POLICY STATEMENT?
A. Yes. We have contracts to provide a small amount of firm power at cost-based
rates to a number of municipals and cooperatives in Ohio and to five
boroughs in Pennsylvania. ATSI also provides transmission service to these
entities. I note also that Mr. Bruce Levy, Senior Vice President of GPU.
Inc., will address the two customers that GPU Energy has that are protected
customers under FERC's merger policy.
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EXHIBIT NO. APP-100
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Q. WILL THE FIRSTENERGY COMPANIES HOLD THESE CUSTOMERS HARMLESS FROM ANY
MERGER-RELATED COST INCREASES?
A. Yes. We will hold these customers harmless from any merger-related costs in
excess of merger savings, and CPU Energy, as discussed by Mr. Levy, will do
the same for its two protected customers. I would note that under the
largest wholesale sales agreement that we have, a contact between TE and
AMP- OHIO, we have no ability to file for an increase in cost-based rates.
Also, the contract is subject to a rate cap for both the base and fuel
components of the rate until the end of 2005, at which time base rates are
further reduced.
Q. WHAT ABOUT ATSI'S TRANSMISSION CUSTOMERS?
A. Some of ATSI's transmission dependent customers take service under pre-Order
No. 888 grandfathered transmission arrangements. These customers have the
right to remain under their grandfathered arrangements in lieu of switching
to service under ATSI's open access tariff. Approval of this merger will not
affect those arrangements. Such customers will continue to pay the same
rates, and have the same rights and obligations, as provided in their
grandfathered transmission arrangements. In addition, there are many
transmission customers under ATSI's OATT who do not have pre-Order No. 888
transmission rights. The costs underlying ATSI's transmission revenue
requirement are unlikely to change materially, if they change at all, as a
result of the merger. ATSI commits, however, that it will not seek to
include in its
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transmission revenue requirement under its OATT any merger-related
transmission costs in excess of merger savings. When the RTO of which ATSI
will be a member implements its OATT, ATSI will extend this commitment to
preclude the inclusion of merger-related costs in excess of merger savings
from ATSI's revenue requirement in the computation of the RTO's rates. This
will ensure that all of ATSI's transmission customers under both ATSI's
OATT, and when effective, the RTO's OATT, are held harmless with respect to
any adverse cost effects attributable to the merger.
Q DOES THIS CONCLUDE YOUR TESTIMONY?
A. Yes.
<PAGE> 167
AFFIDAVIT
STATE OF OHIO )
)
COUNTY OF SUMMIT )
Anthony J. Alexander, being duly sworn, deposes and states: that he
prepared the Direct Testimony and Exhibits of Anthony J. Alexander and that the
statements contained therein and the Exhibits attached hereto are true and
correct to the best of his knowledge and belief.
/s/ Anthony J. Alexander
-----------------------------------
Anthony J. Alexander
President, FirstEnergy Corp.
SUBSCRIBED AND SWORN TO BEFORE ME, this the 9th day of November, 2000.
/s/ Michael R. Beiting
-----------------------------------
Notary Public, State of
Printed Name: Michael R. Beiting
My Commission has no expiration date
[Notary Seal]
MICHAEL R. BEITING, Attorney at Law
Notary Public -- State of Ohio
My Commission has no expiration date.
Section 147.03 R.C.
<PAGE> 168
EXHIBIT NO. APP-101
<PAGE> 169
FIRSTENERGY GENERATING UNIT NDC AND PRIMARY FUEL
YEAR IN- NDC PRIMARY
PLANT NAME UNIT # SERVICE (MW) FUEL
---------- ------ ------- ---- ------------
ASHTABULA 7 1953 44 Coal
ASHTABULA 8 1953 44 Coal
ASHTABULA 9 1953 44 Coal
ASHTABULA 5 1958 244 Coal
ASHTABULA TOTAL 376
BAY SHORE 1 1955 136 Steam
BAY SHORE 2 1959 138 Coal
BAY SHORE 3 1963 142 Coal
BAY SHORE 4 1968 215 Coal
BAY SHORE CT 1967 17 #2 Oil
BAY SHORE TOTAL 648
BEAVER VALLEY 1 1976 810 Uranium
BEAVER VALLEY 2 1987 820 Uranium
BEAVER VALLEY TOTAL 1630
R.E. BURGER 3 1950 94 Coal
R.E. BURGER 4 1955 156 Coal
R.E. BURGER 5 1955 156 Coal
R.E. BURGER EMD (3) 1972 7 #2 Oil
R.E. BURGER TOTAL 413
DAVIS-BESSE 1 1977 883 Uranium
DAVIS-BESSE TOTAL 883
EASTLAKE 1 1953 132 Coal
EASTLAKE 2 1953 132 Coal
EASTLAKE 3 1954 132 Coal
EASTLAKE 4 1956 240 Coal
EASTLAKE 5 1972 597 Coal
EASTLAKE CT 1973 29 #2 Oil
EASTLAKE TOTAL 1262
EDGEWATER 4 1957 100 Gas
EDGEWATER CT (2) 1973 48 #2 Oil
EDGEWATER TOTAL 148
LAKESHORE 18 1962 245 Coal
LAKESHORE EMD (2) 1966 4 #2 Oil
LAKESHORE TOTAL 249
MAD RIVER CT (2) 1972 60 #2 Oil
MAD RIVER TOTAL 60
MANSFIELD 1 1976 780 Coal
MANSFIELD 2 1977 780 Coal
MANSFIELD 3 1980 800 Coal
MANSFIELD TOTAL 2360
*1 PERRY 1 1987 1265 Uranium
PERRY TOTAL 1265
RICHLAND CT (3) 1967 42 Oil/Gas
RICHLAND 4 2000 130 Gas
RICHLAND 5 2000 130 Gas
RICHLAND 6 2000 130 Gas
RICHLAND TOTAL 432
SAMMIS 1 1959 180 Coal
SAMMIS 2 1960 180 Coal
SAMMIS 3 1961 180 Coal
SAMMIS 4 1962 180 Coal
SAMMIS 5 1967 300 Coal
SAMMIS 6 1969 600 Coal
SAMMIS 7 1971 600 Coal
SAMMIS EMD (5) 1972 13 #2 Oil
SAMMIS TOTAL 2233
STRYKER CT 1968 18 #2 Oil
STRYKER TOTAL 18
WEST LORAIN CT (2) 1973 120 #2 Oil
*2 WEST LORAIN 2 2001 85 #2 Oil
*2 WEST LORAIN 3 2001 85 #2 Oil
*2 WEST LORAIN 4 2001 85 #2 Oil
*2 WEST LORAIN 5 2001 85 #2 Oil
*2 WEST LORAIN 6 2001 85 #2 Oil
WEST LORAIN TOTAL 545
SENECA 1 1970 210 Hydro
SENECA 2 1970 195 Hydro
SENECA 3 1970 30 Hydro
SENECA TOTAL 435
FIRSTENERGY TOTAL 12957
*1 Reflects uprating from 1248 to 1265 mw expected to occur around March
2001.
*2 Reflects units expected to be added by 2001.
<PAGE> 170
EXHIBIT NO. APP-102
<PAGE> 171
[FIRST ENERGY LOGO]
Combined
FirstEnergy/GPU
Organization
Overview
<TABLE>
<CAPTION>
<S> <C> <C> <C>
FIRSTENERGY ORGANIZATION
FirstEnergy Corp.
(FE)
|
_______________________________________________________________________________________|_________________|
| |
| __________________________________________________|
| | |
| - Ohio Edison Company ATSI FirstEnergy Services
| | (American Transmission Systems) |
| | |
| | |
| | _________________________|_______________________
| - Pennsylvania Power Company | |
| | |
| |-- PennPower Energy GPU Capital
| | (International Investments)
| |
| |
| |
| - Cleveland Electric Illuminating |
| |-- FirstEnergy Generation Corp.
| Company |
| |
| |
| - Toledo Edison Company |
| |
| |-- GPU International
| |
| - Jersey Central Power & Light |
| |
| |-- GPU Power
|
| - Metropolitan Edison
|
|
|
| - Pennsylvania Electric
</TABLE>
[CHART TO CONTINUE BELOW]
<TABLE>
<CAPTION>
<S> <C> <C> <C>
FIRSTENERGY ORGANIZATION
FirstEnergy Corp.
(FE)
|
_____________________________________________________________________|__________
| |
|______________________________________ |
| | |
FENOC FE Ventures |-- FirstEnergy Facilities
(FirstEnergy Nuclear | Services Group
Operating Company) |
|
|-- Marbel Energy Corp.
|
|
|
|
|
|-- MYR Group
|
|
|
|
|
|-- GPU Service, Inc.
</TABLE>
<PAGE> 172
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Ohio Edison Company, )
The Cleveland Electric Illuminating Company, )
The Toledo Edison Company, Pennsylvania )
Power Company, American Transmission )
Systems, Inc. and their public utility affiliates )
)
and ) Docket No. EC01- -000
)
Jersey Central Power & Light Company, )
Metropolitan Edison Company, )
Pennsylvania Electric Company and their )
public utility affiliates )
PREPARED DIRECT TESTIMONY
OF BRUCE L. LEVY
ON BEHALF OF APPLICANTS
<PAGE> 173
EXHIBIT NO. APP-200
PAGE 1 OF 11
QUALIFICATIONS AND EMPLOYMENT HISTORY
Q. WILL YOU PLEASE STATE YOUR NAME AND BUSINESS ADDRESS?
A. My name is Bruce L. Levy. My business address is GPU, Inc., 300 Madison
Avenue, Morristown, New Jersey 07962-1911.
Q. BY WHOM ARE YOU EMPLOYED AND WHAT IS YOUR PRESENT POSITION?
A. I am senior vice president and chief financial officer of GPU, Inc.,
headquartered in Morristown, New Jersey. In this capacity, I have executive
financial oversight for GPU, Inc. and its subsidiary companies. I am also
responsible for all domestic and international merger, acquisition and
strategic development activities.
Q. PLEASE PROVIDE YOUR EDUCATION, PROFESSIONAL QUALIFICATIONS AND EXPERIENCE.
A. I was promoted into my current post in 1998 from my previous position as GPU
International Group president and chief executive officer and served in that
capacity since 1991. I also served as president of GPU Advanced Resources,
GPU, Inc.'s non-regulated retail energy subsidiary. I joined GPU, Inc. in
1985 as vice president-business development of the Energy Initiatives
subsidiary. I am past president of the Electric Power Supply Association, a
national trade association representing competitive power suppliers active
in national and international power markets. Prior to joining the GPU
system, I held various positions at Stone & Webster Engineering Corporation
with
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responsibility for the design, engineering and construction of utility and
industrial power generation facilities. I earned a Bachelor of Engineering
Degree from City College of New York and an MBA in finance from New York
University.
PURPOSE OF DIRECT TESTIMONY
Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY?
A. The purpose of my direct testimony is to support the Section 203 Application
filed jointly by FirstEnergy Corp. and GPU, Inc. in this proceeding. The
Section 203 Application seeks Commission approval for the merger of
FirstEnergy Corp. and GPU, Inc. In particular, my direct testimony
describes: (i) the corporate structure of GPU, Inc. and its public utility
subsidiaries; (ii) the recent divestiture of substantially all of GPU,
Inc.'s generation assets; (iii) the operations of GPU, Inc.'s public utility
subsidiaries; and (iv) the effect of the merger on wholesale rates.
BACKGROUND
Q. PLEASE PROVIDE BACKGROUND TO THE MERGER.
A. On August 8, 2000, FirstEnergy Corp. ("FirstEnergy") and GPU, Inc. announced
the approval of a definitive merger agreement under which FirstEnergy would
acquire all of the outstanding shares of GPU, Inc.'s common stock for
approximately $4.5 billion in cash and FirstEnergy common stock. FirstEnergy
also would assume approximately $7.4 billion of GPU's debt and preferred
stock. Under the agreement, GPU, Inc. shareholders would receive the
equivalent of $36.50 for each share of GPU common stock they own,
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EXHIBIT NO. APP-200
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payable in cash or in FirstEnergy common stock, so long as FirstEnergy's
common stock price is between $24.24 and $29.63. The combination of
FirstEnergy and GPU, Inc. would create the nation's sixth largest
investor-owned electric system, based on customers served. As of June 30,
2000, the combined revenues of FirstEnergy and GPU for the previous 12
months totaled $12.0 billion and assets of the companies totaled $38.6
billion. The combined company's principal electric utility operating
companies would include FirstEnergy's Ohio Edison Company and its
Pennsylvania Power Company subsidiary, The Cleveland Electric Illuminating
Company, Toledo Edison Company, and American Transmission Systems, Inc., as
well as GPU, Inc.'s electric utility operating companies -- Jersey Central
Power & Light Company, Metropolitan Edison Company, and Pennsylvania
Electric Company. Together, these companies serve approximately 4.3 million
customers within 37,200 square miles of Ohio, Pennsylvania, New Jersey and
New York.
STRUCTURE OF GPU, INC.
Q. BRIEFLY DESCRIBE THE STRUCTURE OF GPU, INC.
A. GPU, Inc., headquartered in Morristown, New Jersey, is an electric utility
holding company registered under the Public Utility Holding Company Act of
1935. Among other subsidiaries, GPU, Inc. wholly owns three public utility
subsidiaries -- Jersey Central Power & Light Company ("Jersey Central"),
Metropolitan Edison Company ("MetEd") and Pennsylvania Electric Company
("Penelec") (Jersey Central, MetEd and Penelec do business and are
collectively referred to herein as "GPU Energy."). GPU
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Energy provides retail electric service to residential, industrial, and
commercial consumers in portions of Pennsylvania and New Jersey. Penelec, as
lessee of the property of the Waverly Electric Light & Power Company, also
serves a population of approximately 13,700 in Waverly, New York and
vicinity. It also sells electricity at wholesale and provides access to its
transmission facilities through the regional open access transmission tariff
administered by PJM Interconnection, L.L.C. ("PJM"). The Commission
regulates the wholesale rates and services of the companies, and the
Pennsylvania Public Utility Commission, the New Jersey Board of Public
Utilities and the New York Public Service Commission regulate its retail
rates and services in Pennsylvania, New Jersey and New York, respectively.
GPU, Inc.'s 1999 revenues were $4.8 billion and its total assets were $21.7
billion. GPU, Inc.'s other subsidiaries include MYR Group Inc., GPU Advanced
Resources, Inc., GPU Nuclear, Inc., GPU Service, Inc., GPU Telcom Services,
Inc., GPU Power UK in England, Emdersa in Argentina, GPU International Inc.
and GPU GasNet.
GPU ENERGY'S GENERATION DIVESTITURES
Q. HAS GPU ENERGY DIVESTED ITS GENERATION ASSETS?
A. Yes. Over the past two years, GPU Energy has divested substantially all of
its generating assets through the following transactions:
(i) GPU Energy has sold its interest in the Oyster Creek Nuclear Generating
Facility to AmerGen Energy Company, LLC ("AmerGen"). The Commission
authorized
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EXHIBIT NO. APP-200
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this sale on February 23, 2000. Jersey Central Power & Light Co., et al., 90
FERC (Paragraph) 62,127 (2000);
(ii) GPU Energy has sold its interest in 23 generating facilities to Sithe
Energies, Inc. The Commission authorized this sale on June 30, 1999.
Jersey Central Power & Light Co., et al., 87 FERC (Paragraph) 62,379
(1999); see also Jersey Central Power & Light Co., et al., 88 FERC
(Paragraph) 62,223 (1999);
(iii) GPU Energy has sold its 20% interest in the Seneca Pumped Storage
Hydroelectric Generating Station to The Cleveland Electric
Illuminating Company, a subsidiary of FirstEnergy. The Commission
authorized this sale on June 24, 1999. Cleveland Electric Illuminating
Company, 87 FERC (Paragraph) 62,345 (1999);
(iv) GPU Energy has sold its interest in the Three Mile Island Unit 1
Nuclear Generating Facility to AmerGen. The Commission authorized this
sale on April 2, 1999. Jersey Central Power & Light Co., et al., 87
FERC (Paragraph) 61,014 (1999); and
(v) GPU Energy has sold its 50% interest in the Homer City Generating
Station to Mission Energy Westside, Inc. The Commission authorized this
sale on January 13, 1999. New York State Electric & Gas Corporation, et
al., 86 FERC (Paragraph) 61,020 (1999).
In its orders authorizing these sales, the Commission found that the sales
would not have an adverse effect on competition, rates or regulation. In
fact, as a result of these divestitures, GPU Energy has significantly
decreased its ownership of generation, and consequently its share of the
generation market. And, although GPU Energy has
<PAGE> 178
EXHIBIT NO. APP-200
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maintained ownership of its transmission facilities, access to GPU Energy's
transmission facilities will continue to be provided through the regional
open access transmission tariff administered by PJM. As a result of these
sales, GPU Energy now owns only 285 MW of installed capacity. In addition,
GPU Energy currently is negotiating the sale of its 50% ownership interest
representing approximately 200 MW in the Yards Creek Pumped Storage
Facility.
Q. WHAT IS THE BACKGROUND TO GPU, INC.'S DECISION TO DIVEST?
A. On October 12, 1997, GPU, Inc. announced its intention to begin the process
of divesting its generation assets. The announcement reflected a desire to
concentrate on GPU, Inc.'s core business of delivering electricity to
customers, rather than using resources to expand generation capability
enough to be a successful competitor in the merchant generation business. In
particular, GPU Inc.'s decision to divest was in response to: (a) the
ongoing restructuring of the electric utility industry in the United States,
including recent decisions and orders by the Commission promoting additional
competition at the wholesale level and open access to transmission
facilities; (b) restructuring legislation in Pennsylvania and orders of the
Pennsylvania Public Utility Commission requiring the unbundling of different
utility functions and the transition to full competition at the retail
level; and (c) similar restructuring legislation in New Jersey and orders of
the New Jersey Board of Public Utilities. GPU, Inc.'s divestiture received
widespread support from the parties participating in the retail
restructuring proceedings for GPU Energy in Pennsylvania and New Jersey.
<PAGE> 179
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GPU ENERGY'S OPERATIONS
Q. PLEASE DESCRIBE GPU ENERGY'S CURRENT WHOLESALE OPERATIONS.
A. GPU Energy sells energy and capacity at wholesale under cost-based and
market-based sales tariffs on file with the Commission. In addition, Penelec
has two partial wholesale requirements customers -- Allegheny Electric
Cooperative, Inc. ("AEC") and West Penn Power Company ("West Penn"). Penelec
sells supplemental "power and energy" to AEC under a 1993 agreement. AEC
resells this power and energy to its members, which are retail electric
cooperative corporations located in Pennsylvania and New Jersey. In 1999,
under the 1993 agreement, Penelec supplied approximately 105 MW of AEC's 313
MW total load. Penelec provides service to West Penn under a 1973 service
agreement under Penelec's Tariff No. 1. This service allows West Penn to
meet the requirements of approximately 4 MW of isolated load in Clinton
County, Pennsylvania.
Recently, the Pennsylvania Boroughs of Goldsboro, Lewisberry, Royalton,
Berlin, East Conemaugh, Hooversville, Girard, Smethport and Summerhill
terminated their wholesale requirements service from GPU Energy. Lewisberry
terminated as of May 1, 2000. Goldsboro, Royalton, Berlin, Hooversville,
Girard and Smethport terminated as of June 1, 2000. East Conemaugh and
Summerhill will terminate as of December 1, 2000. Similarly, the New Jersey
Boroughs of Butler, Lavallette, Madison, Pemberton and Seaside Heights
terminated their wholesale requirements service from GPU Energy as of June
1, 1999.
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EXHIBIT NO. APP-200
PAGE 8 OF 11
Q. PLEASE DESCRIBE GPU ENERGY'S RETAIL OPERATIONS AND THE STATUS OF RETAIL
ACCESS IN NEW JERSEY AND PENNSYLVANIA.
A. As noted above, GPU Energy provides retail electric service to residential,
industrial, and commercial consumers in portions of Pennsylvania and New
Jersey. In Pennsylvania, MetEd and Penelec (collectively, the "Companies")
serve about 1.2 million customers. Retail electric competition was launched
in Pennsylvania on January 1, 1997, when the Electricity Generation Customer
Choice and Competition Act, 66 Pa. C.S. 2801 et seq., ("Competition Act")
became effective. Among other things, the Competition Act: (i) directed the
Pennsylvania Public Utility Commission ("PaPUC") to unbundle electric
utility rates into separate charges for generation, transmission and
distribution; (ii) established "caps" on the generation and transmission and
distribution rates electric utilities could charge their customers; and
(iii) permitted electric generation suppliers ("EGS's") to provide electric
generation services to interested customers over a three-year period
commencing January 1, 1999. In accordance with the Competition Act, MetEd
and Penelec filed proceedings in 1997 to "restructure" their rates. On
October 20, 1998, the PaPUC entered an order in Docket Nos. R-00974008 and
R-00974009 which resolved the restructuring proceedings, and approved a
comprehensive settlement ("Restructuring Settlement") among the majority of
the active parties. Under the terms of the Restructuring Settlement, MetEd's
customers received a 2.5% rate reduction effective January 1, 1999 and
Penelec's customers received a 3.0% rate reduction effective January 1,
1999. In addition, the Restructuring Settlement also established an initial
amount of stranded costs to be recovered from customers via a competitive
transition charge through
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EXHIBIT NO. APP-200
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2010. The initial level of stranded costs will be reset based upon the
results of GPU, Inc.'s generation divestiture described above. As of the end
of September 2000, 812 of the Companies' industrial customers, 12,636 of
their commercial customers and 43,544 of their residential customers,
representing 29.1% of the Companies' total electric load, had chosen an EGS
for their electric supply.
In New Jersey, Jersey Central Power & Light Company ("Jersey Central")
serves over 950,000 customers. New Jersey's restructuring legislation - the
Electric Discount and Energy Competition Act ("EDECA"), N.J.S.A. 48:3-49, ET
SEQ. -- became effective on February 9, 1999, and retail competition in New
Jersey commenced on August 1, 1999. Among other things, EDECA mandated that
all electric public utilities within the State allow customers to purchase
energy and capacity from alternative electric suppliers and reduce
distribution rates by up to 10%. EDECA also required that the reduced rates
remain in effect through a four-year "transition" period ending July 31,
2003. On May 24, 1999, the New Jersey Board of Public Utilities ("Board")
approved, with modifications, Jersey Central's Stipulation of Settlement of
its restructuring proceedings (BPU Docket Nos. EO97070458, EO97070459 and
EO97070460). Consistent with the Board's modification and approval of the
Stipulation of Settlement, Jersey Central implemented a 5% rate reduction on
that date. Power began to flow from alternative electric suppliers to
customers within New Jersey on November 14, 1999. On August 1, 2000, Jersey
Central implemented an additional 1% rate reduction. Pursuant to the Board's
modification of the Stipulation of Settlement, Jersey Central will implement
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EXHIBIT NO. APP-200
PAGE 10 OF 11
additional rate reductions of 2% and 3% on August 1, 2001 and August 1,
2002, respectively, resulting in an aggregate 11% rate reduction. This rate
reduction will be sustained until the end of the four-year transition period
on July 31, 2003, when the rate cap for all electric utilities across New
Jersey terminates. As of the end of September 2000, 314 of Jersey Central's
industrial customers, 10,962 of Jersey Central's commercial customers and
9,065 of Jersey Central's residential customers, representing 9.2% of Jersey
Central's load, had chosen an alternative energy supplier.
EFFECT OF THE MERGER ON WHOLESALE RATES
Q. WILL THE MERGER ADVERSELY AFFECT WHOLESALE REQUIREMENTS RATES?
A. No. The merger will have no affect on GPU Energy's wholesale requirements
rates. As noted above, there are only two customers taking wholesale
requirements service from GPU Energy - Allegheny Electric Cooperative, Inc.
and West Penn Power Company. As described in Section III.B of the
Application, in order to ensure that the merger will not adversely affect
these two wholesale customers, GPU Energy will hold them harmless from any
merger-related costs in excess of merger savings.
Q. WILL THE MERGER ADVERSELY AFFECT TRANSMISSION RATES?
A. No. First, the merger will have no affect on GPU Energy's transmission
rates. After the merger, GPU Energy will remain in PJM and will continue to
own its bulk transmission facilities and access to these facilities will
continue to be provided through the regional
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EXHIBIT NO. APP-200
PAGE 11 OF 11
open access transmission tariff administered by PJM. PJM became a fully
functional Independent System Operator on January 1, 1998. Moreover, on
October 12, 2000 in Docket No. RT01-2-000, PJM and the nine PJM transmission
owners jointly filed their Order 2000 Regional Transmission Organization
("RTO") compliance report, seeking Commission certification of PJM as an
RTO. This filing sets forth the few enhancements necessary for PJM to meet
the Commission's requirements for RTOs. Second, as described in Section
III.B of the Application, GPU Energy will hold any and all transmission
customers harmless from any merger-related costs in excess of merger
savings.
Q. THANK YOU. I HAVE NO FURTHER QUESTIONS.
<PAGE> 184
EXHIBIT NO. APP-200
STATE OF NEW JERSEY
Bruce L. Levy, being duly sworn, deposes and says: that he has read the
foregoing questions and answers labeled as his testimony; that if asked the same
questions his answers in response would be as shown; and that the facts
contained in his answers are true to the best of his knowledge, information and
belief.
/s/ Bruce Levy
------------------------------------
Bruce L. Levy
Sworn to and subscribed before me
this 7th day of November, 2000.
Elaine R. Evans
----------------------------
Notary Public
My Commission expires: 7/11/2001
---------
ELAINE R. EVANS
NOTARY PUBLIC OF NEW JERSEY
My Commission Expires July 11, 2001
13
<PAGE> 185
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Ohio Edison Company, }
The Cleveland Electric Illuminating Company, )
The Toledo Edison Company, }
Pennsylvania Power Company, )
American Transmission Systems, Inc. and )
their public utility affiliates ) Docket No. Ec01-___-000
)
)
and )
)
Jersey Central Power & Light Company, )
Metropolitan Edison Company, )
Pennsylvania Electric Company )
and their public utility affiliates )
PREPARED DIRECT
TESTIMONY AND EXHIBITS OF
RODNEY FRAME
ON BEHALF OF APPLICANTS
<PAGE> 186
APPLICANTS EXHIBIT NO. APP-300
PAGE i of 75
TABLE OF CONTENTS
I. INTRODUCTION 1
-- ------------
II. SUMMARY AND CONCLUSIONS 4
--- -----------------------
III. OVERVIEW OF APPLICANTS' RELEVANT BUSINESS ACTIVITIES 15
---- ----------------------------------------------------
IV. APPENDIX A SCREENING ANALYSIS AND RELEVANT
--- ------------------------------------------
GEOGRAPHIC AND PRODUCT MARKETS 18
------------------------------ --
A. Relevant Product Markets 19
-- ------------------------
1. Energy 19
---------
2. Short term capacity 19
----------------------
3. Long term capacity 20
---------------------
4. Ancillary Services 24
---------------------
5. Transmission 29
---------------
6. Retail Electricity 30
---------------------
B. Appendix A Competitive Analysis Screen 30
-- --------------------------------------
C. Destination Markets 34
-- -------------------
V. DATA SOURCES AND ANALYTICAL PROCEDURES 38
-- --------------------------------------
VI. SUMMARY OF SCREENING ANALYSIS RESULTS 65
--- -------------------------------------
VII. VERTICAL MARKET POWER ISSUES 72
---- ----------------------------
VIII. CONCLUSION 75
----- ----------
<PAGE> 187
APPLICANTS EXHIBIT NO. APP-300
PAGE ii of 75
EXHIBITS
Exhibit APP-301: Resume of Rodney Frame
Exhibit APP-302: List of Abbreviations
Exhibit APP-303: Schematic Depiction of Destination Markets
Exhibit APP-304: Applicants' Energy Sales to other Utilities
Exhibit APP-305: System Lambdas
Exhibit APP-306: Base Case Economic Capacity
Exhibit APP-307: Base Case Available Economic Capacity
Exhibit APP-308: Off Peak Flows between ECAR and PJM
Exhibit APP-309: Sensitivity for Firm ATC
Exhibit APP-310: Sensitivity for Gas Price Basis Differential
Exhibit APP-311: Sensitivity for Alliance Transmission Prices
Exhibit APP-312: Sensitivity for Zero Transmission Price
Exhibit APP-313: Sensitivity for Off Peak 650 MW Sale to GPU
Exhibit APP-314: Sensitivity for GPU divesting Yards Creek to PSEG
Exhibit APP-315: Sensitivity for Henry Hub gas price decrease by $1
Exhibit APP-316: Sensitivity for Henry Hub gas price decrease by $2
Exhibit APP-317: Sensitivity to Move Pepco Sale Outside PJM
<PAGE> 188
APPLICANTS EXHIBIT NO. APP-300
Page 1 of 75
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
OHIO EDISON COMPANY, THE CLEVELAND ELECTRIC )
ILLUMINATING COMPANY, )
THE TOLEDO EDISON COMPANY, )
PENNSYLVANIA POWER COMPANY, )
AMERICAN TRANSMISSION SYSTEMS, INC. AND THEIR PUBLIC )
UTILITY AFFILIATES )
AND ) DOCKET NO. EC01-__-000
)
JERSEY CENTRAL POWER & LIGHT COMPANY, )
METROPOLITAN EDISON COMPANY, )
PENNSYLVANIA ELECTRIC COMPANY )
AND THEIR PUBLIC UTILITY AFFILIATES )
PREPARED DIRECT TESTIMONY AND EXHIBITS OF
RODNEY FRAME
ON BEHALF OF APPLICANTS
I. INTRODUCTION
Q. PLEASE STATE YOUR NAME AND POSITION.
A. My name is Rodney Frame. I am a Principal with Analysis
Group/Economics.
Q. WHAT IS YOUR BUSINESS ADDRESS?
A. My business address is 1747 Pennsylvania Avenue, N.W., Suite
250, Washington, DC 20006.
Q. WHAT IS ANALYSIS GROUP/ECONOMICS?
A. Analysis Group/Economics is a consulting firm that provides
microeconomic and financial analyses for complex litigation,
regulatory proceedings and corporate strategic planning. We
have offices in
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APPLICANTS EXHIBIT NO. APP-300
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Cambridge, MA, Washington, DC, New York City, Montreal and Los
Angeles, Menlo Park and San Francisco, CA. We have
approximately 140 employees.
Q. WHAT IS YOUR FORMAL EDUCATIONAL BACKGROUND?
A. I received a bachelor's degree in business from George
Washington University in Washington, DC. Also at George
Washington, I completed all requirements for my Ph.D. in
Economics with the exception of my thesis. My graduate studies
at George Washington were funded under the National Science
Foundation Graduate Traineeship program.
Q. PLEASE DESCRIBE YOUR PROFESSIONAL EXPERIENCE.
A. I have been employed by Analysis Group/Economics since January
1998. Prior to my affiliation with Analysis Group/Economics, I
was a Vice President at National Economic Research Associates,
Inc. (NERA), where I was employed from 1984 to January 1998.
Most of my work in the last several years, both at Analysis
Group/Economics and at NERA, has involved consulting with
electric utility clients on a variety of competition related
matters including retail competition and restructuring issues,
wholesale bulk power markets and competition, transmission
access and pricing, mergers and acquisitions and contracting
for generation supplies from nonutility suppliers. I
frequently address market power concerns in my work. I have
testified on numerous occasions on these and related topics,
before the Federal Energy Regulatory Commission (FERC), state
regulatory commissions, federal and local courts and the
Commerce Commission of New Zealand. I frequently speak before
industry groups on competition related topics. From 1976 to
1984 I was a Senior Economist with Transcomm, Inc. in Falls
Church, VA. There I directed a number of projects concerning
market structure and ratemaking in the telecommunications
industry, competition among electric utilities, and postal
ratemaking. Prior to my affiliation with Transcomm, I worked
as
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APPLICANTS EXHIBIT NO. APP-300
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an independent economic consultant advising clients mostly on
telecommunications issues.
A copy of my resume is included as Exhibit No. APP-301.
Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
A. FirstEnergy Corp. (FirstEnergy) and GPU, Inc. (GPU) have
proposed to merge.(1) I have been asked by FirstEnergy and GPU
(collectively, Applicants) to provide a competitive assessment
of this proposed merger, and in particular to perform the
Competitive Analysis Screen that is described in Appendix A of
Order 592, the FERC's Merger Policy Statement.(2) An Appendix
A analysis addresses potential horizontal market power
concerns that might arise from a contemplated merger. In
performing this horizontal market power assessment, I also
consider, as appropriate, the comments contained in FERC's
April 16, 1998 NOPR,(3) which I understand to be pending FERC
action in the near future. As well, I examine whether the
combination of FirstEnergy and GPU might create vertical
market power concerns.
Q. HOW IS THE REMAINDER OF YOUR TESTIMONY ORGANIZED?
A. Section II summarizes my analysis and conclusions. Section III
provides a brief overview of features of Applicants' business
activities that are most relevant for an assessment of
potential market power concerns. Section IV describes the
Appendix A screening analysis and the relevant product and
geographic markets included in my study. Section V discusses
the data sources and methods used for my screening analysis
while Section VI
----------
(1) A variety of abbreviations are used in this testimony. They are identified
in Exhibit No. APP-302.
(2) Inquiry Concerning the Commission's Merger Policy Under the Federal Power
Act: Policy Statement, Order No. 592, 77 FERC (Paragraph) 61,263, issued
December 18, 1996.
(3) Revised Filing Requirements Under Part 33 of the Commission's Regulations,
Notice of Proposed Rulemaking, 83 FERC (Paragraph) 61,027, April 16, 1998.
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APPLICANTS EXHIBIT NO. APP-300
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discusses and summarizes the results. These results, which are
shown in a series of tables attached to this testimony as
exhibits, include those for both what I refer to as the base case
analysis as well as those for a number of scenarios (sensitivity
analyses) where potentially important input variables or
assumptions are varied. Section VII addresses potential vertical
market concerns. Section VIII provides my conclusion. The data
and computer models used in my analysis are included in
"workpapers" which are provided on compact disks (CD).
II. SUMMARY AND CONCLUSIONS
Q. WOULD YOU PLEASE SUMMARIZE YOUR ANALYSIS?
A. My testimony principally provides an application of the
Competitive Analysis Screen of Appendix A of FERC's Merger
Policy Statement to the proposed merger of FirstEnergy and
GPU. In this analysis, I focus largely upon markets for
short-term or non-firm energy. I do not include an analysis of
the proposed merger's effect on short-term capacity markets.
Analyses of short-term capacity markets generally focus upon
quantities of uncommitted capacity held by applicants and
their competitors. However, in this case such an examination
would be superfluous because neither of the Applicants holds
any uncommitted capacity, as that term generally is defined,
and therefore cannot realistically be considered as potential
sellers of short term capacity. The merger therefore will not
remove an independent seller of short term capacity from the
market.
In addition to assessing the merger's effects on short term
energy markets, I also consider whether the merger will have
an adverse effect on competition to supply long-term capacity
and competition to supply ancillary services. As concerns the
former, examinations of market power in long term capacity
generally focus upon perceived entry barriers. Because neither
of the Applicants has the ability to erect barriers to those
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APPLICANTS EXHIBIT NO. APP-300
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that might compete with them in the construction of new
generation capacity, I conclude that the merger will not have
an adverse effect on competition to supply long term capacity.
I also conclude that the merger will not have an adverse
competitive effect on the supply of ancillary services. There
is only a single geographic market where each of the
Applicants owns generation that is capable of supplying
ancillary services, but in that single case Applicants' shares
are far too small to suggest potential market power concerns
from the combination. Moreover, there appears to be such a
surplus of ancillary service capability in that single
geographic market that ancillary service prices in all
likelihood would be unchanged even if Applicants withdrew
their capacity from the market entirely.
To perform the Appendix A Competitive Analysis Screen that is
used for examining non-firm or short-term energy markets, I
assembled available data concerning generator costs and other
characteristics, load levels by time period, long term
purchases and sales contracts, market prices, transmission
prices and losses (both for existing single system and
regional tariffs and proposed regional tariffs), and
transmission capacities between various market participants
including Applicants and their first, second and third tier
utilities. Each direct interconnection of Applicants
represents a separate destination market for my analysis
including as destination markets, as appropriate, groups of
entities operating under a single open access transmission
tariff. I also assembled data on historical wholesale
transactions of Applicants to determine whether this initial
list of destination markets should be expanded. Based upon
this review, as well as the results that I report below for
the individual destination markets that are included in my
analysis, I concluded that there was no need to expand the
initial list of destination markets. Then, to develop
computations for Economic Capacity and Available Economic
Capacity,
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APPLICANTS EXHIBIT NO. APP-300
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the two key capacity measures employed in an Appendix A
analysis, I first determined the "competitive" price for each
destination market. I developed a range of prices for this
purpose by looking both at historical system lambda data in
the several control areas relevant for my study and publicly
available forward price information.
For the Economic Capacity measure, I determined what
generation could be delivered into each destination market at
a delivered price no greater than 1.05 times the competitive
price. The generation which can be delivered into each
destination market includes both that which already is located
within the destination market itself as well as generation
which could be imported from the outside. In determining which
generators could meet this test, I used the generation cost
and transmission price and loss data which had been assembled.
Transmission flows into each destination market were capped by
transmission limits, both single path nonfirm (ATC in the base
case and firm ATCs and TTCs in sensitivity analyses) limits
and, where applicable, simultaneous limits as well. As is
appropriate for an Appendix A analysis, premerger and
postmerger shares and Herfindahl-Hirshmann Indexes (HHIs)(4)
were computed using both the generation within each
destination market as well as that which could be delivered to
the destination market from the outside up to appropriate
(path by path and simultaneous) transmission limits.
My computations for the Available Economic Capacity measure
were performed in the same fashion except that each supplier's
native load was deducted from its Economic Capacity in order
to determine the Available Economic Capacity which it might
have available to sell in the destination market. Determining
Available Economic Capacity is becoming
----------
(4) The HHI for a market is equal to the sum of the squared market shares of
the individual firms in the market. Thus, a market with four equally sized
competitors has an HHI of 2,500 (i.e., 25(2) x 4 = 625 x 4 = 2,500) and a
market with 10 equally sized competitors has an HHI of 1,000 (i.e., 10(2) x
10 = 100 x 10 = 1,000).
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APPLICANTS EXHIBIT NO. APP-300
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increasingly difficult as retail customer choice evolves. The
process I used was to assume that, for the most part, each
traditional supplier that historically had a native load sales
obligation continued to serve that same native load. I
determined each traditional supplier's native load obligation
using publicly filed data which, as appropriate, were
escalated to 2001, the study year for my analysis. The only
exception that I made to this general procedure for
determining Available Economic Capacity concerns GPU, where I
employed load forecasts that reflect expected sales losses to
competitors. This is conservative in the sense that it will
cause GPU's Available Economic Capacity to be higher than if
the same procedure used for the other suppliers also was
employed for Available Economic Capacity. When I say that it
is conservative to do so here and elsewhere, I mean that I
have selected a technique or assumption that, in comparison to
available alternatives, produces higher HHIs and higher HHI
changes. If the merger safely falls short of screening
threshold levels when these conservative assumptions are
employed, one can be assured that it also will fall short of
those screening threshold levels in cases where less
conservative assumptions are employed.
For my base case analysis, I compute pre and post merger HHIs,
and therefore changes in HHIs, for a number of different
destination market, season and time period combinations. I
examine 12 different destination markets, three seasons
(summer, winter and spring/fall) and five different time
periods in the summer season and three different time periods
in the winter and spring/fall seasons. These different time
periods and seasons collectively bound a range of demand and
price levels, reflect different generator capabilities and
availabilities and incorporate different base case uses of the
transmission system. I do the analyses both for Economic
Capacity and Available Economic Capacity.
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Q. ARE THERE A PRIORI EXPECTATIONS ABOUT WHAT AN APPENDIX A
ANALYSIS OF THE FIRSTENERGY-GPU MERGER WILL SHOW?
A. Yes. In responding, I will address Available Economic Capacity
and Economic Capacity separately. First, as concerns Available
Economic Capacity, GPU has sold almost all of the generating
assets that it formerly owned and so, given the native load
obligations that it retains under the retail customer choice
programs now in effect in Pennsylvania and New Jersey where
its retail electric service territories are located, is not
likely to have any Available Economic Capacity at all. If this
is true, then the proposed merger will have no effect at all
on concentrations of Available Economic Capacity. As concerns
Economic Capacity, the fact that GPU has sold most of the
generating assets that it formerly owned also suggests that
the concentration effects of the proposed merger will not be
great (although not nonexistent as they are for Available
Economic Capacity), but there are other important factors as
well that support this a priori view.
FirstEnergy is located to the west of PJM where GPU is
located. Energy principally flows into PJM from the west
(where FirstEnergy is located) and south so the principal
geographic markets of potential concern with the proposed
merger should be those in PJM. If there are no market power
concerns from the merger in geographic markets within PJM
(i.e., in the PJM destination market itself and in destination
markets within PJM defined by important internal PJM
interfaces), there are not likely to be market power concerns
in any other destination market.
Within PJM there are nearly 60,000 MW of generation resources
and only about 5,600 MW of simultaneous import capability at
most. GPU has sold most of the generation resources that it
previously owned within PJM and relies upon purchases in the
market to meet a large portion of its commitments to provide
energy to its wholesale and remaining retail
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APPLICANTS EXHIBIT NO. APP-300
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customers. Today GPU owns only 285 MW of generation within PJM
and has under long term contract only 2,543 MW more.(5) This
is a relatively small portion of the total generation
available to supply load in PJM - less than 4 percent - and
much less than GPU's expected peak demand. FirstEnergy owns an
even smaller portion of generation in PJM (less than 3/4 of
one percent), just the 435 MW Seneca pumped storage
hydroelectric generating facility. The bulk of FirstEnergy's
generation is outside of PJM and, to be delivered into PJM,
must compete against that of numerous other suppliers in ECAR,
the Southeastern Electric Reliability Council (SERC)
coordination region and the Mid-American Interconnected
Network (MAIN) coordination region. FirstEnergy today has no
preferential rights to use the import capability into PJM nor,
as Mr. Alexander testifies, will it be seeking to assert any
native load priority rights to use the interconnection between
it and GPU affiliate Penelec post merger. Both pre and post
merger it will be required to obtain tariffed transmission
service to be able to make sales into PJM, just as would any
other party. Given that the import capability into PJM is
limited in comparison to total market size, that FirstEnergy
would be allocated only a limited proportion of that import
capability using any reasonable allocation procedure, and that
each Applicant's pre-merger presence in PJM is relatively
small, it is intuitive that the proposed merger will not
present realistic horizontal market power concerns in
geographic markets within PJM using the Economic Capacity
measure. Moreover, since PJM is the geographic region that,
given the location of Applicants and the
----------
(5) In arriving at this figure I include (i) GPU's purchases from Qualifying
Facilities (1,600 MW), (ii) certain bilateral capacity with energy
purchases that it has made from other utility suppliers (100 MW) that
extend past year 2001, (iii) its short term buy back from the Oyster Creek
nuclear unit (619 MW) that it formerly owned but which now has been sold to
AmerGen and (iv) resources owned by its wholesale customer Allegheny
Electric Cooperative (AEC) where those resources are used to serve the
combined (GPU plus AEC) load (224 MW). I do not include the buy backs from
other facilities that GPU formerly owned but now has sold, either because
those buy backs do not involve the purchase of energy (as opposed to
installed capacity credits) which is the principal focus of my analysis, or
because they will expire during 2001 and therefore should not be included
in a forward looking merger analysis. I also exclude the purchase of
capacity credits from other utilities when
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APPLICANTS EXHIBIT NO. APP-300
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predominant west-to-east direction of power flows, is most
likely to be affected by a merger of FirstEnergy and GPU, a
"clean bill of health" there strongly suggests that there is
likely to be a clean bill of health in other geographic
markets as well.
On an a priori basis, market power concerns are even less
likely in destination markets other than PJM. For example, one
destination market included in my analysis is the New York
Power Pool (NYPP), but neither merging partner owns generating
assets in NYPP (except for nonutility generation (NUG)
projects that GPU's GPU International affiliate is in the
process of selling to Aquilla Energy, a subsidiary of
UtiliCorp United). FirstEnergy's presence in NYPP is even more
muted than its limited presence in PJM. NYPP lies to the north
of PJM and FirstEnergy's generation generally must pass
through PJM to reach NYP (Paragraph) If FirstEnergy's presence
in PJM, to which it has a direct interconnection, is
relatively small, it follows naturally that its presence in
NYPP, with which it is not directly interconnected, will be
even less.
FirstEnergy is located in ECAR, which lies to the west of PJM.
For destination markets to the west (and south) of PJM, GPU is
not likely to be an important competitor pre merger because
the predominant direction of power flow is west to east and
not east to west (or south). This by itself suggests, on an a
priori basis, that the proposed merger will not present
horizontal market power concerns in those markets because the
merger will not be removing a significant competitor from the
market. At times when transmission constraints into PJM are
binding, which in essence is something that is assumed to be
the case in an Appendix A examination of individual
destination markets, prices will be higher in PJM than in
areas to the west such as ECAR. GPU's incentive naturally will
be to sell its
----------
there is no accompanying energy as well as capacity and energy purchases
from other utilities that expire before the end of 2001.
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APPLICANTS EXHIBIT NO. APP-300
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output into the market where it can get the higher price,
i.e., PJM, and not in markets to the west where lower prices
prevail. If GPU's output is sold in PJM, then it is not a
competitor in markets to the west and so the merger does not
remove a competitor from those markets.
