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File No. 70-9381
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
* * *
AMENDMENT NO. 4
TO
FORM U-1
APPLICATION OR DECLARATION
under the
PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
* * *
AMERICAN ELECTRIC POWER COMPANY, INC.
1 Riverside Plaza, Columbus, Ohio 43215
---------------------------
and
CENTRAL AND SOUTH WEST CORPORATION
1616 Woodall Rodgers
Freeway, Dallas, Texas 75202
---------------------------
(Name of companies and top registered holding company
parents filing this statement and address
of principal executive offices)
* * *
Armando A. Pena Wendy G. Hargus
Treasurer Treasurer
American Electric Power Company, Inc. Central and South West Corporation
1 Riverside Plaza 1616 Woodall Rodgers Freeway
Columbus, OH 43215 Dallas, TX 75202
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<TABLE>
<S> <C>
Susan Tomasky Jeffrey D. Cross
Executive Vice President and General Counsel Vice President and General Counsel
American Electric Power Company, Inc. AEP Resources, Inc.
1 Riverside Plaza 1 Riverside Plaza
Columbus, OH 43215 Columbus, OH 43215
Marianne K. Smythe Joris M. Hogan
Wilmer, Cutler & Pickering Milbank, Tweed, Hadley & McCloy L.L.P.
2445 M Street, N.W. 1 Chase Manhattan Plaza
Washington, DC 20037-1420 New York, NY 10005
</TABLE>
(Names and addresses of agents for service)
2
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TABLE OF CONTENTS
Page
ITEM 1. DESCRIPTION OF MERGER..... ......................................... 9
A. INTRODUCTION.......................................................... 9
B. DESCRIPTION OF THE PARTIES TO THE MERGER ............................. 12
1. General Description ................................................ 12
2. Description of Energy Sales and Facilities ......................... 21
C. DESCRIPTION OF MERGER AND STATEMENT AS TO CONSIDERATION .............. 37
1. Background of the Merger ........................................... 37
2. Merger Agreement ................................................... 38
3. Reasons for the Merger ............................................. 39
4. AEP Management Following the Merger ................................ 40
ITEM 2. FEES, COMMISSIONS AND EXPENSES ..................................... 40
ITEM 3. APPLICABLE STATUTORY PROVISIONS .................................... 40
A. SECTION 10(b) ........................................................ 43
1. Section 10(b)(1) ................................................... 43
2. Section 10(b)(2) ................................................... 54
3. Section 10(b)(3) ................................................... 60
B. Section 10(c) ........................................................ 63
1. Section 10(c)(1) ................................................... 63
2. Section 10(c)(2) ................................................... 98
C. Section 10(f) ........................................................ 106
D. INTRA-SYSTEM FINANCING AND OTHER COMMISSION AUTHORIZATIONS ........... 106
E. SERVICE AGREEMENT; APPROVAL OF METHODOLOGY FOR ALLOCATING COSTS UNDER. 110
F. ACQUISITION OF NON-UTILITY BUSINESSES ................................ 114
G. ORGANIZATION OF MERGER SUB; ACQUISITION OF MERGER SUB COMMON STOCK ... 114
ITEM 4. REGULATORY APPROVAL ................................................ 115
A. ANTITRUST CONSIDERATIONS ............................................. 115
B. ATOMIC ENERGY ACT .................................................... 116
C. FEDERAL POWER ACT .................................................... 116
D. COMMUNICATIONS ACT ................................................... 118
E. ARKANSAS COMMISSION .................................................. 118
F. LOUISIANA COMMISSION ................................................. 118
G. OKLAHOMA COMMISSION .................................................. 113
H. TEXAS COMMISSION ..................................................... 119
I. INDIANA COMMISSION ................................................... 120
J KENTUCKY COMMISSION .................................................. 120
K. MISSOURI COMMISSION .................................................. 121
L. MICHIGAN COMMISSION .................................................. 115
M. AFFILIATE CONTRACTS .................................................. 121
ITEM 5. PROCEDURE .......................................................... 121
ITEM 6. EXHIBITS AND FINANCIAL STATEMENTS .................................. 122
ITEM 7. INFORMATION AS TO ENVIRONMENTAL EFFECTS ............................ 133
STATUS OF STATE RESTRUCTURING LEGISLATION Appendix A
GLOSSARY OF TERMS
The following abbreviations or acronyms used in this Application-Declaration are
defined below:
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AEGCo AEP Generating Company
AEP American Electric Power Company, Inc. before
the Merger, unless the context indicates
otherwise
AEPC AEP Communications, LLC
AEP Common Stock AEP common stock, $6.50 par value
AEPES AEP Energy Services, Inc. (formerly, AEP Energy
Solutions, Inc.)
AEPRESCO AEP Resources Service Company (formerly, AEP
Energy Services, Inc.)
AEP Resources AEP Resources, Inc.
AEPSC American Electric Power Service Corporation
AEP System American Electric Power System, an integrated
electric utility system owned and operated by
AEP's U.S. electric utility subsidiaries
Alliance RTO Application Application of Alliance RTO for Approval of
Transaction under Section 203 of the Federal
Power Act, FERC Docket No. EC99-80 (filed June
3, 1999)
Ameren Ameren Corporation, a public utility holding
company registered under the 1935 Act
Antitrust Division Antitrust Division of U.S. Department of
Justice
APCo Appalachian Power Company
Applicants AEP and CSW
Arkansas Commission Arkansas Public Service Commission
Atomic Energy Act Atomic Energy Act of 1954, as amended
C3 Communications C3 Communications, Inc.
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Central Dispatch Planning Computer software program,
developed by the Applicants using proprietary
technology and technology licensed from third
parties, which forecasts the generation needs
of the Combined System and schedules each
generating unit accordingly
Central Economic Dispatch Computer software program,
developed by the Applicants using proprietary
technology and technology licensed from third
parties, which adjusts, every four seconds, the
dispatch of each generating unit within the
Combined System
Combined Company AEP following the Merger
Combined System System resulting from combination of the AEP
System and CSW System following the Merger
Commission Securities and Exchange Commission
Consumers Consumers Energy Company
Contract Path Contractual reservation of 250 MW over the
Ameren system providing firm point-to-point
transmission service from AEP's Breed-Casey
interconnection with Ameren to CSW's MOKANOK
line interconnection with Ameren
CPL Central Power and Light Company
CSPCo Columbus Southern Power Company
CSW Central and South West Corporation before the
Merger, unless the context indicates otherwise
CSW Common Stock CSW common stock, $3.50 par value
CSW Credit CSW Credit, Inc.
CSW Energy CSW Energy, Inc.
CSW Energy Services CSW Energy Services, Inc.
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CSW International CSW International, Inc.
CSW Leasing CSW Leasing, Inc.
CSWS Central and South West Services, Inc.
CSW System CSW Electric Power System, an integrated
electric utility system, owned and operated by
CSW's U.S. electric utility subsidiaries
D.C. Circuit U.S. Court of Appeals for the District of
Columbia Circuit
Detroit Edison Detroit Edison Company
Division Commission's Division of Investment Management
DOJ U.S. Department of Justice
Duke Duke Energy Corporation, an integrated energy
and energy services provider including an
electric public utility
ECAR East Central Area Reliability Council
Energy Act Energy Policy Act of 1992
EnerShop EnerShop Inc.
Entergy Entergy Corporation, a public utility holding
company registered under the 1935 Act
ERCOT Electric Reliability Council of Texas
EWG Exempt Wholesale Generator
Exchange Ratio specified in the Merger Agreement of
converting CSW Common Stock for AEP Common
Stock, i.e., each share of CSW Common Stock
converts into 0.60 shares of AEP Common Stock
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Excluded Shares Shares of CSW Common Stock owned by AEP, Merger
Sub or any other direct or indirect subsidiary
of AEP and shares of CSW Common Stock that are
owned by CSW or any direct or indirect
subsidiary of CSW, in each case not held on
behalf of third parties
FCC Federal Communications Commission
FERC Federal Energy Regulatory Commission
FERC Stipulation Stipulation of American Electric Power Company,
Inc., Central and South West Corporation, and
Commission Trial Staff, FERC Docket No. EC
98-40 (filed June 24, 1999)
FirstEnergy FirstEnergy Corporation
FPA Federal Power Act
FTC Federal Trade Commission
FUCO Foreign Utility Company
HHI Herfindahl-Hirschman Index
HSR Act Hart-Scott-Rodino Antitrust Improvements Act of
1976
HVDC High Voltage Direct Current
I&M Indiana Michigan Power Company
Indiana Commission Indiana Utility Regulatory Commission
IPP Independent Power Producer
ISO Independent System Operator
Kentucky Commission Kentucky Public Service Commission
KPCo Kentucky Power Company
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KgPCo Kingsport Power Company
Kv Kilovolt
KwH Kilowatt hours
Louisiana Commission Louisiana Public Service Commission
Merger Business combination of AEP and CSW pursuant to
the Merger Agreement
Merger Agreement Agreement and Plan of Merger, dated
as of December 21, 1997 among CSW, AEP and
Merger Sub in which Merger Sub will be merged
with and into CSW and CSW will become a
wholly-owned subsidiary of AEP
Michigan Commission The Michigan Public Service Commission
Merger Sub Augusta Acquisition Corporation, to become a
wholly owned subsidiary of AEP
MISO Midwest Independent Transmission System
Operator, Inc.
Missouri Commission Missouri Public Service Commission
MOKANOK Line 345 Kv transmission line jointly owned by
PSO, UE, Associated Electric Cooperative and
Kansas Gas and Electric Company.
Morgan Stanley Morgan Stanley & Co. Incorporated, an
investment banking firm and CSW's financial
adviser with respect to the Merger
MW Megawatts
Nanyang Electric Nanyang General Light Electric Co., Ltd.
NCE New Century Energies, Inc.
NEPOOL New England Power Pool
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1935 Act Public Utility Holding Company Act of 1935, as
amended
1995 Report The Regulation of Public Utility Holding
Companies (report to Congress by the Division,
June 1995)
NRC Nuclear Regulatory Commission
NSP Northern States Power Company
OASIS Open Access Same-Time Information System
OATT Open Access Transmission Tariff
OG&E Oklahoma Gas & Electric Company
Ohio Commission Public Utilities Commission of Ohio
Oklahoma Commission Corporation Commission of the State of Oklahoma
OPCo Ohio Power Company
PG&E PG&E Corporation, a public utility holding
company
PSNH Public Service Company of New Hampshire
PSO Public Service Company of Oklahoma
QF Qualifying Facility as defined in the Public
Utility Regulatory Policies Act of 1978
Registration Statement Joint Proxy Statement/Prospectus dated April
16, 1998 of AEP and CSW
RTO Regional Transmission Organization
Salomon Salomon Smith Barney Inc., an investment
banking firm and AEP's financial adviser with
respect to the Merger
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SEEBOARD SEEBOARD plc, one of the 12 regional
electricity companies formed due to the
restructuring and subsequent privatization of
the United Kingdom electricity industry in 1990
Southern The Southern Company, a public utility holding
company registered under the 1935 Act
SPP Southwest Power Pool
STP South Texas Project, a two-unit nuclear
electricity generating station in which CPL
owns a 25.2% interest
STP Operating STP Nuclear Operating Company
SWEPCO Southwestern Electric Power Company
Texas Commission Public Utility Commission of Texas
UE Union Electric Company, a public utility and a
wholly owned subsidiary of Ameren
Virginia Commission The Virginia State Corporations Commission
Virginia Power Virginia Electric and Power Company
West Virginia Commission West Virginia Public Service Commission
WPCo Wheeling Power Company
WR Western Resources, Inc.
WTU West Texas Utilities Company
Yorkshire Electricity Yorkshire Electricity Group plc,
one of the 12 regional electricity companies
formed due to the restructuring and subsequent
privatization of the United Kingdom electricity
industry in 1990
ITEM 1. DESCRIPTION OF THE MERGER
Applicants, pursuant to Sections 6, 7, 9(a)(1) and 10, 11, 12, 13, 32 and
33 of the 1935 Act and the rules thereunder, hereby amend and restate the Form
U-1 Application-Declaration in
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File No. 70-9381 ("Application-Declaration"). As set forth in greater detail
below, Applicants hereby request the following authority from the Commission
with respect to the proposed Merger of AEP, a New York corporation, and CSW, a
Delaware corporation:
a. the acquisition by AEP of all of the issued and outstanding CSW
Common Stock;
b. the acquisition by AEP of common stock of Merger Sub;
c. the issuance of AEP Common Stock to effect the Merger;
d. the amendment of AEP's existing authority to authorize the Combined
Company to support the financing arrangements and to conduct the
business activities of CSW (as discussed in Item 3.D below);
e. the adoption of a service agreement to permit, under Section 13 of
the 1935 Act and the Commission's rules thereunder, AEPSC (the
surviving service company for the Combined System after CSWS is
merged into AEPSC) to render services to the Combined Company's
utility and non-utility subsidiaries and an expansion of AEP's
allocation factors following the Merger (as discussed in Item 3.E
below); and
f. the acquisition by AEP of CSW's non-utility businesses (to the
extent jurisdictional, as discussed in Item 3.F below).
Applicants further request that the Commission grant such other authority
as may be necessary in connection with the Merger.
A. INTRODUCTION
This Application-Declaration seeks approvals relating to the proposed
Merger of AEP and CSW. Pursuant to the Merger Agreement, AEP will acquire all of
the issued and outstanding shares of CSW Common Stock. Both AEP and CSW are
registered with the Commission as holding companies under the 1935 Act.
(References to "AEP" or "CSW" refer to each Applicant and/or its subsidiaries,
jointly or separately.)
AEP owns all of the outstanding shares of common stock of seven U.S.
electric utility operating subsidiaries: APCo, CSPCo, I&M, KPCo, KgPCo, OPCo and
WPCo. The service area of AEP's electric utility subsidiaries covers portions of
Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia and West Virginia. AEP
also owns all of the common stock of AEGCo and AEPSC, among others. AEP
indirectly owns 50% of the outstanding share capital of Yorkshire Electricity.