The Appendix A screening analysis that I have conducted and
report on herein reinforces the a priori perceptions discussed
above.
Q. PLEASE SUMMARIZE THE RESULTS OF YOUR APPENDIX A SCREENING
ANALYSIS.
A. Consistent with my a priori expectations, for Available
Economic Capacity there are no changes in HHIs resulting from
the merger because one of the Applicants, GPU, has sold most
of the generating resources that it previously owned and
therefore has no Available Economic Capacity at any price
level. Its combination with FirstEnergy, therefore, cannot
possibly increase concentration of Available Economic Capacity
in any destination market.
For Economic Capacity, in virtually all cases the merger
induced HHI increases that I compute fall below the threshold
levels included in Appendix A, which in turn are derived from
the April 1992 Horizontal Merger Guidelines of the US
Department of Justice and Federal Trade Commission (Merger
Guidelines). The only exceptions involve the FirstEnergy
destination market where the HHI increases in the summer,
spring/fall and winter off peak periods exceed the Merger
Guidelines' screening thresholds and the Duquesne Light
Company (DQE) destination market, where the HHI increase in
the winter and spring/fall off peak periods exceed the Merger
Guidelines screening thresholds. However, as I explain further
below, I do not believe that these limited screen violations
represent a real market power concern arising from the
proposed merger. The reasons include the difficulty in
exercising market
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APPLICANTS EXHIBIT NO. APP-300
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power during off peak hours through the withholding of
capacity when such a high percentage of the capacity operating
then consists of units or portions of units (nuclear units and
the minimum operating levels for baseload coal units) that
cannot be easily or economically withheld. Moreover, the
predominant direction of energy flow between ECAR, where
FirstEnergy, DQE and numerous other ECAR suppliers are
located, and the Mid-Atlantic Area Coordinating region (MAAC),
where GPU's generating assets are located, is west to east,
that is from FirstEnergy and other ECAR suppliers into PJM.
At times when transmission constraints into PJM are binding,
which in essence is something that is assumed to be the case
in an Appendix A framework when individual destination markets
are examined, prices will be higher in PJM than in areas to
the west such as ECAR.(6) GPU's incentive is to sell its
output into the market where it can get the higher price,
i.e., PJM, and not in markets to the west where lower prices
prevail. Thus, while the screening analysis and resulting HHI
changes might indicate that some of GPU's capacity resources
could be competitive in the FirstEnergy and DQE destination
markets, or in other ECAR destination markets, during off peak
periods, it is relatively rare for energy actually to flow in
the east to west direction that would make this a realistic
outcome.
In addition to these base case analyses, I also analyzed
several alternative scenarios where I assume different
transmission prices (including those where the proposed
Alliance regional transmission tariff is assumed to be in
place), transmission capacities, and natural gas prices, as
well as further asset sales by GPU. These scenarios
collectively bound a range of
----------
(6) If it were not true that prices in PJM were higher than those in ECAR, then
there would be no reason for supplies to move from ECAR to PJM in a fashion
that creates the constraints that are implicitly presumed to exist in an
Appendix A destination market analysis.
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expectations about now unknown future market structure and
conditions. The results from these sensitivities reinforce the
conclusion derived from the base case, which is that the
proposed merger of FirstEnergy and GPU does not suggest
realistic concerns about the potential exercise of horizontal
market power. I also include a sensitivity analysis that
assumes, consistent with Mr. Alexander's FERC testimony that
is being filed concurrently with the merger application, that
post-merger FirstEnergy sends 650 MWH of energy into the PJM
ISO's control area during each off peak hour to help GPU meet
its energy supply obligations to retail customers in its
service territory. As part of this scenario, I assume that
FirstEnergy acquires the transmission capacity necessary to
implement the energy transfer and that transmission capability
available to others therefore concomitantly is reduced.
Another sensitivity analysis that I examine assumes,
hypothetically, that FirstEnergy's existing sale of 450 MW to
Potomac Electric Power Company (Pepco) inside of PJM instead
is delivered outside of PJM, which makes more non firm import
capability into PJM available to FirstEnergy and other
parties.
The HHI changes in most of these sensitivity analyses contain
the same limited, and inconsequential in my view, off peak
screen violations as the base case, but no additional ones.
However, in the sensitivity analysis when the 650 MW of energy
is shipped from FirstEnergy to PJM post merger in off peak
hours, but not pre merger, one effect is to reduce the HHIs in
the FirstEnergy destination market and therefore to eliminate
the minor base case screen violations referred to above.
Q. PLEASE SUMMARIZE YOUR ANALYSIS OF THE PROPOSED MERGER'S
POTENTIAL EFFECT ON VERTICAL MARKET POWER CONCERNS.
A. I do not believe that the proposed merger presents realistic
concerns about vertical market power. Principal vertical
market power concerns
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involving wholesale electricity supply generally are
associated with fears that vertically integrated transmission
owners will use their transmission assets to favor sales of
their generation over sales of generation by their
competitors. GPU already has turned over operational control
of its transmission assets to the PJM ISO, so there should be
no concern that GPU could use its transmission assets in
anticompetitive fashion. Moreover, GPU and the other
transmission owners within PJM intend that the PJM ISO become
a Regional Transmission Organization (RTO) that will meet
FERC's Order 2000 RTO requirements, and have made a filing
with FERC to begin that process. This should mitigate any
residual concern on this score. FirstEnergy also has committed
to participate in either the Alliance or another FERC-approved
RTO, which should mitigate concerns that it might be able to
use its transmission assets in an anticompetitive fashion.
Finally, because of the prevailing west to east power flows
from ECAR to PJM, it is the PJM area which is most important
for an assessment of the competitive impacts of the proposed
merger. Because GPU sold virtually all of its generating
assets and is a net purchaser of energy to meet its load
commitments, GPU and/or its native load customers will suffer,
not benefit, if energy prices in PJM rise. This would more
than offset the benefits that FirstEnergy might make on any
additional or higher priced energy sales within PJM. Thus,
even if the merged firm were able artificially to restrict
transmission into PJM, and therefore raise energy prices
there, it would lose money if this happened. There is no need
for policy makers to be concerned that the merged firm might
be motivated to undertake actions that are unprofitable to it.
Q. DID YOU ALSO EXAMINE WHETHER APPLICANTS CONTROL ENTRY BARRIERS
THAT MIGHT BE USED TO THWART THEIR GENERATION COMPETITORS?
A. Yes. I determined that they do not control any such entry
barriers (such as sites at which new generation might be
constructed, fuel supplies and fuel
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transport facilities). Accordingly, the proposed merger
should not create or enhance market power concerns on this
score. Moreover, while one of FirstEnergy's affiliates does
own natural gas pipeline facilities, there are no electric
generators served off of those pipelines. This eliminates
any concern that the merger might create vertical market
power problems for existing electric generators.
III. OVERVIEW OF APPLICANTS' RELEVANT BUSINESS ACTIVITIES
Q. WHAT TOPIC IS DISCUSSED IN THIS SECTION OF YOUR TESTIMONY?
A. In this section I provide a brief overview of Applicants'
business activities that are most relevant for a competitive
assessment of the proposed merger.
Q. PLEASE DESCRIBE FIRSTENERGY.
A. FirstEnergy's business operations are described more
completely by Mr. Alexander. FirstEnergy is a public utility
holding company that was formed from the 1997 merger of Ohio
Edison Company and Centerior Energy Corporation. FirstEnergy
has four operating company affiliates, Ohio Edison Company,
The Cleveland Electric Illuminating Company, The Toledo Edison
Company and Pennsylvania Power Company (Penn Power). These
operating company affiliates have retail electric service
territories that cover much of northern Ohio and northwestern
Pennsylvania and collectively own or control under long term
contract generating facilities with a total capacity of
approximately 12,500 MW. The coincident peak demand of the
four operating companies (excluding long term wholesale
transactions) is forecast to be 11,643 MW for the summer of
2001. Another FirstEnergy subsidiary, American Transmission
Systems, Inc. (ATSI), now owns and operates the transmission
assets that formerly were owned by FirstEnergy's four
operating company affiliates. While these transmission assets
now are controlled by ATSI, FirstEnergy
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is a participant in the Alliance organization that is seeking
Regional Transmission Organization (RTO) status from FERC and
has committed to participate in another RTO if the Alliance
ultimately is not approved as an RTO by FERC.
ATSI's transmission assets interconnect with the following
other transmissions systems: Allegheny Energy (Allegheny),
American Electric Power Company (AEP), Dayton Power & Light
Company (DPL), Duquesne Light Company (DQE), Detroit Edison
Company (DetEd) and, through GPU's Pennsylvania Electric
Company (Penelec) subsidiary, PJM.
There are several smaller electric utility systems in the
FirstEnergy control area that are connected to ATSI's
transmission system and which receive transmission service
from FirstEnergy and in some cases wholesale electric service
as well. These smaller systems include Cleveland Public Power,
the City of Painesville, 35 municipal systems that are members
of and receive their wholesale bulk power from American
Municipal Power-Ohio and five municipal electric systems in
Pennsylvania (Pennsylvania boroughs). FirstEnergy also
provides transmission service to eleven rural electric
cooperatives who are members of Buckeye Rural Electric
Cooperative, Inc.
Retail customer choice already has commenced in Pennsylvania
where Penn Power's retail service territory is located and is
scheduled to begin in Ohio, where the other of FirstEnergy's
operating company subsidiaries are located, beginning January
1, 2001. As part of the restructuring in Pennsylvania, Penn
Power's unbundled generation rates are subject to a rate cap
through 2005. As part of the retail customer choice program
being introduced in Ohio, FirstEnergy's base distribution
rates have been frozen through 2007 and FirstEnergy is at risk
for a portion of its stranded
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cost recovery if customer switching falls short of 20 percent.
FirstEnergy has committed to make available up to 1120 MW of
generation to competing retail marketers and brokers to enable
them to provide retail electric service in Ohio.
In addition to its regulated electric business, FirstEnergy
also owns FirstEnergy Services, which competes for retail
customers in other states plus Marbel Energy Corporation
(Marbel), which owns natural gas reserves, production
facilities and an intrastate and short interstate pipeline.
Q. PLEASE DESCRIBE THE DOMESTIC OPERATIONS OF GPU.
A. The domestic business operations of GPU are described more
completely in Mr. Levy's testimony. GPU is a public utility
holding company with three domestic public utility
subsidiaries, Jersey Central Power & Light Company,
Metropolitan Edison Company (MetEd) and Pennsylvania Electric
Company (Penelec). JCPL, MetEd and Penelec do business as GPU
Energy and provide retail electric service principally to
customers in New Jersey and Pennsylvania.(7) GPU formerly
owned nearly 7000 MW of electric generating facilities but now
has sold all but 285 MW as part of the industry restructuring
in New Jersey and Pennsylvania.(8) GPU has purchased energy
and/or capacity rights from certain of those sold resources
but those purchased rights, excluding the ones that expire in
the near term, when combined with GPU's remaining owned assets
and other (NUG and utility) purchases, sum to levels far below
those needed to provide service to GPU's traditional native
load customers even after accounting for expected load loss to
retail competitors.
----------
(7) Penelec leases the facilities of the Waverly Electric Light & Power Company
and through these also provides retail electric service in and around
Waverly, New York and vicinity.
(8) Not included in these figures are NUG facilities owned by GPU affiliate GPU
International that now are in the process of being sold to Aquilla Energy,
an affiliate of UtiliCorp United.
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As of December 1, 2000 GPU will have only two wholesale
customers. GPU sells to Allegheny Electric Cooperative (AEC)
its full requirements beyond those met by AEC's purchase of
hydroelectric power from the New York Power Authority. As part
of the contractual arrangements with AEC GPU receives the
output from AEC's 10 percent ownership interest in the
Susquehanna nuclear station and its Raystown run-of-river
hydroelectric facility. AEC also sells approximately 4 MW of
power to Allegheny affiliate West Penn Power.
GPU is a participant in the PJM ISO. It has turned over
operational control of its transmission service to the PJM ISO
and made those facilities available for use under the PJM
ISO's open access transmission tariff. The transmission
facilities of the PJM ISO interconnect with transmission
facilities of FirstEnergy, Allegheny, Virginia Electric and
Power Company (VEPCO) and the New York ISO. GPU and the other
transmission owners within the PJM ISO have filed with FERC to
become an RTO.
Retail customer choice has been implemented in both of the
principal jurisdictions (Pennsylvania and New Jersey) where
the GPU operating companies' retail service territories are
located. In both jurisdictions there are currently in effect
price caps that govern what GPU's operating company affiliates
can charge for unbundled generation service.
IV. APPENDIX A SCREENING ANALYSIS AND RELEVANT GEOGRAPHIC AND PRODUCT
MARKETS
Q. WHAT TOPICS ARE DISCUSSED IN THIS SECTION OF YOUR TESTIMONY?
A. In this section of my testimony I describe the Appendix A
Competitive Analysis Screen and the determination of relevant
geographic and product
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markets for a competitive assessment of the proposed
FirstEnergy-GPU merger.
A. RELEVANT PRODUCT MARKETS
1. ENERGY
Q. WHAT RELEVANT PRODUCT MARKETS DO YOU EXAMINE IN YOUR
TESTIMONY?
A. FERC generally considers three product markets in its market
power investigations, short term capacity, long term capacity
and short term or non firm energy. In assessing the
competitive implications of a merger of FirstEnergy and GPU,
only the last of these, short term energy, is relevant or
requires any detailed investigation. It is this product market
that is the principal focus of my analysis herein, although I
briefly discuss long term capacity and ancillary services as
well.
2. SHORT TERM CAPACITY
Q. PLEASE EXPLAIN WHY SHORT TERM CAPACITY IS NOT A RELEVANT
PRODUCT THAT IS INCLUDED IN YOUR ANALYSIS.
A. GPU sold most of its generating capacity, and therefore is not
realistically a participant in short term capacity markets.
Generally, the ability to participate in short term capacity
markets is evaluated by looking at a participant's uncommitted
capacity, that is its total owned resources plus long term
(greater than one year in duration) firm purchases less that
required to fulfill its commitment to native load and other
firm sales customers (including appropriate planning reserves
to support those sales). GPU projects a native load obligation
for summer 2001 that is much greater that the long term
capacity resources under its control of only 6,316 MW.(9) With
this large deficit, GPU clearly cannot participate as a
----------
(9) As indicated, GPU has sold most of the generating capacity that it
previously owned. The long term capacity resource total cited in the text
includes (i) the relatively small quantity of owned resources
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seller in short term capacity markets. While GPU's short
capacity position by itself is sufficient to insure that the
proposed merger will not have adverse competitive effects in
short term capacity markets, FirstEnergy also is short. This
further supports the conclusion about the lack of an adverse
competitive impact. FirstEnergy forecast a peak demand of
11,871 MW for summer 2000(10) but had committed long term
capacity resources of only 12,524 MW.(11) Thus, even using a
very low reserve margin of only 6 percent, FirstEnergy, as is
GPU, is short of capacity and must rely on short term
purchases in the market to meet its summer load obligations.
Therefore, it likewise cannot realistically be considered a
seller in these markets.
3. LONG TERM CAPACITY
Q. PLEASE DISCUSS THE EFFECT OF THE PROPOSED MERGER ON MARKETS
FOR LONG TERM CAPACITY.
A. FERC has determined as a general matter that market power
concerns should not be present in long term capacity markets
because of the ability of new firms to enter the market.(12)
This general conclusion is reinforced
----------
that GPU has not sold (285 MW consisting of its 50 percent or 200 MW
interest in the Yards Creek pump storage facility, its 19.4 MW York Haven
hydroelectric facility and its 66 MW Forked River combustion turbine), (ii)
certain NUG resources that it has under long term contract (totaling 1,600
MW), (iii) its buyback of energy from the Oyster Creek nuclear unit that it
sold to AmerGen (619 MW), (iv) 100 MW of capacity with energy purchases
from other utility suppliers, (v) 224 MW of resources owned by AEC but used
by GPU to meet the combined GPU plus AEC load and (vi) 3,488 MW in the
repurchase of capacity that it sold to Sithe. (Note that the repurchase
from Sithe involves capacity but not energy. These capacity rights without
energy are not appropriately attributed to GPU in the Appendix A energy
market analysis reported on herein.) Not included in this 6,213 MW resource
total are contract purchases that expire before the end of 2001 or
generating units that GPU has sold that have buyback provisions that expire
before the end of 2001. By their very nature, merger analyses should be
forward looking and so such soon-terminating purchases ought to be excluded
from GPU's total.
(10) FirstEnergy's load in this case includes its 450 MW long term "system" or
reserved capacity sale to Potomac Electric Power Company (Pepco).
(11) This figure is equal to 13,224 MW of Available Capacity shown in
FirstEnergy's most recent Long-Term Forecast Report to the Public Utilities
Commission of Ohio less 700 MW of firm purchases that will expire by the
end of the year and therefore which are not properly reflected in a
forward-looking merger analysis.
(12) See Promoting Wholesale Competition Through Open Access Non-Discriminatory
Transmission Services by Public Utilities, Docket RM 95-8-000 and Recovery
of Stranded Costs by Public Utilities
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by actual evidence of entry in numerous regions throughout the
country, including ECAR where FirstEnergy is located and in
the Mid-Atlantic Area Coordinating region (MAAC) where GPU is
located.(13) However, FERC considers whether applicants
(either merging partners or those requesting initial or
continuing market based pricing authority) control entry
barriers that might be used to block entry by their
competitors. In this case, as I describe below, Applicants do
not control entry barriers that could be used to block their
competitors. Accordingly, the proposed merger, if consummated,
does not present concerns about market power in long term
capacity markets.
The potential entry barriers usually considered in FERC's
market power discussions include control of sites at which new
generation might be constructed, control of fuel supplies and
control of fuel transport facilities. As concerns sites at
which new generation might be constructed, there is ample
evidence that site unavailability is not thwarting such new
supplies. Within PJM, there are more than 5000 MW of
generation currently in operation that are owned by non
traditional suppliers including capacity under long term
contract to traditional utility suppliers and, as well, nearly
13,000 MW of projects in development that have requested
interconnection studies from the PJM ISO just since the
beginning of this year. GPU, of course, has sold most of the
generating assets that it formerly owned and so it does not
have the ability now to expand its owned capacity at those
sites or prevent any one else from using them to do so.
FirstEnergy owns numerous generating sites, some of which
undoubtedly have the potential for siting additional units.
But other traditional suppliers also have their own existing
sites that could be
----------
and Transmitting Utilities, Docket No. RM 94-7-001, Order 888 Final Rule,
75 FERC (Paragraph) 61,080, April 24, 1996.
(13) Mr. Alexander indicates there are at least 16 applications now pending
before the Ohio Power Siting Board for nearly 10,000 MW in new generation
capacity that is proposed to be on line by the end of 2003.
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expanded. These entities include Orion Power Holding, Inc.,
which owns three generating plants (Niles, New Castle and Avon
Lake) located in FirstEnergy's control area that formerly were
owned by FirstEnergy. Moreover, as Mr. Alexander testifies,
there are at least 16 applications now pending before the Ohio
Power Siting Board for nearly 10,000 MW in new generation
capacity that would come on line between now and summer 2003.
None of the entities making these applications are affiliated
with FirstEnergy or GPU. Additionally, as Mr. Alexander also
testifies, although an application to the Ohio Power Siting
Board has not yet been filed, an affiliate of CME Energy
announced last month its intention to construct a new 2,200 MW
gas fired merchant plant in Lawrence County, Ohio and
indicated that it held an option to purchase the 280 acres
required for the plant site. FirstEnergy does not own CME
Energy's proposed plant site and therefore cannot restrict its
development by denying access to a needed site. From this
information, it is evident that Applicants do not control all
of the sites at which new generation capacity might be
constructed and that site unavailability in fact is not
blocking new entrants. Accordingly, there should be no merger
induced concerns on this score.
As concerns fuel supplies and fuel transport facilities, most
new generation facilities today are natural gas fired
combustion turbines or combined cycles and so the focus for an
entry barrier assessment should be on control of natural gas
supplies and transport. GPU does not own any natural gas
production, storage or transport facilities in the US and so
does not have any ability to thwart potential competitors on
this score.
FirstEnergy does not own any coal mines or coal transportation
facilities and procures coal for its generating stations under
a mixture of long term and spot purchases from unaffiliated
coal producers. However, through its Marbel Energy Corporation
subsidiary (Marbel), FirstEnergy indirectly
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owns gas reserves and production. Marbel owns (i) a small LDC
that serves 4,700 retail customers in Ohio and (ii) Marbel
HoldCo, Inc (HoldCo). HoldCo is a 50 percent owner in Great
Lakes Energy Partners, L.L.C. (Great Lakes), a joint venture
with Range Resources Corporation of Fort Worth, Texas. Great
Lakes owns gas reserves and production in the Appalachian
Basin, as well as an intrastate and an interstate pipeline.
Great Lakes has annual revenues of approximately $115 million.
Great Lakes' intrastate pipeline facilities are located in
northeast Ohio, while the interstate pipeline is an
approximately 100 mile segment running between an interstate
Columbia Gas Transmission line in West Virginia and
Washington, County, Ohio. There are no electric generators
served off of Great Lakes' two pipelines. Moreover,
FirstEnergy's interests in these natural gas production and
transport facilities do not give it the ability to block those
that might compete with FirstEnergy in the development of new
electric generation. There are numerous other interstate
pipelines (Columbia Gas, Tenneco, Texas Eastern, CNG and
National Fuel) in the same general area and, as well, numerous
other parties that own gas production facilities. Moreover,
the gas transport facilities owned by Great Lakes and Marbel's
LDC all are available for use by competitors under open access
tariffs.
For the reasons discussed above, there should be no concerns
about merger-induced market power in short term or long term
capacity markets and so it is only the short term or non firm
energy market that should be the principal focus of a
competitive investigation of the proposed FirstEnergy-GPU
merger. It is for analyzing short term or nonfirm energy that
I use the Appendix A screening analysis described below.
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4. ANCILLARY SERVICES
Q. HAVE YOU ALSO CONSIDERED WHETHER THE MERGED FIRM MIGHT BE ABLE
TO EXERCISE MARKET POWER IN ANCILLARY SERVICE MARKETS?
A. Yes. While I have not done a detailed analysis, I do not
believe that the proposed merger will raise market power
problems for the provision of ancillary services. Because of
concerns about reliability and the differential costs that
would be involved, ancillary services generally are not
provided from remote (out-of-control area) locations. This
means that the only geographic market of interest for
assessing potential ancillary service related market power
concerns associated with the FirstEnergy-GPU merger is PJM
because it is only within PJM that both Applicants own
generation.(14) Within PJM, the only ancillary service that is
now procured separately by the PJM ISO at market determined
prices is regulation and so that is the only ancillary service
that needs to be analyzed now.
Q. PLEASE DESCRIBE YOUR ANALYSIS OF THE EFFECTS OF THE MERGER ON
THE SUPPLY OF REGULATION SERVICE WITHIN PJM.
A. Within PJM, both FirstEnergy and GPU own generating resources
that could be used to supply regulation service to the PJM
ISO. These units
----------
(14) In the discussion below, I indicate that, at some times, for purposes of an
energy market analysis, it may be appropriate to examine destination
markets that consist only of portions of PJM. These portions of PJM are
defined by important internal interfaces within PJM that at times are
constrained. However, for purposes of analyzing regulation and other
ancillary services, it is not necessary to consider geographic markets that
encompass less than all of PJM. One reason is that FirstEnergy's only
generating asset within PJM (Seneca) is located in a different portion of
PJM than are the two generating facilities that GPU owns that can be used
to provide ancillary services, Yards Creek and Forked River. (Seneca is
located to the west of the Central Transfer Interface in PJM while Forked
River and Yards Creek are located to the east of the Eastern Transfer
Interface.) Also, as concerns regulation specifically, it is my
understanding that, even during times when the three internal interfaces
within PJM are at their limits, the PJM ISO still acquires regulation on a
PJM wide basis, and not from subregions within PJM defined by those
internal interfaces. See, e.g., the affidavit of
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are, for GPU, its Forked River combustion turbine and its 50
percent interest in the Yards Creek pumped storage facility(15
and, for FirstEnergy, its Seneca pumped storage facility. As I
understand it, Seneca is not currently equipped to provide
regulation to the PJM ISO but could be equipped to do so in
the future. The maximum amount of regulation service that a
particular generator can supply to the PJM ISO is equal to the
amount by which it can ramp up or ramp down its output within
a 5 minute time period. For Seneca this is equal to 150 MW
while for Yards Creek and Forked River combined it is equal to
140 MW.
The PJM ISO's filing to FERC earlier this year requesting
market based pricing for regulation contains some information
that can be useful in interpreting these maximum regulating
capability figures for FirstEnergy and GPU within PJM.(16)
That filing indicates that units within the PJM control area
have the ability to supply a total of 2392 MW of regulation
service during on peak periods, where the 2392 MW reflects a
derating to account for the effects of forced outages. The on
peak periods are the only time periods relevant for an
assessment of the FirstEnergy-GPU merger because that is the
only time that pumped storage facilities such as Seneca and
Yards Creek are likely to be generating electricity. During
other time periods they are likely to be pumping water to
support future peak period electricity generation, but not
generating electricity themselves. Conservatively assuming
that Seneca and Forked River are included in the PJM ISO's
2392 MW figure for total regulating capability within PJM,
(17)
----------
Joseph E. Bowring, the Manager of PJM's Marketing Monitoring Unit, in
Docket No. ER00-1630-000.
(15) Yards Creek currently is used to provide regulation within PJM. Forked
River, while equipped to do so as well, is not currently used in this
fashion.
(16) See the Affidavit of Joseph E. Bowring in Docket No. ER00-1630-000. While
Mr. Bowring's affidavit contains some information that is useful in
interpreting the above cited figures concerning regulating capability
within PJM, other information that might be helpful has been redacted in
the public version of Mr. Bowring's affidavit and therefore was not
available to me for my analysis.
(17) It is not possible to determine whether or not this is the case from the
information contained in the publicly available version of the PJM ISO's
filing. As indicated, Seneca is not currently equipped to
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this translates into a maximum share of the total regulating
capacity of 5.3 percent for FirstEnergy and a maximum share of
the total regulating capability of 5.6 percent for GPU.(18)
Using the standard "2 x a x b" formula to determine merger
induced HHI changes (where "a" and "b" are the pre-merger
market shares of the merging parties), this means that the
merger of FirstEnergy and GPU will increase the market HHI by
no more than 59. From the non redacted portion of the PJM
ISO's filing, it appears that the peak period HHI measure of
relevance for regulating capacity within PJM, using what the
PJM ISO refers to as total as opposed to available (i.e., net
of native load requirements) regulation capacity, is 1612. As
described below, this portrays a "moderately concentrated"
market under the Merger Guidelines. A premerger HHI of 1612
plus a merger induced HHI change of 59 produces a post merger
HHI of 1671 which still is in the moderately concentrated
range under the Merger Guidelines. A merger induced HHI
increase of 59 for a moderately concentrated market falls
below the screening threshold levels of the Merger Guidelines.
While the indicated HHI increase for regulating capacity
within PJM falls below the threshold screening levels of the
Merger Guidelines, there is additional and much more
significant information that indicates that market power for
the supply of regulation in PJM will not result from the
FirstEnergy-GPU merger. The PJM ISO's filing with FERC seeking
market based pricing for regulation indicated that the highest
peak period requirement for regulation in PJM during the next
few years, equal to 1.1 percent of forecast peak demand, is
approximately 575 MW. This is only a small portion of the 2392
MW that the PJM ISO identified as capable of
----------
provide regulation service in PJM and Forked River, while capable of
providing regulation, is not currently used for this purpose.
(18) In computing these shares I have adjusted the above identified ramping
capabilities (150 MW for Seneca and 140 MW combined for Yards Creek and
Forked River) downward (to 134 MW and 127 MW respectively) to account for
forced outages and therefore make the figures for Seneca, Yards Creek and
Forked River consistent with those in the PJM ISO's analysis.
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supplying regulation to the PJM ISO. Such a large excess of
supply over requirements suggests that the HHIs are not likely
to be useful for assessing potential market power concerns in
the context of the FirstEnergy-GPU merger. Were the merged
firm to withdraw its regulating resources from the market
entirely,(19) either by physical withholding or by bidding
"too high", and even if the possibility of new entrants was
ignored entirely, other existing suppliers still would have
sufficient regulating capacity to be able to meet 350 percent
of PJM's peak regulation requirements. The Applicants'
withdrawal of their limited regulating capacity therefore
would have virtually no discernible effect. Accordingly,
Applicants would not be able to exercise market power.
Q. YOUR DISCUSSION OF ANCILLARY SERVICES ABOVE CONCERNS ONLY
REGULATION. HAVE YOU ALSO CONSIDERED WHETHER THE MERGER OF
FIRSTENERGY AND GPU MIGHT CREATE MARKET POWER CONCERNS FOR
SUPPLY OF OTHER ANCILLARY SERVICES, SUCH AS SPINNING RESERVE
AND OPERATING RESERVE, TO THE PJM ISO?
A. Yes. Spinning reserve and operating reserve are not procured
separately by the PJM ISO now but are procured in combination
with energy in a fashion that makes an energy market analysis
the proper tool to assess market power concerns. This argument
was advanced by the Supporting Companies in their request for
market based pricing authority for sale of energy and certain
ancillary services through the PJM ISO in Docket No.
ER97-3729-000. It appears to have been accepted by FERC when
it approved market based pricing authority. (20) Because the
energy market analysis for the proposed FirstEnergy-GPU merger
provided herein does not indicate any merger induced market
power concerns for energy
----------
(19) In this context, remember that Seneca is not currently used to provide
regulation in PJM and that it would be a pro-competitive event in PJM were
it to provide regulation in the future.
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markets within PJM, the same therefore can be said about
spinning and operating reserve as well under the current
bundled (energy and ancillary services together) joint
procurement process employed in PJM. Moreover, because of the
relatively small shares that Applicants hold, the proposed
merger will not create market power concerns even if and when
PJM moves to unbundled pricing of spinning and operating
reserve. The regulation analysis above shows that Applicants'
shares of potential regulating capability within PJM are too
small to suggest merger induced market power concerns. But
almost by definition their shares of spinning and operating
reserve capability will be even less than their shares of
regulating capability. There is much more generating capacity
capable of providing spinning and operating reserve than there
is generation capacity that can provide regulation. The
denominator used in the share analysis of a spinning reserve
or operating reserve computation is much larger than for a
regulating capacity computation. For Applicants, however,
their numerators are not that much larger because the
regulation analysis already includes all of their units that
are capable of providing spinning and operating reserve.(21)
With a larger denominator, and only slightly larger
numerators, Applicants' market shares for spinning and
operating reserve necessarily would be below those for
regulation.
----------
(20) See 86 FERC (Paragraph) 61,248.
(21) The numerators would be slightly higher because Applicants' generators are
likely to have somewhat more capability to provide spinning and operating
reserve than they are regulation, but not that much more. The other units
that GPU owns (York Haven, a run of river hydroelectric facility) or has
output rights in that extend past year end 2001 (Oyster Creek, various NUG
purchases, plus AEC's interest in Susquehanna and Raystown) that were not
included in the regulation analysis are not likely to have sufficient
dispatch flexibility to be used for providing spinning or operating reserve
ancillary services. FirstEnergy's only generating resource within PJM is
Seneca and so it already is included in the regulation analysis.
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Q. ARE THERE OTHER ANCILLARY SERVICES WITHIN PJM THAT SHOULD BE
CONSIDERED IN ASSESSING POTENTIAL MARKET POWER CONCERNS
ARISING FROM THE FIRSTENERGY-GPU MERGER?
A. No. One other ancillary service is Reactive Supply and Voltage
Control from Generation Sources Service. However, this service
is provided on a cost basis within PJM and so, by definition,
it is not possible that market power might be exercised. Also,
FirstEnergy's and GPU's generators within PJM are not located
sufficiently close to each other to be competing sources for
this service, which must be provided from localized resources
Another potentially relevant ancillary service is Energy
Imbalance Service. However, except for certain penalty
features, the payments for Energy Imbalance Service are
largely tied to the PJM hourly spot energy price. This has
important implications for an assessment of market power.
Because the energy market analysis included herein indicates
that the FirstEnergy-GPU merger will not have adverse effects
on energy markets within PJM, there is no need to make a
separate analysis of the market power implications of the
proposed merger for Energy Imbalance Service. The same
analysis that suggests that the merger will not create market
power concerns in energy markets within PJM can be used to
support a similar conclusion for Energy Imbalance Service.
5. TRANSMISSION
Q. DO THE TRANSMISSION LINES OWNED BY FIRSTENERGY AND GPU
REPRESENT COMPETING ALTERNATIVES BETWEEN ANY POINTS OF RECEIPT
AND POINTS OF DELIVERY?
A. No, but I do not believe that it should be an important
consideration in assessing this merger even if they did
because of (i) GPU's current participation in the PJM ISO,
(ii) the intention of GPU and other PJM transmission owners
that PJM become an RTO, as evidenced by their
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recent FERC filing, and (iii) FirstEnergy's stated intention
to participate in the Alliance or another FERC-approved RTO.
6. RETAIL ELECTRICITY
Q. PLEASE DISCUSS THE EFFECTS OF THE PROPOSED MERGER ON RETAIL
COMPETITION.
A. The most important factor for ensuring competitive retail
markets, in my view, is ensuring that retailing entities are
able to procure the wholesale supplies that they need to
resell to their customers in markets that are characterized by
an absence of market power. The analyses that I present herein
provide comfort on this score, that is, that the merger of
FirstEnergy and GPU will not present concerns about the
exercise of market power in wholesale energy and capacity
markets. Of course, both FirstEnergy and GPU are actual and
potential providers of "pure" retailing services in each
others' traditional service territories, i.e., where the pure
retailing function is considered apart from the wholesale
supply function. However, the merger should not create any
concerns about reduced competition at this level simply
because there are so many firms that are capable of providing
these pure retailing services that the reduction of one actual
or potential supplier from the market is inconsequential.
Accordingly, I do not believe that it is necessary to address
this topic further.
B. APPENDIX A COMPETITIVE ANALYSIS SCREEN
Q. PLEASE DESCRIBE GENERALLY FERC'S APPENDIX A SCREENING
ANALYSIS.
A. The basic approach under an Appendix A screening analysis is
to define individual destination markets, determine the
competitive price in each of those individual destination
markets and then measure concentration and changes in
concentration of ownership of generating resources that are in
or can be delivered to that destination market at a delivered
price that is no
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more than 1.05 times the competitive price. The HHIs produced
from this analysis then are compared to the screening
threshold levels of the Merger Guidelines. If those screening
threshold levels are not exceeded, then it generally will be
concluded that the proposed merger presents no concerns about
horizontal market power. If the screening thresholds are
exceeded, further analyses may be required before it can be
determined whether the proposed merger would have adverse
competitive effects.
In determining which supplies can be economically delivered to
each destination market, the analysis must incorporate
transmission prices and reflect transmission system limits.
The analyses are to be conducted for different seasons and
time periods, to reflect a variety of demand and supply
conditions. The individual destination markets are to include
each entity that is interconnected with one or both of the
applicants, plus any additional entities to which at least one
of the applicants has made significant sales in the past. For
determining the competitive price, FERC in the past has stated
a preference for using historical system lambda data. As I
discuss more fully below, for my analysis I rely upon both
historical system lambda data and publicly available forward
price data to determine a range of competitive price levels to
use in my analysis.
Determining which resources actually can compete in each
destination market at a price that is no more than 1.05 times
the competitive price (for each season and load period)
requires taking into account variable costs (fuel, O&M and
emissions) on a generator by generator basis, transmission
capacities and transmission prices and losses. Moreover,
because it generally will be true that there are more
resources competing to use a particular transmission path than
that transmission path can accommodate, it is necessary in the
analysis to allocate the limited transmission capability among
competing suppliers. FERC has stated a preference for using
OASIS data for Available Transmission Capability to
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determine the transmission quantities to use in the analysis
but also has indicated that at times it will be appropriate to
incorporate simultaneous as opposed to single path limits into
the analysis.(22) Finally, FERC has indicated that there are
two different generation capacity measures that ought to be
examined in an Appendix A screening analysis. The first of
these, Economic Capacity, is all capacity that can be
delivered to the destination market at a price that is no
greater than 1.05 times the competitive price in that market.
The second, Available Economic Capacity, is equal to Economic
Capacity less that required to meet the supplier's obligation
to its native load customers plus its preexisting firm sales
commitments.
Q. ARE MEASURES OF TOTAL CAPACITY AND UNCOMMITTED CAPACITY USEFUL
IN AN APPENDIX A ANALYSIS?
A. Total Capacity is equal to all capacity owned or otherwise
controlled by a particular supplier whereas Uncommitted
Capacity for any one supplier is equal to its Total Capacity
less that required to fulfill its obligations to native load
and other firm customers. I do not believe that these measures
are required by FERC to be used in an Appendix A analysis, nor
do I believe that it would be useful to include them.
Because they reflect variable costs and transmission costs and
limits, the Economic Capacity and Available Economic Capacity
measures that are incorporated in an Appendix A analysis are
more sophisticated measures of market participants' abilities
to compete in particular markets than are the Total Capacity
and Uncommitted Capacity measures. There is no obvious reason
to supplement an analysis that already includes more
sophisticated capacity measures with some less sophisticated
capacity measures and so I have not done so. As indicated,
however, neither of the Applicants has any Uncommitted
Capacity as that term generally is used
----------
(22) See 80 FERC (Paragraph) 61,039 (1997) re: Ohio Edison Company et al.
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and so including it in the analysis now would serve no useful
purpose. Moreover, as concerns Total Capacity, the analyses
reported on below include some time periods when the market
prices are so high that virtually all generation capacity is
operating. Analyses during such time periods are akin to Total
Capacity analyses although, as required by Appendix A, they
incorporate transmission prices (which are not very important
in a relative sense in an Appendix A analysis during these
high priced time periods) and limits.
Q. WHAT ARE THE MERGER GUIDELINES SCREENING THRESHOLD LEVELS?
A. Under the Appendix A process, the HHI changes that are
computed are to be compared to the threshold levels contained
in the Merger Guidelines. The Merger Guidelines considers
markets with post merger HHIs less than 1,000 to be
"unconcentrated." Mergers in unconcentrated markets ordinarily
require no further analysis notwithstanding the level of HHI
increase that results from the merger. The Merger Guidelines
considers markets with post merger HHIs between 1,000 and
1,800 to be "moderately concentrated." If a merger in a
moderately concentrated market causes the HHI to increase by
more than 100, the merger, according to the Merger Guidelines,
"potentially raise[s] significant competitive concerns"
depending on other factors such as ability to collude and
barriers to entry. The Merger Guidelines considers markets
with post merger HHIs greater than 1,800 to be "highly
concentrated." If a merger in such a market causes the HHI to
increase by more than 50, the merger "potentially raise[s]
significant competitive concerns" according to the Merger
Guidelines, again depending on other factors. Importantly,
having merger-induced HHI increases that exceed the threshold
screening levels of the Merger Guidelines does not mean that a
merger must fail on competitive grounds. Rather, it means only
that Applicants must provide additional information and that
additional analyses must be performed.
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C. DESTINATION MARKETS
Q. WHAT DESTINATION MARKETS ARE EXAMINED IN YOUR APPENDIX A
SCREENING ANALYSIS?
A. There are 12 destination markets included in my Appendix A
screening analysis, centered on (i) Allegheny, (ii) AEP, (iii)
DPL, (iv) DQE, (v) FirstEnergy, (vi) the Michigan Electric
Coordinating System (MECS), (vii) NYPP, (viii) PJM and
portions of it termed (ix) PJM West/Central/East, (x) PJM
Central/East and (xi) PJM East and (xii) VEPCO. In one way or
another, each of these entities or aggregation of entities is
directly interconnected with at least one of the Applicants.
These destination markets are depicted schematically in
Exhibit No. APP-303.
FirstEnergy's transmission facilities are directly
interconnected with Allegheny, AEP, DPL, Detroit Edison
Company (DetEd), DQE and GPU operating subsidiary Penelec. I
define and analyze separate destination markets centered on
four of these entities taken individually, Allegheny, AEP, DPL
and DQE.
DetEd, along with Consumers Energy, is a participant in MECS,
which has its own single system open access transmission
tariff. Accordingly, I define a separate destination market
centered on all of MECS and not just DetEd with which
FirstEnergy is directly interconnected. Doing so is consistent
with FERC precedent as I understand it.
Penelec and GPU's other operating subsidiaries are
participants in the PJM ISO's single system open access
tariff. Accordingly, also consistent with FERC precedent, I
examine a separate destination market centered on the entirety
of PJM and not just the particular systems within PJM that are
directly interconnected with one or both of the Applicants.
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Because GPU is a participant in the single system PJM open
access transmission tariff, I consider GPU's interconnections
to be entities directly interconnected with any of the
transmission facilities operated by the PJM ISO, not just
those owned by GPU. For this reason VEPCO is included as a
separate destination market in my study. VEPCO's transmission
lines connect with those of Pepco which, along with GPU, is
one of the entities whose transmission facilities are operated
by the PJM ISO.
The transmission facilities operated by the PJM ISO also are
directly interconnected with those operated by the New York
ISO. Because the New York ISO also has a single system open
access transmission tariff, I include the entirety of the New
York ISO as a separate destination market as well.
In addition to the destination markets identified above, I
also examine separate destination markets reflecting portions
of PJM to account for times when important internal interfaces
within PJM are at or close to their limits. Within PJM there
are three well recognized internal interfaces (referred to as
the Eastern, Central and Western interfaces) that sometimes
reach their limits for west to east transfers. I refer to the
separate destination markets demarcated by these internal
interfaces as PJM/East, PJM Central/East and PJM
West/Central/East, where PJM East represents the area within
PJM to the east of the Eastern interface, PJM Central/East
represents the area within PJM to the east of the Central
interface and PJM West/Central/East represents the area within
PJM to the east of the Western interface. PJM Central/East
includes all of PJM East and PJM West/Central/East includes
all of PJM Central/East. I do not examine as separate
destination markets areas in PJM that lie to the west of these
three important internal interfaces, because the predominant
direction of energy flow within PJM is west to east and
because of my understanding that
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these internal interfaces have not been binding in the past in
the opposite direction.
As indicated, I include a separate destination market centered
on FirstEnergy. The FirstEnergy market can be used for
assessing the potential competitive effects of the proposed
merger on the smaller electric utilities (such as Cleveland
Public Power, the City of Painesville, AMP-Ohio and the
Pennsylvania boroughs) that are directly connected to
FirstEnergy's transmission system. Similarly, other of the
destination markets (including PJM and the disaggregated
portions of PJM) can be used to assess the potential
competitive effects of the proposed merger on smaller systems
located in those destination markets. Thus, because both are
located within PJM, the effects of the merger on the Allegheny
Electric Cooperative, GPU's principal remaining wholesale
customer(23), and the Wellsboro Electric Company, one of
FirstEnergy's wholesale customers, can be assessed using the
figures reported for the PJM destination market.
Q. HAVE YOU INCLUDED AS PART OF YOUR APPENDIX A ANALYSIS ANY
INDIVIDUAL DESTINATION MARKETS OTHER THAN THOSE CENTERED ON
ENTITIES DIRECTLY INTERCONNECTED WITH ONE OF THE APPLICANTS?
A. No. I examined historical information concerning the
Applicants' sales to other utilities to see if it was
appropriate to include additional destination markets and
determined that it was not. Exhibit No. APP-304 is a table
that shows MW quantities and revenues from wholesale sales
made by each of the Applicants during the last three years
(1997-99). The information for GPU comes from the Form 1s
filed by its three operating company subsidiaries while that
for FirstEnergy was provided to me by FirstEnergy. There is
only one utility that both Applicants made sales to
----------
(23) As indicated, however, GPU also sells approximately 4 MW to Allegheny
affiliate West Penn Power.
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during this time period that is not included as a destination
market in my analysis, either on its own or as part of a
larger area (e.g., PJM). That one entity is Cinergy, with GPU
having sold a total of 15 GWH to Cinergy during the three year
period and FirstEnergy having sold a total of 431 GWH. For the
three year time period these amounts represent only 1/100 of
one percent (GPU) and 2/10 of one percent (FirstEnergy) of
Cinergy's system input.
However, while both Applicants have historically made some
wholesale sales to Cinergy, I do not believe that it is
necessary to include a separate Cinergy destination market in
my study in order to assess the affects of the proposed merger
or that any useful information would be provided were I to do
so. Cinergy is simply too remote from Applicants to think that
there will be a discernable HHI change from the merger if it
were analyzed as a separate destination market. Neither of the
Applicants is directly interconnected with Cinergy and
therefore, to make wholesale sales to it, would have to go
through an intermediate system. FirstEnergy can reach Cinergy
using either the AEP or DPL transmission systems while GPU
would require transmission service from either (i) FirstEnergy
and AEP or DPL or (ii) Allegheny and AEP (plus, of course, the
PJM ISO). However, in the results that I report below, the
effects of the FirstEnergy-GPU merger in both the AEP and DPL
destination markets are very small, never even approaching the
Merger Guidline's threshold screen levels. The merger induced
HHI changes necessarily would be much smaller in the Cinergy
market, which requires the extra wheel through AEP or DPL (for
FirstEnergy) and Allegheny plus AEP (for GPU) and where the
presence of Applicants as a result would be that much less.
Because of the location of the Applicants' resources, if their
merger passes competitive muster in the AEP and DPL markets,
then it also must pass competitive muster in markets that are
even more remote and where wheeling through AEP or DPL would
be required in order to make sales.