CSW owns all of the outstanding shares of common stock of four U.S.
electric utility operating subsidiaries: CPL, PSO, SWEPCO and WTU. The service
area of CSW's electric
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utility subsidiaries covers portions of Arkansas, Louisiana, Oklahoma and Texas.
CSW also owns all of the common stock of CSWS, among others, and indirectly owns
all of the outstanding share capital of SEEBOARD.
The Merger Agreement provides for a business combination of AEP and CSW in
which Merger Sub will be merged into CSW. CSW will be the surviving corporation
and will become a wholly owned subsidiary of AEP. Immediately following the
Merger, the Combined Company will be a holding company with respect to CSW,
which, in turn, will be a holding company with respect to the electric utility
subsidiaries and other subsidiaries it currently owns (with the exception of
CSWS, which will be merged into AEPSC, and CSW Credit, which will be directly
held by the Combined Company). AEP's utility and non-utility subsidiaries will
remain subsidiaries of AEP, and CSW's utility and non-utility subsidiaries,
which will continue to be owned by CSW, will become indirect subsidiaries of AEP
(except for CSWS and CSW Credit). The final ownership structure has not yet been
determined.
Upon consummation of the Merger, each share of issued and outstanding CSW
Common Stock (other than Excluded Shares) will be exchangeable for 0.60 shares
of AEP Common Stock. The former holders of CSW Common Stock will own
approximately 40% of the outstanding shares of AEP Common Stock after the
Merger. The only voting securities of AEP that will be publicly held will be AEP
Common Stock; the Merger is expected to have no effect on the issued and
outstanding public debt securities, preferred stock and/or preferred trust
securities of CSW and the respective subsidiaries of AEP and CSW.
With respect to the cost of capital of AEP and CSW, the nationally
recognized rating agencies of Moody's Investors Service, Standard & Poor's, Duff
& Phelps and Fitch reaffirmed their rating of the outstanding first mortgage
bonds, commercial paper and other rated securities of AEP and CSW and/or their
subsidiaries shortly after the Merger announcement. Since that time, there has
been no merger-related change in any of the ratings by the rating agencies.(1)
The Merger will produce substantial benefits to the public, investors and
consumers and will meet all applicable standards of the 1935 Act. Applicants
believe that the Merger offers significant strategic and financial benefits to
them and to their respective shareholders, as well as to their employees,
customers and the communities in which they provide service. These benefits
include, among others:
(i) The Combined Company will operate more efficiently and be better
equipped to keep rates low in an increasingly competitive electric utility
industry;
(ii) The Combined Company will achieve savings through the
elimination of duplication in corporate and administrative programs,
greater efficiencies in operations
- ----------
(1) On January 6, 1998, Standard & Poor's revised its ratings outlook on
CSW's regulated U.S. units to negative from stable and affirmed its ratings on
these utilities.
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and business processes, improved purchasing power, and the combination of
two workforces;
(iii) The Merger will result in a Combined Company with a stronger
financial base, improved position in the credit markets and greater market
diversity;
(iv) The Merger will diversify the service territory of the Combined
System, reducing exposure to local changes in economic and competitive
conditions; and
(v) The Merger will enhance the profitability of the Combined
Company through increased scale.
Applicants estimate the net non-fuel savings from the Merger to be nearly
$2 billion and the net fuel-related savings to be approximately $98 million over
the first ten years following the Merger. The projected Merger fuel and non-fuel
savings are discussed in greater detail in Item 3.B.2 below. A copy of the
Merger Agreement is incorporated by reference and attached as Exhibit B-1.
At their Annual Meeting on May 27, 1998, holders of AEP Common Stock
overwhelmingly approved the shareholder actions necessary to effect the Merger.
The following day, holders of CSW Common Stock overwhelmingly approved the
Merger at their Annual Meeting. Various aspects of the Merger are subject to the
approval of this Commission as well as the: (i) FERC; (ii) NRC; (iii) FCC; (iv)
Louisiana Commission; (v) Oklahoma Commission; and (vi) Arkansas Commission. In
addition, the Applicants must obtain pre-Merger clearance from the DOJ according
to procedures set forth in the HSR Act and a determination by the Texas
Commission that the Merger is consistent with the public interest. Applicants
have made filings with each of these regulatory agencies.
On November 23, 1999, an Initial Decision was issued by the Administrative
Law Judge at FERC approving the Merger, a copy of which is filed as Exhibit
D-1.7 and incorporated by reference. FERC is scheduled to issue a final decision
no later than March 2000. The NRC approved the transfer of control of CPL's NRC
licenses, a copy of which is filed as Exhibit D-6.2 and incorporated by
reference, and on December 9, 1999, granted an extension of such approval to
June 30, 2000. On July 26, 1999, Applicants filed with the DOJ under the HSR
Act. On February 2, 2000, DOJ notified Applicants that it had completed its
review of the Merger and that no further action is warranted. On July 29, 1999,
Applicants filed an application with the FCC to transfer control of certain
licenses held by CSW subsidiaries to AEP, a copy of which is filed as Exhibit
D-9.1. On January 21, 2000, the FCC approved the transfer of certain microwave
licenses held by CSW. Orders approving the Merger have been received from the
Arkansas Commission, the Louisiana Commission, the Oklahoma Commission, the
Kentucky Commission, the Indiana Commission, and the Michigan Commission, copies
of which are filed as Exhibit D-2.2, Exhibit D-3.2, Exhibit D-4.2, Exhibit
D-7.1, Exhibit D-8.1, and Exhibit D-10.1, respectively, and incorporated by
reference. On November 18, 1999, the Texas Commission issued an order finding
the Merger to be consistent with the public interest, a copy
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of which is filed as Exhibit D-5.5 and incorporated by reference. To realize the
benefits of the Merger promptly, Applicants ask that the Commission review this
Application-Declaration and issue an order approving the Merger and granting
authority for the attendant transactions set forth above as expeditiously as
practicable without a hearing.
B. DESCRIPTION OF THE PARTIES OF THE MERGER
1. General Description
a. AEP
AEP, a New York corporation, has its principal executive offices at 1
Riverside Plaza, Columbus, Ohio. AEP was incorporated under the laws of the
State of New York in 1906 and reorganized in 1925. AEP is a registered public
utility holding company that owns all of the outstanding shares of common stock
of seven U.S. electric utility operating subsidiaries: APCo, CSPCo, I&M, KPCo,
KgPCo, OPCo and WPCo. Most of the operating revenues of AEP and its subsidiaries
are derived from sales of electricity. AEP also owns, either directly or
indirectly, all of the common stock of four material non-utility businesses --
AEP Resources, AEPRESCO, AEPC, and AEPES -- and all of the common stock of two
other businesses -- AEGCo and AEPSC. AEP indirectly owns 50% of the outstanding
share capital of Yorkshire Electricity.
AEP and its subsidiaries are subject to the broad regulatory provisions of
the 1935 Act administered by the Commission. Various of its subsidiaries are
also subject to regulation by the FERC under the FPA with respect to rates for
interstate sale at wholesale and transmission of electric power, accounting and
other matters and construction and operation of hydroelectric projects.
AEP's electric utility operating subsidiaries serve approximately 3
million customers in Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia and
West Virginia. The generating and transmission facilities of these subsidiaries
are physically interconnected, and their operations are coordinated, as a single
integrated electric utility system. Transmission networks are interconnected
with extensive distribution facilities in the territories served.
At December 31, 1998, the U.S. subsidiaries of AEP had a total of 17,943
employees. AEP, as such, has no employees. The electric utility operating
subsidiaries of AEP are each described below:
APCo (organized in Virginia in 1926) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 888,000 customers in the southwestern portion of Virginia
and southern West Virginia, and in supplying electric power at wholesale
to other electric utility companies and municipalities in those states and
in Tennessee. At December 31, 1998, APCo had 3,577 employees. Among the
principal industries served by APCo are coal mining, primary metals,
chemicals and textile mill products. A comparatively small part of the
properties and business of APCo is located in the northeastern end of
Tennessee. APCo's retail rates
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and certain other matters are subject to regulation by the West Virginia
Commission and the State Corporation Commission of Virginia.
CSPCo (organized in Ohio in 1937, the earliest direct predecessor
company having been organized in 1883) is engaged in the generation, sale,
purchase, transmission and distribution of electric power to approximately
640,000 customers in central and southern Ohio, and in supplying electric
power at wholesale to other electric utilities and to municipally owned
distribution systems within its service area. At December 31, 1998, CSPCo
had 1,528 employees. Among the principal industries served by CSPCo are
food processing, chemicals, primary metals, electronic machinery and paper
products. CSPCo's retail rates and certain other matters are subject to
regulation by the Ohio Commission.
I&M (organized in Indiana in 1925) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 554,000 customers in northern and eastern Indiana and
southwestern Michigan, and in supplying electric power at wholesale to
other electric utility companies, rural electric cooperatives and
municipalities. At December 31, 1998, I&M had 3,074 employees. Among the
principal industries served by I&M are primary metals, transportation
equipment, electrical and electronic machinery, fabricated metal products,
rubber and miscellaneous plastic products and chemicals and allied
products. I&M's retail rates and certain other matters are subject to
regulation by the Indiana Commission and the Michigan Public Service
Commission. I&M also is subject to regulation by the NRC under the Atomic
Energy Act with respect to the operation of its nuclear generation plant.
KPCo (organized in Kentucky in 1919) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 170,000 customers in eastern Kentucky, and in supplying
electric power at wholesale to other utilities and municipalities in
Kentucky. At December 31, 1998, KPCo had 541 employees. The principal
industries served by KPCo include coal mining, petroleum refining, primary
metals and chemicals. KPCo's retail rates and certain other matters are
subject to regulation by the Kentucky Commission.
KgPCo (organized in Virginia in 1917) provides electric service to
approximately 44,000 customers in Kingsport and eight neighboring
communities in northeastern Tennessee. KgPCo has no generating facilities
of its own. It purchases electric power distributed to its customers from
APCo. At December 31, 1998, KgPCo had 65 employees. The principal
industries served by KgPCo include chemicals and allied products, paper
products, stone, clay, glass and concrete products, textiles and printing
products. KgPCo's retail rates and certain other matters are subject to
regulation by the Tennessee Regulatory Authority.
OPCo (organized in Ohio in 1907 and reincorporated in 1924) is
engaged in the generation, sale, purchase, transmission and distribution
of electric power to
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approximately 685,000 customers in the northwestern, east central, eastern
and southern sections of Ohio, and in supplying electric power at
wholesale to other electric utility companies and municipalities. At
December 31, 1998, OPCo and its wholly owned subsidiaries had 4,170
employees. Among the principal industries served by OPCo are primary
metals, rubber and plastic products, stone, clay, glass and concrete
products, petroleum refining and chemicals. OPCo's retail rates and
certain other matters are subject to regulation by the Ohio Commission.
WPCo (organized in West Virginia in 1883 and reincorporated in 1911)
provides electric service to approximately 42,000 customers in northern
West Virginia. WPCo has no generating facilities of its own. It purchases
electric power distributed to its customers from OPCo. At December 31,
1998, WPCo had 80 employees. The principal industries served by WPCo
include chemicals, coal mining and primary metal products. WPCo's retail
rates and certain other matters are subject to regulation by the West
Virginia Commission.
AEGCo was organized in Ohio in 1982 as an electric generating company.
AEGCo sells power at wholesale to I&M, KPCo and Virginia Electric and Power
Company, an unaffiliated public utility. AEGCo has no employees.
AEPSC provides, at cost, accounting, administrative, information systems,
engineering, financial, legal, maintenance and other services to the AEP
companies. The executive officers of AEP and its public utility subsidiaries are
all employees of AEPSC.
AEP, primarily through AEP Resources, AEPRESCO, AEPC, and AEPES, pursues
new non-utility business opportunities, particularly those which allow use of
its expertise. These subsidiaries are described below:
AEP Resources' primary business is development of, and investment
in, EWGs, FUCOs, QFs and other energy-related domestic and international
investment opportunities and projects.
AEP Resources indirectly owns 50% of the outstanding share capital
of Yorkshire Electricity. Yorkshire Electricity is principally engaged in
the distribution of electricity to approximately 2.2 million customers in
its authorized service territory which is comprised of 3,860 square miles
and located centrally on the east coast of England.
AEP Resources' indirect subsidiary, AEP Pushan Power, LDC, has a 70%
interest in Nanyang Electric, a joint venture organized to develop and
build two 125 MW coal-fired generating units near Nanyang City in the
Henan Province of The Peoples' Republic of China. Funding for the
construction of the generating units was completed in June 1999.
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A subsidiary of AEP Resources also has an equity interest, which,
subject to certain conditions, could reach 20%, in Pacific Hydro Limited,
an Australian company that develops and operates hydroelectric facilities.
In December 1998, AEP Resources, through wholly-owned subsidiaries,
acquired CitiPower Pty., an electric distribution and retail sales company
in Victoria, Australia. CitiPower Pty. serves approximately 240,000
customers in a service area that covers approximately 100 square miles in
the city of Melbourne.
In December 1998, AEP Resources acquired from Equitable Resources,
Inc. midstream gas operations consisting of: (i) a 2,000-mile intrastate
pipeline system in Louisiana, (ii) four natural gas processing plants that
straddle the pipeline, and (iii) a storage facility, including an existing
salt dome storage cavern and a second cavern under construction, both
connected to the most active gas trading area in North America. The
pipeline and storage facility are interconnected to 15 interstate and 23
intrastate pipelines. The gas trading and marketing group included in this
purchase was acquired by AEPES.
AEP received approval from the Commission under the 1935 Act to
issue and sell securities in an amount up to 100% of its consolidated
retained earnings (approximately $1,692,000,000 at June 30, 1999) for
investment in EWGs and FUCOs through AEP Resources. American Elec. Power
Co., HCAR No. 26864 (Apr. 27, 1998).
AEPRESCO offers engineering, construction, project management and
other consulting services for projects involving transmission,
distribution or generation of electric power both domestically and
internationally.
AEPC, an "exempt telecommunications company" under the 1935 Act, was
formed in 1997 to pursue opportunities in the telecommunications field.
AEPC operates a fiber optic line that runs through Kentucky, Ohio,
Virginia and West Virginia. This fiber optic line is capable of providing
high speed telecommunications capacity to other telecommunications
companies. In addition to establishing and providing fiber optic services,
AEPC also made investments in two companies engaged in providing digital
personal communications services, the West Virginia PCS Alliance, LLC and
the Virginia PCS Alliance, LLC.
AEPES is authorized to engage in energy-related activities,
including marketing electricity, gas and other energy commodities. As
noted above, AEPES acquired the gas trading and marketing group of
Equitable Resources, Inc. AEPES is an energy-related company under Rule
58.
AEP Common Stock is listed on the New York Stock Exchange, Inc. under the
trading symbol, "AEP." As of October 31, 1999, there were 194,103,349 shares of
AEP Common Stock outstanding. All shares of the common stock of APCo, CSPCo,
I&M, KPCo, KgPCo, OPCo and WPCo are held by AEP.
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<PAGE> 18
APCo has four series of cumulative preferred stock issued and outstanding,
one of which is listed on a public securities exchange. As of June 30, 1999,
there were 191,157 shares of its 4-1/2% Cumulative Preferred Stock outstanding
(listed on the Philadelphia Stock Exchange); 77,100 shares of its 5.90% Series
Cumulative Preferred Stock outstanding; 61,500 shares of its 5.92% Cumulative
Preferred Stock outstanding; and 84,500 shares of its 6.85% Cumulative Preferred
Stock outstanding.
CSPCo has one series of cumulative preferred stock outstanding that is not
listed on a public securities exchange. As of June 30, 1999, there were 250,000
shares of its 7% Cumulative Preferred Stock outstanding.
I&M has seven series of cumulative preferred stock outstanding, none of
which is listed on any public securities exchange. June 30, 1999, there were
59,214 shares of its 4-1/8% Cumulative Preferred Stock outstanding; 14,512
shares of its 4.56% Cumulative Preferred Stock outstanding; 18,931 shares of its
4.12% Cumulative Preferred Stock outstanding; 167,000 shares of its 5.90%
Cumulative Preferred Stock outstanding; 202,500 shares of its 6-1/4% Cumulative
Preferred Stock outstanding; 182,500 shares of its 6-7/8% Cumulative Preferred
Stock outstanding; and 132,450 shares of its 6.30% Cumulative Preferred Stock
outstanding.
OPCo has seven series of cumulative preferred stock outstanding, none of
which is listed on a public securities exchange. As of June 30, 1999, there were
14,968 shares of its 4.08% Cumulative Preferred Stock outstanding; 101,767
shares of its 4-1/2% Cumulative Preferred Stock outstanding; 23,100 shares of
its 4.20% Cumulative Preferred Stock outstanding; 32,274 shares of its 4.40%
Cumulative Preferred Stock outstanding; 82,500 shares of its 5.90% Cumulative
Preferred Stock outstanding; 31,000 shares of its 6.02% Cumulative Preferred
Stock outstanding; and 5,000 shares of its 6.35% Cumulative Preferred Stock
outstanding.
AEP's consolidated operating revenues for the twelve months ended June 30,
1999, after eliminating intercompany transactions, were $6,327,000,000.
Consolidated assets of AEP and its subsidiaries as of June 30, 1999, were
approximately $20.6 billion, consisting of $12.9 billion in net electric utility
property, plant and equipment and $7.7 billion in other corporate assets. More
detailed information concerning AEP and its subsidiaries is contained in AEP's
Annual Report on Form 10-K for the year ended December 31, 1998, and the
Quarterly Report on Form 10-Q for the quarter ended September 30, 1999, each of
which is attached and incorporated by reference as Exhibits G-15 and G-21,
respectively.
b. CSW
CSW, incorporated under the laws of Delaware in 1925, has its principal
executive offices at 1616 Woodall Rodgers Freeway, Dallas, Texas. CSW is a
public utility holding company registered under the 1935 Act that owns all of
the common stock of four U.S. electric utility operating subsidiaries: CPL, PSO,
SWEPCO, and WTU. CSW also owns all of the common stock of CSWS, CSW Energy, CSW
International, C3 Communications, EnerShop,
16
<PAGE> 19
CSW Energy Services, and CSW Credit, and indirectly owns all of the outstanding
share capital of SEEBOARD. In addition, CSW owns 80% of the outstanding shares
of common stock of CSW Leasing.
CSW's electric utility subsidiaries are public utility companies engaged
in generating, purchasing, transmitting, distributing and selling electricity.
CSW's U.S. electric utility operating subsidiaries serve an average of
approximately 1.7 million customers in portions of Texas, Oklahoma, Louisiana
and Arkansas. These companies serve a mix of residential, commercial and
diversified industrial customers.
CSW and its subsidiaries are subject to the broad regulatory provisions of
the 1935 Act administered by the Commission. Various of the subsidiaries are
also subject to regulation by the FERC under the FPA with respect to rates for
interstate sale at wholesale and transmission of electric power, accounting and
other matters and construction and operation of hydroelectric projects.
At December 31, 1998, the U.S. subsidiaries of CSW had 6,971 employees.
CSW, as such, has no employees. The electric utility operating subsidiaries of
CSW are described below:
CPL (organized in Texas in 1945) is engaged in the generation, sale,
purchase, transmission and distribution of electric power to approximately
642,000 customers in portions of south Texas, and in supplying electric
power at wholesale to other electric utility companies and municipalities.
At December 31, 1998, CPL had 1,555 employees. The principal industries
served by CPL include manufacturing, mining, agricultural, transportation
and public utilities sectors. The Texas Commission has original
jurisdiction over retail rates in the unincorporated areas and appellate
jurisdiction over retail rates in the incorporated areas served by CPL.
CPL is also subject to regulation by the NRC under the Atomic Energy Act
with respect to the operation of its ownership interest in a nuclear
generating plant.
PSO (organized in Oklahoma in 1913) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 486,000 customers in portions of eastern and southwestern
Oklahoma, and in supplying electric power at wholesale to other electric
utility companies and municipalities. At December 31, 1998, PSO had 1,227
employees. The principal industries served by PSO include natural gas and
oil production, oil refining, steel processing, aircraft maintenance,
paper manufacturing and timber products, glass, chemicals, cement,
plastics, aerospace, telecommunications and rubber goods. PSO is subject
to the jurisdiction of the Oklahoma Commission with respect to retail
rates.
SWEPCO (organized in Delaware in 1912) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 419,000 customers in portions of northeastern Texas,
northwestern Louisiana and western Arkansas, and in supplying electric
power at wholesale to other electric utility companies
17
<PAGE> 20
and municipalities. At December 31, 1998, SWEPCO had 1,461 employees. The
principal industries served by SWEPCO include mining, manufacturing,
chemical products, petroleum products, agriculture and tourism. SWEPCO is
subject to the jurisdiction of the Arkansas Commission and the Louisiana
Commission with respect to retail rates, as well as the Texas Commission
as set forth in the description of the regulation of CPL above.
WTU (organized in Texas in 1927) is engaged in the generation, sale,
purchase, transmission and distribution of electric power to approximately
188,000 customers in portions of central west Texas, and in supplying
electric power at wholesale to other electric utility companies and
municipalities. At December 31, 1998, WTU had 913 employees. WTU serves
manufacturing and processing plants producing cotton seed products, oil
products, electronic equipment, precision and consumer metal products,
meat products, gypsum products and carbon fiber products. The territory
also has several military installations and state correctional
institutions. WTU is subject to the jurisdiction of the Texas Commission
as set forth in the description of the regulation of CPL above.
CSWS performs, at cost, various accounting, engineering, tax, legal,
financial, electronic data processing, centralized economic dispatching of
electric power and other services for the CSW companies, primarily for CSW's
U.S. electric utility subsidiaries. After the Merger, services performed by CSWS
will be performed by AEPSC.
CSW's material non-utility businesses are conducted through CSW Energy,
CSW International, CSW Energy Services, C3 Communications, CSW Credit, EnerShop
and CSW Leasing. These subsidiaries are described below:
CSW Energy develops, owns and operates independent power production
and cogeneration facilities within the U.S. Currently, CSW Energy has
ownership interests in seven projects, six in operation and one in
development.
CSW International engages in international activities, including
developing, acquiring, financing and owning EWGs and FUCOs, either alone
or with local or other partners. CSW International indirectly owns all of
the outstanding share capital of SEEBOARD. CSW acquired indirect control
of SEEBOARD in April 1996. SEEBOARD's principal regulated businesses are
the distribution and supply of electricity. SEEBOARD is engaged in other
businesses, including gas supply, electricity generation and electrical
contracting. SEEBOARD's service area covers approximately 3,000 square
miles in southeast England. The service area extends from the outlying
areas of London to the English Channel.
CSW received approval from the Commission under the 1935 Act to
issue and sell securities in an amount up to 100% of its consolidated
retained earnings (approximately $1,785,000,000 at June 30, 1999) for
investment in EWGs and FUCOs
18
<PAGE> 21
through CSW Energy and CSW International. Central and South West Corp., et
al., HCAR No. 26653 (January 24, 1997).
CSW Energy Services was formed to compete in restructured electric
utility markets. It also engages in the business of marketing, selling,
and leasing to certain consumers throughout the United States certain
electric vehicles and retrofit kits subject to limitations imposed by the
Commission.
C3 Communications has two main lines of business. C3 Communications'
Utility Automation Division specializes in providing automated meter
reading and related services to investor-owned municipal and cooperative
electric utilities. C3 Communications also offers systems to aggregate
meter data from a variety of technologies and vendor products that span
multiple communication mode infrastructures including broadband, wireless
network, power line carrier and telephony-based systems. C3 Communications
is an "exempt telecommunications company" under the 1935 Act.
CSW Credit was originally formed to purchase, without recourse,
accounts receivable from the CSW electric utility subsidiaries to reduce
working capital requirements. Because CSW Credit's capital structure is
more highly leveraged than that of the CSW electric utility subsidiaries
and due to CSW Credit's higher short-term debt ratings, CSW's overall cost
of capital is lower. Subsequent to its formation, under the 1935 Act, CSW
Credit's business has expanded to include the purchase, without recourse,
of accounts receivable from certain non-affiliated parties subject to
limitations imposed by the Commission.
EnerShop, an energy-related company under Rule 58, provides energy
services to commercial, industrial, institutional and governmental
customers in Texas. These services help reduce a customer's operating
costs through increased energy efficiencies and improved equipment
operations. EnerShop utilizes the skills of local trade allies in offering
services that include facility analysis; project management; engineering
design; equipment procurement; and construction and performance
monitoring.
CSW Leasing, approved by the Commission in 1985, is a joint venture with
CIT Group/Capital Equipment Financing. It was formed to invest in leveraged
leases.
CSW Common Stock is listed on the New York Stock Exchange, Inc., and the
Chicago Stock Exchange, Inc., under the trading symbol, "CSR." As of October 31,
1999, there were 212,648,293 shares of CSW Common Stock issued and outstanding.
All shares of the common stock of CPL, PSO, SWEPCO and WTU are held by CSW.
CPL has five series of cumulative preferred stock issued and outstanding.
As of December 31, 1998, there were 42,048 shares of 4.00% Series Cumulative
Preferred Stock outstanding; 17,476 shares of 4.20% Series Cumulative Preferred
Stock outstanding; 750,000 shares of Auction Money Market Cumulative Preferred
Stock outstanding; 425,000 shares of
19
<PAGE> 22
Auction Series A Cumulative Preferred Stock outstanding; and 425,000 shares of
Auction Series B Cumulative Preferred Stock outstanding. CPL has one series of
8.00% Cumulative Quarterly Income Preferred Securities issued and outstanding,
which are listed on the NYSE. As of December 31, 1998, the principal amount of
$150,000,000 of such trust preferred securities was outstanding.
PSO has two series of cumulative preferred stock issued and outstanding.
As of December 31, 1998, there were 44,636 shares of 4.00% Series Cumulative
Preferred Stock outstanding and 8,069 shares of 4.24% Series Cumulative
Preferred Stock outstanding. PSO has one series of 8.00% Trust Originated
Preferred Securities issued and outstanding, which are listed on the NYSE. As of
December 31, 1998, the principal amount of $75,000,000 of such trust preferred
securities was outstanding.
SWEPCO has three series of cumulative preferred stock issued and
outstanding. As of December 31, 1998, there were 37,727 shares of 5.00% Series
Cumulative Preferred Stock outstanding; 1,908 shares of 4.65% Series Cumulative
Preferred Stock outstanding; and 7,386 shares of 4.28% Series Cumulative
Preferred Stock outstanding. SWEPCO has one series of 7.875% Trust Preferred
Securities issued and outstanding, which are listed on the NYSE. As of December
31, 1998, the principal amount of $110,000,000 of such trust preferred stock was
outstanding.
WTU has one series of cumulative preferred stock issued and outstanding.
As of December 31, 1998, there were 23,675 shares of 4.40% Series Cumulative
Preferred Stock outstanding.
CSW's consolidated operating revenues for the six months ended June 30,
1999, after eliminating intercompany transactions, were approximately $2.5
billion. Consolidated assets of CSW and its subsidiaries as of June 30, 1999
were approximately $13.9 billion, consisting of $8.6 billion in net electric
utility property, plant and equipment and $5.3 billion in other corporate
assets. More detailed information concerning CSW and its subsidiaries is
contained in CSW's Annual Report on Form 10-K for the year ended December 31,
1998 and the Quarterly Report on Form 10-Q for the quarter ended June 30, 1999,
each of which is attached and incorporated by reference as Exhibits G-17 and
G-22, respectively.
c. Merger Sub
Merger Sub, a transitory subsidiary of AEP, was incorporated under the
laws of the State of Delaware, solely for the purpose of effecting the Merger.