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Exhibit No. APP-304 does not indicate any other potential
destination market utilities to whom both Applicants have made
sales during the past three years but it does indicate certain
utilities that one of the Applicants has made sales to during
that time period that are not included as separate destination
markets in my analysis. However, for the same reason as
discussed above (i.e., no need to examine more remote
destination markets when there are only insignificant
merger-related effects in less remote destination markets), I
have not examined individual destination markets centered on
any of these other utilities.
The results from the 12 destination markets that I did examine
suggests that it would be pointless to include any additional
destination markets in my study. The merger-induced HHI
changes for the most part are very small in all of the
destination markets examined. The merger induced HHI changes
would be even smaller if additional markets more remote from
Applicants' generating resources were studied simply because
Applicants' relative influence in those additional, more
remote markets would be that much less.
V. DATA SOURCES AND ANALYTICAL PROCEDURES
Q. WHAT STUDY YEAR DO YOU USE FOR YOUR ANALYSIS?
A. Merger analyses should be forward looking and so my study
models conditions as they are expected to exist in calendar
year 2001. To use a calendar 2001 study year requires, in many
cases, adjusting certain historical data to bring it forward
in time. The procedures I use to do so are described below. I
use calendar year 2001 as a representative time period to
examine the likely competitive effects of the merger in the
near term. In some respects, however, the use of such a near
term time period for the assessment acts to overstate the
effects of the merger as measured in my study. Over time, as
GPU sells its remaining owned generation, as
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the energy sell back provisions from GPU's Oyster Creek sale
expire, as new merchant capacity enters commercial operation
and as new regional transmission tariffs are implemented, the
impacts of the proposed merger, however limited they are shown
to be in my study, will be even less.
Q. PLEASE DESCRIBE THE DATA SOURCES USED IN YOUR ANALYSIS.
A. Conducting an Appendix A analysis requires assembling data
for, among other things, generation ownership, generator
capacities and variable costs, purchases and sales
transactions between marketplace participants, load
responsibility by supplier, transmission capacity both on path
by path and simultaneous bases and transmission prices and
losses.
My principal source for data concerning generator size, type,
location, and ownership was the 1999 EIA Form 860A and the
1998 EIA Form 860B. This was supplemented with information
provided by RDI. Generators were derated for outages based
upon information in NERC's "Generating Unit and Statistical
Brochure 1994-1998" with adjustments made for peaking units
when the NERC outage factors seemed too high. Forced outages
were assumed to occur throughout the year while maintenance
was assumed to occur during the spring/fall season only.
Information for generator heat rates comes from EIA Form 860
for 1995, the latest year for which such information is
publicly available. For units that have been added since 1995,
the heat rates were estimated from information available for
comparable units.
SO2 emissions costs for coal units were developed principally
from RDI and FERC Form 423 information for sulfur and heat
contents, EIA Form 860 for heat rates and Cantor Fitzgerald
for allowance prices. Scrubbed units were identified using the
latest version of the EIA Clean Air Act Browser, as
supplemented with information from RDI. Emissions rates
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for units that are scrubbed were assumed in my analysis to be
decreased by 90 percent from those that otherwise would be
estimated. Scrubbing was assumed to increase variable O & M
costs by $1.30 per MWH. I also included costs for NOx
emissions for generating units located in the northeast. I
used NOx emissions data from EPA's Emissions Scorecard 1999
and allowance price estimates and variable O&M cost adders
provided by FirstEnergy. In some cases I also used emissions
information provided by RDI.
Q. HOW DID YOU DETERMINE WHAT FUEL PRICES TO USE IN YOUR
ANALYSIS?
A. For prices for natural gas, I employed two procedures. With
the first, I developed month by month and plant by plant
prices paid for delivered spot natural gas from FERC Form 423
information for the years 1995 to 1999. I then subtracted
month by month historical prices at Henry Hub from the Form
423 plant by plant figures to develop monthly basis
differentials for each plant. To reflect different seasonal
transportation costs, the basis differentials then were
averaged, weighted by the quantity purchased in each reported
transaction, for all Januarys, Februarys,..., Novembers and
Decembers from the different years. The resulting basis
differentials for each month then were added to NYMEX futures
prices for Henry Hub for December 2000 through November 2001
to obtain delivered price estimates appropriate for the 2001
study year for each plant. I used December 2000 for this
computation rather than December 2001 so that my winter
figures would be based on three consecutive calendar months.
When Form 423 prices were not available for a particular plant
for a particular month, the quantity-weighted average prices
paid for deliveries to other plants in the region (or adjacent
regions) were used. The resulting monthly forecast prices for
each plant then were averaged to produce prices for the
summer, winter and spring/fall seasons used in the analysis.
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I had some concern that the above described procedure for
estimating delivered natural gas prices to each natural gas
fired plant might at times overstate the true basis
differential. This would be true if the delivered Form 423
prices included some perhaps small but unknowable amount of
fixed fuel transport costs. To mitigate concern on this score,
I also employed an alternative procedure. With it I determined
the basis differential, again plant by plant and month by
month, using historical information from Bloomberg both for
Henry Hub prices and for deliveries from various pipelines to
various locations. Each of the gas fired generators was mapped
to one of the locations for which Bloomberg reports this
historical information. As with the first procedure, the
resulting differential, again on a month by month basis, was
added to the adjusted NYMEX futures price to obtain delivered
natural gas price estimates for the study period. The monthly
figures then were averaged to provide seasonal values.
The procedures used to develop prices for the other fuels were
much simpler. For fuel types that had widely reported spot
purchases, such as coal, No. 2 fuel oil and No. 6 fuel oil, I
used as a basis historical FERC Form 423 prices from the 1995
to 1999 time period. I escalated these to August 2000 levels
using fuel specific producer price escalators from the Bureau
of Labor Statistics, and then raised these now current values
to the study year using EIA forecast fuel specific price
increases. When Form 423 prices were not available for a
particular plant for a particular month, the quantity weighted
average prices paid for deliveries to other plants in the
region (or adjacent regions) were used. For fuel types where
no spot transactions were reported in the Form 423s, prices
for other fuels were used as a proxy, e.g., No. 2 fuel oil for
jet fuel.
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Q. DID YOU DO ANY SENSITIVITY ANALYSES THAT ADJUST FOR THE RECENT
UPTURN IN NATURAL GAS PRICES?
A. Yes. Natural gas prices at Henry Hub have increased by roughly
150 percent since the beginning of this year. The futures
prices that I use in my base case analysis embody this recent
dramatic increase, which has produced Henry Hub prices in the
neighborhood of $5 per mmbtu. I perform sensitivity analyses
that assume lower natural gas prices than this, one where the
price is $1 per mmbtu lower and another where the price is $2
per mmbtu lower.
Q. HOW DOES YOUR STUDY INCORPORATE NEW GENERATION CAPACITY
ADDITIONS THAT ARE NOT INCLUDED IN THE GENERATION DATA BASE
THAT YOU HAVE DESCRIBED?
A. The publicly available EIA data source that I relied upon for
identifying generators to use in my analysis was current as of
1998. I supplemented this data base with units that could be
identified from public sources (including RDI) as being added
during 1999 and 2000, or were projected to be added during
2000 and 2001 and indicated as being under construction. The
complete list of generating units is included in my
workpapers.
Q. HOW DID YOU DETERMINE THE MARKET PARTICIPANTS' LOADS FOR USE
IN DETERMINING THEIR AVAILABLE ECONOMIC CAPACITY?
A. I developed peak load information for market participants from
a variety of sources including EIA Form 411 reports,
individual supplier load and resource reports and other
sources such as FERC Form 1s, Electric Utility Week, Electric
World Directory 2000, and EIA Form 861. I used peak demands as
forecast for calendar year 2001. Where the peak demands were
historical, they were inflated to year 2001 using regional
escalators.
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Q. WHAT SEASONS AND TIME PERIODS DID YOU INCLUDE IN YOUR
ANALYSIS?
A. My analysis includes three seasons (summer, winter and
spring/fall) and "super peak," peak and off peak time periods
within each of these. As well, I include two separate and even
higher demand summer peak periods to reflect the type of
system conditions that can give rise to extraordinary price
run ups such as have been seen for short time periods the past
few summers. Accordingly, there are a total of 11 different
seasonal and time period "slices" included in my analysis. I
used EIA Form 714 information on hour by hour loads in
conjunction with the peak demand information to determine
demand for each season and time period in the study. When
utility specific load shapes were not available, I used a load
shape from a nearby supplier which peaks in the same season.
Looking at different seasons and time periods in the fashion
that I have allows the analysis to incorporate a full range of
market clearing price levels. It also allows the analysis to
reflect different seasonal transmission limits and different
seasonal availabilities.
I define the summer season as the months of June, July and
August, the winter season as the months of December, January
and February, and the spring/fall season as all other months.
During each season the peak hours are from 6:00 AM to 10:00 PM
while the off peak hours are all other hours. Additionally, to
reflect the possibility that prices might rise significantly
during just a few peak hours per year, I also defined "super"
peak periods that, for each season, consisted of just the few
hours when demand was the highest. During the winter and
spring/fall periods, I looked separately at the 150 hours when
demand was the highest, calling this the "super peak" and
calling all remaining peak hours the "peak." During the
summer, when extreme price increases seem most likely, I
defined and analyzed separate periods consisting of the 50
hours with the greatest load ("super peak I"), the 100 hours
with the next greatest loads
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("super peak II") and the 400 hours with the next greatest
loads ("super peak III").(24) The remaining peak period hours
are referred to simply as "peak".
Q. DO YOU ADJUST THE VARIOUS MARKET PARTICIPANTS' DEMANDS TO
REFLECT ESTIMATES OF LOAD LOST TO COMPETING SUPPLIERS IN
JURISDICTIONS WHERE RETAIL CUSTOMER CHOICE HAS BEEN
INTRODUCED?
A. For the most part, no. There is no sufficient publicly
available information to do so nor is there, in my view, a non
arbitrary procedure that could be employed. As FERC has
recognized in a not unrelated context, involving an
application for market based pricing authority, substantial
uncertainty is involved in seeking to do so.(25) As an
alternative, I made the assumption that each traditional
supplier continues to meet the same native load obligations
that it always has. This approach has the merit of treating
suppliers in symmetric fashion and not producing different
results depending on whether optimistic or pessimistic
forecasts of customer load retention are employed. Of course,
the load estimates are utilized in an Appendix A analysis only
in the process to determine Available Economic Capacity. In
the current study, I determined that GPU has no Available
Economic Capacity even when I ignore potential load loss to
competitors. This means that, even using this very
conservative assumption, the merger will not have any affect
on concentration of Available Economic Capacity and therefore
that it is not particularly important if the load values for
other market participants are not stated precisely.
----------
(24) I used the highest demand hours on the FirstEnergy system for this
categorization, which then was applied to all other suppliers.
(25) See EME Homer City Generation, L.P., 86 FERC (Paragraph) 61, 016 (1999).
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Q. ARE THERE ANY CURRENTLY EXISTING LONG TERM PURCHASE OR SALE
TRANSACTIONS BETWEEN FIRSTENERGY AND GPU?
A. No.
Q. HOW DID YOU IDENTIFY THE PURCHASE AND SALE TRANSACTIONS TO
INCLUDE IN YOUR STUDY?
A. The purchase and sales transactions of interest for an
Appendix A analysis are those that are long term in nature.
Purchase and sale transactions which are short term in nature
or which expire in the near term should not be incorporated in
a forward looking merger analysis. The study year that I use
for implementing the Appendix A Competitive Analysis Screen is
calendar year 2001. So, for purposes of my study, I sought to
identify and properly attribute only those purchase and sale
transactions that extended past year 2001. Thus, purchase or
sale transactions that expire during or before 2001 are
excluded. The category of excluded purchase transactions,
among other things, properly encompasses purchases that, as
indicated, the Applicants intend to make during the upcoming
months to meet their summer 2001 load responsibilities as well
as soon-to-terminate buybacks from some of the units that GPU
has sold.
Applicants supplied information on their own long term
purchases and sales. FirstEnergy has only two long term
purchases that extend past the end of year 2001 and therefore
which are properly included in an Appendix A screening
analysis. One of these is the output that is likely to be made
available to it as one of the joint owners of the Ohio Valley
Electric Company (OVEC). The bulk of OVEC's output
historically has been sold to the United States Enrichment
Corporation (USEC) or its predecessor, and the amount
available to FirstEnergy and the other joint owners has been
only that which is not required by USEC for uranium
enrichment. USEC's requirements from OVEC now are on the
decline,
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however. FirstEnergy has provided an estimate of the amount of
energy that is likely to be available to it and the other
joint owners of OVEC during 2001 and these amounts have been
attributed as resources to FirstEnergy and the other joint
owners in my study. FirstEnergy's only other long term
purchase that extends past the end of year 2001 is a 300 MW
unit purchase from DetEd's interest in the Ludington pumped
storage facility in Michigan. Similar to what is done with the
other purchase and sale transactions, this amount is added to
FirstEnergy's resource total and subtracted from that of
DetEd.
FirstEnergy makes long term capacity and energy sales to
Pepco, Wellsboro Electric Company (Wellsboro), the City of
Painesville and AMP-Ohio.(26) The most significant long term
sale is a 450 MW "system" sale to Pepco. For my base case, I
have subtracted this amount from FirstEnergy's resources (plus
an additional amount to account for reserves, appropriate in
the case of a sale of this nature) and added it to Pepco's
resources.(27) FirstEnergy provided pricing information to
allow the resources for this transaction to be deducted from
its supply stack appropriately, and added to that of
Pepco.(28) I also include a sensitivity analysis that assumes
that this 450 MW is not delivered to Pepco in PJM but,
instead, is delivered to another supplier (Allegheny) at a
delivery point outside of PJM.
----------
(26) FirstEnergy also sells regulation, spinning and operating reserve to DQE
under a transaction that runs until May of 2002. Because some of the
resources that FirstEnergy needs to support this sale (up to 78 MW) could
also be used at least at times to provide nonfirm energy, I have not
subtracted them from FirstEnergy's totals in determining its Economic
Capacity and Available Economic Capacity for my study. It is conservative
to attribute this capacity to FirstEnergy in calculating post merger HHIs.
(27) FirstEnergy includes its obligation under this transaction as part of its
load. For consistency, in determining FirstEnergy's load for purposes of
computing Available Economic Capacity in my study, I subtracted the 450 MW
Pepco obligation from FirstEnergy's load.
(28) Pepco has sold certain of its generating assets and rights under power
purchase agreements to an affiliate of Southern Energy International (SEI).
However, for my study, I attribute this capacity to Pepco and not SEI
assuming, as is discussed below and as is consistent with trade press
accounts, that there are interim period sellback arrangements under which
Pepco will buyback energy from the capacity it sells to SEI.
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FirstEnergy also sells the equivalent of requirements power to
Wellsboro, which is located in the PJM control area, under a
five year contract that extends until 2003. In my study, this
sale is treated as an addition to FirstEnergy's load rather
than a subtraction from its capacity.(29) This is conservative
and tends to increase FirstEnergy's shares and the merger
induced HHI changes, albeit by a relatively small amount.
FirstEnergy also sells up to 50 MW to the City of Painesville,
which is located in the FirstEnergy control area, on a year
round basis. The sale to Painesville involves stated energy
prices except during 250 hours per year when the energy prices
are market based. The billing demand is determined by
Painesville's actual monthly take from FirstEnergy under the
contract without any minimum contract demand or ratchets to
account for variations in the actual month to month takes. In
fact, there has been substantial month to month variation in
the extent to which Painesville has used this contract since
its August 1999 inception, with Painesville in some months
using the full 50 MW but in other months using none at all.
For purposes of the screening study, I have chosen to ignore
FirstEnergy's obligation to sell capacity and energy to
Painesville under this contract. This is a very conservative
approach because it attributes too much capacity to
FirstEnergy and therefore artificially overstates the HHIs and
merger induced HHI changes. The alternative approach, to
attribute the 50 MW to Painesville and deduct it from
FirstEnergy's share, seemingly would be misleading, and
difficult to implement in nonarbitrary fashion for an energy
market analysis, because Painesville pays no demand charge in
months when it does not take any energy under the contract.
Finally, FirstEnergy also sells 42 MW of capacity and energy
to AMP-Ohio under contract arrangements that extend through
2008. Because the
---------
(29) The load data used to determine FirstEnergy's Available Economic Capacity
includes the Wellsboro obligation.
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load that is served by this sale is included in FirstEnergy's
load forecast, I have not deducted the resources to serve this
load from FirstEnergy's total. This is a conservative way to
treat this transaction because it artificially overstates
FirstEnergy's shares of Economic Capacity, albeit by a
relatively small amount.
GPU has no long term sales that have been included in my
analysis.(30) Its long term purchases appropriate for
inclusion in my energy market analysis include those from (i)
several NUGs, (ii) other investor owned utilities, (iii) the
buy back of energy from the Oyster Creek nuclear unit that it
sold to AmerGen and (iv) AEC's interest in the Susquehanna
nuclear station and a run-of-river hydroelectric facility. GPU
also has entered into energy buy backs from sale of its
interest in the Homer City units that it sold to Edison
Mission Energy (EME) and from its sale of the Three Mile
Island I nuclear unit to AmerGen, but those buybacks expire
during 2001 and therefore are not reflected as a GPU energy
resource in my analysis. Rather, the interest in Homer City
formerly owned by GPU is attributed to EME and Three Mile
Island is attributed to PECO Energy, one of AmerGen's owners.
GPU's sale of several of its generators to Sithe (which in
turn has sold those generators to Reliant) includes a buy back
of installed capacity credits from Sithe, but not energy, and
therefore is not reflected as a GPU resource in my analysis.
For reasons discussed above, my analysis focuses upon energy
markets, not capacity markets. Therefore, in my study, the
units originally sold by GPU to Sithe are appropriately
attributed to Reliant, which purchased those units from Sithe.
----------
(30) GPU sells requirements power to Allegheny Electric Cooperative (AEC). Under
this arrangement, GPU sells to AEC all of its requirements not provided by
a hydroelectric allocation from the New York Power Authority and receives
the output from AEC's 10 percent ownership in the Susquehanna nuclear
station and AEC's Raystown hydroelectric facility. However, I treat AEC as
part of GPU's load, not as an independent wholesale market seller, and so
do not model this transaction separately in the Appendix A Study. GPU also
sells a small amount (4 MW) to Allegheny affiliate West Penn Power. This
amount also is included as part of GPU's load and therefore not modeled
separately in the Appendix A analysis.
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The basic generator data base used for my study includes NUGS
but does not identify the utility purchasers for those NUGs
that are not merchant plants, which is much of the listing.
For my study, I used a combination of reliability council EIA
Form 411 reports, individual company load and resource reports
and FERC Form 1 filings to attribute most of these NUGs to
individual utility purchasers. Those that could not be so
attributed were assumed to be merchant plants but ignored if
the owner has less than 200 MW of capacity. This is a
conservative assumption that artificially tends to increase
the concentration changes measured in my analysis.
The generator database that I assembled does not identify
which NUGs are dispatchable and which are "must take" nor, so
far as I am aware, is there any publicly available database
that does so. GPU identified for me which of its NUG purchases
are from dispatchable units. For other suppliers with
significant NUG purchases, where possible, I used their Form
1s to develop historical capacity factors and assumed that
fossil fuel fired units with very high capacity factors were
not dispatchable but that fossil fuel fired NUG units with
lower capacity factors were dispatchable. For other types of
NUG units, and where capacity factor information was not
readily available, I assumed that the NUG purchases were
nondispatchable. Nondispatchable NUGs were assumed in my
analysis to have a dispatch price of zero.
I used reliability council EIA Form 411 reports, individual
company load and resource reports and FERC Form 1 information
to develop information on utility-to-utility purchases and
sales for transactions not involving Applicants. Developing
information on these utility-to-utility transactions
undoubtedly is one of the more challenging tasks in
undertaking an Appendix A analysis. The available information
is incomplete as to its coverage of transactions and many
times difficult to
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interpret. Pricing information is especially sparse. Where it
could be discerned that a transaction was from a specified
unit, I assumed that the energy price for the sale was equal
to the unit specific cost information that was contained in my
database. Certain other transactions were classified as
"baseload" or "peaking" depending upon particular
circumstances and priced so that they were dispatched
appropriately in the algorithms used to produce the HHIs and
HHI changes. Prices for certain other transactions were
developed using Form 1 information when that seemed
appropriate based on the information that was available. I
recognize, however, that except for the Applicants'
transactions, my information on purchase and sale
transactions, while perhaps the best that can be obtained
using publicly available sources, is less than perfect.
Q. IS IT NECESSARY THAT DATA ON LONG TERM PURCHASE AND SALES
TRANSACTIONS BE PERFECT IN ALL RESPECTS IN ORDER TO IMPLEMENT
AN APPENDIX A ANALYSIS?
A. No. An Appendix A analysis develops market share, HHI and HHI
change information. What is most important in such an analysis
is to have accurate information on the Applicants' purchases
and sales. It is this data that will most directly affect the
resulting share and HHI change data. I have been supplied with
such accurate information for the Applicants' purchases and
sales. While it is desirable also to have accurate information
on other suppliers' purchases and sales, errors or omissions
with respect to it will have much less effect on the study
results than would errors or omissions concerning Applicants'
purchases and sales. For purposes of the Economic Capacity
computations, errors or omissions in this area should have
virtually no effect. For example, if a purchase and sale
transaction involving entities other than Applicants is
omitted from the analysis, the affected generation still will
be included in the analysis but simply incorrectly attributed.
The errors from attributing too much generation to one
supplier and not enough to another will be largely
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offsetting. Depending on the precise circumstances,
Applicants' shares of Economic Capacity and the HHI changes
for Economic Capacity that are attributable to the merger are
unlikely to be affected from errors involving third party
purchases and sales, or only marginally affected. Moreover,
while the same is not necessarily true for Available Economic
Capacity computations, as I discuss further below GPU has no
Available Economic Capacity (at any price level, in any
destination market) and so the effect of errors and omissions
(after correctly accounting for Applicants' transactions) is
irrelevant for an assessment of the impact of Applicants'
proposed merger.
Q. MANY TRADITIONAL SUPPLIERS, INCLUDING GPU, HAVE SOLD SOME OR
ALL OF THE GENERATING ASSETS THAT THEY PREVIOUSLY OWNED TO
OTHER PARTIES. MANY OF THESE TRANSACTIONS, INCLUDING THOSE
ENTERED INTO BY GPU, INVOLVE ARRANGEMENTS WHERE THE SELLERS
BUY BACK SOME OF THE ENERGY OR CAPACITY FROM THE UNITS THAT
THEY HAVE SOLD. HOW ARE THESE TRANSACTIONS MODELED IN YOUR
STUDY?
A. I have already discussed my treatment of GPU's asset sales.
Except for Oyster Creek, which involves a continuing sell back
of energy to GPU (through March 2003), I have attributed the
sold assets to the purchasers (or in the case of the assets
originally sold by GPU to Sithe, Reliant, which is the
subsequent purchaser). Other asset sales in the region of the
country most appropriate for an assessment of the
FirstEnergy-GPU merger appear generally, at least so far as
can be gleaned from trade press accounts, to involve the sell
back of energy from the buyer to the seller for an interim
time period. Such sell back arrangements are presumed to be in
place during calendar 2001 for purposes of my study unless
there are trade press reports indicating that they have
expired or will soon expire. Of course, as is true with the
utility-to-utility purchases and sales discussed above,
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failing to model accurately in all cases the buy back
provisions associated with asset transfers that do not involve
Applicants will have no effect or only a marginal effect on
the HHI computations for Economic Capacity. And, because GPU
has no Available Economic Capacity, Economic Capacity is the
only measure of importance for a competitive assessment of the
proposed FirstEnergy-GPU merger.
Q. GPU HAS ANNOUNCED THAT IT INTENDS TO SELL ITS 50 PERCENT (200
MW) INTEREST IN THE YARDS CREEK PUMPED STORAGE HYDROELECTRIC
FACILITY. HOW IS THIS TREATED IN YOUR ANALYSIS?
A. While GPU has announced that it intends to sell its 200 MW
interest in Yards Creek, it has not yet consummated an
agreement for the sale. Accordingly, I attribute the 200 MW
Yards Creek interest to GPU in my base case analysis. To do so
is conservative and therefore artificially overstates the HHI
change resulting from the merger by a small amount. I perform
a sensitivity analysis that assumes that GPU's Yards Creek
interest is sold to Public Service Electric & Gas Company, the
co-owner of Yards Creek, in both the pre- and post-merger
scenarios. Certain of the HHI changes resulting from the
merger are very marginally reduced when this disposition of
Yards Creek is assumed.
Q. PLEASE DISCUSS THE TRANSMISSION CAPACITY DATA USED IN YOUR
ANALYSIS.
A. The transmission capacity data that I use come principally
from various transmission providers' OASIS sites. My base case
analysis uses non firm ATC measures but I also perform a
separate sensitivity analysis using firm ATC values. Where
available, I assembled data from the OASIS sites of both the
Point of Receipt (POR) and Point of Delivery (POD) systems. In
many cases the transmission capacity data shown on those
different
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OASIS sites differ from those on the other site and so I
generally used the lower values in my analysis.
There are three exceptions to this general rule of using the
lower of POR and POD values. One involves the path from
FirstEnergy to DPL where FirstEnergy at times reports an ATC
value of zero when DPL shows positives figures. Using the
"lower of" rule in this case essentially would eliminate
FirstEnergy as a potential market supplier for the time
periods when it reports zero ATC and therefore eliminate the
need for any further analysis for those time periods.
Accordingly, in order to be conservative, I used the higher
ATC values reported by DPL. The second case where I do not use
the lower of different POR or POD reported values involves the
paths from NYPP into PJM. Because I include in my study
destination markets that comprise only a portion of PJM, it is
necessary to have separate values for deliveries from NYPP
into PJM East and from NYPP into the rest of PJM, and only the
PJM OASIS provides such separate values. Accordingly, I employ
them in my analysis even though, when summed, they exceed the
single NYPP to PJM value reported on the NYPP OASIS site. The
third case where I do not use the lower of the POR and POD
values involves paths into PJM from ECAR and SERC and paths
out of PJM into ECAR and SERC. For these paths I use the
values from the PJM OASIS, even in cases where they are
higher, on the assumption that they are more likely to reflect
in proper fashion the interrelationships among the several
paths that are involved than would values derived from
separate FirstEnergy, Allegheny and VEPCO OASIS sites.
One of the destination markets included in my study is NYPP.
NYPP is a destination market because there are direct
interconnections between NYPP entities and entities in PJM,
where GPU is located. In addition to PJM, entities in NYPP are
interconnected with New England Power Pool
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(NEPOOL) suppliers, Hydro Quebec and Ontario Hydro. I was
unable to get ATC and TTC data from OASIS for these
interconnections and so, as proxies, I used transfer
capability measures as provided in regional seasonal
assessment studies.
The OASIS data that I used consisted of monthly values. For
the most part, I averaged the individual monthly values to
obtain seasonal values for the three seasons included in my
study (summer, winter and spring/fall). However, when there
was an individual monthly value that was significantly
different from the values for the other months comprising the
season, I generally ignored that single outlier value in the
averaging process to obtain the seasonal values on the
assumption that more representative seasonal values would be
obtained if I did. When data was not available on a particular
OASIS site for a particular period, the lesser of the values
for the other two seasons was used.
In addition to the path by path transmission capacity values
included in my study, I also asked personnel at FirstEnergy to
estimate certain simultaneous limits for me. These
simultaneous limits reflect the fact that it may not always be
reasonable to sum OASIS derived path by path limits to obtain
limits across multiple paths or into the same control area
because common limiting facilities may be involved. FERC has
suggested that it is appropriate to include such simultaneous
limits in Appendix A analyses.(31) This order discusses the
then-pending merger of Ohio Edison and Centerior, which
created FirstEnergy. Two types of simultaneous limits were
employed. The first reflects limits on imports into entire
control areas while the second reflects limits on imports into
some of those control areas from certain directions. These
limits were not developed for all control areas or directions
but only those where such limits seemed likely to be important
for the analysis based upon a priori understanding
----------
(31) See 80 FERC (Paragraph) 61,039 at page 61,107.
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of the transmission network and flows on it. As an example of
the directional simultaneous limits that were utilized, energy
can flow into the FirstEnergy control area from the east from
PJM, DQE or Allegheny. A simultaneous limit on flows into
FirstEnergy from this direction would cap flows at a level
lower than the sum of the separate ATCs on the
PJM-FirstEnergy, DQE-FirstEnergy and Allegheny-FirstEnergy
paths. I implemented the simultaneous limits in my model by
proportionally scaling down the single path transmission
values so that, when summed, they did not exceed the
appropriate simultaneous limit. I employ both the directional
and control area simultaneous limits in my base case analysis.
The simultaneous limits that are used in my study are included
in my workpapers.
Q. WHAT WAS THE SOURCE OF YOUR DATA ON TRANSMISSION PRICES AND
LOSSES?
A. This information generally comes from the various transmission
providers' OASIS sites and in a few cases from the Order 888
transmission tariffs themselves. I used the ceiling rate for
non firm service. Even though there were a few cases where
transmission providers today post discounts for service on
particular paths in the near term, I had no basis to assume
that such discounts would prevail into the future. In cases
where there were separate peak and off peak rates, I
incorporated these in my analysis. Where there were not, I
used a single "all hours" rate. Where they were separately
stated on a per MWH basis, I added ancillary service charges
for Scheduling, System Control and Dispatch and for Reactive
Supply and Voltage Control from Generation Sources services.
Where there were no such separate ancillary service charges
stated, I assumed that they were included in the base non firm
"access" charge. Where loss levels were specified, I used
those specified loss levels. Where loss levels were not
specified, I used a "default" value of 2.5 percent.
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I used transmission rates for the existing pool wide open
access tariffs for MECS, PJM and NYPP. In a sensitivity
analysis, I assumed that the Alliance transmission tariff was
in effect. This tariff has separate rates for "drive through"
and "drive out" rates on the one hand, and "drive in" and
"drive within" rates on the other. There is a single
system-wide rate for drive through and drive out service but
the drive in and drive within rates are specific depending on
the ultimate sink. The transmission rates that I used for this
sensitivity are contained in the Alliance participants' recent
filing in Docket Nos. ER99-3144-000 and EC99-80-000. Of
course, the Alliance transmission rates are just estimates as
of this point in time, because the tariff rates themselves
have not yet been approved by FERC and also because the
precise composition of this group at the time service begins
is not now known. I also examined an additional sensitivity
scenario where I assume that marginal transmission prices were
zero, i.e., that all transmission payments consisted of fixed
or demand charges that did not depend on the source of
scheduled transactions. While perhaps unrealistic, this
scenario provides an extreme example of a trend toward lower
variable price payments and broader RTOs.(32)
I applied transmission rates in my study for the originating
system and each intervening system between the source and
sink. I did not apply the transmission price for the
destination system (sink), effectively assuming that customers
in the sink all are network customers. It is essentially
inconsequential to make this assumption because including a
separate point-to-point charge for the destination system for
non network customers would penalize all remote supplies by
the same amount and therefore leave their relative ranking
undisturbed.
---------
(32) I also examined a separate sensitivity where I assumed that the single
system transmission rates of the Midwest ISO were in effect. The merger
induced HHI changes when this assumption was employed were
indistinguishable from those of my base case. Accordingly, I do not discuss
it further herein, or report the specific results.
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Q. THE PJM ISO AND ALLEGHENY HAVE ANNOUNCED THAT ALLEGHENY WOULD
JOIN THE PJM ISO AND BE INCORPORATED INTO THE PJM ISO'S
TRANSMISSION TARIFF AS PART OF WHAT IS REFERRED TO AS PJM
WEST. HOW IS THIS REFLECTED IN YOUR ANALYSIS?
A. I have not directly reflected in my analysis the possibility
that Allegheny would join PJM as a part of PJM West because
there is not sufficient publicly available information to
allow this to be done. Moreover, the information that is
publicly available indicates that transmission prices for PJM
West will be designed to keep Allegheny from suffering
transmission revenue losses in the near term when it joins
PJM.(33) If this is true, then it may be that using the
existing Allegheny transmission price to model wheeling across
the Allegheny system in fact accurately represents the prices
that will be in effect even after PJM West is formed, at least
in the near term. In any case, as indicated, I have also
included a sensitivity analysis that assumes that all marginal
transmission prices, including those for wheeling across the
Allegheny system, are zero.
Q. DID YOU INCORPORATE A MAXIMUM NUMBER OF WHEELS IN YOUR
ANALYSIS?
A. Yes. I included suppliers that are one or two wheels away from
each destination market but did not include suppliers that are
more than two wheels away from the destination market. This
was done for computational convenience and does not in any way
limit the usefulness of my results. As discussed below,
application of the Appendix A screening analysis, under the
assumptions that I have employed, indicates that there are no
adverse competitive effects that will arise from the proposed
FirstEnergy-GPU merger. Including suppliers more than two
----------
(33) See Allegheny Power/PJM Interconnection, L.L.C. Memorandum of Agreement
dated October 5, 2000, paragraph 6.K.
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wheels away from the destination markets examined could only
reinforce this conclusion.
Q. HOW HAVE YOU ALLOCATED LIMITED TRANSMISSION PATH CAPABILITY IN
SITUATIONS WHERE THE AMOUNT OF POTENTIALLY COMPETING SUPPLY
EXCEEDS THE PATH CAPABILITY (ADJUSTED AS APPROPRIATE TO
INCORPORATE THE SIMULTANEOUS LIMITS)?
A. This situation arises in all cases with the Economic Capacity
computations. I have used a "proportional" method, which means
that I sum supplies competing to use a particular path and
then attribute to each supplier the amount of the path
represented by the proportion that its competing supplies are
of the total of all competing supplies. Thus, if supplier X
has 200 MW of capacity deemed by the analysis to be competing
to use a particular 400 MW path, and four other competing
suppliers each have 200 MW as well, then supplier X will
receive an allocation of 80 MW or its pro rata 20 percent
share.
I have used the proportional method because it incorporates
the presence of all competing suppliers in the analysis. The
principal alternative to this proportional allocation method
is an "economic" allocation method that assigns the limited
transmission capability to the suppliers with lower delivered
costs. While perhaps more realistic in terms of which
suppliers ultimately will gain access to the limited
transmission capability, the economic allocation method
overlooks entirely in the HHI determinations all suppliers
other than those that gain an allocation of the limited
transmission capability that can deliver energy into the
destination market at a price lower than the competitive price
and therefore ignores the competitive pressure from those
supplies. Seemingly, therefore, it will artificially overstate
market HHIs. For Economic Capacity, which for reasons
discussed earlier is the only capacity measure for which any
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detailed assessment is required for the FirstEnergy-GPU
merger, the economic allocation method also tends to assign
high market shares to entities with substantial quantities of
nuclear generation, effectively for purposes of an Appendix A
analysis assuming that nuclear capacity can be used
simultaneously in multiple destination markets. This occurs
because the nuclear capacity has such low variable costs that
it still can be economic in remote destination markets even
after shouldering multiple transmission charges. The nuclear
capacity actually squeezes out capacity that is more likely to
be competing on the margin. The economic allocation method
also suffers from "knife edge" properties, which means that
very small changes in market clearing price (or transmission
prices) can significantly, and unrealistically in my view,
affect market shares and HHIs. For these reasons, I have
selected the proportional allocation method.
Q. IN YOUR ANALYSIS, HOW DID YOU DETERMINE WHICH TRANSMISSION
PATHS TO USE TO DELIVER THE SUPPLIES FROM INDIVIDUAL SUPPLIERS
TO PARTICULAR DESTINATION MARKETS?
A. Where there is only a single direct path that might be used,
that path obviously is selected. Where there are potentially
competing paths, some selection among them is required.
Unfortunately, there is no one best and non arbitrary decision
rule that can be employed when the proportional (as opposed to
economic) method is used for allocating limited transmission
capability among competing supplies.(34) However, in most
cases it does not matter a great deal how the decision is
made. AEP's transmission system is interconnected with
numerous market participants and a large number of the routing
decisions for the FirstEnergy-GPU merger involve it. Given its
robustness, when the AEP transmission system represents a
----------
(34) When the economic allocation procedure is employed, paths may be selected
in order to minimize the cost of delivered energy to the destination
market.
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potential alternative transmission route, as a practical
matter most of the flows will be routed over it when there are
competing alternatives simply because the capacity on it is so
great.
The approach that I used was conservative. When there was a
choice of competing paths, and one was always preferred both
on the basis of lower price and larger amounts of transmission
capability, it was selected. When one path was preferred on
the basis of lower price, but another path preferred on the
basis of greater quantity of available transmission capacity,
I examined each choice individually and selected the lower
priced choice if the available quantity on it was not
significantly lower than on the competing path(s) and the
greater quantity choice if its ceiling price was not
significantly greater than on the competing paths. My analysis
conservatively is limited to supplies within two wheels of a
destination market and so this path by path analysis is
relatively easy to perform. As it turns out, there is much
more variation in transmission quantity levels than there is
in price levels and so employing this procedure generally
selects the path with the greatest transmission capacity. To
test the reasonableness of the procedure that I employed, I
performed sensitivity analyses that used alternative path
routings and found that the results, in terms of HHIs, HHI
changes and Applicants' shares, changed very little.
I modified this general approach in certain instances to
ensure that my analysis provided a conservative depiction of
the effects of a FirstEnergy-GPU merger. For any Appendix A
analysis, measured HHI changes in the destination markets
centered on Applicants (i.e., in this instance the FirstEnergy
and PJM destination markets) are likely to be greatest.
Accordingly, for the FirstEnergy market, I allowed supplies
from PJM (where GPU's limited generation interests are
located) to reach the FirstEnergy market both through the
direct PJM-FirstEnergy tie as well as
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through the indirect PJM-Allegheny-FirstEnergy tie. This
insures that I do not artificially understate the HHI changes
in the FirstEnergy market, by limiting too much the GPU
supplies that can enter. I employ a similar procedure for
supplies that go from FirstEnergy to PJM, letting them use the
direct FirstEnergy-PJM path as well as the indirect
FirstEnergy-Allegheny-PJM path.
A second exception to the general procedure that I have
outlined was to route competing suppliers through paths other
than FirstEnergy in cases where there was a choice to go
through FirstEnergy or another supplier, unless the selection
of FirstEnergy was obviously superior. For example, energy
from Allegheny could be routed to the DPL market either
through FirstEnergy or AEP. My study uses AEP for this
routing. This is conservative because it artificially
increases Applicants' shares.
Q. HOW DID YOU DETERMINE THE COMPETITIVE OR MARKET CLEARING
PRICES TO USE IN YOUR ANALYSIS?
A. I first looked at historical system lambda prices as filed in
EIA 714 reports for calendar 1999, the most recent year for
which such data generally is available publicly. Historical
system lambdas for each of the seasons and time periods, for
each of the destination markets used in my analysis, are
provided in Exhibit No. APP-305. Several things are striking
from reviewing this exhibit. One is that during the off peak
periods there is relatively little variation among the system
lambda values reported by the different destination
market/control areas. In contrast, there is substantial
variation in these system lambda values during higher demand
time periods. A second striking feature from reviewing Exhibit
No. APP-305 is that while system lambda values do rise when
moving from lower demand to higher demand time periods, the
pattern of these increases is noticeably different from
control area to control area. The top 50 hours summer system
lambda value is only 55 percent above the summer off peak
system
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lambda value in the AEP control area and only 28 percent above
it in the DPL control area. Indeed, the summer top 50 hours
average system lambda values in these two control areas seem
remarkably low, at $17.16 per MWH in the DPL control area and
$17.96 per MWH in the AEP control area. In contrast, the
summer top 50 hours average system lambda in the FirstEnergy
control area was $811.36, nearly 25 times as large as the
summer off peak average system lambda. Likewise, in the DQE
control area the summer top 50 hours system lambda of $693.59
was also roughly 25 times as large as the average summer off
peak system. PJM, MECS and Allegheny also had very high summer
top 50 hours average system lambdas in comparison to the other
markets and in comparison to their own summer off peak average
system lambdas.
It is relatively well known that different suppliers use
somewhat different techniques in developing the system lambda
values that are reported on the EIA Form 714 forms. That this
is true seems apparent from even a cursory examination of
Exhibit No. APP-305. It would be inappropriate simply to use
the individual reported control area by control area figures
in the Appendix A analysis to identify the competitive
clearing price for each destination market because, at least
in the higher demand hours, systems like DPL and AEP simply
are not measuring the same phenomenon that the other systems
are measuring. The alternative approach that I have employed,
which I believe is much more reasonable, is to use the same
competitive prices in each market for each season and time
period combination and, where appropriate (i.e., for the
higher demand time periods), let these reflect a range of
possible market clearing prices. I examined current NYMEX
futures prices for delivery to the PJM and Cinergy systems
during calendar 2001, the study year for my analysis, to help
inform me about what ranges should be used. These NYMEX
futures prices are also reported in Exhibit No. APP-305.
APPLICANTS EXHIBIT NO. APP-300
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Based upon Exhibit No. APP-305, for my analysis, for the
summer off peak I used a price of $20 per MWH while for the
summer peak (including super peak I, II and III) I used a
range of prices from $40 up to $100 per MWH. The NYMEX forward
prices for 2001 are $101.75 per MWH for peak period deliveries
to Cinergy and $89.67 per MWH for peak period deliveries to
PJM. The top end of the range of prices that I examine for the
peak period in the summer months is $100 per MWH, a price that
will bring in to the dispatch virtually all generators in my
database. Accordingly, using a higher super peak value would
not change the results noticeably.
For the winter and spring/fall months I use an off peak price
of $15 per MWH and peak and super peak period prices of $30
and $40, respectively, per MWH.
Q. HOW ARE SUPPLIES FROM NEPOOL INCORPORATED IN YOUR ANALYSIS?
A. NEPOOL is directly interconnected with NYPP. If suppliers that
compete in a market are limited to those within two wheels of
the market, NEPOOL supplies would be able to compete in the
NYPP and PJM markets (including PJM West/Central/East, PJM
Central/East and PJM East). However, in my study I have
excluded NEPOOL supplies entirely. It is conservative to do so
as concerns this merger because including NEPOOL in these
markets could only lower the measured HHI changes from the
merger. I excluded NEPOOL suppliers simply because of the
extra effort that would be involved were they to be included,
and the apparent lack of any significant effect upon my
results.
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Q. HOW IS FIRSTENERGY'S SENECA PUMPED STORAGE UNIT INCLUDED IN
YOUR ANALYSIS?
A. Seneca is located in PJM but is owned entirely by FirstEnergy
and included as one of FirstEnergy's network resources.(35)
Accordingly, for all destination markets except PJM I assume
that Seneca in effect has been "moved" from PJM to
FirstEnergy's control area. The ATCs that I employ in my
analysis presumably have been developed in a fashion to
reflect this "movement." However, for my analysis of the PJM
destination market, and the destination markets that consist
of portions of PJM, I leave Seneca in PJM and do not move it
to FirstEnergy's control area. I believe that this approach is
appropriate. It leaves Seneca in PJM to compete in those
destination markets when the prices are higher there, but also
allows Seneca to be moved to the FirstEnergy control area
using transmission service procured by FirstEnergy from the
PJM ISO when prices are higher there.
Q. THERE ARE NUMEROUS RELATIVELY SMALL ELECTRIC SYSTEMS INCLUDED
IN THE GEOGRAPHIC AREA COVERED BY YOUR ANALYSIS. HOW DID YOU
TREAT THEM?
A. For the most part, I ignored the generating capacity held by
entities with generating resources that totaled less than 200
MW. This results in a very small overstatement of HHIs and
merger induced HHI changes. I did, however, include the
generation owned by Cleveland Public Power and the City of
Painesville that is located inside FirstEnergy's control area.
For entities such as American Municipal Power-Ohio (AMP-Ohio)
that have loads in multiple control areas, for computational
convenience I left those resources where they are located and
did not move them as network resources to the control areas
where their load is located. This also will tend to overstate
HHIs and merger induced HHI changes in the
----------
(35) Until 1999, GPU owned a 20 percent or 87 MW interest in the Seneca station.
Its 20 percent interest was sold to FirstEnergy in 1999.
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FirstEnergy destination market where some of AMP-Ohio's
resources in fact are delivered.
VI. SUMMARY OF SCREENING ANALYSIS RESULTS
Q. PLEASE DESCRIBE YOUR BASE CASE ANALYSIS.
A. There are a number of different variables and assumptions that
enter into an Appendix A analysis. In some cases there is a
clear cut preference as to which choice to make when
alternatives for these variables and assumptions are available
but in other cases there may not be. Likewise, it might be
desirable to perform sensitivity analyses that span a range of
possible future conditions when there is uncertainty
concerning which conditions actually will prevail. This will
inform FERC about potential competitive consequences over a
wide range of future system conditions. My base case employs
non firm ATCs, simultaneous transmission limits as
appropriate, delivered natural gas price estimates based on
the Bloomberg locational price differentials rather than on
FERC Form 423 historical prices and existing single system and
poolwide transmission tariffs. It also assumes that GPU
continues to own its 50 percent interest in the Yards Creek
pumped storage facility even though GPU has indicated its
intention to sell that facility. In various alternative
analyses I change certain of these inputs and assumptions to
determine their importance.
Q. PLEASE DESCRIBE THE RESULTS OF YOUR BASE CASE ANALYSIS.
A. The base case results are summarized in Exhibits No. APP-306
and APP-307. Each is a multi page exhibit that provides, for
each destination market, for each season, time period and
competitive market price examined, the following information:
pre merger and post merger HHIs and the merger induced HHI
changes; each of the Applicants' capacity in
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MW as well as the post merger total for the merged firm;(36)
and each of the Applicants' market shares as well as the
market share of the merged firm. Exhibit No. APP-306 pertains
to Economic Capacity while Exhibit No. APP-307 pertains to
Available Economic Capacity.