Merger Sub has no operations other than those contemplated by the Merger
Agreement. AEP will own all the outstanding common stock, $0.01 par value per
share, of Merger Sub. A copy of the Certificate of Incorporation and By-laws of
Merger Sub are incorporated by reference and attached as Exhibits A-3 and A-4,
respectively. The principal executive office of Merger Sub will be located at 1
Riverside Plaza, Columbus, Ohio.
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<PAGE> 23
2. Description of Energy Sales and Facilties
a. AEP
(i) Energy Sales
<TABLE>
<CAPTION>
KwH of Electric Energy Sold (in millions)
Company Twelve Months Ended December 31, 1998
<S> <C>
APCo 38,860
CSPCo 20,221
I&M 25,285
KPCo 11,375
KgPCo 1,778
OPCo 53,300
WPCo 1,760
AEP Total 130,352(a)
</TABLE>
(a) Total after the elimination of intercompany transactions.
(ii) Electric Generating Facilities
At December 31, 1998, subsidiaries of AEP owned (or leased where
indicated) generating plants with the net power capabilities (winter rating)
shown in the following table:
<TABLE>
<CAPTION>
Net
Megawatt
Owner, Plant Type and Name Location (Near) Capability
<S> <C> <C>
AEGCo:
Steam--Coal Fired:
Rockport Plant (AEGCo share) Rockport, Indiana 1,300(a)
APCo:
Steam--Coal-Fired:
John E. Amos, Units 1 & 2 St. Albans, West Virginia 1,600
John E. Amos, Unit 3 (APCo share) St. Albans, West Virginia 433(b)
Clinch River Carbo, Virginia 705
Glen Lyn Glen Lyn, Virginia 335
Kanawha River Glasgow, West Virginia 400
Mountaineer New Haven, West Virginia 1,300
Philip Sporn, Units 1 & 3 New Haven, West Virginia 308
Hydroelectric--Conventional:
Buck Ivanhoe, Virginia 10
Byllesby Byllesby, Virginia 20
Claytor Radford, Virginia 76
Leesville Leesville, Virginia 40
</TABLE>
21
<PAGE> 24
<TABLE>
<S> <C> <C>
London Montgomery, West Virginia 16
Marmet Marmet, West Virginia 16
Niagara Roanoke, Virginia 3
Reusens Lynchburg, Virginia 12
Winfield Winfield, West Virginia 19
Hydroelectric--Pumped Storage:
Smith Mountain Penhook, Virginia 565
5,858
CSPCo:
Steam--Coal-Fired:
Beckjord, Unit 6 New Richmond, Ohio 53(c)
Conesville, Units 1-3, 5 & 6 Coshocton, Ohio 1,165
Conesville, Unit 4 Coshocton, Ohio 339(c)
Picway, Unit 5 Columbus, Ohio 100
Stuart, Units 1-4 Aberdeen, Ohio 608(c)
Zimmer Moscow, Ohio 330(c)
2,595
I&M:
Steam--Coal-Fired:
Rockport Plant (I&M share) Rockport, Indiana 1,300(a)
Tanners Creek Lawrenceburg, Indiana 995
Steam--Nuclear:
Donald C. Cook Bridgman, Michigan 2,110
Gas Turbine:
Fourth Street Fort Wayne, Indiana 18(d)
Hydroelectric--Conventional:
Berrien Springs Berrien Springs, Michigan 3
Buchanan Buchanan, Michigan 2
Constantine Constantine, Michigan 1
Elkhart Elkhart, Indiana 1
Mottville Mottville, Michigan 1
Twin Branch Mishawaka, Indiana 3
4,434
KPCo:
Steam--Coal-Fired:
Big Sandy Louisa, Kentucky 1,060
OPCo:
Steam--Coal Fired:
John E. Amos, Unit 3 (OPCo share) St. Albans, West Virginia 867(b)
Cardinal, Unit 1 Brilliant, Ohio 600
</TABLE>
22
<PAGE> 25
<TABLE>
<S> <C> <C>
General James M. Gavin Cheshire, Ohio 2,600(e)
Kammer Captina, West Virginia 630
Mitchell Captina, West Virginia 1,600
Muskingum Beverly, Ohio 1,425
Philip Sporn, Units 2, 4 & 5 New Haven, West Virginia 742
Hydroelectric--Conventional:
Racine Racine, Ohio 48
8,512
Total Generating Capability 23,759
SUMMARY:
Total Steam--
Coal-Fired.........................................................................20,795
Nuclear............................................................................ 2,110
Total Hydroelectric--
Conventional....................................................................... 271
Pumped Storage..................................................................... 565
Other.............................................................................. 18
Total Generating Capability 23,759
</TABLE>
(a) Unit 1 of the Rockport Plant is owned one-half by AEGCo and one-half by
I&M. Unit 2 of the Rockport Plant is leased one- half by AEGCo and
one-half by I&M. The leases terminate in 2022 unless extended.
(b) Unit 3 of the John E. Amos Plant is owned one-third by APCo and two-thirds
by OPCo.
(c) Represents CSPCo's ownership interest in generating units owned in common
with two unaffiliated public utilities, Cincinnati Gas & Electric Company
and Dayton Power and Light Company.
(d) Leased from the City of Fort Wayne, Indiana. Since 1975, I&M has leased
and operated the assets of the municipal system of the City of Fort Wayne,
Indiana under a 35-year lease with a provision for an additional 15-year
extension at the election of I&M.
(e) The scrubber facilities at the Gavin Plant are leased. The lease
terminates in 2010 unless extended.
APCo, CSPCo, I&M, KPCo and OPCo are parties to an Interconnection
Agreement, dated July 6, 1951, as amended, defining how they share the costs and
benefits associated with the AEP System's generating plants. Sharing is based
upon each company's "member-load-ratio," which is calculated monthly on the
basis of each company's maximum peak demand in relation to the sum of the
maximum peak demands of all five companies during the preceding 12 months. Since
1995, APCo, CSPCo, I&M, KPCo and OPCo have been parties to the AEP
23
<PAGE> 26
System Interim Allowance Agreement which provides, among other things, for the
transfer of SO2 allowances associated with transactions under the
Interconnection Agreement.
The following table shows the net credits or (charges) allocated among the
parties under the Interconnection Agreement and Interim Allowance Agreement
during the years ended December 31, 1997 and 1998.
<TABLE>
<CAPTION>
1997 1998(a)
---- -------
<S> <C> <C>
APCo $(237,000) $(142,500)
CSPCo (138,000) (146,800)
I&M 67,000 (86,100)
KPCo 20,000 34,000
OPCo 288,000 341,400
</TABLE>
(a) Includes credits and charges from allowance transfers related to the
transactions.
(iii) Electric Transmission and Other Facilities
The following table sets forth, as of December 31, 1998, the total
overhead circuit miles of transmission and distribution lines of the AEP System,
APCo, CSPCo, I&M, KPCo and OPCo and that portion of the total representing 765
Kv lines:
<TABLE>
<CAPTION>
TOTAL OVERHEAD
CIRCUIT MILES OF
TRANSMISSION AND CIRCUIT MILES OF 765
DISTRIBUTION LINES KV LINES
------------------ --------
<S> <C> <C>
AEP System ........................ 128,983(a)(b) 2,022
APCo .............................. 49,793 641
CSPCo ............................. 15,578(a) --
I&M ............................... 20,899 614
KPCo .............................. 10,223 258
OPCo .............................. 29,406 509
</TABLE>
(a) Includes 766 miles of 345 Kv lines jointly owned with non-affiliates.
(b) Includes lines of other AEP System companies not shown.
AEP is a member of ECAR. ECAR's membership includes 29 major electricity
suppliers located in nine states serving more than 36 million people. Membership
is voluntary, and the current full members are those utilities whose generation
and transmission have an impact on the reliability of the interconnected
electric systems in the region. ECAR members interchange power and energy with
one another on a firm, economy and emergency basis.
24
<PAGE> 27
As of December 31, 1998, the AEP System was interconnected through 121
high-voltage transmission interconnections with 26 neighboring electric utility
systems. The all-time and 1998 one-hour peak system demands were 25,940,000 and
23,192,000 kilowatts, respectively (which included 7,314,000 and 3,732,000
kilowatts, respectively, of scheduled deliveries to unaffiliated systems which
the AEP System might, on appropriate notice, have elected not to schedule for
delivery) and occurred on June 17, 1994 and June 22, 1998, respectively. The net
dependable capacity to serve the system load on such dates, including power
available under contractual obligations, was 23,457,000 and 23,761,000
kilowatts, respectively. The all-time and 1998 one-hour internal peak demands
were 19,557,000 and 19,414,000 kilowatts, respectively, and occurred on February
5, 1996 and July 21, 1998, respectively. The net dependable capacity to serve
the system load on such dates, including power dedicated under contractual
arrangements, was 23,765,000 and 23,749,000 kilowatts, respectively.
APCo, CSPCo, I&M, KPCo and OPCo are parties to the Transmission
Equalization Agreement, dated April 1, 1984 (the "Transmission Agreement"),
which defines the method pursuant to which the parties share the costs
associated with their relative ownership of the extra-high-voltage transmission
system (which includes facilities rated 345 Kv and above) and certain facilities
operated at lower voltages (which includes facilities rated 138 Kv and above).
Like the Interconnection Agreement, sharing is based upon each company's
"member-load-ratio."
Other assets owned by AEP include electric distribution systems located
throughout its service area, and property, plant and equipment owned or leased
supporting its electric utility functions.
AEP also owns or leases other physical properties, including real
property, and other facilities necessary to conduct its operations.
(iv) Fuel Supply
The following table shows the sources of power used by the AEP System to
generate electricity:
<TABLE>
<CAPTION>
1997 1998
---- ----
<S> <C> <C>
Coal 92% 99%
Nuclear 7% 0%
Hydroelectric and other 1% 1%
Total 100% 100%
</TABLE>
AEP's average cost of fuel per million BTUs for the calendar years ended
December 31, 1997 and 1998 was 140 cents and 144 cents, respectively.
b. CSW
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<PAGE> 28
(i) Energy Sales
<TABLE>
<CAPTION>
KwH of Electric Energy Sold (in millions)
Company Twelve Months Ended December, 31, 1998
<S> <C>
CPL 23,059
PSO 16,862
SWEPCO 22,936
WTU 7,640
CSW Total 66,994(a)
</TABLE>
(a) Total after elimination of intercompany transactions.
(ii) Electric Generating Facilities
At December 31, 1998, the U.S. electric utility subsidiaries of CSW owned
(or leased where indicated) generating plants with the net power capabilities
(based on summer ambient and water conditions) shown in the following table:
<TABLE>
<CAPTION>
Net
Megawatt
Owner, Plant Type and Name Location (Near) Capability
CPL:
<S> <C> <C>
Steam--Gas:
B.M. Davis Corpus Christi, TX 697
E.S. Joslin Point Comfort, TX 249
J.L. Bates Palm View (Mission), TX 182
La Palma San Benito, TX 206
Laredo Laredo, TX 174
Lon C. Hill Corpus Christi, TX 545
Neuces Bay Corpus Christi, TX 559
Victoria Victoria, TX 482
Steam--Nuclear:
STP Bay City, TX 630(b)
Steam--Coal:
Coleto Creek Fannin (Goliad), TX 632
Oklaunion Vernon, TX 54(c)
Hydroelectric--Conventional:
Eagle Pass Eagle Pass, TX 6
CT--Gas:
La Palma #7 San Benito, TX 48
-----
4,464
PSO:
CT/Steam--Gas:
Comanche Lawton, OK 273(a)
Steam--Gas:
</TABLE>
26
<PAGE> 29
<TABLE>
<S> <C> <C>
Northeastern 1 & 2 Oologah, OK 637
Riverside Jenks, OK 916
Southwest Washita, OK 475
Tulsa Tulsa, OK 330(i)
Steam--Coal:
Northeastern 3 & 4 Oologah, OK 900
Oklaunion Vernon, TX 108(d)
CT--Gas:
Weleetka Weleetka, OK 163
Diesel--Diesel:
Diesels Oklahoma 25
-----
3,827(i)
SWEPCO:
Steam-Gas:
Arsenal Hill Shreveport, LA 110
Knox Lee Cherokee Lake, TX 471
Lieberman Mooringsport, LA 273
Lone Star Dangerfield, TX 50
Wilkes Jefferson, TX 880
Steam--Lignite:
Dolet Hills Mansfield, LA 262(e)
Pirkey Hallsville, TX 580(f)
Steam--Coal:
Flint Creek Gentry, AR 264(g)
Welsh Cason, TX 1,584
-----
4,474
WTU:
Steam-Gas:
Abilene Abilene, TX 18
Fort Phantom Abilene, TX 362
Lake Pauline Quanah, TX 45
Oak Creek Bronte, TX 85
Paint Creek Stamford, TX 238
CT-Gas:
Fort Stockton Ft. Stockton, TX 5
CT/Steam--Gas:
Rio Pecos Girvin, TX 141(a)
San Angelo San Angelo, TX 124(a)
Steam--Coal:
Oklaunion Vernon, TX 377(h)
Diesel--Diesel:
Presidio Presidio, TX 2
Vernon Vernon, TX 9
-----
1,406
Total Generating Capability 14,171(i)
</TABLE>
27
<PAGE> 30
<TABLE>
<CAPTION>
SUMMARY:
<S> <C>
Steam--Gas................................................ 7,984(i)
Steam--Nuclear............................................ 630
Steam--Coal............................................... 3,919
Hydroelectric--Conventional............................... 6
CT--Gas................................................... 216
CT/Steam--Gas............................................. 538
Diesel--Diesel............................................ 36
Steam--Lignite............................................ 842
------
14,171(i)
</TABLE>
(a) Normally operated as combined cycle.
(b) CPL owns 25.2% of STP
(c) CPL owns 7.81% of Oklaunion.
(d) PSO owns 15.6% of Oklaunion.
(e) SWEPCO owns 40.234% of Dolet Hills. Central Louisiana Electric Company,
Northeast Texas Electric Cooperative and Oklahoma Municipal Power Authority own
the rest of the interests in Dolet Hills.
(f) SWEPCO owns 85.936% of Pirkey. Northeast Texas Electric Cooperative and
Oklahoma Municipal Power Authority own the rest of the interests in Pirkey.
(g) SWEPCO owns half of Flint Creek and Arkansas Electric Cooperative
Corporation owns the other half.
(h) WTU owns 54.7% of Oklaunion. (Non-affiliates own 12.29% of Oklaunion).
(i) Excludes 85 MW from units in storage at Tulsa, OK for PSO.
All of the generating facilities described above are located on land owned
by CSW's U.S. electric utility subsidiaries or, in the case of jointly owned
facilities, jointly with other participants. The principal plants and properties
of CSW's electric utility subsidiaries are subject to liens of first mortgage
indentures under which CSW's electric utility subsidiaries' first mortgage bonds
are issued.
As part of Applicants' proposed mitigation plan filed with the FERC,
Applicants agreed to divest 250 MW of capacity in ERCOT and 300 MW of generation
capacity in SPP. In the proceedings before the Texas Commission, Applicants
entered into a settlement with the staff of
28
<PAGE> 31
the Texas Commission under which they agreed to divest 1604 MW of generation
capacity in ERCOT (including the 250 MW of generating capacity contained in the
proposed FERC mitigation plan). The generation units subject to divestiture
include Lon Hill Units 1-4 (CPL)--546 MW; Nueces Bay Plant (CPL)--559 MW; Joslin
Unit 1 (CPL)--249 MW; Frontera Plant (CSW Energy)--250 MW; and Northeastern
Generating Plant (PSO)--300 MW. The timing of divestiture of the generation
capacity located in ERCOT and SPP is conditioned upon there being no violation
of the criteria for pooling-of-interests accounting treatment of the Merger. If
it is determined that the ERCOT divestiture can proceed immediately after the
Merger closes without jeopardizing pooling-of-interests accounting treatment for
the Merger, sale of the plants would begin no later than 90 days after the
Merger closes.(2) Absent that determination, the divestiture would occur
approximately two years after the Merger closes to satisfy the requirements to
use pooling-of-interests accounting treatment. The divestiture of generation
capacity located in SPP is also conditioned upon the plant no longer being
required to meet PSO's native load demand requirements following electric
industry restructuring in Oklahoma.
In addition to the generating facilities described above, CSW has
ownership interests in nonutility electrical generating facilities. Information
concerning U.S. facilities is listed below.
Operating Facilities - United States
<TABLE>
<CAPTION>
Facility Company Location Total Capacity Committed Ownership Interest
-------- ------- -------- -------------- --------- ------------------
<S> <C> <C> <C> <C> <C>
Brush II CSW Energy Colorado 68 68 47%
Ft. Lupton CSW Energy Colorado 272 272 50%
Mulberry CSW Energy Florida 120 110 50%
Orange Cogen CSW Energy Florida 103 97 50%
Newgulf (1) CSW Energy Texas 85 80 100%
Sweeny (2) CSW Energy Texas 330 292 50%
Total 978 919
</TABLE>
(1) The Committed capacity at Newgulf is for the summer of 1999 only.
(2) 205 MW of the committed capacity is for the summer of 1999 only.
CPL, WTU, PSO, SWEPCO, and CSWS are parties to a Restated and Amended
Operating Agreement dated as of January 1, 1997 ("CSW Operating Agreement"). The
CSW Operating Agreement requires CSW's U.S. electric utility operating
subsidiaries to maintain specified annual planning reserve margins and requires
the subsidiaries that have capacity in excess of the required margins to make
such capacity available for sale to other subsidiaries as
- ----------
(2) In a separate filing, the Applicants will seek such further authority
as may be required for the divestiture of generation assets.
29
<PAGE> 32
capacity commitments. The CSW Operating Agreement also delegates to CSWS the
authority to coordinate the acquisition, disposition, planning, design and
construction of CSW's generating units and to supervise the operation and
maintenance of a central control center. CSWS, as agent for the CSW System,
schedules the energy output of the system capability to obtain the lowest cost
of energy for serving aggregate system demand and coordinates off-system
purchases and sales. The CSW Operating Agreement has been accepted for filing
and allowed to become effective by the FERC.
(iii) Electric Transmission and Other Facilities
The following table sets forth the total circuit miles of transmission and
distribution lines of the CSW U.S. electric utility operating subsidiaries as of
December 31, 1998:
<TABLE>
<CAPTION>
TOTAL CIRCUIT MILES OF TOTAL CIRCUIT MILES OF
TRANSMISSION LINES DISTRIBUTION LINES
<S> <C> <C>
CPL 5,000 28,455
PSO 3,573 14,289
SWEPCO 3,382 14,267
WTU 4,570 9,147
Total 16,525 66,158
</TABLE>
CSW's U.S. electric utility subsidiaries' electric transmission and
distribution facilities are mostly located over or under highways, streets and
other public places or property owned by others, for which permits, grants,
easements or licenses have been obtained.
CPL and WTU are members of ERCOT, which operates in Texas. Other ERCOT
members include Texas Utilities Electric Company, Houston Lighting & Power
Company, Texas Municipal Power Agency, Lower Colorado River Authority, the
municipal systems of San Antonio, Austin and Brownsville, the South Texas and
Medina Electric Cooperatives, and several other interconnected systems and
cooperatives. PSO and SWEPCO are members of the SPP, which includes 12
investor-owned utilities, 7 municipalities, 7 cooperatives, 3 state and 1
federal agency as well as IPPs and power marketers operating in the states of
Arkansas, Kansas, Louisiana, Oklahoma and parts of Mississippi, Missouri, New
Mexico and Texas. ERCOT members interchange power and energy with one another on
a firm, economy and emergency basis, as do the members of the SPP.
The highest all-time maximum coincident system demand through 1998 was
13,718 MW on July 27, 1998. The 1998 net dependable capacity to serve the system
load was 14,839 MW. Power generation at the time of the peak was 13,012 MW and
net purchases at the time of the peak were 706 MW. CPL, WTU, PSO, SWEPCO and
CSWS are parties to a Transmission Coordination Agreement dated as of January 1,
1997 ("TCA"). The TCA establishes a coordinating committee, which is charged
with the responsibility of overseeing the coordinated planning of the
transmission facilities of CSW's U.S. electric utility operating subsidiaries,
including the performance of transmission planning studies, the interaction of
such subsidiaries
30
<PAGE> 33
with ISOs and other regional bodies interested in transmission planning and
compliance with the terms of the OATT filed with the FERC and the rules of the
FERC relating to such tariff. Under the TCA, CSW's U.S. electric utility
subsidiaries have delegated to CSWS the responsibility of monitoring the
reliability of their transmission systems and administering the OATT on their
behalf. The TCA also provides for the allocation among CSW's U.S. electric
utility operating subsidiaries of revenues collected for transmission and
ancillary services provided under the OATT. The TCA has been accepted for filing
by the FERC effective as of January 1, 1997, and is the subject of proceedings
commenced to consider the reasonableness of its terms and conditions.
(iv) Fuel Supply
The following table shows the sources of power used by the CSW System:
<TABLE>
<CAPTION>
1997 1998
---- ----
<S> <C> <C>
Natural Gas 36% 38%
Coal 41% 39%
Lignite 9% 8%
Nuclear 7% 7%
Other 0 0
Purchased Power 7% 8%
Total 100% 100%
</TABLE>
CSW's average cost of fuel per million BTUs for the calendar years ended
December 31, 1997 and 1998 was 183 cents and 167 cents, respectively.
3. Electric Coordination
The Combined System will be physically interconnected by means of the
Contract Path, and economically operated as a single interconnected and
coordinated system pursuant to a series of contractual arrangements. Upon
implementation of the System Integration Agreement and the System Transmission
Integration Agreement and through the use of Central Dispatch Planning and
Central Economic Dispatch, the Combined System will have a central dispatch
system capable of scheduling and jointly dispatching the generating resources of
the Combined System on an economical, real-time basis. The Combined System will
be physically interconnected through the 250 MW Contract Path. Each aspect of
the electric coordination and interconnection of the Combined System is
discussed below:
a. System Integration Agreement, System Transmission Integration
Agreement, AEP Interconnection Agreement, CSW Operating Agreement.
The System Integration Agreement provides for the coordination and joint
dispatch of generation within the Combined System. Applicants defined the term
"joint economic dispatch" or "central economic dispatch" to mean the ability of
the merging companies to dispatch their
31
<PAGE> 34
generation units on a least cost basis, taking into account various operating
conditions, in order to achieve certain efficiencies in the operation of the
combined system which could not be realized on a stand-alone basis. The System
Transmission Integration Agreement provides for the coordination of transmission
within the Combined System. The agreements, each of which will take effect upon
consummation of the Merger, are described in the Testimony of J. Craig Baker and
Dennis W. Bethel before the FERC which are filed with Exhibit D-1.1 and
incorporated by reference. The existing AEP Interconnection Agreement and the
existing CSW Operating Agreement will remain in effect after the Merger and
continue to control the distribution of costs and benefits within each zone.
Briefly stated, the existing agreements will continue to govern the allocation
of costs and benefits as between the operating companies of the east zone, on
the one hand, and those of the west zone, on the other. The agreements, which
match intra- and inter-zonal power transfers with the appropriate operating
company, are necessary to assure the affected state regulators that there will
be no cost or benefit transfers within the AEP system or the CSW system as a
result of the Merger. The agreements and their functions are summarized below.
The System Integration Agreement provides for the integration and
coordination of the AEP operating companies and the CSW operating companies and
the distribution of costs and benefits between the two operating zones. The
purpose of the System Integration Agreement, given the settlements with various
State commissions, is to ensure that the benefits achieved through the joint
dispatch of the two zones on a going-forward basis are shared, in the first
instance, between the two zones and then within the zones, based on the
historical cost and benefit sharing arrangements under the existing AEP and CSW
intrasystem agreements. It is designed to function as an umbrella agreement in
addition to the existing AEP Interconnection Agreement and the existing CSW
Operating Agreement, which will continue to control the distribution of costs
and benefits within each zone.
Under the System Integration Agreement, the east zone and the west zone
are each required to have enough generating capacity to meet their respective
firm load obligations. When one zone has surplus capacity available for sale and
the other zone has insufficient capacity, the surplus zone will make its surplus
capacity available. If neither zone has surplus capacity after meeting its firm
load obligations or if third party capacity is cheaper than that from the
surplus zone, then capacity will be purchased from third parties for the zone(s)
with insufficient capacity. Economic energy will be transferred from one zone to
another in order to minimize the total production cost of the Combined System.
The AEP and CSW areas will be centrally dispatched on a least-cost basis for the
Combined System. The designated agent, AEPSC, will perform these functions.
The System Integration Agreement contains four service schedules
governing: (1) the allocation of capacity costs and purchased power costs; (2)
pricing for system capacity exchanges; (3) pricing for system energy exchanges;
and (4) the allocation of "Trading and Marketing Realizations," which are the
net gains or losses from the Combined System's off-system transactions. The
System Integration Agreement applies to the generating resources and loads
served by the Combined System, but not to the transmission facilities owned or
operated by the Combined System.
32
<PAGE> 35
The System Transmission Integration Agreement contains two service
schedules governing: (1) the allocation of transmission costs and revenues
between the two areas; and (2) the allocation of system control and dispatch
costs associated with the integration of the two areas, the cost of the
transmission capacity reserved on other systems to link the two areas, and any
revenues from the resale of those capacity rights. AEPSC will coordinate the
planning, operation and maintenance of transmission facilities and capacity of
the Combined System. The System Transmission Integration Agreement will also
provide a mechanism for coordinating the existing AEP Transmission Agreement and
CSW Coordination Agreement. Specifically, the AEP and CSW transmission
agreements will remain in place in their current form to avoid cost shifts among
the operating companies and between the zones and to reflect the existing
ownership of transmission. The existing agreements will continue to govern the
allocation of costs and benefits associated with transmission assets, as between
the operating companies of the east zone, on the one hand, and those of the west
zone, on the other.
The Combined System will be subject to regulation by the FERC with respect
to transmission and the Combined System intends to operate in full compliance
with all applicable FERC rules and orders regarding, among other things,
tariffs, billing and revenue allocation, immediately upon the consummation of
the Merger. In this regard, on November 23, 1999, the Administrative Law Judge
at FERC issued an Initial Decision that found the rates, terms, and conditions
of service contained in the above agreements, as modified by the Stipulation
between Applicants and FERC Staff, are just, reasonable and not otherwise
unlawful. The Administrative Law Judge's Initial Decision is filed as Exhibit
D-1.7 and incorporated by reference.
The existing AEP Interconnection Agreement and existing CSW Operating
Agreement will provide for the joint dispatch of the respective zones. As noted
above, these agreements will remain in place in their current form to avoid cost
shifts among the operating companies and zones and to reflect the existing
ownership of generation assets.
With respect to AEP, the operating utilities of the AEP system have
historically planned, constructed, and operated their generation and
transmission facilities on a combined system "pool" basis. Pool costs are shared
pursuant to the AEP Interconnection Agreement, which has been amended from time
to time by the AEP operating companies. The AEP Interconnection Agreement
expressly provides, among other things, for the sharing of the costs of
generation facilities used in the integrated operation of the AEP system.
The AEP Interconnection Agreement does not, however, contain any express
provision for the sharing of the costs of transmission facilities used in the
integrated operation of the AEP system. That is the function of the Transmission
Equalization Agreement ("TEA"). The TEA provides for the sharing of the costs of
the system's Extra High Voltage transmission facilities among the AEP operating
companies.