For Economic Capacity, Exhibit No. APP-306 indicates that the
merger induced HHI changes almost universally fall below the
Merger Guidelines' screening thresholds. In most cases the
markets are "highly concentrated" as defined by the Merger
Guidelines but the HHI changes from the merger fall below the
Merger Guidelines' screening threshold of 50. The NYPP and the
various PJM markets fall into the Merger Guidelines'
"unconcentrated" or "moderately concentrated" categories. When
the markets are moderately concentrated, the HHI changes fall
below the screening threshold of 100 for such moderately
concentrated markets. There are only limited exceptions when
the merger induced HHI increases exceed the Merger Guidelines'
screening thresholds. These involve the summer, spring/fall
and winter off peak hours in the FirstEnergy destination
market and the winter and spring/fall off peak periods in the
DQE destination market.
Q. DO THESE OFF PEAK SCREEN VIOLATIONS INDICATE THE PRESENCE OF
MERGER INDUCED MARKET POWER CONCERNS?
A. No. There are several reasons. First, as a general matter, HHI
figures during off peak hours can be seriously misleading as
potential indicators of market power because at such times
there is likely to be a large quantity of supply chasing
relatively little demand. This excess of supply means that
suppliers then will have very little opportunity to raise
their prices
----------
(36) The capacity identified in these exhibits is that which is deemed to make
it into the particular market in question, accounting for, among other
things, delivered prices, transmission limits and the amount of capacity
from other suppliers competing for limited transmission space.
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above competitive levels because other suppliers easily can
fill the breach if one supplier seeks economically or
physically to withhold supply. Moreover, during off peak
periods a high portion of the demand is likely to be served by
nuclear units and the minimum operating levels of coal units
that must be kept operating during off peak periods so that
they will be available to meet demand during the next day's
peak. It is not possible to use such units to exercise market
power by economically or physically withholding their output.
The costs of doing so would be far greater than the benefits
even if the strategy were successful in raising price. For
FirstEnergy, a significant portion of its off peak demand in
fact is met by its nuclear units and the minimum operation
levels of coal units kept on line in order to meet the next
day's peak demand. For example, the minimum operating levels
of FirstEnergy's coal units at Sammis, Bruce Mansfield and
Eastlake total 2350 MW. Its four nuclear units have a total
capacity of 3707 MW. The total of the nuclear units plus the
minimum operating levels of the coal units therefore is 6057
MW. The average daily minimum load for FirstEnergy during 1999
was 6004 MW in the summer, 6049 MW in the winter and 5512 MW
in the spring/fall time periods used in my analysis. Even
after accounting for some modest off peak growth from 1999 to
the 2001 study year used for my analysis, and the effects of
planned and forced outages, it is apparent from these figures
that all or almost all of FirstEnergy's off peak demands will
be met by capacity that cannot be easily withheld from the
market and that it will have no or very little dispatchable
capacity operating during off peak hours that it could
withhold in the hopes of raising price and exercising market
power. This will be true whether or not it merges with GPU.
Accordingly, concerns that the merger could create an
opportunity for the merged entity to profit by withholding
capacity during off peak hours can be dismissed a priori.
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Second, the overwhelmingly predominant direction of energy
flows between ECAR (where FirstEnergy and DQE are located) and
PJM is west to east from ECAR into PJM. Energy flows from PJM
to ECAR only a small portion of the time.
Support for this statement is provided in Exhibit No. APP-308
which indicates that during the September 1997 to September
1999 time period, during off peak hours, energy flowed from
PJM to FirstEnergy only 5.8 percent of the time and from PJM
to Allegheny only 12.6 percent of the time. The remaining
portion of the time energy flowed into PJM from FirstEnergy
and Allegheny. FirstEnergy and Allegheny are the only ECAR
entities that are directly interconnected with PJM. Assuming
that transmission constraints are binding in the west to east
direction, which is the implicit assumption that underlies an
Appendix A analysis of a single destination market, this
implies that, on the margin, even during off peak hours,
energy produced in ECAR is cheaper than energy produced in
PJM. GPU therefore will have an incentive to market its few
remaining resources in PJM, not in ECAR to the west where
prices presumably are lower. Thus, while the procedures of an
Appendix A screening analysis might show that some of the
energy generated by resources that GPU has output rights to in
fact could be economically supplied to the FirstEnergy and DQE
destination markets during off peak time periods, in reality
it is not likely to be supplied there based on the predominant
direction of power flows in the other direction.
Third, the introduction of retail competition notwithstanding,
GPU really does not have any resources available that it might
use in markets to the west of PJM during off peak hours (or
any other time periods for that matter). The energy generating
resources that it owns or has long term energy output rights
to (as I have explained that term above) that are likely to be
operating during off peak hours include roughly 1175 MW of
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nondispatchable NUG purchases, its buy back of energy from the
619 MW Oyster Creek nuclear unit that it sold to AmerGen and
224 MW of nuclear and run-of-river hydroelectric resources
owned by AEC, its wholesale customer, and its own 19 MW York
Haven run-of-river hydroelectric facility. Together these
energy sources total only around 2037 MW, an amount which is
not nearly sufficient to cover GPU's continuing off peak
commitments to its retail and wholesale customers at least in
the near term. They therefore provide neither GPU nor the
merged firm any opportunity to exercise market power in
markets to the west of PJM during off peak periods.
Finally, whatever ability FirstEnergy might have to exercise
market power during off peak hours in destination markets to
the west of PJM (e.g., the FirstEnergy and DQE destination
markets), and for reasons stated above I do not believe that
any such market power exists, will not be enhanced by its
merger with GPU because none of the off peak resources that
would be merged with FirstEnergy's resources can be used to
restrict supply to drive up price. The off peak resources that
GPU has entitlements to are nondispatchable NUG purchases, the
energy buyback from the Oyster Creek nuclear unit, AEC's
interest in Susquehanna and a run-of-river hydroelectric
facility and its own York Haven run-of-river hydroelectric
facility.(37) With the exception of York Haven, GPU now has no
ability to control the output of any of its off peak
resources. It does not own them, cannot affect their dispatch
level and does not have the ability to withhold their energy
output from the market. GPU simply receives and pays for
whatever output that its ownership interest entitles it to,
but has no ability to affect that output level. Thus, those
resources cannot be used to exercise market power. The same
will be true post merger.
----------
(37) The other resources that GPU either owns or has energy entitlements to that
extend past the end of 2001--its owned Yards Creek hydroelectric facility,
the Forked River combustion turbine and two dispatchable NUGs--are not
likely to be dispatched during off peak periods.
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Q. PLEASE DISCUSS THE RESULTS OF YOUR BASE CASE ANALYSIS FOR THE
AVAILABLE ECONOMIC CAPACITY MEASURE.
A. The results for Available Economic Capacity are shown in
Exhibit No. APP-307. They indicate that GPU does not have any
Available Economic Capacity, either in PJM where its
generators are located or in any of the other destination
markets during any season or time period. This automatically
means that there will be no HHI changes resulting from the
merger. The HHI change from a merger generally is given by 2 x
a x b where a and b are the pre merger shares of the merging
parties. If either a or b is zero, which it is for GPU for the
Available Economic Capacity measure, then the merger induced
HHI change is zero. Note that in computing Available Economic
Capacity for GPU, unlike for other suppliers, I used an
estimate of its load obligation after accounting for estimated
load loss to competitors. This is a conservative approach.
Q. PLEASE NOW DISCUSS THE SENSITIVITY ANALYSES THAT YOU
PERFORMED.
A. I performed a variety of sensitivity analyses where, among
other things, I change transmission prices, transmission
capacities and fuel prices. I perform these sensitivity
analyses only for the Economic Capacity computations. There is
no reason to perform sensitivity analyses for the Available
Economic Capacity measure because, as indicated, GPU has no
Available Economic Capacity during any season or at any price
level. The HHI change using this measure therefore always will
be zero and would not be changed with a sensitivity
computation.
The particular sensitivity analyses that I perform for the
Economic Capacity measure are summarized in a series of
exhibits as follows:
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Exhibit No. APP-309 substitutes firm ATC measures of
transmission capacity for non firm ATC measures.
Exhibit No. APP-310 uses the alternative (Form 423 based)
procedure described in the text to develop delivered natural
gas prices.
Exhibit No. APP-311 uses proposed Alliance transmission prices
instead of single system transmission prices where applicable.
Exhibit No. APP-312 uses a variable transmission price of zero
for all transmission paths to provide a proxy for RTO pricing
over a broad geographic range.
Exhibit No. APP-313 assumes that in the off peak hours the
merged firm sells 650 MW into PJM and adjusts the ATC from
FirstEnergy to PJM accordingly.
Exhibit No. APP-314 assumes that GPU sells its interest in the
Yards Creek pumped storage hydroelectric facility to its
co-owner PSEG.
Exhibit No. APP-315 assumes that Henry Hub natural gas prices
are $1 per mmbtu lower than current futures prices at Henry
Hub.
Exhibit No. APP-316 assumes that Henry Hub natural gas prices
are $2 per mmbtu lower than current futures prices at Henry
Hub.
Exhibit No. APP-317 assumes hypothetically that the existing
450 MW sale to Pepco is delivered outside of PJM to Allegheny
rather than to Pepco inside of PJM.
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All other assumptions from the base case remain unchanged for
each of the sensitivity analyses except those specifically
noted. While I could have conducted additional sensitivity
analyses that changed combinations of assumptions, the results
from the sensitivity analyses that I did conduct indicate that
this was not necessary for developing an accurate
representation of the effects of the proposed merger.
For the most part the results of these sensitivity analyses in
terms of merger induced HHI changes are not significantly
different from the base case results. This is not particularly
surprising given the relatively low HHI changes that result
from the base case analysis. One difference from the base case
analysis is shown in Exhibit No. APP-314, when the merged firm
is assumed to sell 650 MW of energy into PJM during off peak
hours. When this occurs the off peak screen violations that
were present in the base case in the FirstEnergy market
disappears.
VII. VERTICAL MARKET POWER ISSUES
Q. ARE THERE IMPORTANT VERTICAL MARKET POWER CONCERNS RAISED BY
THE PROPOSED FIRSTENERGY-GPU MERGER?
A. I do not believe that the proposed merger presents any
realistic vertical market power concerns. In principle,
vertical market power concerns might arise if an integrated
generation and transmission owner were able to use its
transmission ownership to facilitate sales of its generation
over sales of generation by its competitors, perhaps by
limiting access to its transmission facilities or by reducing
the quantity of transmission service that is made available.
In the case of a merger of FirstEnergy and GPU, no such
concerns should be present.
As discussed earlier, energy generally flows into PJM from the
west (and south) and not out of PJM in those directions. This
means that the main
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geographic market of potential concern for assessing the
competitive effects of this merger is PJM or, as discussed
above, portions of PJM defined by important internal
transmission interfaces. Within PJM, GPU already has turned
over operation of its transmission facilities to the PJM ISO,
thereby limiting its ability to grant access to or control
transmission in a fashion that might benefit its generation.
Moreover, GPU and the other transmission owners within PJM
intend that the PJM ISO become an RTO that will meet FERC's
requirements in Order 2000 and recently have filed appropriate
materials with FERC to begin this process. This should reduce
any residual concern about GPU's or the merged firm's ability
to use its transmission assets to benefit sales of its
generation.
Also important in lessening residual concern about the merged
firm's potential exercise of vertical market power is GPU's
position as a net purchaser in wholesale energy markets. That
this is true is evidenced by the fact that it has zero
Available Economic Capacity for all seasons and time periods
studied. GPU is a net purchaser in wholesale energy markets
because, as indicated, it has sold virtually all of its owned
generating assets but still has substantial native load
obligations. Even if, on a pre-merger basis, GPU somehow were
able to manipulate the transmission system inappropriately to
increase energy prices, it would suffer, not benefit, as a
result of such higher prices because it is a net buyer (not
seller) of energy. Accordingly, it should have no incentive to
behave in a fashion to seek to increase price. The same is
true for the merged firm after the consummation of the merger.
If the merged firm somehow were able to manipulate the
transmission system to reduce west to east flows into PJM, for
example, and thereby increase the market price for energy
within PJM, this might under some circumstances produce a
small amount of additional revenue for what are now
FirstEnergy's generators but that amount almost certainly
would be swamped by the extra energy purchase expenses that
would be incurred by what is now GPU to meet its load
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obligations. There is no need for policy makers to worry about
price increases from what would obviously be an unprofitable
transmission manipulation exercise.
In addition to the above considerations, FirstEnergy has
committed to participate in the Alliance or, if the Alliance
fails to achieve timely compliance with FERC's final RTO rule,
another RTO that satisfies FERC's independence, scope and
configuration criterion under the RTO Final Rule. This should
further mitigate any residual concern about the merger
creating the opportunity for the exercise of vertical market
power.
Q. HAVE YOU ALSO CONSIDERED WHETHER FIRSTENERGY'S INDIRECT
OWNERSHIP OF INTERSTATE AND INTRASTATE NATURAL GAS PIPELINES
COULD PRESENT VERTICAL MARKET POWER PROBLEMS WHEN COMBINED
UNDER COMMON OWNERSHIP WITH GPU'S REMAINING GENERATION?
A. Yes. As described above and in Mr. Alexander's FERC testimony,
FirstEnergy's Great Lakes affiliate owns both an intrastate
(Ohio Intrastate Gas Transportation Company) and an interstate
(Gas Transport Inc.) pipeline. I have already described above
why this ownership does not represent an entry barrier for
those that might construct new generation. It likewise does
not present the potential for any competitive problems
involving existing generation resulting from the
FirstEnergy-GPU merger because there are no electric
generators served off of either of Great Lakes' two pipelines,
whether directly by the pipelines themselves or indirectly by
Great Lakes customers using gas from the Great Lakes
pipelines. Accordingly, no further analysis is required on
this score.
APPLICANTS EXHIBIT NO. APP-300
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VIII. CONCLUSION
Q. DO YOU HAVE AN OVERALL CONCLUSION?
A. Yes. The proposed merger of FirstEnergy and GPU will not have
an adverse competitive effect.
Q. DOES THIS CONCLUDE YOUR TESTIMONY.
A. Yes.
<PAGE> 261
AFFIDAVIT
STATE OF CALIFORNIA )
)
COUNTY OF SAN FRANCISCO )
Rodney Frame, being duly sworn, deposes and states: that he prepared the
Direct Testimony and Exhibits of Rodney Frame and that the statements contained
therein and the Exhibits attached hereto are true and correct to the best of his
knowledge and belief.
/s/ Rodney Frame
----------------------------------------
Rodney Frame
SUBSCRIBED AND SWORN TO BEFORE ME, this the Seventh day of
November, 2000.
/s/ Donna M. Boone
----------------------------------------
Notary Public, State of California
Printed Name: Donna M. Boone
---------------------------
My Commission Expires: 8-25-02
------------------
[NOTARY SEAL] DONNA M. BOONE
Commission # 1192992
Notary Public - California
San Francisco County
My Comm. Expires Aug 25, 2002
<PAGE> 262
EXHIBIT NO. APP-301
<PAGE> 263
Exhibit APP-301
Page 1 of 14
RODNEY W. FRAME
PRINCIPAL
Phone: 202-530-3991 1747 Pennsylvania Avenue, NW
Fax: 202-530-0436 Suite 250
[email protected] Washington, DC 20006
Mr. Frame has consulted with electric utility clients on a variety of matters
including industry restructuring, retail competition, wholesale bulk power
markets and competition, market power and mergers, transmission access and
pricing, contractual terms for wholesale service, and contracting for nonutility
generation. A substantial portion of the work has been in conjunction with
litigated antitrust and federal and state regulatory proceedings.
Mr. Frame frequently speaks before electric industry groups on
competition-related topics. He has testified in federal and local courts, before
federal and state regulatory commissions, and before the Commerce Commission of
New Zealand.
Prior to joining Analysis Group/Economics, Mr. Frame was a Vice President at
National Economic Research Associates. Mr. Frame graduated from George
Washington University and pursued graduate work there under a National Science
Foundation Traineeship. His areas of specialization were public finance and
urban economics. He completed all requirements for his Ph.D. degree in economics
with the exception of the thesis.
EDUCATION
1970 B.B.A., George Washington University
1970-73 Ph.D. coursework (all requirements for degree in
economics completed except thesis), George Washington
University
PROFESSIONAL EXPERIENCE
1998 - Analysis Group/Economics
Principal
1984 - 1998 National Economic Research Associates
Vice President and Senior Consultant. Participated in projects
dealing with retail competition, wholesale competition, market
power assessment and determination of relevant markets for
electricity supply, electric utility mergers, transmission
access and pricing, partial requirements ratemaking,
contractual terms for wholesale service, and
<PAGE> 264
Exhibit APP-301
Page 2 of 14
contracting for nonutility generation supplies. Principal
clients were investor-owned electric utilities.
1975 - 1984 Transcomm, Inc.
Senior Economist. Worked on a variety of projects concerning
market structure, pricing and cost development in regulated
industries. Clients included the U.S. Departments of Commerce,
Defense and Energy, the Nuclear Regulatory Commission, the
State of Oregon, bulk mailers and various communications
equipment manufacturers and service providers. Participated in
numerous federal and state regulatory proceedings and was
principal investigator for a multi-year Department of Energy
study addressing various aspects of electric utility
competition.
1974 - 1975 Independent Economic Consultant
Advised telephone equipment manufacturers concerning cost and
rate development for competitive telephone offerings, analyzed
alternative travel agent compensation arrangements and
examined nonbank activity by bank holding company firms.
1973 - 1974 Program of Policy Studies in Science and Technology
Research Staff
1973 Urban Institute
Research Staff
TESTIFYING EXPERIENCE
- Affidavit and Declaration on behalf of Alabama Power Company before the
Environmental Protection Agency in FOIA RIN 003111-99, concerning
appropriateness of protecting certain competively valuable documents from
public release, October 5, 2000.
- Affidavit on behalf of Northeast Utilities Service Company and Select
Energy Inc. before the Federal Energy Regulatory Commission in Docket No.
EL00-102-000, concerning the cost of providing ICAP to New England capacity
market, September 25, 2000.
- Affidavit on behalf of Alabama Power Company before the Federal
Communications Commission in P.A. No. 00-003, concerning appropriateness
of protecting certain competitively sensitive information from public
release, September 6, 2000.
- Affidavit on behalf of Gulf Power Company before the Federal Communications
Commission in P.A. No. 00-004, concerning appropriateness of protecting
certain competitively sensitive information from public release, September
6, 2000.
- Affidavit on behalf of Southern Company and Southern Energy, Inc. before
the Federal Energy Regulatory Commission in Docket No. EC00-121-000,
concerning whether the proposed spin-off of Southern Energy Inc. would
create competitive concerns, August 15, 2000.
- Affidavit on behalf of Northeast Utilities Service Company before the
Federal Energy Regulatory Commission in Docket No. EL00-62-001 and
ER00-2052-002 concerning proposed termination of ICAP market and proposed
mitigation of ICAP prices, May 30, 2000.
<PAGE> 265
Exhibit APP-301
Page 3 of 14
- Prepared Rebuttal Testimony on behalf of Detroit Edison Company before the
Michigan Public Service Commission in Case No. U-12134 concerning the
design of a code of conduct for implementing retail customer choice, March
21, 2000.
- Affidavit on behalf of Split Rock Energy LLC in Docket No. ER00-1857-000
concerning Split Rock LLC's application for market based pricing authority,
March 10, 2000.
- Affidavit on behalf of Baltimore Gas and Electric Company, Calvert Cliffs,
Inc., Constellation Enterprises, Inc. and Constellation Generation, Inc. in
Docket No. EC00-___-000 and on behalf of Baltimore Gas and Electric
Company, Calvert Cliffs, Inc., Constellation Generation, Inc., and
Constellation Power Source, Inc. in Docket No. ER00-___-000 concerning the
application of Calvert Cliffs, Inc. and Constellation Generation, Inc. for
market based pricing authority, February 11, 2000.
- Deposition in the matter of Cleveland Thermal Energy Company v. Cleveland
Electric Illuminating Company, Case No. 1: 97 CV 3023, United States
District Court, Northern District of Ohio, Eastern Division, October 15,
December 7 and December 8, 1999, concerning competitive issues and damages.
- Supplemental Expert Report on behalf of Cleveland Electric Illuminating
Company in Cleveland Thermal Energy Corp. v. Cleveland Electric
Illuminating Company, Case No. 1: 97 CV 3023, United States District Court,
Northern District of Ohio, Eastern Division, December 1, 1999, concerning
damages issues.
- Expert Report on Behalf of Cleveland Electric Illuminating Company in
Cleveland Thermal Energy Corp. v. Cleveland Electric Illuminating Company,
Case No. 1: 97 CV 3023, United States District Court Northern District of
Ohio, Eastern Division, September 27, 1999, concerning allegations that a
clause giving Cleveland Electric Illuminating Company the right to purchase
electricity at avoided costs from a cogeneration plant that Cleveland
Thermal Energy Corp. would have constructed was anticompetitive and an
unreasonable restraint of trade, and computing damages.
- Deposition in the matter of Florida Municipal Power Agency v. Florida
Power & Light Company, Case No. 92-35-CIV-ORL22C, United States District
Court, Middle District of Florida, Orlando Division, concerning damages and
market issues, August 31, 1999.
- Expert Report on Behalf of Florida Power & Light Company in Florida
Municipal Agency v. Florida Power & Light Company in Case No.
92-35-CIV-ORL22C, United States District Court, Middle District of Florida,
Orlando Division, concerning damages and market issues, August 26, 1999.
- Affidavit on behalf of AmerGen Energy Company before the Federal Energy
Regulatory Commission in Docket Nos. EC99-104-000 and ER99-754-001
concerning AmerGen's proposed acquisition of the Clinton nuclear unit,
August, 1999.
- Affidavit on behalf of AmerGen Energy Company before the Federal Energy
Regulatory Commission in Docket Nos. EC99-98-000 and ER99-754-002
concerning AmerGen's proposed acquisition of the Nine Mile Point 1 nuclear
unit and a portion of the Nine Mile Point 2 nuclear unit, July, 1999.
<PAGE> 266
Exhibit APP-301
Page 4 of 14
- Affidavit on behalf of Minnesota Power, Inc. before the Federal Energy
Regulatory Commission in Docket No. ER99-3586-000 concerning Minnesota
Power's application for market based pricing authority, July, 1999.
- Deposition in the matter of Allegheny Energy Inc. v. DQE, Inc., Civ. A.
No. 98-16396 (RJC), United States District Court, Western District of
Pennsylvania, June 11, 1999, concerning issues relating to the value of
plaintiff's generating assets.
- Affidavit on behalf of Public Service Electric and Gas Company (PSEG)
before the Federal Energy Regulatory Commission concerning PSEG's request
to transfer its generating assets to an affiliate in Docket No. EC
99-____-000, June 1999.
- Expert Report on behalf of Allegheny Energy in Allegheny Energy Inc. v.
DQE, Inc. Civ. A. No. 98-16396 (RJC), United States District Court, Western
District of Pennsylvania, May 17, 1999, concerning issues relating to the
value of plaintiff's generating assets.
- Affidavit on behalf of Baltimore Gas & Electric (BG&E) Company before the
Federal Energy Regulatory Commission concerning BG&E's application for
market based pricing authority in Docket No. ER 99-2948-000, May 13, 1999.
- Affidavit on behalf of Florida Power & Light in Florida Municipal Power
Agency v. Florida Power & Light Co., Case No. 92-35-CIV-ORL-22 concerning
legitimacy of Florida Power & Light's conduct, March 22, 1999.
- Affidavit on behalf of PECO Energy before the Federal Energy Regulatory
Commission concerning PECO's application of market based pricing authority
in Docket No ER 99-1872-000, February, 1999.
- Affidavit on behalf of Northeast Utilities before the Federal Energy
Regulatory Commission concerning Northeast Utilities application for market
based pricing authority in Docket No. ER 99-1829-000, February, 1999.
- Affidavit on behalf of AmerGen Energy Company, LLC (AmerGen) before the
Federal Energy Regulatory Commission in Docket Nos. EC99-11-000,
EL99-13-000 and ER99-754-000 concerning (i) AmerGen's acquisition of Three
Mile Island No. 1 from GPU, Inc. and (ii) AmerGen's application for market
based pricing authority, November, 1998.
- Affidavit on behalf of Constellation Energy Source, Inc. (CES) before the
Federal Energy Regulatory Commission in Docket No. ER99-198-000 concerning
CES's application for market based pricing authority, October 14, 1998.
- Affidavit on behalf of Select Energy, Inc. (Select) before the Federal
Energy Regulatory Commission in Docket No. ER99-14-000 concerning Select's
application for market based pricing authority, October 1, 1998.
- Rebuttal Testimony on Retail Market Power Issues on behalf of Mississippi
Power Company, before the Mississippi Public Service Commission in Docket
No. 96-UA-389 concerning whether Mississippi Power Company will be able to
exercise market power in deregulated retail markets in Mississippi,
September 11, 1998.
<PAGE> 267
Exhibit APP-301
Page 5 of 14
- Prepared Testimony and Report on Retail Market Power Issues on behalf of
Mississippi Power Company, before the Mississippi Public Service Commission
in Docket No. 96-UA-389, concerning whether Mississippi Power Company will
be able to exercise market power in deregulated retail markets in
Mississippi, August 7, 1998.
- Affidavit on behalf of Southern California Edison Company to the Federal
Energy Regulatory Commission concerning market power issues associated with
the supply of ancillary services to the California ISO, July 13, 1998.
- Prepared Rebuttal Testimony on Behalf of Public Service Electric & Gas
Company, with Paul Joskow, before the State of New Jersey, Board of Public
Utilities, in Docket Nos. EX94120585Y, E097070457, E097070460, E097070463
and E097070466, responding to market power issues raised by intervenor
witnesses, including in particular the role of transmission constraints in
market power analyses, appropriate mitigation measures for "load pocket"
situations, proper standards for granting market based pricing authority,
the role of transitional mechanisms in mitigating market power concerns and
the use and role of market simulations in addressing market power topics,
April 13, 1998.
- Prepared Rebuttal Testimony on Behalf of Atlantic City Electric Company,
with Paul Joskow, before the State of New Jersey, Board of Public
Utilities, in Docket Nos. EX94120585Y, E097070457, E094770460, E09707463
and E097070466, responding to market power issues raised by intervenor
witnesses, including in particular the role of transmission constraints in
market power analyses, appropriate mitigation measures for "load pocket"
situations, proper standards for granting based pricing authority and the
use and role of market simulations in addressing market power topics, April
13, 1998.
- Prepared Additional Supplemental Direct Testimony on behalf of Ohio Edison
and Centerior Energy, before the Federal Energy Regulatory Commission,
Docket No. EC97-5-000, concerning the competitive analyses associated with
Ohio Edison's merger with Centerior Energy, August 8, 1997.
- Prepared Testimony on behalf of Public Service Electric & Gas Company on
Market Power Issues, with Paul Joskow, before State of New Jersey, Board of
Public Utilities, concerning market power issues associated with PSE&G's
proposal to implement retail customer choice in its competitive filings in
New Jersey, July 30, 1997.
- Affidavit on behalf of Union Electric Development Corporation before the
Federal Energy Regulatory Commission in Docket No. ER97-3663-000,
concerning Union Electric Development Corporation's request for the right
to make wholesale bulk power sales at market-determined prices, July 8,
1997.
- Affidavit on behalf of Union Electric Company before the Federal Energy
Regulatory Commission in Docket No. ER97-3664-000, concerning Union
Electric's request for the right to make wholesale bulk power sales at
market-determined prices, July 8, 1997.
- Rebuttal Testimony on Reopening on behalf of Union Electric Company and
Central Illinois Public Service Company, before the Illinois Commerce
Commission in Docket No. 95-0551, addressing competitive issues raised by
witnesses for intervenors and the staff of the ICC in response to previous
testimony, May 23, 1997.
<PAGE> 268
Exhibit APP-301
Page 6 of 14
- Rebuttal Testimony on behalf of Wisconsin Power and Light Company,
Interstate Power Company and IES Industries, Inc., before the Public
Service Commission of Wisconsin in Docket No. 6680-UM-100, responding to
concerns raised by intervenors regarding competitive issues associated with
the proposed merger of the three companies, May 20, 1997.
- Direct Testimony on Reopening on behalf of Union Electric Company and
Central Illinois Public Service Company, before the Illinois Commerce
Commission in Docket No. 95-0551, responding to the ICC's request that
applicants apply the screening analysis contained in Appendix A of the
Federal Energy Regulatory Commission's Order 592 to the effects of the
proposed merger on existing and future Illinois retail markets, April 14,
1997.
- Prepared Rebuttal Testimony on behalf of IES Utilities Inc., Interstate
Power Company, Wisconsin Power & Light Company, South Beloit Water, Gas &
Electric Company, Heartland Energy Services and Industrial Energy
Applications, Inc., before the Federal Energy Regulatory Commission in
Docket No. EC96-13-000, responding to issues raised by intervenors
concerning the proposed merger and the application of the screening
analysis contained in Appendix A of FERC's Order 592, April 14, 1997.
- Affidavit on behalf of Constellation Power Source, Inc. before the Federal
Energy Regulatory Commission in Docket No. ER97-2261-000, concerning
Constellation's request for the right to make wholesale bulk power sales at
market-determined prices, March 25, 1997.
- Prepared Supplemental Direct Testimony on behalf of Ohio Edison Company,
Pennsylvania Power Company, The Cleveland Electric Illuminating Company and
The Toledo Edison Company, before the Federal Energy Regulatory Commission
in Docket No. EC97-5-000, concerning the application of the screening
analysis contained in Appendix A of FERC Order 592 to the applicants'
proposed merger, March 20, 1997.
- Prepared Additional Direct Testimony on behalf of IES Utilities Inc.,
Interstate Power Company, Wisconsin Power & Light Company, South Beloit
Water, Gas & Electric Company, Heartland Energy Services and Industrial
Energy Applications, Inc., before the Federal Energy Regulatory Commission
in Docket No. EC96-13-000, concerning the application of the screening
analysis contained in Appendix A of FERC Order 592 to the applicants'
proposed merger, February 27, 1997.
- Prepared Rebuttal Testimony on behalf of Union Electric Company and Central
Illinois Public Service Company before the Federal Energy Regulatory
Commission in Docket Nos. EC96-7-000, et al. addressing competitive issues
related to the proposed merger of Union Electric Company and Central
Illinois Public Service Company, January 13, 1997.
- Affidavit on behalf of Union Electric Company and Central Illinois Public
Service Company before the Federal Energy Regulatory Commission in Docket
Nos. EC96-7-000, et al. concerning the effect of the FERC's Policy
Statement on mergers (Order No. 592) on the proposed merger or Union
Electric Company and Central Illinois Public Service Company, January 13,
1997.
- Prepared Supplemental Direct Testimony on behalf of Union Electric Company
and Central Illinois Public Service Company before the Federal Energy
Regulatory Commission in Docket Nos. EC96-7-000, et al. concerning the
effects of transmission constraints on the potential to exercise market
power as a result of the proposed merger of Union Electric and Central
Illinois Public Service, November 15, 1996.
<PAGE> 269
Exhibit APP-301
Page 7 of 14
- Direct Testimony on behalf of Ohio Edison Company and Centerior before the
Federal Energy Regulatory Commission in Docket No. EC97-5-000 concerning
the effect of the proposed merger of Ohio Edison and Centerior on market
power and competition, November 8, 1996.
- Prepared Direct Testimony on behalf of Union Electric Company before the
Missouri Public Service Commission in Case No. EM-96-149, concerning the
effects on various market power concerns of the proposed merger between
Union Electric Company and Central Illinois Public Service Company,
November 1, 1996.
- Testimony on behalf of Virginia Electric and Power Company in the matter of
Gordonsville Energy, L.P. v. Virginia Electric and Power Company before the
Circuit Court of the City of Richmond, Case No. LA-2266-4, concerning
damages suffered by VEPCO as a result of a NUG outage, and the
appropriateness of a liquidated damages provision in the contract between
VEPCO and the NUG, October 23, 1996.
- Prepared Direct Testimony on behalf of Southern Company Services, Inc.
before the Federal Energy Regulatory Commission in Docket No. ER96-780-000,
concerning whether constraints on the Florida/Southern interface give
Southern the ability to exercise market power, September 23, 1996.
- Deposition in the matter of Gordonsville Energy, L.P. v. Virginia Electric
and Power Company before the Circuit Court of the City of Richmond, Case
No. LA-2266-4, concerning damages suffered by VEPCO as a result of a NUG
outage, September 17, 1996.
- Prepared Rebuttal Testimony on behalf of Public Service Company of New
Mexico before the Federal Energy Regulatory Commission in Docket No.
ER95-1800-000, et al., addressing market power issues raised by intervenors
in response to previous testimony, August 30, 1996.
- Prepared Testimony on behalf of Public Service Company of New Mexico before
the Federal Energy Regulatory Commission in Docket No. ER96-1551-000,
concerning whether PNM possesses market power in transmission-constrained
areas, July 10, 1996.
- Affidavit on behalf of Central Louisiana Electric Company before the
Federal Energy Regulatory Commission in Docket No. ER96-2677-000,
concerning CLECO's request for the right to make wholesale bulk power sales
at market-determined prices, July 9, 1996.
- Supplemental Direct Testimony on behalf of IES Utilities Inc., Interstate
Power Company, Wisconsin Power & Light Company, South Beloit Water, Gas &
Electric Company, Heartland Energy Services and Industrial Energy
Applications, Inc., before the Federal Energy Regulatory Commission in
Docket No. EC96-13-000, examining the effects of the proposed formation of
a regional Independent System Operator on the analyses and conclusions
contained in previous testimony in support of the companies' proposed
merger, June 5, 1996.
- Prepared Testimony on behalf of Minnesota Power & Light Company before the
Federal Energy Regulatory Commission in Docket No. EC95-16-000, concerning
Minnesota Power & Light's request for the right to make wholesale bulk
power sales at market-determined prices, May 16, 1996.
- Prepared Rebuttal Testimony on behalf of IES Industries Inc., Interstate
Power Company and WPL Holdings, Inc. before the Iowa Utilities Board in
Docket No. SPU-96-6 addressing market power and competition issues raised
by intervenors in response to previous merger testimony, April 22, 1996.
<PAGE> 270
Exhibit APP-301
Page 8 of 14
- Prepared Direct Testimony on behalf of IES Utilities Inc., Interstate Power
Company, Wisconsin Power & Light Company, South Beloit Water, Gas &
Electric Company, Heartland Energy Services and Industrial Energy
Applications, Inc., before the Federal Energy Regulatory Commission in
Docket No. EC96-13-000, concerning the effects of their proposed merger on
market power and competition, February 29, 1996.
- Deposition in the matter of Westmoreland-LG&E Partners v. Virginia Electric
and Power Company, Case No. LX-2859-1, concerning interpretation of
capacity payment provisions in power purchase agreement under which
Westmoreland-LG&E sells output of nonutility generator to VEPCO, February
23, 1996 and October 9, 1998.
- Prepared Testimony on behalf of Union Electric Company and Central Illinois
Public Service Company before the Federal Energy Regulatory Commission in
Docket Nos. EC96-7-000 and ER96-679-000, concerning the effects of their
proposed merger on market power and competition, December 22, 1995.
- Prepared Testimony on behalf of Northeast Utilities before the Federal
Energy Regulatory Commission in Northeast Utilities Service Company, Docket
No. ER95-1686-000, concerning FERC's generation dominance standard in
support of Northeast Utilities' request for market-based pricing authority,
November 13, 1995.
- Sur-reply affidavit on behalf of Rochester Gas & Electric before the U.S.
District Court, Western District of New York, in Kamine/Besicorp Allegheny
L.P. v. Rochester Gas & Electric Corporation, Case No. 95-CIV-6045L, in
response to motion by Kamine/Besicorp Allegheny L.P. for a preliminary
injunction, July 10, 1995.
- Prepared Supplemental Rebuttal Testimony on Transmission NOPR Issues on
behalf of Florida Power & Light Company before the Federal Energy
Regulatory Commission in Florida Power & Light Company, Docket Nos.
ER93-465-000, et al., addressing transmission NOPR issues raised by FERC
Staff and Intervenors, May 19, 1995.
- Prepared Direct Testimony on Transmission NOPR Issues on behalf of Florida
Power & Light before the Federal Energy Regulatory Commission in Florida
Power & Light Company, Docket Nos. ER93-465-000, et al., concerning the
effects of FERC's recent Notice of Proposed Rulemaking on issues in FPL's
ongoing case, April 25, 1995.
- Affidavit on behalf of Rochester Gas & Electric before the U.S. District
Court, Western District of New York, in Kamine/Besicorp Allegheny L.P. v.
Rochester Gas & Electric Corporation, Case No. 95-CIV-6045L, in support of
its opposition to a request by Kamine/Besicorp Allegheny L.P. for a
temporary restraining order, March 9, 1995.
- Testimony on behalf of Virginia Power before the Circuit Court of the City
of Richmond in Case No. LW-730-4, Doswell Limited Partnership v. Virginia
Electric Power Company concerning the level of fixed gas transportation
costs associated with the proxy unit which forms the basis for VEPCO's
payments to Doswell, March 2, 1995.
- Prepared Rebuttal Testimony on behalf of American Electric Power Service
Corporation before the Federal Energy Regulatory Commission in Docket No.
ER93-540-001 addressing issues concerning FERC's new comparability standard
and its implications for AEP's transmission service offerings, January 17,
1995.
<PAGE> 271
Exhibit APP-301
Page 9 of 14
- Deposition on behalf of El Paso Electric Company and Central and South
West Services, Inc. before the Federal Energy Regulatory Commission in
Docket Nos. EC94-7-000 and ER94-898-000 concerning "comparability" and
other transmission issues, December 22, 1994.
- Prepared Rebuttal Testimony on behalf of Florida Power & Light Company
before the Federal Energy Regulatory Commission in Florida Power & Light
Company, Docket Nos. ER93-465-000, et al. concerning market power and
competitive issues, comparability and other transmission issues, wholesale
electric service tariff revisions, and issues concerning interchange
contract revisions, December 16, 1994.
- Prepared Rebuttal Testimony on behalf of El Paso Electric Company and
Central and South West Services, Inc., before the Federal Energy Regulatory
Commission, Dockets Nos. EC94-7-000 and ER94-898-000, concerning network
transmission service and point-to-point transmission service, December 12,
1994.
- Prepared Direct Testimony on behalf of Midwest Power Systems, Inc. and
Iowa-Illinois Gas and Electric Company before the Federal Regulatory
Commission, Docket No. EC95-4-000, concerning competitive issues raised by
their proposed merger to form MidAmerican Energy Company, November 10,
1994.
- Deposition on behalf of Florida Power Corporation in Orlando Cogen, Inc.,
et al., v. Florida Power Corporation, Case No. 94-303-CIV-ORL-18, US
District Court in and for the Middle District of Florida, Orlando Division,
involving a contract dispute between FPC and one of its NUG suppliers,
August 30, 1994.
- Prepared Direct Testimony on Comparability Issues on behalf of Florida
Power & Light Company in Florida Power & Light Company, Docket Nos.
ER93-465-000 and ER93-922-000 concerning a discussion of the differences
between types of transmission services, usage of transmission systems by
their owners, transmission services that FPL provides, and how those
services compare and contrast with FPL's own uses of the transmission
system, August 5, 1994.
- Prepared Answering Testimony on behalf of Florida Power & Light Company in
Florida Power & Light Company, Docket Nos. ER93-465-000 and ER93-922-000
concerning (i) whether municipal systems should receive billing credits for
certain transmission facilities which they own which were argued to be part
of an "integrated" transmission grid, and (ii) FPL's obligation to sell
wholesale power under its Nuclear Regulatory Commission antitrust license
conditions, July 7, 1994.
- Deposition on behalf of Virginia Electric & Power Co. in re: Doswell
Limited Partnership v. Virginia Electric & Power Co., Case No. LW-730-4,
Circuit Court for the City of Richmond, involving an alleged fraud and
breach of contract relating to payments by VEPCO to one of its NUG
suppliers, April 5, 1994.
- Prepared Final Rebuttal Testimony on behalf of Central Louisiana Electric
Company before the Federal Energy Regulatory Commission in Docket No.
ER93-498-000, examining an allegation of predatory pricing, March 16, 1994.
- Prepared Rebuttal Testimony on behalf of Central Louisiana Electric Company
before the Federal Energy Regulatory Commission in Docket No. ER93-498-000,
examining an allegation of a municipal joint action agency that Central
Louisiana's contract to provide bulk power service to a new municipal
system customer constituted predatory pricing, December 23, 1993.
<PAGE> 272
Exhibit APP-301
Page 10 of 14
- "Comments on the Commerce Commission's Draft Determination Concerning Trans
Power's Proposal to Recover Fixed/Sunk Transmission Costs," testimony on
competitive issues prepared at the request of The Electricity Industry
Committee, New Zealand, November 30, 1993.
- Prepared Direct Testimony on behalf of Florida Power & Light Company in
Florida Power & Light Company, Docket Nos. ER93-465-000 and ER93-922-000
concerning competitive implications of wholesale tariff revisions,
interchange contract revisions and a proposed "open access" transmission
tariff, November 26, 1993.
- Deposition on Behalf of Florida Power & Light in Florida Municipal Power
Agency v. Florida Power & Light Co. Case No. 92-35-CIV-ORL-22 concerning
damage related issues, July 21 and 22, 1993.
- Affidavit on behalf of Florida Power & Light in Florida Municipal Power
Agency v. Florida Power & Light Co. Case No. 92-35-CIV-ORL-22 concerning
damage related issues, July 14, 1993.
- Prepared Direct Testimony on behalf of the Detroit Edison Company In the
Matter of the Application of the Association of Businesses Advocating
Tariff Equity for Approval of an experimental retail wheeling tariff for
Consumers Power Company, Case No. U-10143, and In the Matter on the
Commission's own motion, to consider approval of an experimental retail
wheeling tariff for The Detroit Edison Company, Case No. U-10176 before the
Michigan Public Service Commission, March 1, 1993.
- Deposition on behalf of Florida Power & Light in Florida Municipal Power
Agency vs. Florida Power & Light Company, Case No. 92-35-CIV-ORL-22,
concerning relevant markets, market power and competitive issues, February
25, 1993.
- Deposition in Tucson Electric Power Company v. SCE Corporation, et al.,
Superior Court of the State California, Case No. 628170, June 19, 1992.
- Affidavit on behalf of Iowa Power Inc. and Iowa Public Service Company,
Federal Energy Regulatory Commission, Concerning the Competitive Effects of
a Merger of the Two Companies, 1991.
- Testimony on behalf of Defendants Union Electric and Missouri Utilities,
in City of Malden, Missouri v. Union Electric Company and Missouri
Utilities Company, U.S. District Court, Eastern District of Missouri,
Southeastern Division, Civil Action No. 83-2533-C, 1988.
- Testimony on behalf of Defendant Union Electric, in City of Kirkwood,
Missouri v. Union Electric Company, U.S. District Court, Eastern District
of Missouri, Civil Action No. 86-1787-C-6 (deposition testimony), 1987.
- Testimony on behalf of Defendant Union Electric Company, in Citizens
Electric Corporation v. Union Electric Company, U.S. District Court,
Eastern District of Missouri, Eastern Division, Civil Action No.
83-2756C(c), 1986.
- Testimony on behalf of Advo-System, Inc., before the Postal Rate
Commission, Docket No. R84-1, Concerning Rates for Third Class Mail, 1984.
- Testimony on behalf of D/FW Signal, Inc., before the Federal
Communications Commission, Docket No. CC83-945, Concerning Cellular
Telephone Service in Dallas-Fort Worth, 1983.
<PAGE> 273
Exhibit APP-301
Page 11 of 14
- Testimony on behalf of the Department of Defense, before the Montana
Public Service Commission, Docket No. 82.2.8, Concerning Telephone Service
Rate Structure, 1982.
- Testimony on behalf of Multnomah County, before the Public Utility
Commissioner of Oregon, Docket UF 3565, Concerning Telephone Service Rate
Structure, 1980.
- Testimony on behalf of the Louisiana Consumer League, before the Louisiana
Public Service Commission, Docket No. U-14078, Concerning Marginal Cost
Pricing for Louisiana Power and Light Company, 1979.
- Testimony on behalf of the State of Oregon, City of Portland, and County of
Multnomah, before the Public Utility Commissioner of Oregon, Dockets UF3342
and UF3343, concerning Rates for Centrex and ESSX Telephone Service, 1978.
SELECTED REPORTS
- "An Economic Assessment of the Benefits of Repealing PUHCA," with John
Landon, Ajay Gupta and Virginia Perry-Failor, prepared for Mid-American
Energy Holdings, April 2000.
- Updated Market Power Analysis for Detroit Edison Company, concerning
Detroit Edison Company's market based pricing authority, submitted to the
Federal Energy Regulatory Commission, December 17, 1999.
- Report of Ameren to the Public Service Commission of Missouri on Market
Power Issues, concerning whether Ameren, created by the merger of Union
Electric Company and Central Illinois Public Service Company, is likely to
have market power if deregulation and retail competition are introduced in
Missouri, February 27, 1998.
- "Supporting Companies' Report on Horizontal Market Power Analysis," with
Paul Joskow, concerning analysis of market power issues in connection with
a proposed reorganization of the PJM Pool, July 14, 1997.
- "International Electricity Sector Investment by US Electric Utilities,"
with Graham Hadley, Paul Hennemeyer and Barbara MacMullen, prepared for The
Kansai Electric Power Company, Inc., March 5, 1997.
- "Report on Horizontal Market Power Issues," with Paul Joskow, prepared for
Southern California Edison Company in FERC Docket No. ER96-1663-000, May
29, 1996.
- "Recent Developments in North American Electric Generation Capacity
Procurement Systems," with Mahim Chellappa, prepared for Electricite de
France (EDF), Paris, France, August 1994.
- "Comments on Transmission Reform Proposals," report prepared for the
Edison Electric Institute, October 1993.
- "Sunk Transmission Cost Recovery Issues," report prepared for The
Electricity Industry Committee, New Zealand, September 1, 1993.
- "Opportunity Cost Pricing for Electric Transmission: An Economic
Assessment," report prepared for Edison Electric Institute, June 1992.
<PAGE> 274
Exhibit APP-301
Page 12 of 14
- "Transmission Access and Pricing: What Does A Good `Open Access' System
Look Like," NERA Working Paper #14, January 1992.
- "Evaluation of Qualifying Facility Proposals," prepared for Florida Power
Corporation, March 1991.
- "Design of Capacity Procurement Systems," prepared for Electricite de
France, January 1991.
- "Issues in the Design of Generating Capacity Procurement Systems," prepared
for TransAlta Utilities, January 1991.
- "Government Regulators and Market Power Issues," prepared for Edison
Electric Institute, January 1991.
- "A Critique and Evaluation of the Large Public Power Council's Transmission
Access and Pricing Proposal," prepared for Edison Electric Institute,
December 1990.
- "The Effects of a Premature Shutdown of the Trojan Nuclear Power Plant,"
prepared for Portland General Electric Company, October 1990.
- "An Examination of the Proper Role for Utilities in Promoting Conservation
Expenditures," prepared for Public Service Electric & Gas Company with T.
Scott Newlon, 1990.
- "Issues Concerning Selection Criteria Development for Capacity RFPs,"
prepared for the Bonneville Power Administration, February 15, 1990.
- "Nonutility Generators and Bonneville Power Administration Resource
Acquisition Policy," prepared for the Bonneville Power Administration, with
David L. Weitzel, January 31, 1990.
- "An Evaluation of Resource Solicitation Alternatives," prepared for the
Bonneville Power Administration, January 31, 1990.
- "Approaching the Transmission Access Debate Rationally," Transmission
Research Group Working Paper Number 1, with Joe D. Pace, November 1987.
- "The Essential Facilities Doctrine," NERA, June 1985.
- "The Nuclear Regulatory Commission's Antitrust Review Process: An
Analysis of the Impacts," Transcomm, Inc., prepared for the U.S. Department
of Energy, 1981.
- "Competitive Aspects of Utility Involvement in Cogeneration and Solar
Programs," Transcomm, Inc., prepared for the U.S. Department of Energy,
June 1981.
- "An Appraisal of Antitrust Review Extension in the Context of Small
Utility Fuel Use Act Compliance," Transcomm, Inc., prepared for the U.S.
Department of Energy, July 28, 1980.
- "Analysis of Proposed License Conditions with Respect to Antitrust
Deficiencies," Transcomm, Inc., prepared for the U.S. Nuclear Regulatory
Commission, 1978.
- "Analysis of NRC Staff's Proposed License Conditions for Midland Units,"
Transcomm, Inc., prepared for the U.S. Nuclear Regulatory Commission,
August 7, 1978.
<PAGE> 275
Exhibit APP-301
Page 13 of 14
SELECTED SPEECHES
- Presentation to the Board of Directors of the Salt River Project on Code
of Conduct Issues Associated with Industry Restructuring, November 9, 1998
- "FERC's Approach To Addressing Horizontal Market Power in Electric
Mergers," speech presented to Infocast Conference on Utility Mergers &
Acquisitions, Washington, D.C., July 17, 1998.
- "Problems in Applying the Appendix A Analytical Screen," speech presented
to the Edison Electric Institute Workshop on Practical Applications of the
FERC Merger Policy Guidelines, Arlington, Virginia, April 1, 1997.
- "Evolving Market Power Issues in the Context of Electric Restructuring,"
speech presented to Eastern Mineral Law Foundation Forum on Natural
Resources and Energy Law, Sanibel Island, Florida, February 13, 1997.
- "An Overview of Antitrust in the Electric Industry," speech presented to
Antitrust Law & Economics for the Electric Industry, sponsored by Energy
Business, Inc., Washington, D.C., February 22, 1996.
- "Moving From Here to There: Some Implications for Electric Transmission,"
speech presented to the Infocast Power Industry Forum, Palm Springs,
California, February 17, 1995.
- "What Does `Comparability' Really Mean?," speech presented to The Federal
Energy Bar Association, Washington, D.C., November 17, 1994.
- "Current Transmission Topics" and "Trans Alta's Unbundled Rate
Proposal," presented to the Canadian Electrical Association, Montreal, PQ,
Canada, May 9, 1994.
- "Retail Wheeling Issues," speech presented to the Edison Electric Institute
National Accounts Workshop, Atlanta, Georgia, February 7, 1994.
- "Retail Wheeling: Doing It the Right Way," speech presented to the Retail
Wheeling Conference, Denver, Colorado, November 8, 1993.
- "Retail Wheeling," speech presented to the Missouri Valley Electric
Association Division Conference, Kansas City, Missouri, October 22, 1993.
- "An Economic Perspective on Current Transmission Pricing Issues," speech
presented to the Edison Electric Institute 1993 Fall Legal Committee
Meeting, Minneapolis, Minnesota, October 7, 1993.
- "Characteristics of a `Good' Retail Wheeling System," speech presented to
the Second Annual Electricity Conference sponsored by Executive
Enterprises, Inc., Washington, D.C., April 21-22, 1993.
- "Characteristics of a `Good' Retail Wheeling System," speech presented to
the Electric Utility Business Environment Conference sponsored by Electric
Utility Consultants, Inc., Denver, Colorado, March 16-17, 1993.
- "Change in the Industry," seminar presentation on privatization and service
unbundling presented to Ontario Hydro management and special strategy task
force, Ontario, Canada, February 3, 1993.
<PAGE> 276
Exhibit APP-301
Page 14 of 14
- "The U.S. Experience and What Is To Come," speech presented to NERA Seminar
on Competition in the Regulated Industries (Electric/Telecommunications),
Rye Town Hilton, Rye Town, New York, October 30, 1992.
- "Emerging Transmission Pricing Issues," speech presented to Electric
Utility Consultants, Inc.'s 3rd Annual Transmission & Wheeling Conference,
Chicago, Illinois, September 22-23, 1992.
- "Emerging Transmission Pricing Issues," speech presented to Executive
Enterprises, Inc., 1992 Electricity Conference: Restructuring the
Electricity Industry, Washington, D.C., September 15-16, 1992.
- "A Pragmatic Look at Open Access," presented to DOE/NARUC Workshop on
Electricity Transmission, Stockbridge, Massachusetts, June 2, 1992.
- "Some Thoughts About Open Access," presented to EMA's Issues and Outlook
Forum, Atlanta, Georgia, May 5, 1992.
- "Transmission Access: How Should We Proceed?" Speech presented to the
Second Annual Transmission and Wheeling Conference, Denver, Colorado,
November 21, 1991.
- "Can We Implement Reasonable Transmission Pricing and Access Procedures?"
presented to the Edison Electric Institute System Planning Committee,
Dallas, Texas, October 24, 1990.
- "Issues in the Design of Competitive Bidding Systems," presented at the
Pennsylvania Electric Association System Planning Meeting," 1990.
- "Should We Use Opportunity Cost Pricing for Transmission?" presented to
the Edison Electric Institute Interconnection Arrangements Committee, 1990.
- "Recent Changes in the Electric Power Industry and Pressures on the
Transmission System," presented at seminar "Competitive Electricity: Why
the Debate?" Sponsored by the Electricity Consumers Resource Council, 1988.
- "Some Thoughts on New Transmission Access and Pricing Proposals," presented
at conference "Transmission Pricing and Access: Reinventing the Wheel,"
sponsored by Cogeneration and Independent Power Coalition of America and
American Cogeneration Association, 1988.
<PAGE> 277
EXHIBIT NO. APP-302
<PAGE> 278
Exhibit APP-302 1 of 1
LIST OF ABBREVIATIONS
AEC Allegheny Electric Cooperative
AEP American Electric Power Company
Allegheny Allegheny Energy
AMP-Ohio American Municipal Power-Ohio
ATC Available Transmission Capacity
ATSI American Transmission Systems, Inc.
CNG Consolidated Natural Gas
Columbia Gas Columbia Gas of Virginia
CPP Cleveland Public Power
DetEd Detroit Edison Company
DPL Dayton Power & Light Company
DQE Duquesne Light Company
ECAR East Central Area Reliability Coordination Agreement
EIA Energy Information Administration
EME Edison Mission Energy
FERC Federal Energy Regulatory Commission
FirstEnergy FirstEnergy Corporation
GPU GPU, Inc.
Great Lakes Great Lakes Energy Partners, L.L.C.
HHI Herfindahl-Hirshmann Index
HoldCo Marble HoldCo, Inc.
ISO Independent System Operator
JCPL Jersey Central Power & Light Company
LDC local distribution company
MAAC Mid-Atlantic Area Council
MAIN Mid-America Interconnected Network, Inc.
MAPP Mid-Continent Area Power Pool
Marbel Marbel Energy Corporation
MECS Michigan Electric Coordinating System
MetEd Metropolitan Edison Company
National Fuel National Fuel Gas Company
NEPOOL New England Power Pool
NERC North American Electric Reliability Council
NUG non-utility generator
NYMEX New York Mercantile Exchange
NYPP New York Power Pool
O&M Operating & Maintenance
OASIS Open-Access Same-Time Information System
OVEC Ohio Valley Electric Company
Penelec Pennsylvania Electric Company
Pepco Potomac Electric Power Company
PJM Pennsylvania-New Jersey-Maryland Interconnection
POD Point of Delivery
POR Point of Receipt
PPL Pennsylvania Power & Light Company
RDI Resource Data International
RTO Regional Transmission Organization
SERC Southeastern Electric Reliability Council
SPP Southwest Power Pool
Tenneco Tenneco Energy Corporation
Texas Eastern Texas Eastern Gas Transmission Corporation
TTC Total Transmission Capacity
USEC United States Enrichment Corporation
VEPCO Virginia Electric & Power Company
Wellsboro Wellsboro Electric Company
<PAGE> 279
EXHIBIT NO. APP-303
<PAGE> 280
EXHIBIT NO. APP-303
Map of Destination Markets for FirstEnergy - GPU Merger.
Exhibit Intentionally Omitted.
<PAGE> 281
EXHIBIT NO. APP-304
<PAGE> 282
Exhibit No. APP-304 page 1 of 2
FIRST ENERGY AND GPU OFF - SYSTEM SALES
1997 - 1999
<TABLE>
<CAPTION>
FIRST ENERGY GPU
Purchasing Company MWH Revenues ($) MWH Revenues ($)
----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
IOUS
AEP 204,939 7,054,000
APS 154,950 3,795,000 88,288 2,229,058
Atlantic Electric - - 22,021 561,966
Baltimore Gas & Electric 417,994 7,554,000 2,255 520,992
Carolina Power & Light 9,773 320,000 2,342 412,964
Cinergy Services, Inc. 431,170 5,416,000 15,086 696,267
Commonwealth Edison 2,800 79,000 - -
Conectiv - - 303,913 8,742,084
Constellation Power 23,739 1,916,000 16,589 401,147
Delmarva Power & Light 5,900 114,000 1,542 70,024
Detroit Edison 1,352,764 6,745,000 10,669 391,998
DPL 249,768 8,851,000 - -
DQE 164,665 3,935,000 - -
Duke Power Co. 11,573 4,673,000 - -
Entergy 3,506 793,000 - -
First Energy - - 61,559 472,230
GPU 347,874 8,653,000
Illinois Power 5,250 102,000 - -
LGE 11,920 197,000 - -
MECS ** 474,753 11,669,000 - -
NIPS 4,839 135,000 - -
Northeast Utilities - - 14,211 176,397
NYPP 357,232 8,433,000 151,669 2,550,489
Ontario Hydro - - 500 12,005
OVEC 23,490 434,000 - -
PECO 196,018 4,565,000 34,516 1,356,348
Penn Power and Light 388,942 17,714,000 60,611 2,046,589
PEPCO 8,849,085 488,580,000 769 13,565
PJM * 396,785 11,990,000 10,425,420 333,838,284
PSEG 596,208 12,520,000 291,862 22,607,686
Southern 950 27,000 - -
VEPCO 11,091 612,000 92,545 2,424,075
WPL 9,600 177,000 - -
- -
MUNICIPAL SYSTEMS - -
-----------------
AMP-Ohio 1,752,364 72,332,000 - -
Berlin Borough - - 55,631 2,288,380
Borough of Goldsboro - - 14,263 788,486
Borough of Lewisberry - - 5,843 309,413
Borough of Middletown - - 165,920 1,659,200
Borough of Royalton - - 11,201 580,237
Butler Borough - - 290,525 8,439,375
Columbia 5,475 149,000 - -
CPP 14,630 3,693,000 - -
East Conemaugh Borough - - 17,729 754,107
Ellwood City 58,503 2,157,000 - -
Engle - - - -
Gerald - - - 41,604
Girard Borough - - 115,971 4,657,263
Grove City 100,449 3,378,000 - -
</TABLE>
<PAGE> 283
Exhibit No. APP-304 page 2 of 2
FIRST ENERGY AND GPU OFF - SYSTEM SALES
1997 - 1999
<TABLE>
<CAPTION>
FIRST ENERGY GPU
Purchasing Company MWH Revenues ($) MWH Revenues ($)
----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Grove City West 5,438 152,000 - -
Hooversville Borough - - 11,042 475,701
Lavallette Borough - - 32,253 1,009,874
Madison Borough - - 282,910 7,934,562
New Wilmington 48,872 2,225,000 - -
Painesville 106,868 2,824,000 - -
Pemberton Borough - - 15,312 429,657
Pike County Power & Light - - 848 42,887
Seaside Heights - - 69,605 2,129,345
Smethport Borough - - 43,796 1,823,738
Summerhill Borough - - 9,424 416,291
Wampum 10,672 512,000 - -
Wellsboro 228,227 7,458,000 115,590 4,406,620
WVPA 29,480 822,000 - -
Zelionopole - 178,000 - -
- -
OTHER - -
-----
Allegheny Electric Coop - - 922,240 47,341,471
Buckeye 1,882,041 66,100,000 - -
Marketers 1,935,056 60,652,000 1,660,569 54,673,434
NJ Pilot Program - - 114,715 2,865,478
Old Dominion Elec Coop - - 8,193 158,753
PA Pilot Program - - - 1,308,442
Penntech 2,163 -
Penntech Residential - 543,912
Redacted - - 1,517,003 66,854,574
System Sales 55,265 1,181,000 - -
----------------------------------------------------------------------------------------------------------------------------
- -
TOTAL SALES 20,940,918 840,866,000 17,079,113 591,456,972
</TABLE>
NOTES:
Total Sales = Sum of Sales from 1997, 1998, and 1999
* Excluding sales to utilities within PJM which are listed separately
** Excluding sales to Detroit Edison which are listed separately
SOURCES:
GPU sales taken from FERC Form 1 Filings (1997, 1998, 1999) First Energy sales
provided by First Energy.
<PAGE> 284
EXHIBIT NO. APP-305
<PAGE> 285
Exhibit APP-305 page 1 of 1
PRICES IN DESTINATION MARKETS
SYSTEM LAMBDAS FOR 1999 ($ PER MWH)
<TABLE>
<CAPTION>
SUMMER SUMMER SUMMER SUMMER SUMMER WINTER
SUPER PEAK I SUPER PEAK II SUPER PEAK III REST OF PEAK OFF PEAK SUPER PEAK
--------------- --------------- ----------------- --------------- ------------- --------------
<S> <C> <C> <C> <C> <C> <C>
AEP 17.96 15.30 14.65 13.30 11.62 14.10
Allegheny 150.41 124.54 52.23 20.06 20.02 22.10
DPL 17.16 18.20 15.93 14.07 13.37 15.58
DQE 693.59 269.59 68.59 27.54 22.56 30.66
FE 811.36 414.37 175.65 66.89 32.48 30.97
MECS 310.11 195.76 79.75 32.15 26.77 41.03
NYISO 42.92 49.53 57.36 49.64 25.10 29.62
PJMEAST 437.16 265.90 83.20 28.94 17.17 31.67
PJMWEST 436.80 246.82 81.62 27.55 16.97 30.70
VEPCO 31.34 29.47 25.89 21.70 16.20 22.29
</TABLE>
<TABLE>
<CAPTION>
WINTER WINTER SPRING/FALL SPRING/FALL SPRING/FALL
REST OF PEAK OFF PEAK SUPER PEAK REST OF PEAK OFF PEAK
---------------- ------------- -------------- --------------- -----------------
<S> <C> <C> <C> <C> <C>
AEP 12.94 11.73 14.36 13.30 11.78
Allegheny 19.15 17.28 22.84 19.85 17.79
DPL 14.00 13.27 15.00 14.53 13.52
DQE 20.87 16.39 37.22 24.56 19.27
FE 23.48 15.21 30.21 24.04 16.39
MECS 21.36 16.27 31.58 22.30 16.03
NYISO 35.03 24.64 28.48 33.24 21.15
PJMEAST 19.71 14.20 37.15 23.26 14.02
PJMWEST 19.16 13.92 34.95 22.73 13.88
VEPCO 16.76 14.82 24.03 18.56 14.77
</TABLE>
NYMEX FUTURES PRICES FOR 2001 ($ PER MWH)
SUMMER WINTER SPRING/FALL
PEAK PEAK PEAK
------------- --------------- ----------------
PJM 89.67 40.70 33.87
Cinergy 101.75 31.83 30.46
SOURCES
NYPP System Lambdas: www.NYISO.com.
System Lambdas for other Regions: FERC Form 714
NYMEX Futures Prices: www.NYMEX.com
<PAGE> 286
EXHIBIT NO. APP-306
<PAGE> 287
Exhibit APP-306 page 1 of 5
BASE CASE ECONOMIC CAPACITY
<TABLE>
<CAPTION>
SUMMER WINTER
-------------------------------------------------------- ------------------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak
---------------------------------- -------- --------- --------- --------- --------- ----------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
FE
Pre-Merger HHI 5,228 5,225 5,085 4,334 3,215 4,948 4,194 4,113
Post-Merger HHI 5,243 5,240 5,101 4,369 3,269 4,985 4,236 4,274
Change 15 15 16 36 54 37 42 161
FE Capacity (MW) 11,798 11,788 11,090 10,101 9,965 10,789 10,162 8,175
GPU Capacity (MW) 17 18 18 43 90 41 52 166
Merged Capacity (MW) 11,815 11,805 11,108 10,144 10,055 10,830 10,215 8,341
FE Market Share 71.6% 71.6% 70.5% 64.8% 54.5% 69.8% 63.9% 63.1%
GPU Market Share 0.1% 0.1% 0.1% 0.3% 0.5% 0.3% 0.3% 1.3%
Merged Market Share 71.7% 71.7% 70.6% 65.1% 55.0% 70.0% 64.2% 64.3%
PJM
Pre-Merger HHI 1,164 1,163 1,181 1,178 1,143 976 1,130 1,551
Post-Merger HHI 1,176 1,175 1,190 1,183 1,155 998 1,141 1,577
Change 12 12 9 5 12 22 11 26
FE Capacity (MW) 761 761 472 206 360 964 390 235
GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971
Merged Capacity (MW) 3,176 3,176 2,515 2,132 2,271 3,136 2,381 2,206
FE Market Share 1.4% 1.4% 1.0% 0.5% 1.1% 2.2% 1.0% 1.2%
GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.0% 5.4% 10.4%
Merged Market Share 5.8% 5.8% 5.5% 5.5% 6.7% 7.3% 6.4% 11.7%
AEP
Pre-Merger HHI 2,434 2,433 2,385 2,464 3,817 2,243 2,131 2,586
Post-Merger HHI 2,434 2,434 2,386 2,464 3,817 2,243 2,131 2,593
Change 1 1 1 1 1 0 1 7
FE Capacity (MW) 3,012 3,011 3,019 2,968 1,664 1,613 1,694 1,591
GPU Capacity (MW) 18 18 21 25 28 26 46 354
Merged Capacity (MW) 3,029 3,030 3,040 2,993 1,692 1,639 1,740 1,945
FE Market Share 6.6% 6.6% 6.7% 6.7% 4.8% 3.4% 3.5% 3.9%
GPU Market Share 0.0% 0.0% 0.0% 0.1% 0.1% 0.1% 0.1% 0.9%
Merged Market Share 6.6% 6.6% 6.7% 6.8% 4.9% 3.5% 3.6% 4.8%
</TABLE>
<TABLE>
<CAPTION>
SPRING / FALL
-----------------------------------
Destination Market Super Peak Off-Peak
---------------------------------- ----------- --------- -----------
<S> <C> <C> <C>
FE
Pre-Merger HHI 4,262 3,519 3,028
Post-Merger HHI 4,298 3,562 3,206
Change 35 43 178
FE Capacity (MW) 8,360 7,847 4,973
GPU Capacity (MW) 35 51 158
Merged Capacity (MW) 8,395 7,898 5,131
FE Market Share 64.3% 57.9% 53.0%
GPU Market Share 0.3% 0.4% 1.7%
Merged Market Share 64.6% 58.3% 54.6%
PJM
Pre-Merger HHI 940 1,059 1,288
Post-Merger HHI 967 1,077 1,320
Change 27 18 32
FE Capacity (MW) 979 460 262
GPU Capacity (MW) 1,885 1,747 1,717
Merged Capacity (MW) 2,864 2,207 1,979
FE Market Share 2.6% 1.5% 1.6%
GPU Market Share 5.1% 5.9% 10.3%
Merged Market Share 7.7% 7.4% 11.8%
AEP
Pre-Merger HHI 1,817 1,693 2,066
Post-Merger HHI 1,817 1,694 2,079
Change 1 1 13
FE Capacity (MW) 2,436 2,558 2,403
GPU Capacity (MW) 26 47 363
Merged Capacity (MW) 2,463 2,605 2,766
FE Market Share 5.7% 5.9% 6.6%
GPU Market Share 0.1% 0.1% 1.0%
Merged Market Share 5.8% 6.0% 7.6%
</TABLE>
<PAGE> 288
Exhibit APP-306, page 2 of 5
BASE CASE ECONOMIC CAPACITY
<TABLE>
<CAPTION>
SUMMER WINTER
-------------------------------------------------------- ------------------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak
---------------------------------- -------- --------- --------- --------- --------- ----------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
APS
Pre-Merger HHI 4,150 4,126 3,886 3,298 3,607 4,550 2,482 2,644
Post-Merger HHI 4,153 4,129 3,889 3,303 3,612 4,554 2,493 2,668
Change 3 3 3 5 5 4 11 24
FE Capacity (MW) 311 311 311 414 362 334 807 640
GPU Capacity (MW) 84 85 89 101 110 89 166 312
Merged Capacity (MW) 394 396 400 516 472 423 973 952
FE Market Share 2.3% 2.3% 2.5% 3.2% 3.0% 2.7% 5.1% 4.9%
GPU Market Share 0.6% 0.6% 0.7% 0.8% 0.9% 0.7% 1.0% 2.4%
Merged Market Share 3.0% 3.0% 3.2% 4.0% 3.9% 3.4% 6.1% 7.3%
DPL
Pre-Merger HHI 7,115 7,092 6,817 5,475 3,907 5,308 3,766 2,963
Post-Merger HHI 7,115 7,092 6,817 5,476 3,909 5,308 3,767 2,967
Change 0 0 0 0 1 0 1 4
FE Capacity (MW) 137 137 137 211 351 234 408 475
GPU Capacity (MW) 0 0 0 1 3 1 2 8
Merged Capacity (MW) 137 137 137 212 354 235 410 484
FE Market Share 3.5% 3.6% 3.9% 5.8% 7.8% 6.3% 9.0% 10.0%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.2%
Merged Market Share 3.5% 3.6% 3.9% 5.8% 7.9% 6.3% 9.0% 10.2%
DQE
Pre-Merger HHI 6,207 6,207 6,030 3,964 5,902 3,369 3,018 2,676
Post-Merger HHI 6,208 6,208 6,030 3,966 5,903 3,371 3,022 2,747
Change 0 0 0 2 1 2 4 70
FE Capacity (MW) 591 591 592 1,774 604 1,348 1,714 2,101
GPU Capacity (MW) 0 0 0 1 1 2 4 41
Merged Capacity (MW) 591 591 593 1,775 605 1,350 1,718 2,142
FE Market Share 17.5% 17.5% 18.7% 37.6% 19.4% 27.5% 30.7% 42.6%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.8%
Merged Market Share 17.5% 17.5% 18.7% 37.7% 19.5% 27.5% 30.8% 43.4%
</TABLE>
<TABLE>
<CAPTION>
SPRING / FALL
---------------------------------
Destination Market Super Peak Off-Peak
----------------------------- -------- -------- ---------
<S> <C> <C> <C>
APS
Pre-Merger HHI 3,958 2,049 2,189
Post-Merger HHI 3,962 2,060 2,215
Change 4 12 26
FE Capacity (MW) 305 732 582
GPU Capacity (MW) 83 165 308
Merged Capacity (MW) 388 897 890
FE Market Share 2.8% 5.1% 5.0%
GPU Market Share 0.8% 1.1% 2.6%
Merged Market Share 3.6% 6.2% 7.6%
DPL
Pre-Merger HHI 4,712 3,243 2,618
Post-Merger HHI 4,713 3,245 2,623
Change 0 1 6
FE Capacity (MW) 228 397 457
GPU Capacity (MW) 1 2 11
Merged Capacity (MW) 229 399 468
FE Market Share 7.2% 10.0% 10.8%
GPU Market Share 0.0% 0.1% 0.3%
Merged Market Share 7.2% 10.0% 11.1%
DQE
Pre-Merger HHI 3,354 3,169 3,461
Post-Merger HHI 3,357 3,174 3,546
Change 3 6 85
FE Capacity (MW) 1,597 2,031 3,021
GPU Capacity (MW) 2 4 44
Merged Capacity (MW) 1,599 2,034 3,064
FE Market Share 36.2% 40.0% 54.3%
GPU Market Share 0.0% 0.1% 0.8%
Merged Market Share 36.3% 40.1% 55.1%
</TABLE>
<PAGE> 289
Exhibit APP-306, page 3 of 5
BASE CASE ECONOMIC CAPACITY
<TABLE>
<CAPTION>
SUMMER WINTER
---------------------------------------------------------- ---------------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak
----------------------------- --------- ----------- ------- -------- ----------- ---------- ------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Merged Market Share 17.5% 17.5% 18.7% 37.7% 19.5% 27.5% 30.8% 43.4%
MECS
Pre-Merger HHI 3,448 3,437 3,290 3,854 2,878 2,643 2,636 3,267
Post-Merger HHI 3,448 3,437 3,290 3,855 2,879 2,643 2,636 3,270
Change 0 0 0 0 1 0 0 2
FE Capacity (MW) 964 963 964 541 1,143 1,184 1,114 1,006
GPU Capacity (MW) 1 1 1 2 11 5 5 18
Merged Capacity (MW) 965 965 965 543 1,154 1,188 1,119 1,024
FE Market Share 4.5% 4.5% 5.5% 3.6% 7.2% 6.3% 6.5% 7.8%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1%
Merged Market Share 4.5% 4.5% 5.5% 3.6% 7.3% 6.3% 6.5% 7.9%
NYPP
Pre-Merger HHI 1,166 1,157 1,173 1,064 939 1,161 1,083 1,017
Post-Merger HHI 1,166 1,158 1,173 1,064 940 1,161 1,083 1,017
Change 0 0 0 0 0 0 0 0
FE Capacity (MW) 10 11 13 8 18 13 8 13
GPU Capacity (MW) 62 63 65 70 83 47 48 106
Merged Capacity (MW) 72 74 78 78 101 59 57 119
FE Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.1% 0.0% 0.1%
GPU Market Share 0.2% 0.2% 0.2% 0.3% 0.6% 0.2% 0.2% 1.0%
Merged Market Share 0.2% 0.2% 0.2% 0.3% 0.8% 0.3% 0.3% 1.1%
VEPCO
Pre-Merger HHI 4,005 3,954 3,425 3,054 2,711 3,098 2,768 1,979
Post-Merger HHI 4,005 3,954 3,426 3,055 2,712 3,099 2,769 1,986
Change 1 1 1 1 1 1 1 7
FE Capacity (MW) 176 176 181 180 128 104 107 207
GPU Capacity (MW) 99 101 105 111 136 138 140 308
Merged Capacity (MW) 275 277 286 292 264 242 247 515
FE Market Share 0.8% 0.8% 0.9% 1.0% 0.8% 0.6% 0.6% 1.6%
</TABLE>
<TABLE>
<CAPTION>
SPRING / FALL
-----------------------------------
Destination Market Super Peak Off-Peak
---------------------------------- ----------- --------- -----------
<S> <C> <C> <C>
MECS
Pre-Merger HHI 2,363 2,351 2,816
Post-Merger HHI 2,364 2,352 2,824
Change 1 1 7
FE Capacity (MW) 1,633 1,531 1,368
GPU Capacity (MW) 7 9 33
Merged Capacity (MW) 1,640 1,540 1,401
FE Market Share 9.9% 10.3% 12.2%
GPU Market Share 0.0% 0.1% 0.3%
Merged Market Share 10.0% 10.4% 12.5%
NYPP
Pre-Merger HHI 1,001 956 807
Post-Merger HHI 1,001 956 810
Change 0 0 3
FE Capacity (MW) 48 34 54
GPU Capacity (MW) 131 148 320
Merged Capacity (MW) 179 182 374
FE Market Share 0.2% 0.2% 0.5%
GPU Market Share 0.5% 0.7% 2.9%
Merged Market Share 0.7% 0.9% 3.4%
VEPCO
Pre-Merger HHI 3,067 2,626 1,734
Post-Merger HHI 3,069 2,628 1,746
Change 1 2 12
FE Capacity (MW) 148 153 254
GPU Capacity (MW) 132 145 316
Merged Capacity (MW) 280 298 570
FE Market Share 0.9% 1.0% 2.2%
</TABLE>
<PAGE> 290
Exhibit APP-306, page 4 of 5
<TABLE>
<CAPTION>
BASE CASE ECONOMIC CAPACITY
SUMMER WINTER
-------------------------------------------------------- ------------------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak
---------------------------------- -------- --------- --------- ------ --------- ----------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
GPU Market Share 0.4% 0.5% 0.5% 0.6% 0.8% 0.8% 0.8% 2.3%
Merged Market Share 1.2% 1.2% 1.4% 1.6% 1.6% 1.3% 1.5% 3.9%
PJM-WESTINT
Pre-Merger HHI 1,164 1,163 1,181 1,178 1,143 976 1,130 1,551
Post-Merger HHI 1,176 1,175 1,190 1,183 1,155 998 1,141 1,577
Change 12 12 9 5 12 22 11 26
FE Capacity (MW) 761 761 472 206 360 964 390 235
GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971
Merged Capacity (MW) 3,176 3,176 2,515 2,132 2,271 3,136 2,381 2,206
FE Market Share 1.4% 1.4% 1.0% 0.5% 1.1% 2.2% 1.0% 1.2%
GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.0% 5.4% 10.4%
Merged Market Share 5.8% 5.8% 5.5% 5.5% 6.7% 7.3% 6.4% 11.7%
PJM-CENTINT
Pre-Merger HHI 1,508 1,507 1,550 1,462 1,479 1,312 1,455 1,564
Post-Merger HHI 1,513 1,513 1,555 1,465 1,487 1,325 1,462 1,589
Change 6 6 5 3 8 13 7 26
FE Capacity (MW) 216 216 149 71 139 320 151 229
GPU Capacity (MW) 2,177 2,177 1,815 1,714 1,713 1,926 1,769 1,962
Merged Capacity (MW) 2,392 2,392 1,964 1,785 1,852 2,246 1,920 2,191
FE Market Share 0.5% 0.5% 0.4% 0.3% 0.6% 1.0% 0.6% 1.2%
GPU Market Share 5.3% 5.4% 5.5% 6.1% 6.9% 6.3% 6.5% 10.5%
Merged Market Share 5.9% 5.9% 5.9% 6.4% 7.5% 7.3% 7.0% 11.7%
PJM-EASTINT
Pre-Merger HHI 1,485 1,477 1,417 1,378 1,350 1,171 1,306 1,667
Post-Merger HHI 1,493 1,484 1,424 1,382 1,360 1,189 1,315 1,691
Change 7 7 7 4 10 18 9 24
FE Capacity (MW) 216 217 150 71 133 292 138 172
GPU Capacity (MW) 1,863 1,864 1,517 1,429 1,441 1,604 1,468 1,757
Merged Capacity (MW) 2,079 2,081 1,667 1,500 1,574 1,896 1,606 1,929
</TABLE>
<TABLE>
<CAPTION>
SPRING / FALL
-----------------------------------
Destination Market Super Peak Off-Peak
---------------------------------- ----------- --------- -----------
<S> <C> <C> <C>
GPU Market Share 0.8% 1.0% 2.7%
Merged Market Share 1.7% 2.0% 5.0%
PJM-WESTINT
Pre-Merger HHI 945 1,059 1,288
Post-Merger HHI 971 1,077 1,320
Change 26 18 32
FE Capacity (MW) 955 460 262
GPU Capacity (MW) 1,885 1,747 1,717
Merged Capacity (MW) 2,841 2,207 1,979
FE Market Share 2.6% 1.5% 1.6%
GPU Market Share 5.1% 5.9% 10.3%
Merged Market Share 7.7% 7.4% 11.8%
PJM-CENTINT
Pre-Merger HHI 1,295 1,365 1,417
Post-Merger HHI 1,311 1,378 1,446
Change 16 13 29
FE Capacity (MW) 317 192 199
GPU Capacity (MW) 1,633 1,533 1,631
Merged Capacity (MW) 1,950 1,725 1,830
FE Market Share 1.3% 0.9% 1.3%
GPU Market Share 6.5% 7.1% 10.9%
Merged Market Share 7.7% 8.0% 12.2%
PJM-EASTINT
Pre-Merger HHI 1,205 1,228 1,432
Post-Merger HHI 1,226 1,243 1,463
Change 21 15 30
FE Capacity (MW) 296 174 173
GPU Capacity (MW) 1,355 1,279 1,467
Merged Capacity (MW) 1,651 1,454 1,640
</TABLE>
<PAGE> 291
Exhibit APP-306, page 5 of 5
BASE CASE ECONOMIC CAPACITY
<TABLE>
<CAPTION>
SUMMER WINTER
-------------------------------------------------------- ------------------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak
---------------------------------- -------- --------- --------- --------- --------- ----------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
FE Market Share 0.7% 0.7% 0.6% 0.3% 0.7% 1.3% 0.7% 1.1%
GPU Market Share 5.7% 5.7% 5.7% 6.4% 7.4% 7.0% 7.0% 11.1%
Merged Market Share 6.3% 6.3% 6.3% 6.8% 8.1% 8.3% 7.6% 12.2%
</TABLE>
<TABLE>
<CAPTION>
SPRING / FALL
-----------------------------------
Destination Market Super Peak Off-Peak
---------------------------------- ----------- --------- -----------
<S> <C> <C> <C>
FE Market Share 1.5% 1.0% 1.3%
GPU Market Share 7.0% 7.5% 11.3%
Merged Market Share 8.5% 8.6% 12.7%
</TABLE>
<PAGE> 292
EXHIBIT NO. APP-307
<PAGE> 293
Exhibit APP-307, page 1 of 5
BASE CASE AVAILABLE ECONOMIC CAPACITY
<TABLE>
<CAPTION>
SUMMER WINTER
---------------------------------------------------------- ----------------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak
------------------------------- -------- ---------- -------- ---------- --------- ---------- -------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
FE
Pre-Merger HHI 1,117 1,213 1,875 1,488 1,524 1,380 1,426 3,029
Post-Merger HHI 1,117 1,213 1,875 1,488 1,524 1,380 1,426 3,029
Change - - - - - - - -
FE Capacity (MW) 686 1,344 1,739 2,477 3,518 1,894 2,537 1,693
GPU Capacity (MW) - - - - - - - -
Merged Capacity (MW) 686 1,344 1,739 2,477 3,518 1,894 2,537 1,693
FE Market Share 13.4% 23.2% 29.8% 31.8% 30.2% 29.9% 31.3% 50.6%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
Merged Market Share 13.4% 23.2% 29.8% 31.8% 30.2% 29.9% 31.3% 50.6%
PJM
Pre-Merger HHI 1,072 1,049 1,095 1,154 1,085 930 1,064 4,382
Post-Merger HHI 1,072 1,049 1,095 1,154 1,085 930 1,064 4,382
Change - - - - - - - -
FE Capacity (MW) 210 227 357 152 335 449 268 -
GPU Capacity (MW) - - - - - - - -
Merged Capacity (MW) 210 227 357 152 335 449 268 -
FE Market Share 0.9% 1.0% 2.1% 1.0% 2.4% 2.9% 2.0% 0.0%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
Merged Market Share 0.9% 1.0% 2.1% 1.0% 2.4% 2.9% 2.0% 0.0%
AEP
Pre-Merger HHI 791 810 1,127 1,411 2,389 975 1,025 4,637
Post-Merger HHI 791 810 1,127 1,411 2,389 975 1,025 4,637
Change - - - - - - - -
FE Capacity (MW) 670 1,255 1,610 2,404 1,686 1,631 1,714 -
GPU Capacity (MW) - - - - - - - -
Merged Capacity (MW) 670 1,255 1,610 2,404 1,686 1,631 1,714 -
FE Market Share 3.9% 6.6% 8.8% 10.8% 8.2% 8.3% 6.6% 0.0%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
Merged Market Share 3.9% 6.6% 8.8% 10.8% 8.2% 8.3% 6.6% 0.0%
</TABLE>
<TABLE>
<CAPTION>
SPRING / FALL
----------------------------------
Destination Market Super Peak Off-Peak
------------------------------- --------- --------- ----------
<S> <C> <C> <C>
FE
Pre-Merger HHI 1,176 1,070 1,756
Post-Merger HHI 1,176 1,070 1,756
Change - - -
FE Capacity (MW) - 711 -
GPU Capacity (MW) - - -
Merged Capacity (MW) - 711 -
FE Market Share 0.0% 11.5% 0.0%
GPU Market Share 0.0% 0.0% 0.0%
Merged Market Share 0.0% 11.5% 0.0%
PJM
Pre-Merger HHI 1,117 1,072 2,561
Post-Merger HHI 1,117 1,072 2,561
Change - - -
FE Capacity (MW) - 237 -
GPU Capacity (MW) - - -
Merged Capacity (MW) - 237 -
FE Market Share 0.0% 2.3% 0.0%
GPU Market Share 0.0% 0.0% 0.0%
Merged Market Share 0.0% 2.3% 0.0%
AEP
Pre-Merger HHI 1,230 1,079 5,559
Post-Merger HHI 1,230 1,079 5,559
Change - - -
FE Capacity (MW) - 694 -
GPU Capacity (MW) - - -
Merged Capacity (MW) - 694 -
FE Market Share 0.0% 4.7% 0.0%
GPU Market Share 0.0% 0.0% 0.0%
Merged Market Share 0.0% 4.7% 0.0%
</TABLE>
<PAGE> 294
Exhibit APP-307,page 2 of 5
BASE CASE AVAILABLE ECONOMIC CAPACITY
<TABLE>
<CAPTION>
SUMMER WINTER
---------------------------------------------------------- ----------------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak
------------------------------- -------- ---------- -------- ---------- --------- ---------- -------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
APS
Pre-Merger HHI 1,145 1,269 1,405 1,337 1,861 2,521 1,328 3,426
Post-Merger HHI 1,145 1,269 1,405 1,337 1,861 2,521 1,328 3,426
Change - - - - - - - -
FE Capacity (MW) 314 315 315 419 367 338 816 -
GPU Capacity (MW) - - - - - - - -
Merged Capacity (MW) 314 315 315 419 367 338 816 -
FE Market Share 5.2% 5.3% 5.8% 6.3% 5.3% 4.5% 7.0% 0.0%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
Merged Market Share 5.2% 5.3% 5.8% 6.3% 5.3% 4.5% 7.0% 0.0%
DPL
Pre-Merger HHI 3,016 3,269 2,996 2,737 2,335 1,297 1,483 2,673
Post-Merger HHI 3,016 3,269 2,996 2,737 2,335 1,297 1,483 2,673
Change - - - - - - - -
FE Capacity (MW) 95 113 118 177 297 185 341 -
GPU Capacity (MW) - - - - - - - -
Merged Capacity (MW) 95 113 118 177 297 185 341 -
FE Market Share 7.6% 8.4% 9.5% 9.5% 9.9% 13.8% 13.2% 0.0%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
Merged Market Share 7.6% 8.4% 9.5% 9.5% 9.9% 13.8% 13.2% 0.0%
DQE
Pre-Merger HHI 4,632 4,465 4,360 3,800 4,474 2,539 2,541 3,920
Post-Merger HHI 4,632 4,465 4,360 3,800 4,474 2,539 2,541 3,920
Change - - - - - - - -
FE Capacity (MW) 598 599 599 1,795 612 1,362 1,734 -
GPU Capacity (MW) - - - - - - - -
Merged Capacity (MW) 598 599 599 1,795 612 1,362 1,734 -
FE Market Share 29.8% 31.6% 33.0% 52.8% 31.4% 41.8% 40.4% 0.0%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
</TABLE>
<TABLE>
<CAPTION>
SPRING / FALL
----------------------------------
Destination Market Super Peak Off-Peak
------------------------------- --------- --------- ----------
<S> <C> <C> <C>
APS
Pre-Merger HHI 1,752 1,046 2,963
Post-Merger HHI 1,752 1,046 2,963
Change - - -
FE Capacity (MW) - 694 -
GPU Capacity (MW) - - -
Merged Capacity (MW) - 694 -
FE Market Share 0.0% 8.4% 0.0%
GPU Market Share 0.0% 0.0% 0.0%
Merged Market Share 0.0% 8.4% 0.0%
DPL
Pre-Merger HHI 875 1,203 2,905
Post-Merger HHI 875 1,203 2,905
Change - - -
FE Capacity (MW) - 223 -
GPU Capacity (MW) - - -
Merged Capacity (MW) - 223 -
FE Market Share 0.0% 10.0% 0.0%
GPU Market Share 0.0% 0.0% 0.0%
Merged Market Share 0.0% 10.0% 0.0%
DQE
Pre-Merger HHI 2,104 2,196 5,553
Post-Merger HHI 2,104 2,196 5,553
Change - - -
FE Capacity (MW) - 694 -
GPU Capacity (MW) - - -
Merged Capacity (MW) - 694 -
FE Market Share 0.0% 26.0% 0.0%
GPU Market Share 0.0% 0.0% 0.0%
</TABLE>
<PAGE> 295
Exhibit APP-307, page 3 of 5
BASE CASE AVAILABLE ECONOMIC CAPACITY
<TABLE>
<CAPTION>
SUMMER WINTER
---------------------------------------------------------- ----------------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak
------------------------------- -------- ---------- -------- ---------- --------- ---------- -------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Merged Market Share 29.8% 31.6% 33.0% 52.8% 31.4% 41.8% 40.4% 0.0%
MECS
Pre-Merger HHI 1,285 1,481 1,819 1,659 1,411 881 1,023 2,212
Post-Merger HHI 1,285 1,481 1,819 1,659 1,411 881 1,023 2,212
Change - - - - - - - -
FE Capacity (MW) 670 794 831 453 968 935 931 -
GPU Capacity (MW) - - - - - - - -
Merged Capacity (MW) 670 794 831 453 968 935 931 -
FE Market Share 17.9% 19.1% 25.0% 15.8% 18.8% 16.5% 17.1% 0.0%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
Merged Market Share 17.9% 19.1% 25.0% 15.8% 18.8% 16.5% 17.1% 0.0%
NYPP
Pre-Merger HHI 1,135 1,181 1,150 1,011 1,404 1,392 1,383 3,800
Post-Merger HHI 1,135 1,181 1,150 1,011 1,404 1,392 1,383 3,800
Change - - - - - - - -
FE Capacity (MW) 26 27 37 22 48 43 26 -
GPU Capacity (MW) - - - - - - - -
Merged Capacity (MW) 26 27 37 22 48 43 26 -
FE Market Share 0.2% 0.2% 0.3% 0.2% 1.0% 0.6% 0.5% 0.0%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
Merged Market Share 0.2% 0.2% 0.3% 0.2% 1.0% 0.6% 0.5% 0.0%
VEPCO
Pre-Merger HHI 725 714 1,132 887 1,021 680 769 3,268
Post-Merger HHI 725 714 1,132 887 1,021 680 769 3,268
Change - - - - - - - -
FE Capacity (MW) 127 206 226 318 236 302 230 -
GPU Capacity (MW) - - - - - - - -
Merged Capacity (MW) 127 206 226 318 236 302 230 -
FE Market Share 2.0% 3.4% 4.0% 5.5% 3.2% 4.0% 3.0% 0.0%
</TABLE>
<TABLE>
<CAPTION>
SPRING / FALL
----------------------------------
Destination Market Super Peak Off-Peak
------------------------------- --------- --------- ----------
<S> <C> <C> <C>
Merged Market Share 0.0% 26.0% 0.0%
MECS
Pre-Merger HHI 863 848 2,853
Post-Merger HHI 863 848 2,853
Change - - -
FE Capacity (MW) - 694 -
GPU Capacity (MW) - - -
Merged Capacity (MW) - 694 -
FE Market Share 0.0% 14.0% 0.0%
GPU Market Share 0.0% 0.0% 0.0%
Merged Market Share 0.0% 14.0% 0.0%
NYPP
Pre-Merger HHI 1,481 1,004 3,467
Post-Merger HHI 1,481 1,004 3,467
Change - - -
FE Capacity (MW) - 119 -
GPU Capacity (MW) - - -
Merged Capacity (MW) - 119 -
FE Market Share 0.0% 1.6% 0.0%
GPU Market Share 0.0% 0.0% 0.0%
Merged Market Share 0.0% 1.6% 0.0%
VEPCO
Pre-Merger HHI 929 914 2,269
Post-Merger HHI 929 914 2,269
Change - - -
FE Capacity (MW) - 139 -
GPU Capacity (MW) - - -
Merged Capacity (MW) - 139 -
FE Market Share 0.0% 2.5% 0.0%
</TABLE>
<PAGE> 296
Exhibit APP-307, page 4 of 5
BASE CASE AVAILABLE ECONOMIC CAPACITY
<TABLE>
<CAPTION>
SUMMER WINTER
---------------------------------------------------------- ----------------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak
------------------------------- -------- ---------- -------- ---------- --------- ---------- -------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
Merged Market Share 2.0% 3.4% 4.0% 5.5% 3.2% 4.0% 3.0% 0.0%
PJM-WESTINT
Pre-Merger HHI 1,072 1,049 1,095 1,154 1,085 930 1,064 4,382
Post-Merger HHI 1,072 1,049 1,095 1,154 1,085 930 1,064 4,382
Change - - - - - - - -
FE Capacity (MW) 210 227 357 152 335 449 268 -
GPU Capacity (MW) - - - - - - - -
Merged Capacity (MW) 210 227 357 152 335 449 268 -
FE Market Share 0.9% 1.0% 2.1% 1.0% 2.4% 2.9% 2.0% 0.0%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
Merged Market Share 0.9% 1.0% 2.1% 1.0% 2.4% 2.9% 2.0% 0.0%
PJM-CENTINT
Pre-Merger HHI 1,180 1,149 1,220 1,198 1,149 926 1,076 4,382
Post-Merger HHI 1,180 1,149 1,220 1,198 1,149 926 1,076 4,382
Change - - - - - - - -
FE Capacity (MW) 115 124 225 101 240 283 201 -
GPU Capacity (MW) - - - - - - - -
Merged Capacity (MW) 115 124 225 101 240 283 201 -
FE Market Share 0.6% 0.7% 1.7% 0.8% 2.1% 2.4% 1.8% 0.0%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
Merged Market Share 0.6% 0.7% 1.7% 0.8% 2.1% 2.4% 1.8% 0.0%
PJM-EASTINT
Pre-Merger HHI 1,128 1,100 1,136 1,176 1,089 918 1,060 4,382
Post-Merger HHI 1,128 1,100 1,136 1,176 1,089 918 1,060 4,382
Change - - - - - - - -
FE Capacity (MW) 147 160 291 123 269 345 240 -
GPU Capacity (MW) - - - - - - - -
Merged Capacity (MW) 147 160 291 123 269 345 240 -
</TABLE>
<TABLE>
<CAPTION>
SPRING / FALL
----------------------------------
Destination Market Super Peak Off-Peak
------------------------------- --------- --------- ----------
<S> <C> <C> <C>
GPU Market Share 0.0% 0.0% 0.0%
Merged Market Share 0.0% 2.5% 0.0%
PJM-WESTINT
Pre-Merger HHI 1,117 1,072 2,561
Post-Merger HHI 1,117 1,072 2,561
Change - - -
FE Capacity (MW) - 237 -
GPU Capacity (MW) - - -
Merged Capacity (MW) - 237 -
FE Market Share 0.0% 2.3% 0.0%
GPU Market Share 0.0% 0.0% 0.0%
Merged Market Share 0.0% 2.3% 0.0%
PJM-CENTINT
Pre-Merger HHI 1,078 1,053 2,561
Post-Merger HHI 1,078 1,053 2,561
Change - - -
FE Capacity (MW) - 180 -
GPU Capacity (MW) - - -
Merged Capacity (MW) - 180 -
FE Market Share 0.0% 2.2% 0.0%
GPU Market Share 0.0% 0.0% 0.0%
Merged Market Share 0.0% 2.2% 0.0%
PJM-EASTINT
Pre-Merger HHI 1,107 1,071 2,561
Post-Merger HHI 1,107 1,071 2,561
Change - - -
FE Capacity (MW) - 231 -
GPU Capacity (MW) - - -
Merged Capacity (MW) - 231 -
</TABLE>
<PAGE> 297
Exhibit APP-307, page 5 of 5
BASE CASE AVAILABLE ECONOMIC CAPACITY
<TABLE>
<CAPTION>
SUMMER WINTER
---------------------------------------------------------- ----------------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak
------------------------------- -------- ---------- -------- ---------- --------- ---------- -------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
FE Market Share 0.8% 0.8% 2.0% 1.0% 2.3% 2.7% 1.9% 0.0%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
Merged Market Share 0.8% 0.8% 2.0% 1.0% 2.3% 2.7% 1.9% 0.0%
</TABLE>
<TABLE>
<CAPTION>
SPRING / FALL
----------------------------------
Destination Market Super Peak Off-Peak
------------------------------- --------- --------- ----------
<S> <C> <C> <C>
FE Market Share 0.0% 2.3% 0.0%
GPU Market Share 0.0% 0.0% 0.0%
Merged Market Share 0.0% 2.3% 0.0%
</TABLE>
<PAGE> 298
EXHIBIT NO. APP-308
<PAGE> 299
Exhibit APP-308, page 1 of 1
OFF PEAK FLOWS BETWEEN ECAR AND PJM
<TABLE>
<CAPTION>
Hours with Hours with
Tie West To East Flow Percentage East to West Flow Percentage
<S> <C> <C> <C> <C>
FirstEnergy-PJM 5734 94.2 354 5.8
Allegheny-PJM 5322 87.4 266 12.6
Source:
http://www.pjm.com/market_system_data/system/downloads/1999netsched.xls (October 31, 2000).
http://www.pjm.com/market_system_data/system/downloads/1998netsched.xls (October 31, 2000).
http://www.pjm.com/market_system_data/system/downloads/spjm97s_a.xls (October 31, 2000).