With respect to CSW, the CSW Operating Agreement provides for the
coordination of construction and operation of jointly-owned facilities; unit
sales to assist companies to meet
33
<PAGE> 36
capacity reserve levels; emergency energy; economy energy; off-system sales and
purchases; and central load dispatching. Schedule A of the CSW Operating
Agreement provides for planning and construction of joint units to be owned by
the CSW operating companies in percentages allocated by the CEO "to achieve a
Prorated Reserve Level" for all participating companies. Schedule B lists the
ownership by individual CSW operating companies of particular generating units.
Basically, the agreement preserves the planning and investment in generation by
the four operating companies when they were independently operated and, at the
same time, integrates and coordinates the planning and investment of the CSW
integrated system.
b. Central Dispatch Planning and Central Economic Dispatch.
AEPSC will coordinate the planning, operation and maintenance of
generating capacity resources and jointly dispatch electricity throughout the
Combined System. The coordination of generation is accomplished through two
computer software programs: Central Dispatch Planning and Central Economic
Dispatch. Central Dispatch Planning forecasts (usually on a day-ahead basis,
although sometimes several days ahead) the generation needs of the Combined
System and determines the least-cost allocation of generation resources
available within the Combined System necessary to meet the forecasted
obligations. The joint dispatch is based on anticipated fuel costs, load levels,
wholesale power market conditions, planned unit maintenance (which units are out
of service or operating below normal operating limits), and prevailing
transmission capabilities (including capacity reserved by third parties). During
the morning of normal working days (Monday through Friday), Central Dispatch
Planning will have scheduled hourly the following day's generation for every
unit in the Combined System (with the exception of Friday, when generation is
scheduled for Saturday, Sunday and Monday).
Central Economic Dispatch computes at regular intervals (currently every
four seconds) the most economic generation dispatch base points resulting from
current operating obligations. While Central Dispatch Planning is based on
predictive conditions, Central Economic Dispatch is a real-time function that
continuously evaluates current operating conditions, and, based on least-cost
allocations and existing transmission constraints, issues new dispatch
instructions to each generating unit within the Combined System.
Central Dispatch Planning and Central Economic Dispatch will be ready to
serve the Combined System prior to the effectiveness of the Merger, and,
accordingly, each will be available to the Combined System immediately upon
consummation of the Merger. Each will utilize the existing electronic
communication infrastructures currently in place in each of the AEP System and
the CSW System. The existing electronic communication infrastructures will feed
data to, and receive instructions from, Central Dispatch Planning and Central
Economic Dispatch via a high speed data link. In this way, the Combined Company
will jointly dispatch the Combined System upon consummation of the Merger.
Post-Merger, there will be two data relay centers; one in Dallas and the
other in Columbus. Central Economic Dispatch will run on a computer system
(EMS). The EMS will control all generating units in the Combined System to the
desired economic base points adjusted
34
<PAGE> 37
for frequency control requirements of the respective control areas. These
centers will be staffed with personnel 24 hours a day, 365 days a year. Merger
transition teams are currently designing the organizational structure and job
responsibilities.
c. 250 MW Contract Path
The Combined Company will transmit power from east to west over the 250 MW
Contract Path. The 250 MW Contract Path's term is from June 1, 1999 to May 31,
2003, which may be renewed through the Ameren OATT. AEPSC will coordinate the
planning of the transmission capacity interconnecting the Combined System.
In order to increase its firm transmission service rights on the MOKANOK
Line, CSW's subsidiary, PSO, entered into an agreement with WR to provide firm
point-to-point transmission service for the transfer of 38 MW of power from
Ameren. The point of receipt and delivery for the 38 MW of power will be the
point of interface with Ameren and WR's and PSO's undivided interest in the
MOKANOK Line. PSO and another CSW subsidiary, SWEPCO, will transmit the 38 MW of
power from the interface between PSO's and WR's undivided interest in the
MOKANOK Line to PSO's 345 Kv bus at its Northeastern Generating Station. PSO
will transmit the remaining 212 MW of power over its undivided interest in the
MOKANOK Line from the interconnection with Ameren on the MOKANOK Line to PSO's
345 Kv bus at its Northeastern Generating Station. In order to enable the 250 MW
Contract Path to accommodate a 250 MW firm transfer, CSW and Ameren agreed that
Ameren would upgrade Ameren's Albion Substation in order to increase available
transfer capability into Ameren from the east during the summer peak period. The
upgrade, effected by installing a 138 Kv reactor, was completed on August 1,
1998.
Applicants have committed to avoid any possible anticompetitive concerns
attributable to the Merger by agreeing to limit their reservation of firm
transmission service from east to west to 250 MW unless the FERC authorizes them
to go above this limit. See Dr. William Hieronymus' testimony filed as an
exhibit to Exhibit D-1.2 and incorporated herein by reference.
d. Additional Power Transfers
The Applicants expect that from time to time there will be opportunity to
transfer energy economically in the Combined Company from west to east. In these
circumstances, Applicants will make use of their rights to nominate secondary
points of receipt and delivery under their transmission service agreements with
WR and Ameren. PSO has the right to transfer approximately 113 MW of energy on a
non-firm basis across the MOKANOK Line. Ameren's OASIS postings indicate that
there are more than 1000 MW of transfer capability across the Ameren system from
the MOKANOK Line to the east.
In addition to the use of the 250 MW Contract Path, quantities in excess
of the 250 MW can be moved within the Combined System in any given hour by using
non-firm transmission rights. Such additional transfers would be made when
circumstances indicate that they would be
35
<PAGE> 38
economical for post-Merger system operations after taking into consideration
opportunity costs. See generally, Testimony of J. Craig Baker, filed with
Exhibit D-1.1 and incorporated herein by reference.
As part of the FERC Stipulation, Applicants agreed to waive the Combined
Company's priority with respect to its use of the HVDC ties for unplanned (i.e.,
non-firm) transactions in ERCOT and non-firm transactions in the SPP. See
Exhibit D-1.2, Supplemental Testimony of Stephen Jones at 15-17. This waiver of
priority would not apply to planned (i.e., firm) transactions that are submitted
to ERCOT or other transfers of firm capacity between the Applicants' SPP and
ERCOT control areas, including the use of the North HVDC tie to export the
output of the Oklaunion generation station to PSO and to Oklahoma Municipal
Power Authority, both located in the SPP.(3) Thus, the Applicants would continue
to use the HVDC ties to integrate CSW's Texas assets with its non-Texas assets
in the same manner that previously has been approved by the Commission.
e. Future Participation in an RTO
On June 3, 1999, AEP and four other utilities filed the Alliance RTO
Application, which was conditionally approved by FERC on December 20, 1999, a
copy of which is filed as Exhibit D-1.8 and incorporated by reference. CSW is
participating in the ERCOT independent regional transmission plan for the
portion of its system that is within ERCOT and is participating in discussions
with other interested parties about the formation of an RTO that would include
its utility systems located in the SPP.(4) Participation in these RTOs will
enhance system reliability after the Merger as described below.
The Applicants' goal ultimately is to further enhance the reliability of
the Combined System through participation in a regional RTO. RTOs provide
strengthened assurances to the marketplace that transmission service will be
available to all eligible customers on a non-discriminatory basis. In addition,
RTOs can enhance regional reliability and, if properly structured and
configured, improve economic efficiencies and provide access to a broad range of
buyers and sellers across a large geographic region.
- ----------
(3) CSW's firm transmission capacity has always been adequate to integrate
its operations, and there has never been a need to assert a priority for
unplanned transactions over the HVDC ties. As a result, Applicants do not expect
their waiver of priority for non-firm use of the HVDC ties to affect the
integration of their system in any manner.
(4) In the order of the Oklahoma Commission approving the Merger, AEP is
required to file with the FERC, not later than six months before retail
competition commences in the State, or December 31, 2001, an application to,
transfer the operational control of bulk transmission facilities owned,
controlled and/or operated by AEP that are currently located in the SPP to a
FERC-approved RTO that is directly interconnected with the AEP system. See
Exhibit 4.2, at 17.
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<PAGE> 39
Until such time as the Combined Company transfers certain control area
functions related principally to reliability and access to one or more RTOs, all
facets of the centralized coordination of the transmission facilities of the
Combined Company's system will be accomplished through the System Transmission
Integration Agreement. At such time as AEP transfers to the RTO certain control
area operations relating principally to system reliability and access, the
remaining functions of the Combined Company's transmission system will continue
to be coordinated through the System Integration Transmission Agreement.
Participation in RTOs can enhance the reliability of the Combined
Company's system in several ways. In the Notice of Proposed Rulemaking regarding
RTOs,(5) FERC found that an RTO would improve efficiencies in the management of
the transmission grid (RTO NOPR at page 33,716); would improve grid reliability
(Id.); would improve market performance (RTO NOPR at page 33,717); and would
facilitate lighter governmental regulation (Id.). It is FERC's view that all
utilities should participate in a FERC-approved RTO.
C. DESCRIPTION OF MERGER AND STATEMENT AS TO CONSIDERATION
1. Background of the Merger
AEP and CSW are seeking to merge to further their mutual strategy of
adapting to an era of historic changes in the electric utility industry. The
electric utility industry is in the process of a transformation to greater
levels of competition in the wholesale and retail energy markets. Technological
advances, consumer pressures and federal and state legislative and regulatory
initiatives are forces affecting this transformation. Efficient, low cost
suppliers of energy with a diverse customer base will be best prepared to
compete successfully in the resulting electric energy marketplace.
Historically, competition in the wholesale and retail electric energy
markets was limited. In the wholesale market, this limitation was due to various
barriers to entry, including the difficulties in obtaining transmission service
over utility systems located between potential buyers and sellers and the
possibility of regulation under the 1935 Act. Pursuant to the Energy Act,
however, Congress authorized the FERC to exempt certain wholesale power sellers
from regulation under the 1935 Act. In 1996, the FERC issued Orders 888 and 889
requiring utilities to provide non-discriminatory, open-access transmission
service upon request. These regulatory developments have resulted in an active,
competitive wholesale market for electricity. Although the retail market for
electricity currently is less developed than the wholesale market, most states
in which the electric utility operating subsidiaries of AEP and CSW provide
retail service have adopted or are actively considering legislative or
regulatory action permitting retail customers to select their electricity
supplier and obligating utilities to provide transmission and distribution
service to competitors. Because of these ongoing legislative and regulatory
activities, the
- ----------
(5) Notice of Proposed Rulemaking, Regional Transmission Organizations,
Docket No. RM99-2-000, 87 FERC ss. 61,173 (May 13, 1999) ("RTO NOPR").
37
<PAGE> 40
managements of AEP and CSW have concluded that there will soon be increased
competition in the retail sector of the business.
Electric utility companies must adapt quickly to this evolving competitive
environment if they are to succeed in it. Many companies are pursuing
consolidation to diversify business risks and create new opportunities for
earnings growth. Assets, such as a utility's transmission network and low cost
generation, will be key factors in structuring the successful electric utility
of the future. Customers in a competitive market will choose electric suppliers
that are efficient and responsive.
For the past several years, AEP and CSW separately have been focusing
their strategic planning activities on preparing for this fundamental evolution.
AEP and CSW have now determined that a merger of the two companies is the best
way to achieve their compatible long-term goals.
2. Merger Agreement
The following is not a complete description of the Merger Agreement and is
qualified in its entirety by reference to the Merger Agreement, which is
attached and incorporated by reference as Exhibit B-l.
The Merger Agreement provides for a business combination of AEP and CSW in
which Merger Sub will be merged with and into CSW. CSW will be the surviving
corporation and will become a wholly-owned subsidiary of AEP. Upon the
consummation of the Merger, each issued and outstanding share of CSW Common
Stock (other than the Excluded Shares) will be exchangeable for 0.60 shares of
AEP Common Stock. Based on the price of AEP Common Stock on December 19, 1997,
the transaction would be valued at $6.6 billion. Each issued and outstanding
share of AEP Common Stock will be unchanged as a result of the Merger.
The former holders of CSW Common Stock will own approximately 40% of the
issued and outstanding AEP Common Stock after the Merger. The Merger is subject
to customary closing conditions, including the receipt of all necessary
governmental approvals, including the approval of the Commission. The Merger is
designed to qualify as a tax-free reorganization under Section 368(a) of the
Internal Revenue Code of 1986, as amended, and will be treated as a
"pooling-of-interests" for accounting purposes.
On December 31, 1999, Applicants executed Amendment No. 1 to the Merger
Agreement which provides that either AEP or CSW may terminate the Merger
Agreement after June 30, 2000 if the Merger has not been consummated by that
date.
3. Reasons for the Merger
The Merger offers significant opportunities to create additional value for
shareholders, customers and employees of the Combined Company. The benefits of
the Merger include the following:
38
<PAGE> 41
- - COST SAVINGS - The Combined Company will be more efficient than either company
standing alone. Merging will allow the companies to create efficiencies in
operations and business processes, eliminate duplicative functions, enhance
their purchasing power, and combine two workforces. The Combined Company should
realize Merger-related non-fuel savings of nearly $2 billion over the first ten
years following the Merger, net of transaction and transition costs, and net
fuel-related savings of approximately $98 million over the same period.
- - COMPETITIVE PRICES AND SERVICES - The Combined Company will use the
efficiencies arising from the Merger to compete effectively in the increasingly
competitive marketplace. Sales to industrial, large commercial and wholesale
customers are at greatest near-term exposure to increased competition; these
customers will choose among potential suppliers those best able to meet their
demands for reliable, low-cost power. The Merger will enable the Combined
Company to serve customers more efficiently and effectively.
- - FINANCIAL STRENGTH - By combining the market capitalization of the individual
companies, the Merger will result in a Combined Company with a stronger
financial base, improved position in the credit markets, and greater market
diversity.
- - GREATER DIVERSIFICATION - The combination of AEP and CSW will diversify the
Combined System's service territory, reducing exposure to adverse changes in any
sector's economic and competitive conditions. The Combined Company will expand
relationships with existing customers and develop relationships with new
customers in its service area, using its combined distribution channels to
market a portfolio of innovative energy-related products at competitive prices.