</TABLE>
<PAGE> 300
EXHIBIT NO. APP-309
<PAGE> 301
Exhibit APP-309, page 1 of 5
SENSITIVITY FOR FIRM ATC
<TABLE>
<CAPTION>
SUMMER WINTER
---------------------------------------------------------- --------------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak
------------------------------ --------- -------- ------- -------- ---------- ------- --------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
FE
Pre-Merger HHI 5,222 5,219 5,079 4,330 3,489 4,951 4,197 4,183
Post-Merger HHI 5,238 5,235 5,097 4,364 3,536 4,983 4,233 4,309
Change 16 16 17 34 47 32 36 126
FE Capacity (MW) 11,798 11,788 11,090 10,101 9,965 10,789 10,162 8,175
GPU Capacity (MW) 18 18 19 41 71 35 44 127
Merged Capacity (MW) 11,816 11,806 11,109 10,142 10,036 10,824 10,207 8,302
FE Market Share 71.6% 71.6% 70.5% 64.8% 57.2% 69.8% 63.9% 63.8%
GPU Market Share 0.1% 0.1% 0.1% 0.3% 0.4% 0.2% 0.3% 1.0%
Merged Market Share 71.7% 71.7% 70.6% 65.1% 57.6% 70.0% 64.2% 64.7%
PJM
Pre-Merger HHI 1,165 1,164 1,183 1,178 1,146 1,038 1,136 1,559
Post-Merger HHI 1,175 1,174 1,190 1,182 1,155 1,057 1,144 1,579
Change 11 11 7 4 9 19 8 19
FE Capacity (MW) 665 665 378 150 269 757 294 175
GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971
Merged Capacity (MW) 3,079 3,079 2,421 2,076 2,180 2,929 2,285 2,146
FE Market Share 1.2% 1.2% 0.8% 0.4% 0.8% 1.8% 0.8% 0.9%
GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.2% 5.4% 10.4%
Merged Market Share 5.6% 5.6% 5.3% 5.3% 6.5% 7.0% 6.2% 11.3%
AEP
Pre-Merger HHI 2,443 2,443 2,396 2,480 3,828 2,260 2,156 2,623
Post-Merger HHI 2,443 2,443 2,396 2,480 3,828 2,260 2,156 2,625
Change 0 0 0 0 0 0 0 2
FE Capacity (MW) 2,309 2,308 2,315 2,275 1,276 2,131 2,237 2,101
GPU Capacity (MW) 4 4 5 6 7 6 7 70
Merged Capacity (MW) 2,313 2,313 2,320 2,281 1,283 2,137 2,244 2,170
FE Market Share 5.0% 5.0% 5.1% 5.2% 3.7% 4.5% 4.6% 5.2%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.2%
Merged Market Share 5.1% 5.1% 5.1% 5.2% 3.7% 4.5% 4.6% 5.3%
</TABLE>
<TABLE>
<CAPTION>
SPRING / FALL
---------------------------------
Destination Market Super Peak Off-Peak
------------------------------ -------- ------- ---------
<S> <C> <C> <C>
FE
Pre-Merger HHI 4,284 3,554 3,220
Post-Merger HHI 4,312 3,586 3,351
Change 28 32 132
FE Capacity (MW) 8,360 7,847 4,973
GPU Capacity (MW) 28 38 108
Merged Capacity (MW) 8,388 7,885 5,082
FE Market Share 64.3% 57.9% 55.0%
GPU Market Share 0.2% 0.3% 1.2%
Merged Market Share 64.6% 58.2% 56.2%
PJM
Pre-Merger HHI 1,025 1,069 1,297
Post-Merger HHI 1,043 1,079 1,314
Change 18 10 17
FE Capacity (MW) 586 255 140
GPU Capacity (MW) 1,885 1,747 1,717
Merged Capacity (MW) 2,471 2,003 1,857
FE Market Share 1.7% 0.9% 0.8%
GPU Market Share 5.3% 5.9% 10.3%
Merged Market Share 7.0% 6.7% 11.1%
AEP
Pre-Merger HHI 1,845 1,734 2,100
Post-Merger HHI 1,845 1,734 2,102
Change 0 0 2
FE Capacity (MW) 2,253 2,365 2,223
GPU Capacity (MW) 5 6 65
Merged Capacity (MW) 2,258 2,371 2,288
FE Market Share 5.3% 5.5% 6.2%
GPU Market Share 0.0% 0.0% 0.2%
Merged Market Share 5.3% 5.5% 6.3%
</TABLE>
<PAGE> 302
Exhibit APP-309, page 2 of 5
SENSITIVITY FOR FIRM ATC
<TABLE>
<CAPTION>
SUMMER WINTER
---------------------------------------------------------- --------------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak
------------------------------ --------- -------- ------- -------- ---------- ------- --------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
APS
Pre-Merger HHI 4,932 4,908 4,668 4,486 4,449 4,780 4,512 4,332
Post-Merger HHI 4,937 4,913 4,674 4,493 4,459 4,787 4,521 4,359
Change 5 5 6 7 9 8 9 27
FE Capacity (MW) 843 843 845 844 844 982 981 1,000
GPU Capacity (MW) 46 47 49 52 64 58 59 130
Merged Capacity (MW) 889 890 894 896 907 1,040 1,039 1,130
FE Market Share 6.9% 7.0% 7.4% 7.7% 7.8% 8.1% 8.6% 10.2%
GPU Market Share 0.4% 0.4% 0.4% 0.5% 0.6% 0.5% 0.5% 1.3%
Merged Market Share 7.3% 7.3% 7.8% 8.2% 8.4% 8.5% 9.1% 11.5%
DPL
Pre-Merger HHI 7,114 7,091 6,815 5,474 3,928 5,307 3,768 2,947
Post-Merger HHI 7,114 7,091 6,815 5,474 3,929 5,307 3,769 2,950
Change 0 0 0 0 0 0 1 3
FE Capacity (MW) 88 88 88 136 227 239 416 462
GPU Capacity (MW) 0 0 0 1 2 1 2 8
Merged Capacity (MW) 88 88 88 136 229 240 417 469
FE Market Share 2.3% 2.3% 2.5% 3.7% 5.1% 6.4% 9.1% 9.7%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.2%
Merged Market Share 2.3% 2.3% 2.5% 3.7% 5.1% 6.4% 9.2% 9.9%
DQE
Pre-Merger HHI 6,206 6,206 6,028 3,964 5,901 3,368 3,015 2,661
Post-Merger HHI 6,206 6,206 6,029 3,965 5,902 3,369 3,017 2,702
Change 0 0 0 1 1 1 2 41
FE Capacity (MW) 592 592 593 1,776 605 1,352 1,719 2,101
GPU Capacity (MW) 0 0 0 1 1 1 2 24
Merged Capacity (MW) 592 592 593 1,776 605 1,353 1,720 2,125
FE Market Share 17.5% 17.5% 18.7% 37.7% 19.5% 27.6% 30.8% 42.7%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.5%
</TABLE>
<TABLE>
<CAPTION>
SPRING / FALL
---------------------------------
Destination Market Super Peak Off-Peak
------------------------------ -------- ------- ---------
<S> <C> <C> <C>
APS
Pre-Merger HHI 4,363 4,089 3,908
Post-Merger HHI 4,371 4,099 3,940
Change 9 11 32
FE Capacity (MW) 908 907 925
GPU Capacity (MW) 50 55 120
Merged Capacity (MW) 958 962 1,046
FE Market Share 8.8% 9.3% 11.1%
GPU Market Share 0.5% 0.6% 1.4%
Merged Market Share 9.3% 9.9% 12.6%
DPL
Pre-Merger HHI 4,710 3,243 2,615
Post-Merger HHI 4,710 3,244 2,620
Change 0 1 5
FE Capacity (MW) 239 415 460
GPU Capacity (MW) 1 2 10
Merged Capacity (MW) 240 417 469
FE Market Share 7.5% 10.4% 10.9%
GPU Market Share 0.0% 0.0% 0.2%
Merged Market Share 7.6% 10.5% 11.1%
DQE
Pre-Merger HHI 3,373 3,190 3,499
Post-Merger HHI 3,374 3,192 3,538
Change 1 2 39
FE Capacity (MW) 1,612 2,049 3,048
GPU Capacity (MW) 1 1 20
Merged Capacity (MW) 1,613 2,051 3,068
FE Market Share 36.6% 40.4% 54.8%
GPU Market Share 0.0% 0.0% 0.4%
</TABLE>
<PAGE> 303
Exhibit APP-309, page 3 of 5
SENSITIVITY FOR FIRM ATC
<TABLE>
<CAPTION>
SUMMER WINTER
---------------------------------------------------------- --------------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak
------------------------------ --------- -------- ------- -------- ---------- ------- --------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Merged Market Share 17.6% 17.6% 18.7% 37.7% 19.5% 27.6% 30.9% 43.2%
MECS
Pre-Merger HHI 3,882 3,872 3,791 3,856 3,743 2,646 2,639 3,259
Post-Merger HHI 3,882 3,872 3,791 3,856 3,743 2,646 2,639 3,262
Change 0 0 0 0 1 0 1 3
FE Capacity (MW) 874 874 875 842 821 1,440 1,350 1,219
GPU Capacity (MW) 1 1 1 3 7 5 6 21
Merged Capacity (MW) 876 875 876 845 828 1,445 1,356 1,240
FE Market Share 4.3% 4.4% 5.4% 5.6% 6.1% 7.6% 7.8% 9.5%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.2%
Merged Market Share 4.3% 4.4% 5.4% 5.6% 6.1% 7.7% 7.9% 9.6%
NYPP
Pre-Merger HHI 1,229 1,226 1,248 1,147 1,096 1,197 1,121 1,085
Post-Merger HHI 1,229 1,226 1,248 1,147 1,096 1,197 1,121 1,085
Change 0 0 0 0 0 0 0 0
FE Capacity (MW) 1 2 2 1 3 4 3 5
GPU Capacity (MW) 13 14 14 15 18 26 27 57
Merged Capacity (MW) 15 15 16 16 20 30 30 62
FE Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1%
GPU Market Share 0.0% 0.0% 0.0% 0.1% 0.2% 0.1% 0.1% 0.6%
Merged Market Share 0.0% 0.0% 0.0% 0.1% 0.2% 0.1% 0.1% 0.6%
VEPCO
Pre-Merger HHI 4,568 4,516 3,963 3,562 3,172 3,565 3,206 2,293
Post-Merger HHI 4,569 4,516 3,964 3,563 3,173 3,566 3,207 2,303
Change 1 1 1 1 1 1 1 9
FE Capacity (MW) 126 126 129 129 92 109 112 208
GPU Capacity (MW) 99 101 106 112 137 140 140 312
Merged Capacity (MW) 225 227 235 241 229 249 253 520
FE Market Share 0.6% 0.6% 0.7% 0.8% 0.6% 0.6% 0.7% 1.8%
</TABLE>
<TABLE>
<CAPTION>
SPRING / FALL
---------------------------------
Destination Market Super Peak Off-Peak
------------------------------ -------- ------- ---------
<S> <C> <C> <C>
Merged Market Share 36.6% 40.4% 55.2%
MECS
Pre-Merger HHI 2,385 2,374 2,848
Post-Merger HHI 2,386 2,376 2,858
Change 1 2 10
FE Capacity (MW) 2,057 1,928 1,736
GPU Capacity (MW) 7 9 36
Merged Capacity (MW) 2,064 1,938 1,772
FE Market Share 12.5% 13.0% 15.5%
GPU Market Share 0.0% 0.1% 0.3%
Merged Market Share 12.5% 13.1% 15.9%
NYPP
Pre-Merger HHI 1,086 1,059 935
Post-Merger HHI 1,086 1,059 936
Change 0 0 0
FE Capacity (MW) 9 9 14
GPU Capacity (MW) 70 76 158
Merged Capacity (MW) 79 85 172
FE Market Share 0.0% 0.0% 0.1%
GPU Market Share 0.3% 0.4% 1.6%
Merged Market Share 0.3% 0.5% 1.8%
VEPCO
Pre-Merger HHI 3,642 3,154 2,073
Post-Merger HHI 3,643 3,156 2,085
Change 1 2 12
FE Capacity (MW) 102 106 180
GPU Capacity (MW) 136 148 325
Merged Capacity (MW) 239 254 505
FE Market Share 0.7% 0.8% 1.8%
</TABLE>
<PAGE> 304
Exhibit APP-309, page 4 of 5
SENSITIVITY FOR FIRM ATC
<TABLE>
<CAPTION>
SUMMER WINTER
---------------------------------------------------------- --------------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak
------------------------------ --------- -------- ------- -------- ---------- ------- --------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
GPU Market Share 0.5% 0.5% 0.6% 0.7% 0.9% 0.8% 0.9% 2.6%
Merged Market Share 1.1% 1.1% 1.3% 1.5% 1.5% 1.5% 1.6% 4.4%
PJM-WESTINT
Pre-Merger HHI 1,165 1,164 1,183 1,178 1,146 1,038 1,136 1,559
Post-Merger HHI 1,175 1,174 1,190 1,182 1,155 1,057 1,144 1,579
Change 11 11 7 4 9 19 8 19
FE Capacity (MW) 665 665 378 150 269 757 294 175
GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971
Merged Capacity (MW) 3,079 3,079 2,421 2,076 2,180 2,929 2,285 2,146
FE Market Share 1.2% 1.2% 0.8% 0.4% 0.8% 1.8% 0.8% 0.9%
GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.2% 5.4% 10.4%
Merged Market Share 5.6% 5.6% 5.3% 5.3% 6.5% 7.0% 6.2% 11.3%
PJM-CENTINT
Pre-Merger HHI 1,523 1,523 1,570 1,473 1,504 1,406 1,508 1,608
Post-Merger HHI 1,528 1,528 1,574 1,475 1,510 1,417 1,514 1,627
Change 5 5 4 2 6 11 5 18
FE Capacity (MW) 186 186 117 51 102 256 110 160
GPU Capacity (MW) 2,175 2,175 1,814 1,713 1,711 1,929 1,764 1,940
Merged Capacity (MW) 2,362 2,362 1,931 1,764 1,813 2,185 1,874 2,101
FE Market Share 0.5% 0.5% 0.4% 0.2% 0.4% 0.9% 0.4% 0.9%
GPU Market Share 5.4% 5.4% 5.5% 6.1% 7.0% 6.5% 6.6% 10.6%
Merged Market Share 5.8% 5.8% 5.9% 6.3% 7.4% 7.4% 7.0% 11.4%
PJM-EASTINT
Pre-Merger HHI 1,503 1,495 1,438 1,390 1,375 1,286 1,361 1,713
Post-Merger HHI 1,510 1,502 1,443 1,393 1,383 1,302 1,368 1,731
Change 7 7 5 3 8 16 7 18
FE Capacity (MW) 187 188 119 52 98 232 102 124
GPU Capacity (MW) 1,862 1,862 1,515 1,427 1,438 1,607 1,461 1,737
Merged Capacity (MW) 2,049 2,050 1,633 1,479 1,537 1,839 1,563 1,861
</TABLE>
<TABLE>
<CAPTION>
SPRING / FALL
---------------------------------
Destination Market Super Peak Off-Peak
------------------------------ -------- ------- ---------
<S> <C> <C> <C>
GPU Market Share 0.9% 1.1% 3.3%
Merged Market Share 1.6% 1.9% 5.1%
PJM-WESTINT
Pre-Merger HHI 1,025 1,069 1,297
Post-Merger HHI 1,043 1,079 1,314
Change 18 10 17
FE Capacity (MW) 586 255 140
GPU Capacity (MW) 1,885 1,747 1,717
Merged Capacity (MW) 2,471 2,003 1,857
FE Market Share 1.7% 0.9% 0.8%
GPU Market Share 5.3% 5.9% 10.3%
Merged Market Share 7.0% 6.7% 11.1%
PJM-CENTINT
Pre-Merger HHI 1,353 1,390 1,440
Post-Merger HHI 1,364 1,397 1,456
Change 11 7 16
FE Capacity (MW) 207 105 104
GPU Capacity (MW) 1,644 1,531 1,625
Merged Capacity (MW) 1,851 1,636 1,730
FE Market Share 0.8% 0.5% 0.7%
GPU Market Share 6.6% 7.1% 11.0%
Merged Market Share 7.4% 7.6% 11.7%
PJM-EASTINT
Pre-Merger HHI 1,287 1,254 1,455
Post-Merger HHI 1,301 1,263 1,472
Change 14 9 16
FE Capacity (MW) 188 96 91
GPU Capacity (MW) 1,369 1,276 1,460
Merged Capacity (MW) 1,557 1,372 1,552
</TABLE>
<PAGE> 305
Exhibit APP-309, page 5 of 5
SENSITIVITY FOR FIRM ATC
<TABLE>
<CAPTION>
SUMMER WINTER
---------------------------------------------------------- --------------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak
------------------------------ --------- -------- ------- -------- ---------- ------- --------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
FE Market Share 0.6% 0.6% 0.5% 0.2% 0.5% 1.1% 0.5% 0.8%
GPU Market Share 5.7% 5.7% 5.8% 6.5% 7.5% 7.4% 7.1% 11.3%
Merged Market Share 6.3% 6.3% 6.2% 6.7% 8.0% 8.4% 7.6% 12.1%
</TABLE>
<TABLE>
<CAPTION>
SPRING / FALL
---------------------------------
Destination Market Super Peak Off-Peak
------------------------------ -------- ------- ---------
<S> <C> <C> <C>
FE Market Share 1.0% 0.6% 0.7%
GPU Market Share 7.2% 7.6% 11.4%
Merged Market Share 8.2% 8.2% 12.1%
</TABLE>
<PAGE> 306
EXHIBIT NO. APP-310
<PAGE> 307
Exhibit APP-310, page 1 of 5
SENSITIVITY FOR GAS PRICE BASIS DIFFERENTIAL
<TABLE>
<CAPTION>
SUMMER WINTER
---------------------------------------------------------- ---------------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak
-------------------------------- --------- ---------- --------- --------- ---------- -------- --------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
FE
Pre-Merger HHI 5,228 5,225 5,083 4,334 3,215 4,948 4,194 4,113
Post-Merger HHI 5,243 5,240 5,100 4,369 3,269 4,986 4,236 4,274
Change 15 15 16 36 54 38 42 161
FE Capacity (MW) 11,798 11,788 11,090 10,101 9,965 10,789 10,162 8,175
GPU Capacity (MW) 17 18 18 43 90 42 52 166
Merged Capacity (MW) 11,815 11,805 11,109 10,144 10,055 10,831 10,215 8,341
FE Market Share 71.6% 71.6% 70.5% 64.8% 54.5% 69.8% 63.9% 63.1%
GPU Market Share 0.1% 0.1% 0.1% 0.3% 0.5% 0.3% 0.3% 1.3%
Merged Market Share 71.7% 71.7% 70.6% 65.1% 55.0% 70.1% 64.2% 64.3%
PJM
Pre-Merger HHI 1,164 1,163 1,178 1,178 1,143 976 1,130 1,551
Post-Merger HHI 1,176 1,175 1,188 1,183 1,155 998 1,141 1,577
Change 12 12 10 5 12 22 11 26
FE Capacity (MW) 761 761 472 206 360 964 390 235
GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971
Merged Capacity (MW) 3,176 3,176 2,515 2,132 2,271 3,136 2,381 2,206
FE Market Share 1.4% 1.4% 1.1% 0.5% 1.1% 2.2% 1.0% 1.2%
GPU Market Share 4.4% 4.4% 4.6% 5.0% 5.7% 5.0% 5.4% 10.4%
Merged Market Share 5.8% 5.8% 5.6% 5.5% 6.7% 7.3% 6.4% 11.7%
AEP
Pre-Merger HHI 2,434 2,433 2,388 2,464 3,817 2,243 2,131 2,586
Post-Merger HHI 2,434 2,434 2,389 2,464 3,817 2,243 2,131 2,593
Change 1 1 1 1 1 0 1 7
FE Capacity (MW) 3,012 3,011 3,019 2,968 1,664 1,613 1,694 1,591
GPU Capacity (MW) 18 18 21 25 28 26 46 354
Merged Capacity (MW) 3,029 3,030 3,040 2,993 1,692 1,639 1,740 1,945
FE Market Share 6.6% 6.6% 6.7% 6.7% 4.8% 3.4% 3.5% 3.9%
GPU Market Share 0.0% 0.0% 0.0% 0.1% 0.1% 0.1% 0.1% 0.9%
Merged Market Share 6.6% 6.6% 6.7% 6.8% 4.9% 3.5% 3.6% 4.8%
</TABLE>
<TABLE>
<CAPTION>
SPRING / FALL
---------------------------------
Destination Market Super Peak Off-Peak
-------------------------------- --------- ------- --------
<S> <C> <C> <C>
FE
Pre-Merger HHI 4,262 3,519 3,028
Post-Merger HHI 4,298 3,562 3,206
Change 35 43 178
FE Capacity (MW) 8,360 7,847 4,973
GPU Capacity (MW) 35 51 158
Merged Capacity (MW) 8,395 7,898 5,131
FE Market Share 64.3% 57.9% 53.0%
GPU Market Share 0.3% 0.4% 1.7%
Merged Market Share 64.6% 58.3% 54.6%
PJM
Pre-Merger HHI 940 1,059 1,288
Post-Merger HHI 967 1,077 1,320
Change 27 18 32
FE Capacity (MW) 979 460 262
GPU Capacity (MW) 1,885 1,747 1,717
Merged Capacity (MW) 2,864 2,207 1,979
FE Market Share 2.6% 1.5% 1.6%
GPU Market Share 5.1% 5.9% 10.3%
Merged Market Share 7.7% 7.4% 11.8%
AEP
Pre-Merger HHI 1,817 1,693 2,066
Post-Merger HHI 1,818 1,694 2,079
Change 1 1 13
FE Capacity (MW) 2,436 2,558 2,403
GPU Capacity (MW) 26 47 363
Merged Capacity (MW) 2,463 2,605 2,766
FE Market Share 5.7% 5.9% 6.6%
GPU Market Share 0.1% 0.1% 1.0%
Merged Market Share 5.8% 6.0% 7.6%
</TABLE>
<PAGE> 308
Exhibit APP-310, page 2 of 5
SENSITIVITY FOR GAS PRICE BASIS DIFFERENTIAL
<TABLE>
<CAPTION>
SUMMER WINTER
---------------------------------------------------------- ---------------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak
-------------------------------- --------- ---------- --------- --------- ---------- -------- --------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
APS
Pre-Merger HHI 4,150 4,126 3,884 3,298 3,607 4,551 2,482 2,644
Post-Merger HHI 4,153 4,129 3,888 3,303 3,612 4,555 2,493 2,668
Change 3 3 3 5 5 4 11 24
FE Capacity (MW) 311 311 311 414 362 334 807 640
GPU Capacity (MW) 84 85 89 101 110 91 166 312
Merged Capacity (MW) 394 396 400 516 472 425 973 952
FE Market Share 2.3% 2.3% 2.5% 3.2% 3.0% 2.7% 5.1% 4.9%
GPU Market Share 0.6% 0.6% 0.7% 0.8% 0.9% 0.7% 1.0% 2.4%
Merged Market Share 3.0% 3.0% 3.2% 4.0% 3.9% 3.4% 6.1% 7.3%
DPL
Pre-Merger HHI 7,115 7,101 6,895 5,475 3,907 5,308 3,766 2,963
Post-Merger HHI 7,115 7,101 6,895 5,476 3,909 5,308 3,767 2,967
Change 0 0 0 0 1 0 1 4
FE Capacity (MW) 137 137 137 211 351 234 408 475
GPU Capacity (MW) 0 0 0 1 3 1 2 8
Merged Capacity (MW) 137 137 137 212 354 235 410 484
FE Market Share 3.5% 3.5% 3.9% 5.8% 7.8% 6.3% 9.0% 10.0%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.2%
Merged Market Share 3.5% 3.6% 3.9% 5.8% 7.9% 6.3% 9.0% 10.2%
DQE
Pre-Merger HHI 6,207 6,207 6,029 3,964 5,902 3,369 3,018 2,676
Post-Merger HHI 6,208 6,207 6,030 3,966 5,903 3,371 3,022 2,747
Change 0 0 0 2 1 2 4 70
FE Capacity (MW) 591 591 592 1,774 604 1,348 1,714 2,101
GPU Capacity (MW) 0 0 0 1 1 2 4 41
Merged Capacity (MW) 591 591 593 1,775 605 1,350 1,718 2,142
FE Market Share 17.5% 17.5% 18.7% 37.6% 19.4% 27.5% 30.7% 42.6%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.8%
</TABLE>
<TABLE>
<CAPTION>
SPRING / FALL
---------------------------------
Destination Market Super Peak Off-Peak
-------------------------------- --------- ------- --------
<S> <C> <C> <C>
APS
Pre-Merger HHI 3,958 2,049 2,189
Post-Merger HHI 3,962 2,060 2,215
Change 4 12 26
FE Capacity (MW) 305 732 582
GPU Capacity (MW) 83 165 308
Merged Capacity (MW) 388 897 890
FE Market Share 2.8% 5.1% 5.0%
GPU Market Share 0.8% 1.1% 2.6%
Merged Market Share 3.6% 6.2% 7.6%
DPL
Pre-Merger HHI 4,712 3,243 2,618
Post-Merger HHI 4,713 3,245 2,623
Change 0 1 6
FE Capacity (MW) 228 397 457
GPU Capacity (MW) 1 2 11
Merged Capacity (MW) 229 399 468
FE Market Share 7.2% 10.0% 10.8%
GPU Market Share 0.0% 0.1% 0.3%
Merged Market Share 7.2% 10.0% 11.1%
DQE
Pre-Merger HHI 3,354 3,169 3,461
Post-Merger HHI 3,357 3,174 3,546
Change 3 6 85
FE Capacity (MW) 1,597 2,031 3,021
GPU Capacity (MW) 2 4 44
Merged Capacity (MW) 1,599 2,034 3,064
FE Market Share 36.2% 40.0% 54.3%
GPU Market Share 0.0% 0.1% 0.8%
</TABLE>
<PAGE> 309
Exhibit APP-310, page 3 of 5
SENSITIVITY FOR GAS PRICE BASIS DIFFERENTIAL
<TABLE>
<CAPTION>
SUMMER WINTER
---------------------------------------------------------- ---------------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak
-------------------------------- --------- ---------- --------- --------- ---------- -------- --------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Merged Market Share 17.5% 17.5% 18.7% 37.7% 19.5% 27.5% 30.8% 43.4%
MECS
Pre-Merger HHI 3,448 3,437 3,290 3,854 2,878 2,643 2,636 3,267
Post-Merger HHI 3,448 3,437 3,290 3,855 2,879 2,643 2,636 3,270
Change 0 0 0 0 1 0 0 2
FE Capacity (MW) 964 963 964 541 1,143 1,184 1,114 1,006
GPU Capacity (MW) 1 1 2 2 11 5 5 18
Merged Capacity (MW) 965 965 965 543 1,154 1,188 1,119 1,024
FE Market Share 4.5% 4.5% 5.5% 3.6% 7.2% 6.3% 6.5% 7.8%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1%
Merged Market Share 4.5% 4.5% 5.5% 3.6% 7.3% 6.3% 6.5% 7.9%
NYPP
Pre-Merger HHI 1,166 1,155 1,159 1,064 939 1,161 1,083 1,017
Post-Merger HHI 1,166 1,155 1,159 1,064 940 1,161 1,083 1,017
Change 0 0 0 0 0 0 0 0
FE Capacity (MW) 10 11 13 8 18 13 8 13
GPU Capacity (MW) 62 63 65 70 83 48 48 106
Merged Capacity (MW) 72 74 78 78 101 60 57 119
FE Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.1% 0.0% 0.1%
GPU Market Share 0.2% 0.2% 0.2% 0.3% 0.6% 0.2% 0.2% 1.0%
Merged Market Share 0.2% 0.2% 0.2% 0.3% 0.8% 0.3% 0.3% 1.1%
VEPCO
Pre-Merger HHI 4,005 3,954 3,411 3,054 2,711 3,099 2,768 1,979
Post-Merger HHI 4,005 3,954 3,412 3,055 2,712 3,100 2,769 1,986
Change 1 1 1 1 1 1 1 7
FE Capacity (MW) 176 176 179 180 128 104 107 207
GPU Capacity (MW) 99 101 105 111 136 141 140 308
Merged Capacity (MW) 275 277 284 292 264 245 247 515
FE Market Share 0.8% 0.8% 0.9% 1.0% 0.8% 0.6% 0.6% 1.6%
</TABLE>
<TABLE>
<CAPTION>
SPRING / FALL
---------------------------------
Destination Market Super Peak Off-Peak
-------------------------------- --------- ------- --------
<S> <C> <C> <C>
Merged Market Share 36.3% 40.1% 55.1%
MECS
Pre-Merger HHI 2,363 2,351 2,816
Post-Merger HHI 2,364 2,352 2,824
Change 1 1 7
FE Capacity (MW) 1,633 1,531 1,368
GPU Capacity (MW) 7 9 33
Merged Capacity (MW) 1,640 1,540 1,401
FE Market Share 9.9% 10.3% 12.2%
GPU Market Share 0.0% 0.1% 0.3%
Merged Market Share 10.0% 10.4% 12.5%
NYPP
Pre-Merger HHI 1,001 956 807
Post-Merger HHI 1,001 956 810
Change 0 0 3
FE Capacity (MW) 48 34 54
GPU Capacity (MW) 131 148 320
Merged Capacity (MW) 179 182 374
FE Market Share 0.2% 0.2% 0.5%
GPU Market Share 0.5% 0.7% 2.9%
Merged Market Share 0.7% 0.9% 3.4%
VEPCO
Pre-Merger HHI 3,067 2,626 1,734
Post-Merger HHI 3,069 2,628 1,746
Change 1 2 12
FE Capacity (MW) 148 153 254
GPU Capacity (MW) 132 145 316
Merged Capacity (MW) 280 298 570
FE Market Share 0.9% 1.0% 2.2%
</TABLE>
<PAGE> 310
Exhibit APP-310, page 4 of 5
SENSITIVITY FOR GAS PRICE BASIS DIFFERENTIAL
<TABLE>
<CAPTION>
SUMMER WINTER
---------------------------------------------------------- ---------------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak
-------------------------------- --------- ---------- --------- --------- ---------- -------- --------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
GPU Market Share 0.4% 0.5% 0.5% 0.6% 0.8% 0.8% 0.8% 2.3%
Merged Market Share 1.2% 1.2% 1.4% 1.6% 1.6% 1.3% 1.5% 3.9%
PJM-WESTINT
Pre-Merger HHI 1,164 1,163 1,178 1,178 1,143 976 1,130 1,551
Post-Merger HHI 1,176 1,175 1,188 1,183 1,155 998 1,141 1,577
Change 12 12 10 5 12 22 11 26
FE Capacity (MW) 761 761 472 206 360 964 390 235
GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971
Merged Capacity (MW) 3,176 3,176 2,515 2,132 2,271 3,136 2,381 2,206
FE Market Share 1.4% 1.4% 1.1% 0.5% 1.1% 2.2% 1.0% 1.2%
GPU Market Share 4.4% 4.4% 4.6% 5.0% 5.7% 5.0% 5.4% 10.4%
Merged Market Share 5.8% 5.8% 5.6% 5.5% 6.7% 7.3% 6.4% 11.7%
PJM-CENTINT
Pre-Merger HHI 1,508 1,507 1,547 1,462 1,479 1,312 1,455 1,564
Post-Merger HHI 1,513 1,513 1,552 1,465 1,487 1,325 1,462 1,589
Change 6 6 5 3 8 13 7 26
FE Capacity (MW) 216 216 149 71 139 320 151 229
GPU Capacity (MW) 2,177 2,177 1,815 1,714 1,713 1,926 1,769 1,962
Merged Capacity (MW) 2,392 2,392 1,964 1,785 1,852 2,246 1,920 2,191
FE Market Share 0.5% 0.5% 0.5% 0.3% 0.6% 1.0% 0.6% 1.2%
GPU Market Share 5.3% 5.4% 5.6% 6.1% 6.9% 6.3% 6.5% 10.5%
Merged Market Share 5.9% 5.9% 6.0% 6.4% 7.5% 7.3% 7.0% 11.7%
PJM-EASTINT
Pre-Merger HHI 1,485 1,477 1,400 1,378 1,350 1,171 1,306 1,667
Post-Merger HHI 1,493 1,484 1,407 1,382 1,360 1,189 1,315 1,691
Change 7 7 7 4 10 18 9 24
FE Capacity (MW) 216 217 150 71 133 292 138 172
GPU Capacity (MW) 1,863 1,864 1,517 1,429 1,441 1,604 1,468 1,757
Merged Capacity (MW) 2,079 2,081 1,667 1,500 1,574 1,896 1,606 1,929
</TABLE>
<TABLE>
<CAPTION>
SPRING / FALL
---------------------------------
Destination Market Super Peak Off-Peak
-------------------------------- --------- ------- --------
<S> <C> <C> <C>
GPU Market Share 0.8% 1.0% 2.7%
Merged Market Share 1.7% 2.0% 5.0%
PJM-WESTINT
Pre-Merger HHI 945 1,059 1,288
Post-Merger HHI 971 1,077 1,320
Change 26 18 32
FE Capacity (MW) 955 460 262
GPU Capacity (MW) 1,885 1,747 1,717
Merged Capacity (MW) 2,841 2,207 1,979
FE Market Share 2.6% 1.5% 1.6%
GPU Market Share 5.1% 5.9% 10.3%
Merged Market Share 7.7% 7.4% 11.8%
PJM-CENTINT
Pre-Merger HHI 1,295 1,365 1,417
Post-Merger HHI 1,311 1,378 1,446
Change 16 13 29
FE Capacity (MW) 317 192 199
GPU Capacity (MW) 1,633 1,533 1,631
Merged Capacity (MW) 1,950 1,725 1,830
FE Market Share 1.3% 0.9% 1.3%
GPU Market Share 6.5% 7.1% 10.9%
Merged Market Share 7.7% 8.0% 12.2%
PJM-EASTINT
Pre-Merger HHI 1,205 1,228 1,432
Post-Merger HHI 1,226 1,243 1,463
Change 21 15 30
FE Capacity (MW) 296 174 173
GPU Capacity (MW) 1,355 1,279 1,467
Merged Capacity (MW) 1,651 1,454 1,640
</TABLE>
<PAGE> 311
Exhibit APP-310, page 5 of 5
SENSITIVITY FOR GAS PRICE BASIS DIFFERENTIAL
<TABLE>
<CAPTION>
SUMMER WINTER
---------------------------------------------------------- ---------------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak
-------------------------------- --------- ---------- --------- --------- ---------- -------- --------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
FE Market Share 0.7% 0.7% 0.6% 0.3% 0.7% 1.3% 0.7% 1.1%
GPU Market Share 5.7% 5.7% 5.9% 6.4% 7.4% 7.0% 7.0% 11.1%
Merged Market Share 6.3% 6.3% 6.4% 6.8% 8.1% 8.3% 7.6% 12.2%
</TABLE>
<TABLE>
<CAPTION>
SPRING / FALL
---------------------------------
Destination Market Super Peak Off-Peak
-------------------------------- --------- ------- --------
<S> <C> <C> <C>
FE Market Share 1.5% 1.0% 1.3%
GPU Market Share 7.0% 7.5% 11.3%
Merged Market Share 8.5% 8.6% 12.7%
</TABLE>
<PAGE> 312
EXHIBIT NO. APP-311
<PAGE> 313
Exhibit APP-311, page 1 of 5
SENSITIVITY FOR ALLIANCE TRANSMISSION PRICES
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
FE
Pre-Merger HHI 5,228 5,225 5,083 4,334 3,214 4,948 4,194 4,134 4,262 3,519 3,048
Post-Merger HHI 5,243 5,240 5,100 4,370 3,271 4,986 4,236 4,277 4,298 3,562 3,203
Change 15 15 17 37 57 38 42 143 36 43 156
FE Capacity (MW) 11,798 11,788 11,090 10,101 9,965 10,789 10,162 8,175 8,360 7,847 4,973
GPU Capacity (MW) 17 18 18 44 96 42 52 147 37 51 138
Merged Capacity (MW) 11,815 11,805 11,109 10,145 10,061 10,831 10,215 8,322 8,396 7,898 5,111
FE Market Share 71.6% 71.6% 70.5% 64.8% 54.5% 69.8% 63.9% 63.1% 64.3% 57.9% 53.0%
GPU Market Share 0.1% 0.1% 0.1% 0.3% 0.5% 0.3% 0.3% 1.1% 0.3% 0.4% 1.5%
Merged Market Share 71.7% 71.7% 70.6% 65.1% 55.0% 70.1% 64.2% 64.2% 64.6% 58.3% 54.4%
PJM
Pre-Merger HHI 1,164 1,163 1,181 1,178 1,143 976 1,130 1,550 940 1,059 1,288
Post-Merger HHI 1,176 1,175 1,190 1,183 1,155 998 1,141 1,571 966 1,077 1,314
Change 12 12 9 5 12 22 11 21 27 18 26
FE Capacity (MW) 761 761 469 206 351 964 389 188 979 459 212
GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 1,885 1,747 1,717
Merged Capacity (MW) 3,176 3,175 2,512 2,132 2,262 3,136 2,381 2,159 2,864 2,207 1,929
FE Market Share 1.4% 1.4% 1.0% 0.5% 1.0% 2.2% 1.0% 1.0% 2.6% 1.5% 1.3%
GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.0% 5.4% 10.4% 5.1% 5.9% 10.3%
Merged Market Share 5.8% 5.8% 5.5% 5.5% 6.7% 7.3% 6.4% 11.4% 7.7% 7.4% 11.5%
AEP
Pre-Merger HHI 2,434 2,433 2,385 2,464 3,816 2,243 2,131 2,561 1,817 1,693 2,074
Post-Merger HHI 2,434 2,434 2,386 2,464 3,817 2,243 2,131 2,564 1,817 1,694 2,078
Change 1 1 1 1 1 0 1 3 1 1 4
FE Capacity (MW) 3,012 3,011 3,020 2,968 1,664 1,613 1,694 1,563 2,437 2,558 2,346
GPU Capacity (MW) 18 18 21 25 20 26 46 137 26 47 126
Merged Capacity (MW) 3,029 3,030 3,041 2,993 1,684 1,639 1,740 1,700 2,463 2,605 2,472
FE Market Share 6.6% 6.6% 6.7% 6.7% 4.8% 3.4% 3.5% 3.8% 5.7% 5.9% 6.5%
GPU Market Share 0.0% 0.0% 0.0% 0.1% 0.1% 0.1% 0.1% 0.3% 0.1% 0.1% 0.3%
Merged Market Share 6.6% 6.6% 6.7% 6.8% 4.9% 3.5% 3.6% 4.1% 5.8% 6.0% 6.8%
</TABLE>
<PAGE> 314
Exhibit APP-311, page 2 of 5
SENSITIVITY FOR ALLIANCE TRANSMISSION PRICES
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
APS
Pre-Merger HHI 4,150 4,126 3,886 3,298 3,606 4,550 2,482 2,604 3,956 2,049 2,141
Post-Merger HHI 4,153 4,129 3,889 3,303 3,611 4,554 2,493 2,628 3,961 2,060 2,168
Change 3 3 3 5 5 4 11 24 4 12 26
FE Capacity (MW) 311 311 311 414 362 334 807 640 305 732 582
GPU Capacity (MW) 84 85 89 101 110 89 166 312 83 165 308
Merged Capacity (MW) 394 396 400 516 472 423 973 952 388 897 890
FE Market Share 2.3% 2.3% 2.5% 3.2% 3.0% 2.7% 5.1% 4.9% 2.8% 5.1% 5.0%
GPU Market Share 0.6% 0.6% 0.7% 0.8% 0.9% 0.7% 1.0% 2.4% 0.8% 1.1% 2.6%
Merged Market Share 3.0% 3.0% 3.2% 4.0% 3.9% 3.4% 6.1% 7.3% 3.6% 6.2% 7.6%
DPL
Pre-Merger HHI 7,115 7,092 6,817 5,475 3,907 5,308 3,766 2,870 4,712 3,243 2,542
Post-Merger HHI 7,115 7,092 6,817 5,476 3,908 5,308 3,767 2,881 4,713 3,245 2,558
Change 0 0 0 0 2 0 1 10 0 1 16
FE Capacity (MW) 137 137 137 211 349 234 408 438 228 397 412