The Merger will result in a Combined Company with more diversity in fuel and
generation, which will reduce dependence upon any one sector of the energy
industry and exposure to fluctuations in certain commodity prices.
- - INCREASED SCALE - As competition intensifies within the industry, scale will
be one contributor to overall business success. Scale is important in many
areas, including utility operations, product development, advertising and
corporate services. Profitability of the Combined Company will be enhanced by
the expanded customer base and the synergies in all of these areas.
4. AEP Management Following the Merger
The Board of Directors of the Combined Company immediately following the
Merger will consist of 15 members and will be reconstituted to include all
then-current board members of AEP, Mr. E. R. Brooks (the current Chairman of
CSW) and four additional outside directors of CSW to be nominated by AEP. Dr. E.
L. Draper, Jr., will be the Chairman and Chief Executive Officer of the Combined
Company. The Merger Agreement also provides that, from and after its
effectiveness, the Combined Company's corporate headquarters will be located in
Columbus, Ohio.
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<PAGE> 42
ITEM 2. FEES, COMMISSIONS AND EXPENSES
<TABLE>
<CAPTION>
Thousands
<S> <C>
Filing fee for Form S-4 $1,759
Accountants' fees *
Legal fees and expenses *
Shareholder communication and
proxy solicitation expenses *
NYSE listing fee *
Exchanging, printing and
engraving stock certificates
expenses *
Investment bankers' fees and
expenses *
Consulting fees *
Miscellaneous *
Total
</TABLE>
(*) To be filed by amendment.
The total fees, commissions and expenses expected to be incurred for
transaction and regulatory processing costs are estimated to be approximately
$53 million.
ITEM 3. APPLICABLE STATUTORY PROVISIONS
The following sections of the 1935 Act and the Commission's rules relate
to the Merger: SECTION OR RULE TRANSACTIONS TO WHICH SECTION OR RULE RELATES
UNDER THE 1935 ACT
6, 7, 12, 32 and 33 Issuance of AEP Common Stock; amendment to AEP's financing
and rules existing authority to allow the Combined Company to engage in
thereunder financing arrangements authorized for CSW; all financing
transactions that do not involve a financing for the
purposes of acquiring an EWG or FUCO.
9, 10, 11 and Acquisition by AEP of CSW Common Stock and Merger common
rules thereunder stock; indirect acquisition by AEP of securities of, and
interests in the business of, CSW's subsidiary companies,
including the non-utility subsidiaries; authority for the
Combined Company to conduct the business activities of
CSW.
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<PAGE> 43
13 and rules Merger of CSWS into AEPSC with AEPSC as the surviving
thereunder service company; approval of service agreement and method
for allocating costs under the service agreement.
Section 9(a)(1) of the 1935 Act provides that unless the acquisition has
been approved by the Commission under Section 10, it shall be unlawful for any
registered holding company or any subsidiary company thereof "to acquire,
directly or indirectly, any securities or utility assets or any other interest
in any business." Section 9(a)(1) is applicable to the proposed Merger because
the transaction involves the acquisition by AEP of CSW Common Stock and the
Merger Sub common stock, and the indirect acquisition of the securities of and
interests in the businesses of CSW's subsidiary companies.
As set forth more fully below, the Merger fully complies with Section 10
of the 1935 Act:
- - The Merger will not create detrimental interlocking relations or a
detrimental concentration of control;
- - The consideration and fees to be paid in the Merger are fair and
reasonable;
- - The Merger will not result in an unduly complicated capital structure for
the Combined Company;
- - The Merger is in the public interest and the interests of investors and
consumers;
- - The Combined System will be a single integrated public utility system;
- - The Merger equitably distributes voting power among the investors in the
Combined Company and does not unduly complicate the structure of the
holding company system;
- - The Merger tends toward the economical and efficient development of an
integrated electric utility system; and
- - The Merger will comply with all applicable state laws.
Under Sections 9 and 10, Congress gave the Commission the responsibility
for "supervision over the future development of utility-holding company
systems." The Southern Co., HCAR No. 25639 (Sept. 22, 1992) (citations omitted)
[hereinafter "Southern"]. Section 1(c) of the 1935 Act directs the Commission to
interpret all provisions of the 1935 Act to meet the problems and eliminate the
evils set forth in the 1935 Act in order to protect the interests of investors,
consumers and the general public. Accordingly, the Commission's mandate under
these sections is "to prevent acquisitions which would be 'attended by the evils
which have featured the past growth of holding companies.'" American Elec. Power
Co., HCAR No. 20633
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<PAGE> 44
(July 21, 1978) (quoting H.R. Rep. No. 1318, 74th Cong., 1st Sess. 16 (1935))
[hereinafter "AEP"]. These evils include the "growth and extension of holding
companies [that] bears no relation to economy of management and operation or the
integration and coordination of related operating properties." Section 1(b)(4)
of the 1935 Act.
As the Supreme Court has recognized, the 1935 Act is an "intricate
statutory scheme" which must be given "practical sense and application." SEC v.
New England Elec. Sys., 384 U.S. 176 (1966), rev'g and remanding 346 F.2d 399
(1st Cir. 1966), rev'g, New England Elec. Sys., 41 SEC 888 (1964), on remand,
376 F.2d 107 (1st Cir. 1967), rev'd, 390 U.S. 207 (1968). In administering the
1935 Act, the Commission must "weigh policies [of the 1935 Act] against each
other and against the needs of particular situations." Union Elec. Co., HCAR No.
18368 (Apr. 10, 1974), aff'd sub nom. City of Cape Girardeau v. SEC, 521 F.2d
324 (D.C. Cir. 1975) (citation omitted) [hereinafter "Union Electric"]. The
Commission is not disposed to "apply concepts such as res judicata or stare
decisis to the essentially regulatory and policy determinations called for in a
Holding Company Act case . . . ." AEP, supra. In considering whether to approve
an acquisition, the Commission "must make that determination in light of
contemporary circumstances . . . and [its] present view of the Act's
requirements." Southern, supra (citations omitted).
The Merger complies with the 1935 Act. In light of contemporary
circumstances, the Merger does not result in any of the concerns the 1935 Act
was intended to address. In this regard, the Merger will benefit the public
interest and the interests of investors and consumers. Adequate safeguards,
through both state and federal regulation, ensure that the public interest and
the interests of investors and consumers continue to be protected. Approval of
the Merger is consistent with previous merger transactions approved by the
Commission under the 1935 Act. Each subsection of Section 10 of the 1935 Act is
addressed below, as well as the public policies underlying the 1935 Act, as they
relate to the Merger.
A. SECTION 10(b)
Section 10(b) of the 1935 Act provides that, if the requirements of
Section 10(f) are satisfied, the Commission shall approve an acquisition under
Section 9(a) unless:
(1) such acquisition will tend towards interlocking relations or the
concentration of control of public utility companies, of a kind or
to an extent detrimental to the public interest or the interest of
investors or consumers;
(2) in case of the acquisition of securities or utility assets, the
consideration, including all fees, commissions, and other
remuneration, to whosoever paid, to be given, directly or
indirectly, in connection with such acquisition is not reasonable or
does not bear a fair relation to the sums invested in or the earning
capacity of the utility assets to be acquired or the utility assets
underlying the securities to be acquired; or
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<PAGE> 45
(3) such acquisition will unduly complicate the capital structure of the
holding company system of the applicant or will be detrimental to
the public interest or the interest of investors or consumers or the
proper functioning of such holding company system.
1. Section 10(b)(1)
Section 10(b)(1) of the 1935 Act requires the Commission to approve a
proposed acquisition unless it finds that the proposed acquisition will "tend
towards interlocking relations or the concentration of control of public utility
companies of a kind or to an extent detrimental to the public interest or the
interest of investors or consumers." As this Section clearly indicates, a merger
does not run afoul of Section 10(b)(1) merely because it causes interlocking
relations or a concentration of control. Rather, a merger will fail the
balancing test set forth in this Section only when the detrimental effects, if
any, from any such interlocking relations or concentration of control caused by
the merger outweigh the benefits of the merger.
a. Interlocking Relations
By its nature, any merger results in interlocking relations between
previously unrelated companies. As the Commission has previously noted: "[W]ith
any addition of a new subsidiary to a holding company system, the Acquisition
will result in certain interlocking relationships between [the two merging
entities]." Northeast Utilities, HCAR No. 25221 (Dec. 21, 1990), modified on
other grounds, HCAR No. 25273 (Mar. 15, 1991), aff'd sub nom. City of Holyoke
Gas & Elec. Dep't v. SEC, 972 F.2d 358 (D.C. Cir. 1992) (citation omitted).
[hereinafter "Northeast I"]. Such "interlocking relationships are necessary to
integrate [the two merging entities.]" Id.
The Merger Agreement provides for the Board of Directors of the Combined
Company to be composed of members drawn from the Boards of Directors of both AEP
and CSW. Specifically, the Board of Directors of the Combined Company will
consist of 15 members including the current Chairman of the Board of CSW and
four other outside directors of CSW to be nominated by AEP. This combined Board
of Directors for the Combined Company is necessary to assure the effective
integration and operation of the Combined Company. As discussed below in Item
3.B.2, the Merger will result in benefits to the public interest and the
interests of investors and consumers. As such, the interlocking relations do not
harm, but rather, promote the interests which Section 10(b)(1) is meant to
protect.
b. Concentration of Control
Under the Section 10(b)(1) concentration of control test, the Commission
"considers various factors, including the size of the resulting system and the
competitive effects of the acquisition." Entergy Corp., HCAR No. 25952 (Dec. 17,
1993), request for reconsideration denied, HCAR No. 26037 (Apr. 28, 1994),
remanded sub nom. Cajun Elec. Power Coop. Inc. v.
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<PAGE> 46
SEC, 1994 WL 704047 (D.C. Cir. Nov. 16, 1994) on remand, Entergy Corp., HCAR No.
26410 (Nov. 17, 1995) (citations omitted) [hereinafter "Entergy"]. These factors
are discussed below.
(i) Size
As the terms of Section 10(b)(1) dictate and as the Commission has
recognized, Section 10(b)(1) does not "impose any precise limits on holding
company growth." AEP, supra. Congress condemned the "growth and extension of
holding companies [that] bears no relation to economy of management and
operation or the integration and coordination of related operating properties."
Section 1(b)(4) of the 1935 Act. The Commission has rejected a mechanical size
analysis under Section 10(b)(1) in favor of assessing the size of the resulting
system as it relates to the efficiencies and economies that can be achieved
through the integration and coordination of the new system's utility operations.
Entergy, supra (rejecting "conclusory assertions that the combined systems would
be too large to satisfy [Section 10(b)(1)]" and finding that merger created a
"large system, but not one that exceeds the economies of scale of current
electrical generation and transmission technology.") Section 10(b)(1) allows the
Commission to "exercise its best judgment as to the maximum size of a holding
company in a particular area, considering the state of the art and the area or
region affected." AEP, supra. Other recent transactions confirm that the
Commission evaluates the resulting size of a merging entity in terms of the
overall effects of the merger. For example, in Centerior Energy Corp., HCAR No.
24073 (Apr. 29, 1986) [hereinafter "Centerior"], the Commission stated that a
"determination of whether to prohibit enlargement of a system by acquisition is
to be made on the basis of all the circumstances, not on the basis of size
alone." See also, Northeast I, supra (applying standard articulated in
Centerior, supra, to find acquisition satisfied Section 10(b)(1)). Likewise, the
Division recommended in its 1995 Report that the Commission approach its
analysis of merger and acquisition transactions in a flexible manner with an
emphasis on whether the transaction creates an entity subject to effective
regulation and results in economies and efficiencies as opposed to focusing on
rigid, mechanical tests. 1995 Report at 66-70.
In short, size alone is not suspect. Rather, as the 1935 Act provides, the
concern is an enlargement of the system that is "of a kind or to an extent
detrimental to the public interest or the interest of investors or consumers"
caused "by the growth and extension of holding companies [that] bears no
relation to economy of management and operation or the integration and
coordination of related operating properties." Sections 10(b)(1) and 1(b)(4) of
the 1935 Act.
For purposes of comparison, the table below provides certain operating
information derived from publicly available documents for a selected group of
public utility systems. Each public utility system, with the exception of CSW,
consistently ranks at or near the top of virtually all categories presented.
These data identify and rank the largest public utility systems in the United
States. Among the utilities presented, AEP currently ranges from the third (two
categories) to the sixth largest (two categories) public utility system in the
United States depending on the criterion of measurement. Giving effect to the
Merger as of December 31, 1998, on a pro forma basis, the Combined Company would
have ranged from the largest (two
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<PAGE> 47
categories) to the sixth largest public utility system in the United States,
again depending on the criterion of measurement.
(As of December 31, 1998)
<TABLE>
<CAPTION>
Electric U.S.
Operating Total Electric U.S. Sales Market Generation
System Revenues Assets Customers in KwH Capitalization Capacity
($Millions) ($Millions) (Millions) (Billions) ($Millions)(a) (MWh)
<S> <C> <C> <C> <C> <C> <C>
Duke 17,610 26,806 2.0 82.0 23,255 17,300
Southern 11,403 36,192 3.8 164.3 20,280 31,159
Entergy 11,495 22,848 2.5 113.2 7,669 21,727
PG&E 19,942 33,234 4.6 77.9 12,052 10,938
AEP 6,346 19,483 3.0 130.4 9,027 23,759
CSW 3,488 13,744 1.7 67.0 5,833 14,205
Combined Company 9,834 33,227 4.7 197.4 14,860 37,964
Proposed
PECO/Unicom 11,972 38,748 4.9 172.5 16,211 30,039
Combined (b)
</TABLE>
(a) Based on number of shares outstanding multiplied by the closing stock
price at December 31, 1998.
(b) Recently announced merger which would form a new registered holding
company.