GPU Capacity (MW) 0 0 0 1 5 1 2 26 1 2 35
Merged Capacity (MW) 137 137 137 212 354 235 410 464 229 399 447
FE Market Share 3.5% 3.6% 3.9% 5.8% 7.7% 6.3% 9.0% 9.2% 7.2% 10.0% 9.7%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.6% 0.0% 0.1% 0.8%
Merged Market Share 3.5% 3.6% 3.9% 5.8% 7.9% 6.3% 9.0% 9.8% 7.2% 10.0% 10.5%
DQE
Pre-Merger HHI 6,207 6,207 6,029 3,964 5,902 3,369 3,018 2,572 3,355 3,169 2,711
Post-Merger HHI 6,208 6,208 6,029 3,967 5,904 3,371 3,022 2,642 3,357 3,174 2,796
Change 0 0 0 2 1 2 4 70 3 6 85
FE Capacity (MW) 591 591 592 1,774 604 1,348 1,714 2,101 1,597 2,031 2,115
GPU Capacity (MW) 0 0 0 1 1 2 4 41 2 4 44
Merged Capacity (MW) 591 591 592 1,775 605 1,350 1,718 2,142 1,599 2,034 2,159
FE Market Share 17.5% 17.5% 18.6% 37.6% 19.4% 27.5% 30.7% 42.6% 36.2% 40.0% 45.4%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.8% 0.0% 0.1% 0.9%
Merged Market Share 17.5% 17.5% 18.7% 37.7% 19.5% 27.5% 30.8% 43.4% 36.3% 40.1% 46.4%
</TABLE>
<PAGE> 315
Exhibit APP-311, page 3 of 5
SENSITIVITY FOR ALLIANCE TRANSMISSION PRICES
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
MECS
Pre-Merger HHI 3,448 3,437 3,290 3,854 2,878 2,643 2,636 3,249 2,363 2,351 2,789
Post-Merger HHI 3,448 3,437 3,290 3,855 2,879 2,643 2,636 3,251 2,364 2,352 2,796
Change 0 0 0 0 1 0 0 2 1 1 7
FE Capacity (MW) 964 963 964 541 1,144 1,184 1,114 1,023 1,634 1,531 1,350
GPU Capacity (MW) 1 1 1 2 11 5 5 13 7 9 31
Merged Capacity (MW) 965 965 966 543 1,154 1,188 1,119 1,037 1,641 1,540 1,381
FE Market Share 4.5% 4.5% 5.5% 3.6% 7.2% 6.3% 6.5% 7.9% 9.9% 10.3% 12.1%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% 0.0% 0.1% 0.3%
Merged Market Share 4.5% 4.5% 5.5% 3.6% 7.3% 6.3% 6.5% 8.0% 10.0% 10.4% 12.4%
NYPP
Pre-Merger HHI 1,166 1,157 1,173 1,064 939 1,161 1,083 1,017 1,001 956 807
Post-Merger HHI 1,166 1,158 1,173 1,064 940 1,161 1,083 1,017 1,001 956 810
Change 0 0 0 0 0 0 0 0 0 0 3
FE Capacity (MW) 10 11 13 8 18 13 8 13 48 34 54
GPU Capacity (MW) 62 63 65 70 83 47 48 106 131 148 320
Merged Capacity (MW) 72 74 78 78 101 59 57 119 179 182 374
FE Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.1% 0.0% 0.1% 0.2% 0.2% 0.5%
GPU Market Share 0.2% 0.2% 0.2% 0.3% 0.6% 0.2% 0.2% 1.0% 0.5% 0.7% 2.9%
Merged Market Share 0.2% 0.2% 0.2% 0.3% 0.8% 0.3% 0.3% 1.1% 0.7% 0.9% 3.4%
VEPCO
Pre-Merger HHI 4,005 3,954 3,428 3,053 2,714 3,099 2,768 1,957 3,067 2,626 1,712
Post-Merger HHI 4,005 3,954 3,429 3,055 2,716 3,100 2,769 1,961 3,068 2,628 1,721
Change 1 1 1 1 1 1 1 4 1 2 9
FE Capacity (MW) 176 176 179 180 126 104 107 120 148 153 178
GPU Capacity (MW) 99 101 106 116 153 141 140 308 137 145 335
Merged Capacity (MW) 275 277 285 297 279 245 247 428 285 298 513
FE Market Share 0.8% 0.8% 0.9% 1.0% 0.8% 0.6% 0.6% 0.9% 0.9% 1.0% 1.5%
GPU Market Share 0.4% 0.5% 0.5% 0.6% 0.9% 0.8% 0.8% 2.3% 0.8% 1.0% 2.9%
Merged Market Share 1.2% 1.3% 1.4% 1.6% 1.7% 1.3% 1.5% 3.2% 1.7% 2.0% 4.5%
</TABLE>
<PAGE> 316
Exhibit APP-311, page 4 of 5
SENSITIVITY FOR ALLIANCE TRANSMISSION PRICES
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PJM-WESTINT
Pre-Merger HHI 1,164 1,163 1,181 1,178 1,143 976 1,130 1,550 944 1,059 1,288
Post-Merger HHI 1,176 1,175 1,190 1,183 1,155 998 1,141 1,571 970 1,077 1,314
Change 12 12 9 5 12 22 11 21 26 18 26
FE Capacity (MW) 761 761 469 206 351 964 389 188 955 459 212
GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 1,885 1,747 1,717
Merged Capacity (MW) 3,176 3,175 2,512 2,132 2,262 3,136 2,381 2,159 2,841 2,207 1,929
FE Market Share 1.4% 1.4% 1.0% 0.5% 1.0% 2.2% 1.0% 1.0% 2.6% 1.5% 1.3%
GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.0% 5.4% 10.4% 5.1% 5.9% 10.3%
Merged Market Share 5.8% 5.8% 5.5% 5.5% 6.7% 7.3% 6.4% 11.4% 7.7% 7.4% 11.5%
PJM-CENTINT
Pre-Merger HHI 1,508 1,507 1,550 1,462 1,479 1,312 1,455 1,564 1,295 1,365 1,417
Post-Merger HHI 1,513 1,513 1,555 1,465 1,487 1,325 1,462 1,584 1,311 1,378 1,440
Change 6 6 5 3 8 13 7 20 16 13 24
FE Capacity (MW) 216 216 148 71 135 320 151 183 317 192 161
GPU Capacity (MW) 2,177 2,177 1,815 1,714 1,713 1,926 1,769 1,962 1,633 1,533 1,631
Merged Capacity (MW) 2,392 2,392 1,963 1,785 1,848 2,246 1,920 2,145 1,950 1,725 1,792
FE Market Share 0.5% 0.5% 0.4% 0.3% 0.5% 1.0% 0.6% 1.0% 1.3% 0.9% 1.1%
GPU Market Share 5.3% 5.4% 5.5% 6.1% 6.9% 6.3% 6.5% 10.5% 6.5% 7.1% 10.9%
Merged Market Share 5.9% 5.9% 5.9% 6.4% 7.5% 7.3% 7.0% 11.4% 7.7% 8.0% 12.0%
PJM-EASTINT
Pre-Merger HHI 1,485 1,477 1,417 1,378 1,350 1,171 1,306 1,667 1,205 1,228 1,432
Post-Merger HHI 1,493 1,484 1,424 1,382 1,360 1,189 1,315 1,686 1,226 1,243 1,456
Change 7 7 6 4 10 18 9 19 21 15 25
FE Capacity (MW) 216 217 148 71 130 292 138 137 296 174 140
GPU Capacity (MW) 1,863 1,864 1,517 1,429 1,441 1,604 1,468 1,757 1,355 1,279 1,467
Merged Capacity (MW) 2,079 2,080 1,665 1,500 1,571 1,896 1,606 1,894 1,651 1,454 1,607
</TABLE>
<PAGE> 317
Exhibit APP-311, page 5 of 5
SENSITIVITY FOR ALLIANCE TRANSMISSION PRICES
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
FE Market Share 0.7% 0.7% 0.6% 0.3% 0.7% 1.3% 0.7% 0.9% 1.5% 1.0% 1.1%
GPU Market Share 5.7% 5.7% 5.7% 6.4% 7.4% 7.0% 7.0% 11.1% 7.0% 7.5% 11.3%
Merged Market Share 6.3% 6.3% 6.3% 6.8% 8.1% 8.3% 7.6% 12.0% 8.5% 8.6% 12.4%
</TABLE>
<PAGE> 318
EXHIBIT NO. APP-312
<PAGE> 319
Exhibit APP-312, page 1 of 5
SENSITIVITY FOR ZERO TRANSMISSION PRICE
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
FE
Pre-Merger HHI 5,228 5,225 5,083 4,334 3,213 4,948 4,194 3,823 4,262 3,519 2,608
Post-Merger HHI 5,243 5,240 5,099 4,369 3,260 4,985 4,236 3,909 4,297 3,562 2,698
Change 15 15 16 35 47 37 42 86 35 43 90
FE Capacity (MW) 11,798 11,788 11,090 10,101 9,965 10,789 10,162 8,175 8,360 7,847 4,973
GPU Capacity (MW) 17 17 18 42 79 41 52 96 35 51 95
Merged Capacity (MW) 11,815 11,805 11,108 10,143 10,044 10,830 10,215 8,271 8,395 7,898 5,069
FE Market Share 71.6% 71.6% 70.5% 64.8% 54.5% 69.8% 63.9% 60.6% 64.3% 57.9% 48.3%
GPU Market Share 0.1% 0.1% 0.1% 0.3% 0.4% 0.3% 0.3% 0.7% 0.3% 0.4% 0.9%
Merged Market Share 71.7% 71.7% 70.6% 65.1% 54.9% 70.0% 64.2% 61.3% 64.6% 58.3% 49.3%
PJM
Pre-Merger HHI 1,164 1,163 1,181 1,178 1,143 976 1,130 1,553 940 1,059 1,292
Post-Merger HHI 1,176 1,175 1,190 1,183 1,155 998 1,141 1,581 967 1,077 1,326
Change 12 12 9 5 12 22 11 28 27 18 33
FE Capacity (MW) 761 761 472 206 354 964 389 251 979 459 273
GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 1,885 1,747 1,717
Merged Capacity (MW) 3,176 3,176 2,515 2,132 2,265 3,136 2,381 2,222 2,864 2,207 1,990
FE Market Share 1.4% 1.4% 1.0% 0.5% 1.0% 2.2% 1.0% 1.3% 2.6% 1.5% 1.6%
GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.0% 5.4% 10.4% 5.1% 5.9% 10.3%
Merged Market Share 5.8% 5.8% 5.5% 5.5% 6.7% 7.3% 6.4% 11.7% 7.7% 7.4% 11.9%
AEP
Pre-Merger HHI 2,434 2,433 2,385 2,464 3,815 2,243 2,131 2,182 1,817 1,693 1,730
Post-Merger HHI 2,434 2,434 2,386 2,464 3,816 2,243 2,131 2,183 1,817 1,694 1,733
Change 1 1 1 1 0 0 1 1 1 1 3
FE Capacity (MW) 3,012 3,011 3,020 2,968 1,664 1,613 1,694 1,563 2,437 2,558 2,346
GPU Capacity (MW) 18 18 20 24 15 25 46 87 25 47 95
Merged Capacity (MW) 3,029 3,029 3,040 2,992 1,679 1,639 1,740 1,650 2,461 2,605 2,441
FE Market Share 6.6% 6.6% 6.7% 6.7% 4.8% 3.4% 3.5% 3.5% 5.7% 5.9% 5.8%
GPU Market Share 0.0% 0.0% 0.0% 0.1% 0.0% 0.1% 0.1% 0.2% 0.1% 0.1% 0.2%
Merged Market Share 6.6% 6.6% 6.7% 6.8% 4.9% 3.5% 3.6% 3.7% 5.8% 6.0% 6.1%
</TABLE>
<PAGE> 320
Exhibit APP-312, page 2 of 5
SENSITIVITY FOR ZERO TRANSMISSION PRICE
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
APS
Pre-Merger HHI 4,150 4,126 3,886 3,299 3,607 4,550 2,482 2,531 3,957 2,052 2,064
Post-Merger HHI 4,153 4,129 3,889 3,304 3,613 4,554 2,493 2,551 3,962 2,064 2,087
Change 3 3 3 5 5 4 11 20 4 12 23
FE Capacity (MW) 311 311 311 414 362 334 807 629 305 732 568
GPU Capacity (MW) 84 84 87 101 106 89 166 283 83 165 293
Merged Capacity (MW) 394 395 399 515 468 423 973 912 387 897 861
FE Market Share 2.3% 2.3% 2.5% 3.2% 3.0% 2.7% 5.1% 4.7% 2.8% 5.1% 4.7%
GPU Market Share 0.6% 0.6% 0.7% 0.8% 0.9% 0.7% 1.0% 2.1% 0.8% 1.1% 2.4%
Merged Market Share 3.0% 3.0% 3.2% 4.0% 3.9% 3.4% 6.1% 6.9% 3.6% 6.2% 7.2%
DPL
Pre-Merger HHI 7,115 7,092 6,816 5,475 3,870 5,308 3,766 2,857 4,712 3,243 2,436
Post-Merger HHI 7,115 7,092 6,816 5,476 3,871 5,308 3,767 2,860 4,713 3,245 2,440
Change 0 0 0 0 1 0 1 2 0 1 5
FE Capacity (MW) 137 137 137 211 351 234 408 483 228 397 451
GPU Capacity (MW) 0 0 0 1 3 1 2 6 1 2 9
Merged Capacity (MW) 137 137 137 212 354 235 410 489 229 399 460
FE Market Share 3.5% 3.6% 3.9% 5.8% 7.8% 6.3% 9.0% 10.2% 7.2% 10.0% 10.7%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% 0.0% 0.1% 0.2%
Merged Market Share 3.5% 3.6% 4.0% 5.8% 7.9% 6.3% 9.0% 10.3% 7.2% 10.0% 10.9%
DQE
Pre-Merger HHI 6,207 6,207 6,029 3,964 5,903 3,368 3,018 2,563 3,355 3,169 3,278
Post-Merger HHI 6,208 6,208 6,030 3,966 5,903 3,370 3,022 2,580 3,357 3,174 3,300
Change 0 0 0 2 1 2 4 17 3 6 22
FE Capacity (MW) 591 591 593 1,774 604 1,348 1,714 2,065 1,597 2,031 2,949
GPU Capacity (MW) 0 0 0 1 0 2 4 10 2 4 11
Merged Capacity (MW) 591 591 593 1,775 605 1,350 1,718 2,075 1,599 2,034 2,960
FE Market Share 17.5% 17.5% 18.7% 37.6% 19.4% 27.5% 30.7% 41.9% 36.2% 40.0% 53.0%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.2% 0.0% 0.1% 0.2%
Merged Market Share 17.5% 17.5% 18.7% 37.7% 19.5% 27.5% 30.8% 42.1% 36.3% 40.1% 53.2%
</TABLE>
<PAGE> 321
Exhibit APP-312, page 3 of 5
SENSITIVITY FOR ZERO TRANSMISSION PRICE
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
MECS
Pre-Merger HHI 3,448 3,437 3,290 3,854 2,878 2,643 2,636 3,241 2,363 2,351 2,784
Post-Merger HHI 3,448 3,437 3,290 3,855 2,879 2,643 2,636 3,242 2,364 2,352 2,790
Change 0 0 0 0 1 0 0 1 1 1 6
FE Capacity (MW) 964 963 964 541 1,144 1,184 1,114 1,023 1,634 1,531 1,350
GPU Capacity (MW) 1 1 1 2 8 4 5 12 7 9 28
Merged Capacity (MW) 965 965 966 543 1,152 1,188 1,119 1,035 1,640 1,540 1,378
FE Market Share 4.5% 4.5% 5.5% 3.6% 7.2% 6.3% 6.5% 7.9% 9.9% 10.3% 12.1%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% 0.0% 0.1% 0.2%
Merged Market Share 4.5% 4.5% 5.5% 3.6% 7.3% 6.3% 6.5% 8.0% 10.0% 10.4% 12.3%
NYPP
Pre-Merger HHI 1,166 1,157 1,173 1,064 883 1,161 1,083 945 1,001 956 761
Post-Merger HHI 1,166 1,157 1,173 1,064 883 1,161 1,083 945 1,001 956 764
Change 0 0 0 0 0 0 0 0 0 0 2
FE Capacity (MW) 10 10 13 8 17 13 8 12 48 34 49
GPU Capacity (MW) 62 63 64 70 80 47 48 95 131 148 296
Merged Capacity (MW) 72 73 77 78 97 59 57 107 178 182 345
FE Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.1% 0.0% 0.1% 0.2% 0.2% 0.4%
GPU Market Share 0.2% 0.2% 0.2% 0.3% 0.6% 0.2% 0.2% 0.9% 0.5% 0.7% 2.6%
Merged Market Share 0.2% 0.2% 0.2% 0.3% 0.7% 0.3% 0.3% 1.0% 0.7% 0.9% 3.1%
VEPCO
Pre-Merger HHI 4,005 3,954 3,428 3,054 2,704 3,098 2,768 1,907 3,067 2,626 1,659
Post-Merger HHI 4,005 3,954 3,429 3,055 2,705 3,099 2,769 1,911 3,069 2,628 1,666
Change 1 1 1 1 1 1 1 3 1 2 7
FE Capacity (MW) 176 176 179 180 126 104 107 109 148 153 158
GPU Capacity (MW) 99 100 103 111 131 138 140 279 132 145 300
Merged Capacity (MW) 275 276 282 291 257 242 247 389 280 298 458
FE Market Share 0.8% 0.8% 0.9% 1.0% 0.8% 0.6% 0.6% 0.8% 0.9% 1.0% 1.4%
GPU Market Share 0.4% 0.5% 0.5% 0.6% 0.8% 0.8% 0.8% 2.1% 0.8% 1.0% 2.6%
Merged Market Share 1.2% 1.2% 1.4% 1.6% 1.5% 1.3% 1.5% 2.9% 1.7% 2.0% 4.0%
</TABLE>
<PAGE> 322
Exhibit APP-312, page 4 of 5
SENSITIVITY FOR ZERO TRANSMISSION PRICE
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PJM-WESTINT
Pre-Merger HHI 1,164 1,163 1,181 1,178 1,143 976 1,130 1,553 944 1,059 1,292
Post-Merger HHI 1,176 1,175 1,190 1,183 1,155 998 1,141 1,581 971 1,077 1,326
Change 12 12 9 5 12 22 11 28 26 18 33
FE Capacity (MW) 761 761 472 206 354 964 389 251 956 459 273
GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 1,885 1,747 1,717
Merged Capacity (MW) 3,176 3,176 2,515 2,132 2,265 3,136 2,381 2,222 2,841 2,207 1,990
FE Market Share 1.4% 1.4% 1.0% 0.5% 1.0% 2.2% 1.0% 1.3% 2.6% 1.5% 1.6%
GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.0% 5.4% 10.4% 5.1% 5.9% 10.3%
Merged Market Share 5.8% 5.8% 5.5% 5.5% 6.7% 7.3% 6.4% 11.7% 7.7% 7.4% 11.9%
PJM-CENTINT
Pre-Merger HHI 1,508 1,507 1,550 1,462 1,479 1,312 1,455 1,566 1,295 1,365 1,420
Post-Merger HHI 1,513 1,513 1,555 1,465 1,487 1,325 1,462 1,593 1,311 1,378 1,450
Change 6 6 5 3 8 13 7 27 16 13 30
FE Capacity (MW) 216 216 149 71 137 320 151 245 317 192 208
GPU Capacity (MW) 2,177 2,177 1,815 1,714 1,713 1,926 1,769 1,962 1,633 1,533 1,631
Merged Capacity (MW) 2,392 2,392 1,964 1,785 1,850 2,246 1,920 2,206 1,950 1,725 1,838
FE Market Share 0.5% 0.5% 0.4% 0.3% 0.6% 1.0% 0.6% 1.3% 1.3% 0.9% 1.4%
GPU Market Share 5.3% 5.4% 5.5% 6.1% 6.9% 6.3% 6.5% 10.5% 6.5% 7.1% 10.9%
Merged Market Share 5.9% 5.9% 5.9% 6.4% 7.5% 7.3% 7.0% 11.8% 7.7% 8.0% 12.3%
PJM-EASTINT
Pre-Merger HHI 1,485 1,477 1,417 1,378 1,350 1,171 1,306 1,668 1,205 1,228 1,435
Post-Merger HHI 1,493 1,484 1,424 1,382 1,360 1,188 1,315 1,694 1,226 1,243 1,467
Change 7 7 7 4 10 18 9 26 21 15 32
FE Capacity (MW) 216 217 150 71 131 292 138 183 296 174 180
GPU Capacity (MW) 1,863 1,864 1,517 1,429 1,441 1,604 1,468 1,757 1,355 1,279 1,467
Merged Capacity (MW) 2,079 2,081 1,667 1,500 1,572 1,896 1,606 1,941 1,651 1,454 1,647
</TABLE>
<PAGE> 323
Exhibit APP-312, page 5 of 5
SENSITIVITY FOR ZERO TRANSMISSION PRICE
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
FE Market Share 0.7% 0.7% 0.6% 0.3% 0.7% 1.3% 0.7% 1.2% 1.5% 1.0% 1.4%
GPU Market Share 5.7% 5.7% 5.7% 6.4% 7.4% 7.0% 7.0% 11.1% 7.0% 7.5% 11.3%
Merged Market Share 6.3% 6.3% 6.3% 6.8% 8.1% 8.3% 7.6% 12.3% 8.5% 8.6% 12.7%
</TABLE>
<PAGE> 324
EXHIBIT NO. APP-313
<PAGE> 325
Exhibit APP-313, page 1 of 5
SENSITIVITY FOR OFF-PEAK 650 MW SALE TO GPU
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
FE
Pre-Merger HHI 5,228 5,225 5,085 4,334 3,215 4,948 4,194 4,113 4,262 3,519 3,028
Post-Merger HHI 5,243 5,240 5,101 4,369 3,120 4,985 4,236 4,095 4,298 3,562 2,922
Change 15 15 16 36 (95) 37 42 (18) 35 43 (106)
FE Capacity (MW) 11,798 11,788 11,090 10,101 9,965 10,789 10,162 8,175 8,360 7,847 4,973
GPU Capacity (MW) 17 18 18 43 90 41 52 166 35 51 158
Merged Capacity (MW) 11,815 11,805 11,108 10,144 9,465 10,830 10,215 7,766 8,395 7,898 4,559
FE Market Share 71.6% 71.6% 70.5% 64.8% 54.5% 69.8% 63.9% 63.1% 64.3% 57.9% 53.0%
GPU Market Share 0.1% 0.1% 0.1% 0.3% 0.5% 0.3% 0.3% 1.3% 0.3% 0.4% 1.7%
Merged Market Share 71.7% 71.7% 70.6% 65.1% 53.6% 70.0% 64.2% 62.9% 64.6% 58.3% 51.8%
PJM
Pre-Merger HHI 1,164 1,163 1,181 1,178 1,143 976 1,130 1,551 940 1,059 1,288
Post-Merger HHI 1,176 1,175 1,190 1,183 1,136 998 1,141 1,543 967 1,077 1,302
Change 12 12 9 5 (7) 22 11 (8) 27 18 14
FE Capacity (MW) 761 761 472 206 360 964 390 235 979 460 262
GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 1,885 1,747 1,717
Merged Capacity (MW) 3,176 3,176 2,515 2,132 2,810 3,136 2,381 2,724 2,864 2,207 2,489
FE Market Share 1.4% 1.4% 1.0% 0.5% 1.1% 2.2% 1.0% 1.2% 2.6% 1.5% 1.6%
GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.0% 5.4% 10.4% 5.1% 5.9% 10.3%
Merged Market Share 5.8% 5.8% 5.5% 5.5% 8.2% 7.3% 6.4% 13.9% 7.7% 7.4% 14.3%
AEP
Pre-Merger HHI 2,434 2,433 2,385 2,464 3,817 2,243 2,131 2,586 1,817 1,693 2,066
Post-Merger HHI 2,434 2,434 2,386 2,464 3,818 2,243 2,131 2,594 1,817 1,694 2,083
Change 1 1 1 1 1 0 1 8 1 1 17
FE Capacity (MW) 3,012 3,011 3,019 2,968 1,664 1,613 1,694 1,591 2,436 2,558 2,403
GPU Capacity (MW) 18 18 21 25 28 26 46 354 26 47 363
Merged Capacity (MW) 3,029 3,030 3,040 2,993 1,697 1,639 1,740 2,025 2,463 2,605 2,853
FE Market Share 6.6% 6.6% 6.7% 6.7% 4.8% 3.4% 3.5% 3.9% 5.7% 5.9% 6.6%
GPU Market Share 0.0% 0.0% 0.0% 0.1% 0.1% 0.1% 0.1% 0.9% 0.1% 0.1% 1.0%
Merged Market Share 6.6% 6.6% 6.7% 6.8% 4.9% 3.5% 3.6% 5.0% 5.8% 6.0% 7.9%
</TABLE>
<PAGE> 326
Exhibit APP-313, page 2 of 5
SENSITIVITY FOR OFF-PEAK 650 MW SALE TO GPU
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
APS
Pre-Merger HHI 4,150 4,126 3,886 3,298 3,607 4,550 2,482 2,644 3,958 2,049 2,189
Post-Merger HHI 4,153 4,129 3,889 3,303 3,613 4,554 2,493 2,672 3,962 2,060 2,222
Change 3 3 3 5 6 4 11 28 4 12 33
FE Capacity (MW) 311 311 311 414 362 334 807 640 305 732 582
GPU Capacity (MW) 84 85 89 101 110 89 166 312 83 165 308
Merged Capacity (MW) 394 396 400 516 505 423 973 1,037 388 897 984
FE Market Share 2.3% 2.3% 2.5% 3.2% 3.0% 2.7% 5.1% 4.9% 2.8% 5.1% 5.0%
GPU Market Share 0.6% 0.6% 0.7% 0.8% 0.9% 0.7% 1.0% 2.4% 0.8% 1.1% 2.6%
Merged Market Share 3.0% 3.0% 3.2% 4.0% 4.2% 3.4% 6.1% 8.0% 3.6% 6.2% 8.4%
DPL
Pre-Merger HHI 7,115 7,092 6,817 5,475 3,907 5,308 3,766 2,963 4,712 3,243 2,618
Post-Merger HHI 7,115 7,092 6,817 5,476 3,904 5,308 3,767 2,958 4,713 3,245 2,611
Change 0 0 0 0 (3) 0 1 (5) 0 1 (7)
FE Capacity (MW) 137 137 137 211 351 234 408 475 228 397 457
GPU Capacity (MW) 0 0 0 1 3 1 2 8 1 2 11
Merged Capacity (MW) 137 137 137 212 341 235 410 461 229 399 442
FE Market Share 3.5% 3.6% 3.9% 5.8% 7.8% 6.3% 9.0% 10.0% 7.2% 10.0% 10.8%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.2% 0.0% 0.1% 0.3%
Merged Market Share 3.5% 3.6% 3.9% 5.8% 7.6% 6.3% 9.0% 9.7% 7.2% 10.0% 10.4%
DQE
Pre-Merger HHI 6,207 6,207 6,030 3,964 5,902 3,369 3,018 2,676 3,354 3,169 3,461
Post-Merger HHI 6,208 6,208 6,030 3,966 5,902 3,371 3,022 2,762 3,357 3,174 3,566
Change 0 0 0 2 0 2 4 86 3 6 105
FE Capacity (MW) 591 591 592 1,774 604 1,348 1,714 2,101 1,597 2,031 3,021
GPU Capacity (MW) 0 0 0 1 1 2 4 41 2 4 44
Merged Capacity (MW) 591 591 593 1,775 604 1,350 1,718 2,151 1,599 2,034 3,075
FE Market Share 17.5% 17.5% 18.7% 37.6% 19.4% 27.5% 30.7% 42.6% 36.2% 40.0% 54.3%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.8% 0.0% 0.1% 0.8%
Merged Market Share 17.5% 17.5% 18.7% 37.7% 19.5% 27.5% 30.8% 43.6% 36.3% 40.1% 55.3%
</TABLE>
<PAGE> 327
Exhibit APP-313, page 3 of 5
SENSITIVITY FOR OFF-PEAK 650 MW SALE TO GPU
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
MECS
Pre-Merger HHI 3,448 3,437 3,290 3,854 2,878 2,643 2,636 3,267 2,363 2,351 2,816
Post-Merger HHI 3,448 3,437 3,290 3,855 2,875 2,643 2,636 3,264 2,364 2,352 2,807
Change 0 0 0 0 (3) 0 0 (3) 1 1 (9)
FE Capacity (MW) 964 963 964 541 1,143 1,184 1,114 1,006 1,633 1,531 1,368
GPU Capacity (MW) 1 1 1 2 11 5 5 18 7 9 33
Merged Capacity (MW) 965 965 965 543 1,110 1,188 1,119 977 1,640 1,540 1,322
FE Market Share 4.5% 4.5% 5.5% 3.6% 7.2% 6.3% 6.5% 7.8% 9.9% 10.3% 12.2%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% 0.0% 0.1% 0.3%
Merged Market Share 4.5% 4.5% 5.5% 3.6% 7.0% 6.3% 6.5% 7.6% 10.0% 10.4% 11.8%
NYPP
Pre-Merger HHI 1,166 1,157 1,173 1,064 939 1,161 1,083 1,017 1,001 956 807
Post-Merger HHI 1,166 1,158 1,173 1,064 939 1,161 1,083 1,017 1,001 956 809
Change 0 0 0 0 (0) 0 0 (0) 0 0 2
FE Capacity (MW) 10 11 13 8 18 13 8 13 48 34 54
GPU Capacity (MW) 62 63 65 70 83 47 48 106 131 148 320
Merged Capacity (MW) 72 74 78 78 121 59 57 142 179 182 448
FE Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.1% 0.0% 0.1% 0.2% 0.2% 0.5%
GPU Market Share 0.2% 0.2% 0.2% 0.3% 0.6% 0.2% 0.2% 1.0% 0.5% 0.7% 2.9%
Merged Market Share 0.2% 0.2% 0.2% 0.3% 0.9% 0.3% 0.3% 1.3% 0.7% 0.9% 4.1%
VEPCO
Pre-Merger HHI 4,005 3,954 3,425 3,054 2,711 3,098 2,768 1,979 3,067 2,626 1,734
Post-Merger HHI 4,005 3,954 3,426 3,055 2,712 3,099 2,769 1,986 3,069 2,628 1,748
Change 1 1 1 1 1 1 1 8 1 2 15
FE Capacity (MW) 176 176 181 180 128 104 107 207 148 153 254
GPU Capacity (MW) 99 101 105 111 136 138 140 308 132 145 316
Merged Capacity (MW) 275 277 286 292 306 242 247 599 280 298 666
FE Market Share 0.8% 0.8% 0.9% 1.0% 0.8% 0.6% 0.6% 1.6% 0.9% 1.0% 2.2%
GPU Market Share 0.4% 0.5% 0.5% 0.6% 0.8% 0.8% 0.8% 2.3% 0.8% 1.0% 2.7%
Merged Market Share 1.2% 1.2% 1.4% 1.6% 1.8% 1.3% 1.5% 4.5% 1.7% 2.0% 5.8%
</TABLE>
<PAGE> 328
Exhibit APP-313, page 4 of 5
SENSITIVITY FOR OFF-PEAK 650 MW SALE TO GPU
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PJM-WESTINT
Pre-Merger HHI 1,164 1,163 1,181 1,178 1,143 976 1,130 1,551 945 1,059 1,288
Post-Merger HHI 1,176 1,175 1,190 1,183 1,136 998 1,141 1,543 971 1,077 1,302
Change 12 12 9 5 (7) 22 11 (8) 26 18 14
FE Capacity (MW) 761 761 472 206 360 964 390 235 955 460 262
GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 1,885 1,747 1,717
Merged Capacity (MW) 3,176 3,176 2,515 2,132 2,810 3,136 2,381 2,724 2,841 2,207 2,489
FE Market Share 1.4% 1.4% 1.0% 0.5% 1.1% 2.2% 1.0% 1.2% 2.6% 1.5% 1.6%
GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.0% 5.4% 10.4% 5.1% 5.9% 10.3%
Merged Market Share 5.8% 5.8% 5.5% 5.5% 8.2% 7.3% 6.4% 13.9% 7.7% 7.4% 14.3%
PJM-CENTINT
Pre-Merger HHI 1,508 1,507 1,550 1,462 1,479 1,312 1,455 1,564 1,295 1,365 1,417
Post-Merger HHI 1,513 1,513 1,555 1,465 1,496 1,325 1,462 1,604 1,311 1,378 1,480
Change 6 6 5 3 16 13 7 40 16 13 63
FE Capacity (MW) 216 216 149 71 139 320 151 229 317 192 199
GPU Capacity (MW) 2,177 2,177 1,815 1,714 1,713 1,926 1,769 1,962 1,633 1,533 1,631
Merged Capacity (MW) 2,392 2,392 1,964 1,785 2,434 2,246 1,920 2,666 1,950 1,725 2,332
FE Market Share 0.5% 0.5% 0.4% 0.3% 0.6% 1.0% 0.6% 1.2% 1.3% 0.9% 1.3%
GPU Market Share 5.3% 5.4% 5.5% 6.1% 6.9% 6.3% 6.5% 10.5% 6.5% 7.1% 10.9%
Merged Market Share 5.9% 5.9% 5.9% 6.4% 9.8% 7.3% 7.0% 14.2% 7.7% 8.0% 15.6%
PJM-EASTINT
Pre-Merger HHI 1,485 1,477 1,417 1,378 1,350 1,171 1,306 1,667 1,205 1,228 1,432
Post-Merger HHI 1,493 1,484 1,424 1,382 1,356 1,189 1,315 1,680 1,226 1,243 1,480
Change 7 7 7 4 6 18 9 13 21 15 48
FE Capacity (MW) 216 217 150 71 133 292 138 172 296 174 173
GPU Capacity (MW) 1,863 1,864 1,517 1,429 1,441 1,604 1,468 1,757 1,355 1,279 1,467
Merged Capacity (MW) 2,079 2,081 1,667 1,500 2,155 1,896 1,606 2,433 1,651 1,454 2,148
</TABLE>
<PAGE> 329
Exhibit APP-313, page 5 of 5
SENSITIVITY FOR OFF-PEAK 650 MW SALE TO GPU
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
FE Market Share 0.7% 0.7% 0.6% 0.3% 0.7% 1.3% 0.7% 1.1% 1.5% 1.0% 1.3%
GPU Market Share 5.7% 5.7% 5.7% 6.4% 7.4% 7.0% 7.0% 11.1% 7.0% 7.5% 11.3%
Merged Market Share 6.3% 6.3% 6.3% 6.8% 11.1% 8.3% 7.6% 15.4% 8.5% 8.6% 16.6%
</TABLE>
<PAGE> 330
EXHIBIT NO. APP-314
<PAGE> 331
Exhibit APP-314, page 1 of 5
SENSITIVITY FOR GPU DIVESTING YARDS CREEK TO PSEG
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
FE
Pre-Merger HHI 5,228 5,225 5,085 4,334 3,215 4,948 4,194 4,113 4,262 3,519 3,028
Post-Merger HHI 5,241 5,239 5,101 4,369 3,269 4,982 4,236 4,274 4,295 3,562 3,206
Change 14 14 16 36 54 34 42 161 32 43 178
FE Capacity (MW) 11,798 11,788 11,090 10,101 9,965 10,789 10,162 8,175 8,360 7,847 4,973
GPU Capacity (MW) 16 16 18 43 90 38 52 166 33 50 158
Merged Capacity (MW) 11,814 11,804 11,108 10,144 10,055 10,827 10,215 8,341 8,393 7,897 5,131
FE Market Share 71.6% 71.6% 70.5% 64.8% 54.5% 69.8% 63.9% 63.1% 64.3% 57.9% 53.0%
GPU Market Share 0.1% 0.1% 0.1% 0.3% 0.5% 0.2% 0.3% 1.3% 0.3% 0.4% 1.7%
Merged Market Share 71.7% 71.7% 70.6% 65.1% 55.0% 70.0% 64.2% 64.3% 64.6% 58.3% 54.6%
PJM
Pre-Merger HHI 1,173 1,172 1,183 1,178 1,143 983 1,130 1,551 946 1,060 1,288
Post-Merger HHI 1,184 1,183 1,192 1,183 1,155 1,003 1,141 1,577 971 1,078 1,320
Change 11 11 9 5 12 21 11 26 24 18 32
FE Capacity (MW) 761 761 472 206 360 964 390 235 979 460 262
GPU Capacity (MW) 2,235 2,235 2,005 1,926 1,911 1,992 1,990 1,971 1,739 1,733 1,717
Merged Capacity (MW) 2,997 2,997 2,478 2,132 2,271 2,956 2,380 2,206 2,718 2,193 1,979
FE Market Share 1.4% 1.4% 1.0% 0.5% 1.1% 2.2% 1.0% 1.2% 2.6% 1.5% 1.6%
GPU Market Share 4.0% 4.1% 4.4% 5.0% 5.7% 4.6% 5.4% 10.4% 4.7% 5.8% 10.3%
Merged Market Share 5.4% 5.5% 5.5% 5.5% 6.7% 6.8% 6.4% 11.7% 7.3% 7.4% 11.8%
AEP
Pre-Merger HHI 2,434 2,433 2,385 2,464 3,817 2,243 2,131 2,586 1,817 1,693 2,066
Post-Merger HHI 2,434 2,434 2,386 2,464 3,817 2,243 2,131 2,593 1,817 1,694 2,079
Change 0 0 1 1 1 0 1 7 1 1 13
FE Capacity (MW) 3,012 3,011 3,019 2,968 1,664 1,613 1,694 1,591 2,436 2,558 2,403
GPU Capacity (MW) 16 17 21 25 28 24 46 354 24 47 363
Merged Capacity (MW) 3,028 3,028 3,040 2,993 1,692 1,637 1,740 1,945 2,461 2,605 2,766
FE Market Share 6.6% 6.6% 6.7% 6.7% 4.8% 3.4% 3.5% 3.9% 5.7% 5.9% 6.6%
GPU Market Share 0.0% 0.0% 0.0% 0.1% 0.1% 0.1% 0.1% 0.9% 0.1% 0.1% 1.0%
Merged Market Share 6.6% 6.6% 6.7% 6.8% 4.9% 3.5% 3.6% 4.8% 5.8% 6.0% 7.6%
</TABLE>
<PAGE> 332
Exhibit APP-314, page 2 of 5
SENSITIVITY FOR GPU DIVESTING YARDS CREEK TO PSEG
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
APS
Pre-Merger HHI 4,151 4,126 3,886 3,298 3,607 4,551 2,482 2,644 3,958 2,049 2,189
Post-Merger HHI 4,153 4,129 3,889 3,303 3,612 4,554 2,493 2,668 3,962 2,060 2,215
Change 3 3 3 5 5 4 11 24 4 11 26
FE Capacity (MW) 311 311 311 414 362 334 807 640 305 732 582
GPU Capacity (MW) 77 79 87 101 110 82 166 312 77 164 308
Merged Capacity (MW) 388 390 398 516 472 416 973 952 381 895 890
FE Market Share 2.3% 2.3% 2.5% 3.2% 3.0% 2.7% 5.1% 4.9% 2.8% 5.1% 5.0%
GPU Market Share 0.6% 0.6% 0.7% 0.8% 0.9% 0.7% 1.0% 2.4% 0.7% 1.1% 2.6%
Merged Market Share 2.9% 2.9% 3.2% 4.0% 3.9% 3.3% 6.1% 7.3% 3.5% 6.2% 7.6%
DPL
Pre-Merger HHI 7,115 7,092 6,817 5,475 3,907 5,308 3,766 2,963 4,712 3,243 2,618
Post-Merger HHI 7,115 7,092 6,817 5,476 3,909 5,308 3,767 2,967 4,712 3,244 2,623
Change 0 0 0 0 1 0 1 4 0 1 6
FE Capacity (MW) 137 137 137 211 351 234 408 475 228 397 457
GPU Capacity (MW) 0 0 0 1 3 1 2 8 1 2 11
Merged Capacity (MW) 137 137 137 212 354 235 410 484 229 399 468
FE Market Share 3.5% 3.6% 3.9% 5.8% 7.8% 6.3% 9.0% 10.0% 7.2% 10.0% 10.8%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.2% 0.0% 0.1% 0.3%
Merged Market Share 3.5% 3.6% 3.9% 5.8% 7.9% 6.3% 9.0% 10.2% 7.2% 10.0% 11.1%
DQE
Pre-Merger HHI 6,207 6,207 6,030 3,964 5,902 3,369 3,018 2,676 3,354 3,169 3,461
Post-Merger HHI 6,208 6,208 6,030 3,966 5,903 3,370 3,022 2,747 3,357 3,174 3,546
Change 0 0 0 2 1 2 4 70 3 6 85
FE Capacity (MW) 591 591 592 1,774 604 1,348 1,714 2,101 1,597 2,031 3,021
GPU Capacity (MW) 0 0 0 1 1 2 4 41 2 4 44
Merged Capacity (MW) 591 591 593 1,775 605 1,349 1,718 2,142 1,599 2,034 3,064
FE Market Share 17.5% 17.5% 18.7% 37.6% 19.4% 27.5% 30.7% 42.6% 36.2% 40.0% 54.3%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.8% 0.0% 0.1% 0.8%
Merged Market Share 17.5% 17.5% 18.7% 37.7% 19.5% 27.5% 30.8% 43.4% 36.3% 40.1% 55.1%
</TABLE>
<PAGE> 333
Exhibit APP-314, page 3 of 5
SENSITIVITY FOR GPU DIVESTING YARDS CREEK TO PSEG
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
MECS
Pre-Merger HHI 3,448 3,437 3,290 3,854 2,878 2,643 2,636 3,267 2,363 2,351 2,816
Post-Merger HHI 3,448 3,437 3,290 3,855 2,879 2,643 2,636 3,270 2,363 2,352 2,824
Change 0 0 0 0 1 0 0 2 1 1 7
FE Capacity (MW) 964 963 964 541 1,143 1,184 1,114 1,006 1,633 1,531 1,368
GPU Capacity (MW) 1 1 1 2 11 4 5 18 7 9 33
Merged Capacity (MW) 965 965 965 543 1,154 1,188 1,119 1,024 1,640 1,540 1,401
FE Market Share 4.5% 4.5% 5.5% 3.6% 7.2% 6.3% 6.5% 7.8% 9.9% 10.3% 12.2%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% 0.0% 0.1% 0.3%
Merged Market Share 4.5% 4.5% 5.5% 3.6% 7.3% 6.3% 6.5% 7.9% 10.0% 10.4% 12.5%
NYPP
Pre-Merger HHI 1,166 1,158 1,173 1,064 939 1,161 1,083 1,017 1,001 956 807
Post-Merger HHI 1,166 1,158 1,173 1,064 940 1,161 1,083 1,017 1,001 956 810
Change 0 0 0 0 0 0 0 0 0 0 3
FE Capacity (MW) 10 11 13 8 18 13 8 13 48 34 54
GPU Capacity (MW) 57 59 64 70 83 43 48 106 121 147 320
Merged Capacity (MW) 68 69 77 78 101 55 57 119 169 181 374
FE Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.1% 0.0% 0.1% 0.2% 0.2% 0.5%
GPU Market Share 0.1% 0.2% 0.2% 0.3% 0.6% 0.2% 0.2% 1.0% 0.5% 0.7% 2.9%
Merged Market Share 0.2% 0.2% 0.2% 0.3% 0.8% 0.2% 0.3% 1.1% 0.7% 0.9% 3.4%
VEPCO
Pre-Merger HHI 4,005 3,954 3,425 3,054 2,711 3,098 2,768 1,979 3,067 2,626 1,734
Post-Merger HHI 4,005 3,954 3,426 3,055 2,712 3,099 2,769 1,986 3,069 2,628 1,746
Change 1 1 1 1 1 1 1 7 1 2 12
FE Capacity (MW) 176 176 181 180 128 104 107 207 148 153 254
GPU Capacity (MW) 92 93 103 111 136 126 140 308 122 144 316
Merged Capacity (MW) 268 269 284 292 264 230 247 515 270 297 570
</TABLE>
<PAGE> 334
Exhibit APP-314, page 4 of 5
SENSITIVITY FOR GPU DIVESTING YARDS CREEK TO PSEG
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
FE Market Share 0.8% 0.8% 0.9% 1.0% 0.8% 0.6% 0.6% 1.6% 0.9% 1.0% 2.2%
GPU Market Share 0.4% 0.4% 0.5% 0.6% 0.8% 0.7% 0.8% 2.3% 0.7% 1.0% 2.7%
Merged Market Share 1.2% 1.2% 1.4% 1.6% 1.6% 1.3% 1.5% 3.9% 1.6% 2.0% 5.0%
PJM-WESTINT
Pre-Merger HHI 1,173 1,172 1,183 1,178 1,143 983 1,130 1,551 951 1,060 1,288
Post-Merger HHI 1,184 1,183 1,192 1,183 1,155 1,003 1,141 1,577 975 1,078 1,320
Change 11 11 9 5 12 21 11 26 24 18 32
FE Capacity (MW) 761 761 472 206 360 964 390 235 955 460 262
GPU Capacity (MW) 2,235 2,235 2,005 1,926 1,911 1,992 1,990 1,971 1,739 1,733 1,717
Merged Capacity (MW) 2,997 2,997 2,478 2,132 2,271 2,956 2,380 2,206 2,695 2,193 1,979
FE Market Share 1.4% 1.4% 1.0% 0.5% 1.1% 2.2% 1.0% 1.2% 2.6% 1.5% 1.6%
GPU Market Share 4.0% 4.1% 4.4% 5.0% 5.7% 4.6% 5.4% 10.4% 4.7% 5.8% 10.3%
Merged Market Share 5.4% 5.5% 5.5% 5.5% 6.7% 6.8% 6.4% 11.7% 7.3% 7.4% 11.8%
PJM-CENTINT
Pre-Merger HHI 1,524 1,523 1,554 1,462 1,479 1,325 1,455 1,564 1,308 1,366 1,417
Post-Merger HHI 1,529 1,529 1,558 1,465 1,487 1,337 1,462 1,589 1,322 1,379 1,446
Change 5 5 5 3 8 12 7 26 15 12 29
FE Capacity (MW) 216 216 149 71 139 320 151 229 317 192 199
GPU Capacity (MW) 1,998 1,998 1,778 1,714 1,713 1,747 1,767 1,962 1,487 1,519 1,631
Merged Capacity (MW) 2,213 2,213 1,926 1,785 1,852 2,067 1,918 2,191 1,804 1,711 1,830
FE Market Share 0.5% 0.5% 0.4% 0.3% 0.6% 1.0% 0.6% 1.2% 1.3% 0.9% 1.3%
GPU Market Share 4.9% 4.9% 5.4% 6.1% 6.9% 5.7% 6.5% 10.5% 5.9% 7.0% 10.9%
Merged Market Share 5.4% 5.4% 5.8% 6.4% 7.5% 6.7% 7.0% 11.7% 7.1% 7.9% 12.2%
PJM-EASTINT
Pre-Merger HHI 1,509 1,500 1,422 1,378 1,350 1,190 1,306 1,667 1,224 1,230 1,432
Post-Merger HHI 1,516 1,507 1,428 1,382 1,360 1,206 1,315 1,691 1,244 1,245 1,463
Change 7 7 6 4 10 16 9 24 19 15 30
FE Capacity (MW) 216 217 150 71 133 292 138 172 296 174 173
GPU Capacity (MW) 1,684 1,685 1,479 1,429 1,441 1,425 1,466 1,757 1,209 1,265 1,467
Merged Capacity (MW) 1,900 1,901 1,629 1,500 1,574 1,717 1,604 1,929 1,505 1,439 1,640
</TABLE>
<PAGE> 335
Exhibit APP-314, page 5 of 5
SENSITIVITY FOR GPU DIVESTING YARDS CREEK TO PSEG
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
FE Market Share 0.7% 0.7% 0.6% 0.3% 0.7% 1.3% 0.7% 1.1% 1.5% 1.0% 1.3%
GPU Market Share 5.1% 5.1% 5.6% 6.4% 7.4% 6.2% 7.0% 11.1% 6.3% 7.5% 11.3%
Merged Market Share 5.8% 5.8% 6.2% 6.8% 8.1% 7.5% 7.6% 12.2% 7.8% 8.5% 12.7%
</TABLE>
<PAGE> 336
EXHIBIT NO. APP-315
<PAGE> 337
Exhibit APP-315, page 1 of 5
SENSITIVITY FOR HENRY HUB GAS PRICE DECREASE BY $1
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
FE
Pre-Merger HHI 5,228 5,225 5,055 4,545 3,215 4,948 4,194 4,113 4,492 3,519 3,028
Post-Merger HHI 5,243 5,240 5,070 4,579 3,269 4,985 4,236 4,274 4,525 3,561 3,206
Change 15 15 15 34 54 37 42 161 34 42 178
FE Capacity (MW) 11,798 11,788 11,090 10,897 9,965 10,789 10,162 8,175 9,072 7,847 4,973
GPU Capacity (MW) 17 17 17 42 90 41 52 166 35 49 158
Merged Capacity (MW) 11,815 11,805 11,107 10,939 10,055 10,830 10,215 8,341 9,107 7,897 5,131
FE Market Share 71.6% 71.6% 70.3% 66.5% 54.5% 69.8% 63.9% 63.1% 66.2% 57.9% 53.0%
GPU Market Share 0.1% 0.1% 0.1% 0.3% 0.5% 0.3% 0.3% 1.3% 0.3% 0.4% 1.7%
Merged Market Share 71.7% 71.7% 70.4% 66.8% 55.0% 70.0% 64.2% 64.3% 66.5% 58.3% 54.6%
PJM
Pre-Merger HHI 1,164 1,163 1,166 1,217 1,143 976 1,130 1,551 971 1,008 1,288
Post-Merger HHI 1,176 1,175 1,174 1,221 1,155 998 1,141 1,577 995 1,026 1,320
Change 12 12 8 5 12 22 11 26 24 17 32
FE Capacity (MW) 761 761 473 208 360 964 390 235 979 460 262
GPU Capacity (MW) 2,415 2,415 2,043 1,997 1,911 2,171 1,991 1,971 1,957 1,747 1,717
Merged Capacity (MW) 3,176 3,176 2,516 2,205 2,271 3,136 2,381 2,206 2,935 2,207 1,979
FE Market Share 1.4% 1.4% 1.0% 0.5% 1.1% 2.2% 1.0% 1.2% 2.5% 1.5% 1.6%
GPU Market Share 4.4% 4.4% 4.2% 4.7% 5.7% 5.0% 5.4% 10.4% 4.9% 5.7% 10.3%
Merged Market Share 5.8% 5.8% 5.2% 5.2% 6.7% 7.3% 6.4% 11.7% 7.4% 7.2% 11.8%
AEP
Pre-Merger HHI 2,434 2,433 2,385 2,403 3,817 2,243 2,131 2,586 1,781 1,692 2,066
Post-Merger HHI 2,434 2,434 2,386 2,403 3,817 2,243 2,131 2,593 1,781 1,693 2,079
Change 1 1 1 1 1 0 1 7 1 1 13
FE Capacity (MW) 3,012 3,011 3,020 2,972 1,664 1,613 1,694 1,591 2,436 2,558 2,403
GPU Capacity (MW) 18 18 19 25 28 25 46 354 26 47 363
Merged Capacity (MW) 3,029 3,030 3,039 2,997 1,692 1,639 1,740 1,945 2,463 2,605 2,766
FE Market Share 6.6% 6.6% 6.7% 6.7% 4.8% 3.4% 3.5% 3.9% 5.6% 5.9% 6.6%
GPU Market Share 0.0% 0.0% 0.0% 0.1% 0.1% 0.1% 0.1% 0.9% 0.1% 0.1% 1.0%
Merged Market Share 6.6% 6.6% 6.7% 6.7% 4.9% 3.5% 3.6% 4.8% 5.7% 6.0% 7.6%
</TABLE>
<PAGE> 338
Exhibit APP-315, page 2 of 5
SENSITIVITY FOR HENRY HUB GAS PRICE DECREASE BY $1
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
APS
Pre-Merger HHI 4,150 4,126 3,886 3,370 3,607 4,550 2,482 2,644 4,029 2,047 2,189
Post-Merger HHI 4,153 4,129 3,890 3,375 3,612 4,554 2,493 2,668 4,033 2,058 2,215
Change 3 3 3 5 5 4 11 24 4 11 26
FE Capacity (MW) 311 311 311 415 362 334 807 640 305 732 582
GPU Capacity (MW) 84 85 81 98 110 89 166 312 81 160 308
Merged Capacity (MW) 394 395 392 513 472 423 973 952 386 892 890
FE Market Share 2.3% 2.3% 2.5% 3.2% 3.0% 2.7% 5.1% 4.9% 2.8% 5.1% 5.0%
GPU Market Share 0.6% 0.6% 0.6% 0.7% 0.9% 0.7% 1.0% 2.4% 0.7% 1.1% 2.6%
Merged Market Share 3.0% 3.0% 3.1% 3.9% 3.9% 3.4% 6.1% 7.3% 3.5% 6.2% 7.6%
DPL
Pre-Merger HHI 7,115 7,101 7,020 5,703 3,907 5,308 3,766 2,963 4,898 3,243 2,618
Post-Merger HHI 7,115 7,101 7,020 5,703 3,909 5,308 3,767 2,967 4,898 3,245 2,623
Change 0 0 0 0 1 0 1 4 0 1 6
FE Capacity (MW) 137 137 137 212 351 234 408 475 228 397 457
GPU Capacity (MW) 0 0 0 1 3 1 2 8 1 2 11
Merged Capacity (MW) 137 137 137 213 354 235 410 484 229 399 468
FE Market Share 3.5% 3.5% 3.7% 5.4% 7.8% 6.3% 9.0% 10.0% 6.9% 10.0% 10.8%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.2% 0.0% 0.1% 0.3%
Merged Market Share 3.5% 3.6% 3.7% 5.4% 7.9% 6.3% 9.0% 10.2% 6.9% 10.0% 11.1%
DQE
Pre-Merger HHI 6,207 6,207 6,029 3,968 5,902 3,368 3,018 2,676 3,354 3,169 3,461
Post-Merger HHI 6,208 6,208 6,029 3,970 5,903 3,370 3,022 2,747 3,357 3,174 3,546
Change 0 0 0 2 1 2 4 70 3 6 85
FE Capacity (MW) 591 591 593 1,776 604 1,348 1,714 2,101 1,597 2,031 3,021
GPU Capacity (MW) 0 0 0 1 1 2 4 41 2 4 44
Merged Capacity (MW) 591 591 593 1,777 605 1,350 1,718 2,142 1,599 2,034 3,064
FE Market Share 17.5% 17.5% 18.7% 37.7% 19.4% 27.5% 30.7% 42.6% 36.2% 40.0% 54.3%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.8% 0.0% 0.1% 0.8%
Merged Market Share 17.5% 17.5% 18.7% 37.7% 19.5% 27.5% 30.8% 43.4% 36.3% 40.1% 55.1%
</TABLE>
<PAGE> 339
Exhibit APP-315, page 3 of 5
SENSITIVITY FOR HENRY HUB GAS PRICE DECREASE BY $1
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
MECS
Pre-Merger HHI 3,448 3,437 3,365 3,784 2,878 2,641 2,636 3,267 2,371 2,351 2,816
Post-Merger HHI 3,448 3,437 3,366 3,784 2,879 2,642 2,636 3,270 2,372 2,352 2,824
Change 0 0 0 0 1 0 0 2 1 1 7
FE Capacity (MW) 964 963 964 544 1,143 1,184 1,114 1,006 1,633 1,531 1,368
GPU Capacity (MW) 1 1 1 2 11 4 5 18 7 9 33
Merged Capacity (MW) 965 965 966 546 1,154 1,188 1,119 1,024 1,640 1,540 1,401
FE Market Share 4.5% 4.5% 4.8% 3.5% 7.2% 6.3% 6.5% 7.8% 9.7% 10.3% 12.2%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% 0.0% 0.1% 0.3%
Merged Market Share 4.5% 4.5% 4.8% 3.5% 7.3% 6.3% 6.5% 7.9% 9.7% 10.4% 12.5%
NYPP
Pre-Merger HHI 1,166 1,153 1,139 1,152 939 1,153 1,083 1,017 1,029 954 807
Post-Merger HHI 1,166 1,153 1,139 1,152 940 1,153 1,083 1,017 1,029 955 810
Change 0 0 0 0 0 0 0 0 0 0 3
FE Capacity (MW) 10 10 12 7 18 13 8 13 46 33 54
GPU Capacity (MW) 62 63 60 69 83 47 48 106 129 144 320
Merged Capacity (MW) 72 73 72 76 101 59 57 119 175 177 374
FE Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.1% 0.0% 0.1% 0.2% 0.2% 0.5%
GPU Market Share 0.2% 0.2% 0.2% 0.2% 0.6% 0.2% 0.2% 1.0% 0.5% 0.7% 2.9%
Merged Market Share 0.2% 0.2% 0.2% 0.3% 0.8% 0.3% 0.3% 1.1% 0.6% 0.9% 3.4%
VEPCO
Pre-Merger HHI 4,005 3,954 3,698 3,260 2,711 3,098 2,768 1,979 3,261 2,625 1,734
Post-Merger HHI 4,005 3,954 3,699 3,261 2,712 3,099 2,769 1,986 3,262 2,627 1,746
Change 1 1 1 1 1 1 1 7 1 2 12
FE Capacity (MW) 176 176 179 180 128 104 107 207 148 153 254
GPU Capacity (MW) 99 100 96 108 136 138 140 308 130 141 316
Merged Capacity (MW) 275 276 275 289 264 242 247 515 278 294 570
FE Market Share 0.8% 0.8% 0.9% 0.9% 0.8% 0.6% 0.6% 1.6% 0.9% 1.0% 2.2%
GPU Market Share 0.4% 0.5% 0.5% 0.6% 0.8% 0.8% 0.8% 2.3% 0.8% 0.9% 2.7%
Merged Market Share 1.2% 1.2% 1.3% 1.5% 1.6% 1.3% 1.5% 3.9% 1.6% 2.0% 5.0%
</TABLE>
<PAGE> 340
Exhibit APP-315, page 4 of 5
SENSITIVITY FOR HENRY HUB GAS PRICE DECREASE BY $1
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PJM-WESTINT
Pre-Merger HHI 1,164 1,163 1,166 1,217 1,143 976 1,130 1,551 976 1,008 1,288
Post-Merger HHI 1,176 1,175 1,174 1,221 1,155 998 1,141 1,577 1,000 1,026 1,320
Change 12 12 8 5 12 22 11 26 24 17 32
FE Capacity (MW) 761 761 473 208 360 964 390 235 955 460 262
GPU Capacity (MW) 2,415 2,415 2,043 1,997 1,911 2,171 1,991 1,971 1,957 1,747 1,717
Merged Capacity (MW) 3,176 3,176 2,516 2,205 2,271 3,136 2,381 2,206 2,912 2,207 1,979
FE Market Share 1.4% 1.4% 1.0% 0.5% 1.1% 2.2% 1.0% 1.2% 2.4% 1.5% 1.6%
GPU Market Share 4.4% 4.4% 4.2% 4.7% 5.7% 5.0% 5.4% 10.4% 5.0% 5.7% 10.3%
Merged Market Share 5.8% 5.8% 5.2% 5.2% 6.7% 7.3% 6.4% 11.7% 7.4% 7.2% 11.8%
PJM-CENTINT
Pre-Merger HHI 1,508 1,507 1,513 1,536 1,479 1,312 1,455 1,564 1,355 1,277 1,417
Post-Merger HHI 1,513 1,513 1,518 1,539 1,487 1,325 1,462 1,589 1,369 1,289 1,446
Change 6 6 4 3 8 13 7 26 14 12 29
FE Capacity (MW) 216 216 144 70 139 320 151 229 313 192 199
GPU Capacity (MW) 2,177 2,177 1,812 1,782 1,713 1,926 1,769 1,962 1,702 1,533 1,631
Merged Capacity (MW) 2,392 2,392 1,956 1,851 1,852 2,246 1,920 2,191 2,015 1,725 1,830
FE Market Share 0.5% 0.5% 0.4% 0.2% 0.6% 1.0% 0.6% 1.2% 1.1% 0.9% 1.3%
GPU Market Share 5.3% 5.4% 5.1% 5.7% 6.9% 6.3% 6.5% 10.5% 6.2% 6.8% 10.9%
Merged Market Share 5.9% 5.9% 5.5% 5.9% 7.5% 7.3% 7.0% 11.7% 7.4% 7.7% 12.2%
PJM-EASTINT
Pre-Merger HHI 1,485 1,477 1,423 1,404 1,350 1,170 1,306 1,667 1,211 1,180 1,432
Post-Merger HHI 1,493 1,484 1,429 1,407 1,360 1,188 1,315 1,691 1,229 1,195 1,463
Change 7 7 5 3 10 18 9 24 18 15 30
FE Capacity (MW) 216 217 146 71 133 292 138 172 293 169 173
GPU Capacity (MW) 1,863 1,864 1,511 1,495 1,441 1,604 1,468 1,757 1,424 1,271 1,467
Merged Capacity (MW) 2,079 2,081 1,657 1,565 1,574 1,896 1,606 1,929 1,717 1,440 1,640
</TABLE>
<PAGE> 341
Exhibit APP-315, page 5 of 5
SENSITIVITY FOR HENRY HUB GAS PRICE DECREASE BY $1
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
FE Market Share 0.7% 0.7% 0.5% 0.3% 0.7% 1.3% 0.7% 1.1% 1.4% 1.0% 1.3%
GPU Market Share 5.7% 5.7% 5.3% 5.9% 7.4% 7.0% 7.0% 11.1% 6.7% 7.4% 11.3%
Merged Market Share 6.3% 6.3% 5.8% 6.2% 8.1% 8.3% 7.6% 12.2% 8.0% 8.4% 12.7%
</TABLE>
<PAGE> 342
EXHIBIT NO. APP-316
<PAGE> 343
Exhibit APP-316, page 1 of 5
SENSITIVITY FOR HENRY HUB GAS PRICE DECREASE BY $2
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
FE
Pre-Merger HHI 5,228 5,225 5,060 4,518 3,215 5,161 4,193 4,113 4,464 3,749 3,028
Post-Merger HHI 5,243 5,240 5,074 4,548 3,269 5,195 4,235 4,274 4,494 3,790 3,206
Change 15 15 14 30 54 35 41 161 30 41 178
FE Capacity (MW) 11,798 11,788 11,111 10,897 9,965 11,637 10,162 8,175 9,072 8,560 4,973
GPU Capacity (MW) 17 17 16 37 90 40 51 166 32 48 158
Merged Capacity (MW) 11,815 11,805 11,127 10,934 10,055 11,676 10,214 8,341 9,104 8,608 5,131
FE Market Share 71.6% 71.6% 70.4% 66.4% 54.5% 71.4% 63.9% 63.1% 66.0% 60.0% 53.0%
GPU Market Share 0.1% 0.1% 0.1% 0.2% 0.5% 0.2% 0.3% 1.3% 0.2% 0.3% 1.7%
Merged Market Share 71.7% 71.7% 70.5% 66.6% 55.0% 71.6% 64.2% 64.3% 66.2% 60.3% 54.6%
PJM
Pre-Merger HHI 1,165 1,163 1,186 1,216 1,090 1,022 1,082 1,551 985 1,056 1,288
Post-Merger HHI 1,177 1,175 1,193 1,220 1,102 1,042 1,092 1,577 1,005 1,072 1,320
Change 12 12 8 4 11 20 11 26 20 15 32
FE Capacity (MW) 761 761 471 207 360 968 390 235 986 460 262
GPU Capacity (MW) 2,415 2,415 2,043 1,997 1,911 2,241 1,991 1,971 1,957 1,819 1,717
Merged Capacity (MW) 3,176 3,176 2,514 2,204 2,271 3,209 2,381 2,206 2,943 2,279 1,979
FE Market Share 1.4% 1.4% 0.9% 0.4% 1.0% 2.1% 1.0% 1.2% 2.3% 1.4% 1.6%
GPU Market Share 4.4% 4.4% 4.1% 4.3% 5.5% 4.8% 5.2% 10.4% 4.5% 5.5% 10.3%
Merged Market Share 5.7% 5.8% 5.0% 4.8% 6.5% 6.8% 6.3% 11.7% 6.7% 6.9% 11.8%
AEP
Pre-Merger HHI 2,434 2,433 2,385 2,402 3,816 2,191 2,129 2,586 1,776 1,659 2,066
Post-Merger HHI 2,434 2,434 2,386 2,403 3,817 2,191 2,130 2,593 1,777 1,660 2,079
Change 1 1 1 1 1 0 1 7 1 1 13
FE Capacity (MW) 3,012 3,011 3,008 2,960 1,664 1,616 1,694 1,591 2,440 2,558 2,403
GPU Capacity (MW) 17 18 18 22 28 25 46 354 23 46 363
Merged Capacity (MW) 3,029 3,030 3,026 2,982 1,692 1,640 1,740 1,945 2,463 2,604 2,766
FE Market Share 6.6% 6.6% 6.6% 6.6% 4.8% 3.4% 3.5% 3.9% 5.7% 5.8% 6.6%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.1% 0.1% 0.9% 0.1% 0.1% 1.0%
Merged Market Share 6.6% 6.6% 6.7% 6.7% 4.9% 3.4% 3.6% 4.8% 5.7% 5.9% 7.6%
</TABLE>
<PAGE> 344
Exhibit APP-316, page 2 of 5
SENSITIVITY FOR HENRY HUB GAS PRICE DECREASE BY $2
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
APS
Pre-Merger HHI 4,150 4,126 3,887 3,371 3,607 4,619 2,480 2,644 4,030 2,099 2,189
Post-Merger HHI 4,153 4,129 3,890 3,375 3,612 4,623 2,490 2,668 4,034 2,110 2,215
Change 3 3 3 4 5 4 10 24 4 11 26
FE Capacity (MW) 311 311 310 413 362 334 807 640 305 732 582
GPU Capacity (MW) 83 85 78 88 110 86 162 312 73 157 308
Merged Capacity (MW) 394 395 389 501 472 420 969 952 378 889 890
FE Market Share 2.3% 2.3% 2.5% 3.1% 3.0% 2.6% 5.1% 4.9% 2.8% 5.0% 5.0%
GPU Market Share 0.6% 0.6% 0.6% 0.7% 0.9% 0.7% 1.0% 2.4% 0.7% 1.1% 2.6%
Merged Market Share 3.0% 3.0% 3.1% 3.8% 3.9% 3.3% 6.1% 7.3% 3.4% 6.1% 7.6%
DPL
Pre-Merger HHI 7,115 7,101 7,067 5,880 3,907 5,547 3,766 2,963 5,178 3,404 2,618
Post-Merger HHI 7,115 7,101 7,067 5,880 3,909 5,547 3,767 2,967 5,179 3,405 2,623
Change 0 0 0 0 1 0 1 4 0 1 6
FE Capacity (MW) 137 137 136 211 351 235 408 475 230 397 457
GPU Capacity (MW) 0 0 0 1 3 1 2 8 1 2 11
Merged Capacity (MW) 137 137 137 212 354 236 410 484 231 399 468
FE Market Share 3.5% 3.5% 3.6% 5.1% 7.8% 5.9% 9.0% 10.0% 6.4% 9.6% 10.8%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.2% 0.0% 0.1% 0.3%
Merged Market Share 3.5% 3.6% 3.6% 5.1% 7.9% 5.9% 9.0% 10.2% 6.4% 9.6% 11.1%
DQE
Pre-Merger HHI 6,207 6,207 6,027 3,956 5,902 3,368 3,018 2,676 3,356 3,168 3,461
Post-Merger HHI 6,208 6,208 6,027 3,958 5,903 3,370 3,022 2,747 3,359 3,174 3,546
Change 0 0 0 2 1 2 4 70 2 6 85
FE Capacity (MW) 591 591 590 1,769 604 1,349 1,714 2,101 1,600 2,031 3,021
GPU Capacity (MW) 0 0 0 1 1 2 4 41 1 3 44
Merged Capacity (MW) 591 591 591 1,770 605 1,351 1,718 2,142 1,601 2,034 3,064
FE Market Share 17.5% 17.5% 18.6% 37.6% 19.4% 27.5% 30.7% 42.6% 36.3% 40.0% 54.3%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.8% 0.0% 0.1% 0.8%
Merged Market Share 17.5% 17.5% 18.6% 37.6% 19.5% 27.5% 30.8% 43.4% 36.3% 40.1% 55.1%
</TABLE>
<PAGE> 345
Exhibit APP-316, page 3 of 5
SENSITIVITY FOR HENRY HUB GAS PRICE DECREASE BY $2
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
MECS
Pre-Merger HHI 3,448 3,437 3,372 3,794 2,878 2,664 2,636 3,267 2,545 2,338 2,816
Post-Merger HHI 3,448 3,437 3,372 3,794 2,879 2,664 2,636 3,270 2,545 2,339 2,824
Change 0 0 0 0 1 0 0 2 1 1 7
FE Capacity (MW) 964 963 961 542 1,143 1,190 1,114 1,006 1,644 1,531 1,368
GPU Capacity (MW) 1 1 1 2 11 4 5 18 6 8 33
Merged Capacity (MW) 965 965 962 544 1,154 1,194 1,119 1,024 1,650 1,539 1,401
FE Market Share 4.5% 4.5% 4.7% 3.0% 7.2% 5.9% 6.5% 7.8% 8.6% 10.0% 12.2%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% 0.0% 0.1% 0.3%
Merged Market Share 4.5% 4.5% 4.7% 3.0% 7.3% 5.9% 6.5% 7.9% 8.6% 10.1% 12.5%
NYPP
Pre-Merger HHI 1,166 1,153 1,147 1,138 939 1,182 1,083 1,017 1,025 968 807
Post-Merger HHI 1,166 1,153 1,147 1,138 940 1,182 1,083 1,017 1,025 968 810
Change 0 0 0 0 0 0 0 0 0 0 3
FE Capacity (MW) 10 10 11 7 18 12 8 13 41 31 54
GPU Capacity (MW) 62 63 58 61 83 45 47 106 117 142 320
Merged Capacity (MW) 72 73 69 68 101 57 55 119 159 173 374
FE Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% 0.1% 0.1% 0.5%
GPU Market Share 0.2% 0.2% 0.2% 0.2% 0.6% 0.2% 0.2% 1.0% 0.4% 0.6% 2.9%
Merged Market Share 0.2% 0.2% 0.2% 0.2% 0.8% 0.2% 0.3% 1.1% 0.5% 0.8% 3.4%
VEPCO
Pre-Merger HHI 4,005 3,954 3,699 3,545 2,711 3,306 2,766 1,979 3,578 2,837 1,734
Post-Merger HHI 4,005 3,954 3,700 3,546 2,712 3,307 2,767 1,986 3,579 2,839 1,746
Change 1 1 1 1 1 1 1 7 1 2 12
FE Capacity (MW) 176 176 178 178 128 103 107 207 146 153 254
GPU Capacity (MW) 99 100 93 97 136 132 137 308 117 139 316
Merged Capacity (MW) 275 276 271 275 264 235 244 515 263 291 570
FE Market Share 0.8% 0.8% 0.9% 0.9% 0.8% 0.5% 0.6% 1.6% 0.8% 1.0% 2.2%
GPU Market Share 0.4% 0.5% 0.4% 0.5% 0.8% 0.7% 0.8% 2.3% 0.6% 0.9% 2.7%
Merged Market Share 1.2% 1.2% 1.3% 1.4% 1.6% 1.2% 1.4% 3.9% 1.4% 1.8% 5.0%
</TABLE>
<PAGE> 346
Exhibit APP-316, page 4 of 5
SENSITIVITY FOR HENRY HUB GAS PRICE DECREASE BY $2
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PJM-WESTINT
Pre-Merger HHI 1,165 1,163 1,186 1,216 1,090 1,022 1,082 1,551 989 1,056 1,288
Post-Merger HHI 1,177 1,175 1,193 1,220 1,102 1,042 1,092 1,577 1,009 1,072 1,320
Change 12 12 8 4 11 20 11 26 20 15 32
FE Capacity (MW) 761 761 471 207 360 968 390 235 963 460 262
GPU Capacity (MW) 2,415 2,415 2,043 1,997 1,911 2,241 1,991 1,971 1,957 1,819 1,717
Merged Capacity (MW) 3,176 3,176 2,514 2,204 2,271 3,209 2,381 2,206 2,919 2,279 1,979
FE Market Share 1.4% 1.4% 0.9% 0.4% 1.0% 2.1% 1.0% 1.2% 2.2% 1.4% 1.6%
GPU Market Share 4.4% 4.4% 4.1% 4.3% 5.5% 4.8% 5.2% 10.4% 4.5% 5.5% 10.3%
Merged Market Share 5.7% 5.8% 5.0% 4.8% 6.5% 6.8% 6.3% 11.7% 6.7% 6.9% 11.8%
PJM-CENTINT
Pre-Merger HHI 1,510 1,507 1,540 1,524 1,387 1,391 1,372 1,564 1,358 1,363 1,417
Post-Merger HHI 1,516 1,513 1,544 1,526 1,394 1,402 1,379 1,589 1,369 1,373 1,446
Change 6 6 4 2 7 11 7 26 11 10 29
FE Capacity (MW) 216 216 143 67 139 312 151 229 303 188 199
GPU Capacity (MW) 2,177 2,177 1,811 1,778 1,713 1,993 1,769 1,962 1,698 1,602 1,631
Merged Capacity (MW) 2,392 2,392 1,954 1,845 1,852 2,305 1,920 2,191 2,000 1,790 1,830
FE Market Share 0.5% 0.5% 0.4% 0.2% 0.5% 0.9% 0.5% 1.2% 1.0% 0.8% 1.3%
GPU Market Share 5.3% 5.4% 4.9% 5.2% 6.7% 5.9% 6.3% 10.5% 5.5% 6.5% 10.9%
Merged Market Share 5.8% 5.9% 5.3% 5.4% 7.2% 6.8% 6.8% 11.7% 6.5% 7.3% 12.2%
PJM-EASTINT
Pre-Merger HHI 1,490 1,477 1,490 1,463 1,301 1,224 1,262 1,667 1,309 1,223 1,432
Post-Merger HHI 1,497 1,484 1,495 1,466 1,310 1,238 1,271 1,691 1,323 1,235 1,463
Change 7 7 5 3 10 14 9 24 13 12 30
FE Capacity (MW) 216 217 144 68 129 288 135 172 286 167 173
GPU Capacity (MW) 1,863 1,864 1,509 1,486 1,433 1,669 1,460 1,757 1,417 1,339 1,467
Merged Capacity (MW) 2,079 2,081 1,653 1,555 1,563 1,957 1,595 1,929 1,703 1,507 1,640
</TABLE>
<PAGE> 347
Exhibit APP-316, page 5 of 5
SENSITIVITY FOR HENRY HUB GAS PRICE DECREASE BY $2
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
FE Market Share 0.7% 0.7% 0.5% 0.2% 0.7% 1.1% 0.6% 1.1% 1.2% 0.9% 1.3%
GPU Market Share 5.6% 5.7% 5.1% 5.2% 7.3% 6.4% 6.9% 11.1% 5.8% 7.0% 11.3%
Merged Market Share 6.3% 6.3% 5.5% 5.5% 8.0% 7.5% 7.5% 12.2% 6.9% 7.8% 12.7%
</TABLE>
<PAGE> 348
EXHIBIT NO. APP-317
<PAGE> 349
Exhibit APP-317, page 1 of 5
SENSITIVITY TO MOVE PEPCO SALE OUTSIDE PJM
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
FE
Pre-Merger HHI 5,228 5,225 5,085 4,333 3,214 4,948 4,193 4,112 4,262 3,519 3,027
Post-Merger HHI 5,242 5,240 5,101 4,369 3,268 4,985 4,235 4,271 4,297 3,562 3,202
Change 15 15 16 36 54 37 42 159 35 43 175
FE Capacity (MW) 11,798 11,788 11,090 10,101 9,965 10,789 10,162 8,175 8,360 7,847 4,973
GPU Capacity (MW) 17 18 18 43 90 41 52 163 35 50 155
Merged Capacity (MW) 11,815 11,805 11,109 10,144 10,055 10,831 10,215 8,338 8,395 7,898 5,129
FE Market Share 71.6% 71.6% 70.5% 64.8% 54.5% 69.8% 63.9% 63.1% 64.3% 57.9% 53.0%
GPU Market Share 0.1% 0.1% 0.1% 0.3% 0.5% 0.3% 0.3% 1.3% 0.3% 0.4% 1.7%
Merged Market Share 71.7% 71.7% 70.6% 65.1% 55.0% 70.1% 64.2% 64.3% 64.6% 58.3% 54.6%
PJM
Pre-Merger HHI 1,165 1,164 1,181 1,176 1,149 978 1,136 1,611 939 1,063 1,323
Post-Merger HHI 1,177 1,176 1,190 1,181 1,161 1,001 1,147 1,637 966 1,081 1,355
Change 12 12 9 5 12 23 11 26 26 18 32
FE Capacity (MW) 747 747 459 199 347 948 384 225 958 452 250
GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 1,885 1,747 1,717
Merged Capacity (MW) 3,162 3,162 2,502 2,125 2,258 3,119 2,375 2,196 2,843 2,200 1,967
FE Market Share 1.4% 1.4% 1.0% 0.5% 1.0% 2.2% 1.0% 1.2% 2.6% 1.5% 1.5%
GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.1% 5.4% 10.7% 5.1% 5.9% 10.5%
Merged Market Share 5.8% 5.8% 5.6% 5.5% 6.8% 7.3% 6.5% 11.9% 7.7% 7.5% 12.0%
AEP
Pre-Merger HHI 2,433 2,432 2,384 2,463 3,816 2,241 2,130 2,585 1,816 1,693 2,065
Post-Merger HHI 2,433 2,433 2,385 2,463 3,817 2,241 2,130 2,591 1,816 1,694 2,078
Change 0 0 1 1 1 0 1 6 1 1 12
FE Capacity (MW) 3,012 3,011 3,019 2,968 1,664 1,613 1,694 1,591 2,436 2,558 2,403
GPU Capacity (MW) 16 17 19 23 25 24 42 330 24 43 338
Merged Capacity (MW) 3,027 3,028 3,038 2,991 1,689 1,637 1,736 1,920 2,460 2,601 2,742
FE Market Share 6.6% 6.6% 6.7% 6.7% 4.8% 3.4% 3.5% 3.9% 5.7% 5.9% 6.6%
GPU Market Share 0.0% 0.0% 0.0% 0.1% 0.1% 0.0% 0.1% 0.8% 0.1% 0.1% 0.9%
Merged Market Share 6.6% 6.6% 6.7% 6.8% 4.9% 3.5% 3.6% 4.7% 5.8% 6.0% 7.6%
</TABLE>
<PAGE> 350
Exhibit APP-317, page 2 of 5
SENSITIVITY TO MOVE PEPCO SALE OUTSIDE PJM
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
APS
Pre-Merger HHI 3,888 3,864 3,628 3,089 3,364 4,241 2,359 2,488 3,757 1,981 2,103
Post-Merger HHI 3,891 3,867 3,631 3,093 3,368 4,244 2,368 2,510 3,761 1,992 2,127
Change 3 3 3 5 5 4 10 22 4 11 24
FE Capacity (MW) 324 324 325 431 377 349 840 667 319 763 608
GPU Capacity (MW) 78 80 83 95 103 84 155 298 76 151 286
Merged Capacity (MW) 402 404 408 526 480 433 995 965 395 914 894
FE Market Share 2.3% 2.4% 2.5% 3.2% 3.0% 2.7% 5.1% 4.9% 2.9% 5.2% 5.1%
GPU Market Share 0.6% 0.6% 0.6% 0.7% 0.8% 0.6% 0.9% 2.2% 0.7% 1.0% 2.4%
Merged Market Share 2.9% 2.9% 3.1% 3.9% 3.8% 3.4% 6.1% 7.2% 3.5% 6.2% 7.4%
DPL
Pre-Merger HHI 7,115 7,092 6,817 5,475 3,907 5,308 3,766 2,963 4,712 3,243 2,618
Post-Merger HHI 7,115 7,092 6,817 5,476 3,908 5,308 3,767 2,967 4,713 3,244 2,624
Change 0 0 0 0 1 0 1 4 0 1 6
FE Capacity (MW) 137 137 137 211 351 234 408 475 228 397 457
GPU Capacity (MW) 0 0 0 1 3 1 2 9 1 2 12
Merged Capacity (MW) 137 137 137 212 354 235 410 484 229 399 469
FE Market Share 3.5% 3.6% 3.9% 5.8% 7.8% 6.3% 9.0% 10.0% 7.2% 10.0% 10.8%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.2% 0.0% 0.1% 0.3%
Merged Market Share 3.5% 3.6% 3.9% 5.8% 7.9% 6.3% 9.0% 10.2% 7.2% 10.0% 11.1%
DQE
Pre-Merger HHI 6,207 6,207 6,029 3,964 5,902 3,367 3,016 2,675 3,354 3,168 3,461
Post-Merger HHI 6,207 6,207 6,029 3,965 5,903 3,369 3,020 2,741 3,356 3,173 3,540
Change 0 0 0 2 1 2 4 66 2 5 79
FE Capacity (MW) 591 591 592 1,774 604 1,348 1,714 2,101 1,597 2,031 3,021
GPU Capacity (MW) 0 0 0 1 1 2 4 38 1 3 41
Merged Capacity (MW) 591 591 593 1,775 605 1,349 1,717 2,139 1,599 2,034 3,061
FE Market Share 17.5% 17.5% 18.7% 37.6% 19.4% 27.5% 30.7% 42.6% 36.2% 40.0% 54.3%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.1% 0.8% 0.0% 0.1% 0.7%
Merged Market Share 17.5% 17.5% 18.7% 37.7% 19.5% 27.5% 30.8% 43.4% 36.3% 40.1% 55.0%
</TABLE>
<PAGE> 351
Exhibit APP-317, page 3 of 5
SENSITIVITY TO MOVE PEPCO SALE OUTSIDE PJM
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
MECS
Pre-Merger HHI 3,448 3,437 3,290 3,854 2,878 2,643 2,636 3,267 2,363 2,351 2,816
Post-Merger HHI 3,448 3,437 3,290 3,855 2,879 2,643 2,636 3,270 2,364 2,352 2,824
Change 0 0 0 0 1 0 0 2 1 1 8
FE Capacity (MW) 964 963 964 541 1,143 1,184 1,114 1,006 1,633 1,531 1,368
GPU Capacity (MW) 1 1 2 2 11 5 5 18 7 9 34
Merged Capacity (MW) 965 965 965 543 1,155 1,188 1,119 1,025 1,640 1,540 1,402
FE Market Share 4.5% 4.5% 5.5% 3.6% 7.2% 6.3% 6.5% 7.8% 9.9% 10.3% 12.2%
GPU Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.0% 0.0% 0.1% 0.0% 0.1% 0.3%
Merged Market Share 4.5% 4.5% 5.5% 3.6% 7.3% 6.3% 6.5% 7.9% 10.0% 10.4% 12.6%
NYPP
Pre-Merger HHI 1,166 1,158 1,173 1,064 940 1,161 1,083 1,017 1,001 956 807
Post-Merger HHI 1,166 1,158 1,173 1,064 940 1,161 1,083 1,017 1,001 956 810
Change 0 0 0 0 0 0 0 0 0 0 3
FE Capacity (MW) 10 10 12 8 17 12 8 13 46 33 51
GPU Capacity (MW) 63 64 66 71 84 47 49 107 132 150 322
Merged Capacity (MW) 73 74 78 79 101 59 57 120 178 183 373
FE Market Share 0.0% 0.0% 0.0% 0.0% 0.1% 0.1% 0.0% 0.1% 0.2% 0.2% 0.5%
GPU Market Share 0.2% 0.2% 0.2% 0.3% 0.7% 0.2% 0.2% 1.0% 0.5% 0.8% 2.9%
Merged Market Share 0.2% 0.2% 0.2% 0.3% 0.8% 0.3% 0.3% 1.1% 0.7% 0.9% 3.4%
VEPCO
Pre-Merger HHI 4,003 3,951 3,422 3,050 2,706 3,096 2,764 1,968 3,065 2,623 1,722
Post-Merger HHI 4,003 3,952 3,423 3,051 2,707 3,097 2,765 1,976 3,066 2,625 1,735
Change 1 1 1 1 1 1 1 8 1 2 12
FE Capacity (MW) 176 176 181 180 128 104 107 207 148 153 254
GPU Capacity (MW) 100 102 106 113 138 140 142 318 134 147 325
Merged Capacity (MW) 276 278 287 293 266 244 249 525 282 300 578
FE Market Share 0.8% 0.8% 0.9% 1.0% 0.8% 0.6% 0.6% 1.6% 0.9% 1.0% 2.2%
GPU Market Share 0.4% 0.5% 0.5% 0.6% 0.8% 0.8% 0.8% 2.4% 0.8% 1.0% 2.8%
Merged Market Share 1.2% 1.3% 1.5% 1.6% 1.6% 1.3% 1.5% 4.0% 1.7% 2.0% 5.0%
</TABLE>
<PAGE> 352
Exhibit APP-317, page 4 of 5
SENSITIVITY TO MOVE PEPCO SALE OUTSIDE PJM
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PJM-WESTINT
Pre-Merger HHI 1,165 1,164 1,181 1,176 1,149 978 1,136 1,611 945 1,063 1,323
Post-Merger HHI 1,177 1,176 1,190 1,181 1,161 1,001 1,147 1,637 971 1,081 1,355
Change 12 12 9 5 12 23 11 26 26 18 32
FE Capacity (MW) 747 747 459 199 347 948 384 225 931 452 250
GPU Capacity (MW) 2,415 2,415 2,043 1,926 1,911 2,171 1,991 1,971 1,885 1,747 1,717
Merged Capacity (MW) 3,162 3,162 2,502 2,125 2,258 3,119 2,375 2,196 2,816 2,200 1,967
FE Market Share 1.4% 1.4% 1.0% 0.5% 1.0% 2.2% 1.0% 1.2% 2.5% 1.5% 1.5%
GPU Market Share 4.4% 4.4% 4.5% 5.0% 5.7% 5.1% 5.4% 10.7% 5.1% 5.9% 10.5%
Merged Market Share 5.8% 5.8% 5.6% 5.5% 6.8% 7.3% 6.5% 11.9% 7.7% 7.5% 12.0%
PJM-CENTINT
Pre-Merger HHI 1,509 1,509 1,552 1,463 1,482 1,316 1,459 1,611 1,297 1,367 1,433
Post-Merger HHI 1,515 1,514 1,557 1,466 1,490 1,330 1,466 1,637 1,313 1,380 1,462
Change 6 6 5 3 8 13 7 26 16 13 29
FE Capacity (MW) 217 217 148 71 138 321 153 225 316 193 198
GPU Capacity (MW) 2,179 2,179 1,818 1,717 1,717 1,929 1,773 1,971 1,635 1,537 1,642
Merged Capacity (MW) 2,396 2,396 1,966 1,788 1,855 2,251 1,926 2,196 1,950 1,729 1,840
FE Market Share 0.5% 0.5% 0.4% 0.3% 0.6% 1.1% 0.6% 1.2% 1.2% 0.9% 1.3%
GPU Market Share 5.3% 5.4% 5.5% 6.1% 7.0% 6.3% 6.5% 10.7% 6.5% 7.1% 11.0%
Merged Market Share 5.9% 5.9% 6.0% 6.4% 7.5% 7.4% 7.1% 11.9% 7.7% 8.0% 12.3%
PJM-EASTINT
Pre-Merger HHI 1,489 1,481 1,422 1,382 1,357 1,178 1,314 1,711 1,209 1,233 1,458
Post-Merger HHI 1,496 1,488 1,428 1,386 1,367 1,196 1,324 1,736 1,230 1,249 1,488
Change 7 7 6 4 10 18 9 24 21 16 30
FE Capacity (MW) 215 216 148 70 131 291 139 171 293 174 170
GPU Capacity (MW) 1,867 1,867 1,521 1,434 1,447 1,607 1,473 1,781 1,358 1,284 1,480
Merged Capacity (MW) 2,082 2,083 1,669 1,504 1,578 1,899 1,611 1,952 1,650 1,457 1,650
</TABLE>
<PAGE> 353
Exhibit APP-317, page 5 of 5
SENSITIVITY TO MOVE PEPCO SALE OUTSIDE PJM
<TABLE>
<CAPTION>
SUMMER WINTER SPRING / FALL
---------------------------------------------- ------------------------ ------------------------
Destination Market Top 50 Next 100 Super Peak Off-Peak Super Peak Off-Peak Super Peak Off-Peak
------------------------ ------ -------- ----- ---- -------- ----- ---- -------- ----- ---- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
FE Market Share 0.7% 0.7% 0.6% 0.3% 0.7% 1.3% 0.7% 1.1% 1.5% 1.0% 1.3%
GPU Market Share 5.7% 5.7% 5.8% 6.5% 7.5% 7.1% 7.0% 11.3% 7.0% 7.6% 11.5%
Merged Market Share 6.3% 6.3% 6.3% 6.8% 8.1% 8.3% 7.7% 12.4% 8.6% 8.6% 12.8%
</TABLE>
<PAGE> 354
Pursuant to 18 C.F.R. Section 388.112 Privileged
Information Has Been Removed