Sources: POWERdat database (Resource Data International, Inc.); Form 10-K and
Form 10-Q Filings; 10 Year Statistical Reports; and Annual Reports.
The table above does not reflect Applicants' agreement to divest 1604 MW
of generation capacity in ERCOT and, as part of Applicants' FERC mitigation
plan, to divest 300 MW of generation capacity in SPP. Even without taking into
account these divestitures of generation capacity, the data show that, as of
December 31, 1998, Duke, Southern, Entergy, PECO/UNICOM and PG&E would have been
larger than the Combined Company in terms of operating revenues; Southern,
PECO/UNICOM and PG&E would have been larger than the Combined Company in terms
of total assets; and Duke, PECO/UNICOM and Southern would have been larger than
the Combined Company in total market capitalization. In addition, the Combined
Company would be sixth largest in terms of operating revenues, fourth largest in
terms of total assets and market capitalization; and second largest in terms of
total U.S. electric customers. Thus, the data show that the Combined Company
will be comparable in size to other large public utility systems.
Moreover, the size of the Combined Company would not cause a concentration
of control within the relevant region under existing Commission precedent. In
Northeast I, supra, the Commission approved a merger in which the combined
system would have 29% of the peak load capacity, 36.7% of the total assets and
less than one-third of the operating revenues, number of
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<PAGE> 48
electric customers and KwH sales when compared to the regional electric utility
industry. The Commission further noted that these figures were well below the
40% level that would have resulted in the merger the Commission blocked for
other reasons in New England Elec. Sys., HCAR No. 18801 (Feb. 4, 1975) ("NEES
Decision"). Id. at n. 53 (when measured by operating revenues, number of
electric customers, KwH sales, KwH capacity and electric power generated in KwH,
the combined companies in the NEES Decision would have represented "about 40% of
New England").
Applicants propose that the relevant region for evaluating the size of the
Combined Company should include the Combined Company and those electric
utilities directly interconnected with AEP and/or CSW ("Interconnected
Utilities").(6) See Entergy, supra (Commission adopted the applicants'
definition of the relevant region for purposes of measuring size to include
applicants and those electric utilities directly interconnected with either or
both). As the table below indicates, the size of the Combined Company compared
to the size of the Interconnected Utilities and the Combined Company varies from
11 percent to 15 percent depending on the criterion of measurement. Further, if
data from the Applicants' historical wholesale customers are added to these
Interconnected Utilities data (the sum equaling the relevant destination markets
for purposes of measuring market power as described in the testimony of Dr.
Hieronymus before the FERC, attached as exhibits to Exhibits D-1.1 and D-1.2 and
summarized in Item 3.A.1.b.(ii)., 'Antitrust Considerations', infra), then the
size of the Combined Company as a percentage of the destination markets
identified by Dr. Hieronymus is even smaller.
<TABLE>
<CAPTION>
Number of
Net Electric Utility Electric Electric Total Net
Plant Revenues Customers 12 Total Sales Generation
($Thousands) ($Thousands) Mo. Avg. (MwH) (MwH)
<S> <C> <C> <C> <C> <C>
Combined Company 18,589,138 9,833,518 4,733,734 197,345,794 192,992,107
Region (b) 172,487,197 84,261,562 33,525,779 (a) 1,558,199,149 1,332,170,731
% of total 11% 12% 14% 13% 15%
</TABLE>
- ----------
(6) Interconnected Utilities include: Brownsville Public Utilities Board,
Carolina Power & Light Co., Central Illinois Light Co., Central Illinois Public
Service Co., Central Louisiana Electric Co. Inc., Cincinnati Gas & Electric,
Commonwealth Edison Co., Consumers Energy Co., Dayton Power & Light Co., Duke
Power Co., Entergy, Duquesne Light Co., Empire District Electric Co., Grand
River Dam Authority, Houston Light & Power Co., Illinois Power Co., Indianapolis
Power & Light Co., Kentucky Utilities Co., Louisville Gas and Electric Co.,
Lower Colorado River Authority, Monongahela Power Co., Northern Indiana Public
Service Co., Ohio Edison Co., Ohio Valley Electric Corp., Oklahoma Gas and
Electric Co., PSI Energy Inc., San Antonio Public Service Board, Southwestern
Public Service Co., Texas Utilities Electric Co., The Cleveland Electric
Illuminating Co., The Toledo Edison Co., Union Electric Company, Virginia
Electric & Power Co., West Penn Power Co., Western Resources Inc., Southwestern
Power Administration, and Tennessee Valley Authority. Certain other
municipalities and co-ops interconnect with AEP and/or CSW; however, due to the
lack of publicly available information regarding them, their data are not
included herein.
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<PAGE> 49
represented
by Combined
Company
(a) The customers of the Tennessee Valley Authority and Southwestern Power
Administration are not included in this figure, since these federal power
marketing agencies typically do not have retail customers. The Tennessee
Valley Authority has 160 distributor customers and Southwestern Power
Administration has 92 customers comprised of municipalities, federal
agencies and cooperatives.
(b) The Region includes the Interconnected Utilities and the Combined Company
Sources: POWERdat database (Resource Data International, Inc.); Form 10-K and
Form 10-Q Filings; 10 Year Statistical Reports; and Annual Reports.
Specifically, as the table above indicates, at December 31, 1998, the
Combined Company would have represented no more than the following percentages
of the utility industry in the region, in terms of the above criteria: net
electric plant (11%); electric revenues (12%); number of electric customers
(14%); MwH sales (13%); and total net generation (15%). As such, the size of the
Combined Company relative to the relevant region is significantly below the 40%
threshold previously cited by the Commission. In fact, two of these percentages
would be even less if the data reflected Applicants' agreement to divest 1604 MW
of generation capacity in ERCOT and, as part of Applicants' FERC mitigation
plan, to divest 300 MW of generation capacity in SPP.
By definition, any merger creates an entity larger than each of the
constituent parts. However, the size of the Combined Company will not exceed the
economies of scale of current electrical generation and transmission technology
and, therefore, does not exceed the maximum size of a holding company
considering the "state of the art." Technological changes have resulted in power
being transmitted over greater distances with less line loss, single integrated
computer networks that more efficiently dispatch generation sources and control
constricted transmission areas, and generation technologies that have reduced
the cost of power and increased the flexibility of power plant siting. Moreover,
changes in the regulatory and legal framework have resulted in an increase in
non-utility generators, non-utility marketers and brokers. Together, these
technological, legal and regulatory changes have resulted in increased
competition within the industry.(7) Given these present realities, the size of
the Combined System will not result in a "concentration of control" of a kind or
to an extent detrimental to the interests of the public, investors or consumers.
As described in detail below in Item 3.B.2, the Merger is expected to yield
significant economies and efficiencies. Net non-production savings of nearly $2
billion and net fuel-related savings of approximately $98 million are projected
over the first ten years. These savings will be realized by investors and
customers.
- ----------
(7) The "state of the art" is discussed in depth in Item 3.B.1.a below.
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<PAGE> 50
(ii) Antitrust Considerations
The Commission's analysis under Section 10(b)(1) also includes a
consideration of federal antitrust policies.(8) If the Commission determines
that an acquisition will tend towards the concentration of control of public
utility companies, it balances this effect against the benefits from the
acquisition to determine whether the acquisition passes the Section 10(b)(1)
balancing test. The Commission "has approved acquisitions that decrease
competition when it concludes that the acquisitions would result in benefits
such as possible economies of scale, elimination of the duplication of
facilities and activities, sharing of production capacity and reserves, and
generally more efficient operations." Northeast I, supra. The Commission has
also explained that the "antitrust ramifications of an acquisition must be
considered in light of the fact that public utilities are regulated monopolies
and that federal and state administrative agencies regulate the rates charged
consumers." Id.
When assessing the possible anticompetitive effects of a proposed
acquisition, the Commission is -
primarily concerned with the structure of public utility holding company
systems. The Commission, however, has also considered anticompetitive
issues involving the allocation of excess generating capacity,
transmission access and the flow of electricity over transmission lines of
a holding company system.
Entergy, supra (citations omitted).
The FERC has jurisdiction over the Merger under Section 203 of the FPA. As
explained more fully herein, the FERC Administrative Law Judge has recommended
that the FERC find the Merger to be consistent with the public interest based,
in part, upon the absence of adverse competitive consequences of the proposed
transaction. The Commission has relied upon the expertise of other federal
regulators in determining the anticompetitive effects of proposed merger
transactions, and the D.C. Circuit has upheld the Commission's ability to
watchfully defer to other regulators:
[W]hen the SEC and another regulatory agency both have jurisdiction over a
particular transaction, the SEC may 'watchfully defer[]' to the
proceedings held before -- and the result reached by -- that other agency.
Madison Gas & Elec. Co. v. SEC, 168 F.3d 1337, 1341-42 (D.C. 1999), citing City
of Holyoke Gas & Elec. Dep't v. SEC, 972 F.2d 358 (D.C. Cir. 1992) (dismissing
challenge to order approving merger that asserted Commission could not rely on
FERC and state review of competitive effects) [hereinafter "Madison Gas"].
Consistent with the foregoing, the Division in its 1995 Report recommended that
"the SEC avoid duplicative review of acquisitions and, where possible, defer to
the work of other regulators in reviewing acquisitions." 1995 Report at 66. In
- ----------
(8) See, e.g., Conective, HCAR No. 26832 (Feb. 25, 1998)[hereinafter
"Connectiv"].
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<PAGE> 51
this case, the SEC can watchfully defer to other agencies (namely, the DOJ and
the FERC) on the question of competitive issues because consummation of the
Merger may not take place until and unless potential competitive concerns have
been addressed by these agencies under the HSR Act procedures as well as under
Section 203 of the FPA.
ii(a). The Role of the DOJ
Pursuant to the HSR Act, AEP and CSW are required to file with the
Antitrust Division Premerger Notification and Report Forms. See 16 C.F.R. Parts
801 through 803. The purpose of the HSR Act reporting requirements is to
"facilitate evaluation of the antitrust implications of the proposed transaction
and, where the competitive consequences appear substantial, to permit the
Antitrust Division to challenge the legality of the transaction."(9) The HSR Act
prohibits consummation of the Merger until the statutory waiting period has
expired or been terminated. On July 26, 1999, Applicants filed with the
Antitrust Division under the HSR Act. On August 26, 1999, AEP and CSW received a
request for additional information from the Antitrust Division. AEP and CSW
filed the additional information with the Antitrust Division in November 1999.
On February 2, 2000, the Antitrust Division notified Applicants that it had
completed its review of the Merger and that no further action is warranted.
ii(b). The Role of the FERC
AEP and CSW filed a joint application with the FERC on April 30, 1998,
(see Exhibit D-1.1 filed herewith), as supplemented on January 13, 1999, (see
Exhibit D-1.2 filed herewith), pursuant to Section 203 of the FPA for approval
of the Merger. On November 23, 1999, the ALJ at FERC issued an Initial Decision
which found that the Applicants met their burden of establishing that the Merger
would not produce adverse competitive effects (see Exhibit D-1.7, page 9). The
ALJ further found that AEP and CSW demonstrated that the Merger "will not give
[them] the ability to use transmission to affect competition in an adverse
manner." Id. With respect to ratepayer protection measures that were offered by
Applicants, the ALJ found that the ratepayer protection measures "provide full
protection for wholesale requirements and transmission customers from any
adverse rate consequences resulting from the proposed merger." Id., page 11. The
ALJ further found that these ratepayer protections "are more than sufficient to
ensure that affected ratepayers do not pay any merger costs that [AEP and CSW]
incur in excess of merger benefits." Id. In sum, the ALJ concluded that the
application, as supplemented, conformed to FERC Order No. 592 in which the FERC
adopted the DOJ/FTC Merger Guidelines as the framework for analyzing the impact
of a merger on competition in affected markets.(10) A final decision from FERC
approving the Merger is expected no later than March, 2000.
- ----------
(9) Premerger Practice Notification Manual at xi (American Bar Association
1991).
(10) Inquiry Concerning the Commission's Merger Policy under the Federal
Power Act: Policy Statement, Order No. 592, Docket No. RM96-6-000, Regulations
Preambles, Paragraph 31,044 at 30,109 (December 30, 1996).
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<PAGE> 52
The AEP/CSW application to the FERC contained testimony by Dr. William
Hieronymus analyzing the Merger pursuant to FERC Order No. 592. Copies of Dr.
Hieronymus' testimony are filed as exhibits to Exhibits D-1.1 and D-1.2. The
analysis presented therein measures the competitive effect of the Merger within
the relevant destination markets. Dr. Hieronymus concludes that, with the
mitigation measures which the Applicants propose as a condition of the Merger,
the Merger will not adversely affect competition in any of the destination
markets that were analyzed. The Administrative Law Judge at FERC agreed that
Applicants' mitigation plans eliminate any Guidelines screen failures
attributable to a combination of Applicants' generating facilities (see Exhibit
D-1.7, page 9). Dr. Hieronymus' testimony is summarized below:
(x) Product Markets
The FERC presumes the long-term capacity market to be competitive, unless
special factors exist that limit the ability of long-term capacity markets to
develop. The evidence demonstrates that the Combined Company will not control
transmission access, fuel supplies or generation plant sites. Accordingly, the
Combined Company will not have market power in long-term capacity markets.
For the shorter term markets, the FERC applies a market screen analysis to
determine if a merger raises competitive concerns. For that purpose, the FERC
uses four product measures: 1) Total Capacity; 2) Uncommitted Capacity; 3)
Available Economic Capacity; and 4) Economic Capacity.
With respect to the Total Capacity measure, the overall size of the market
will be in excess of 340,000 MW in 1999, growing to almost 360,000 MW in 2001.
The Total Capacity of the Combined System is approximately 39,000 MW (less the
1604 MW of generating assets located in ERCOT and 300 MW of generating assets
located in SPP that Applicants have agreed to divest). Applying the screening
analysis, Dr. Hieronymus concluded that the market is unconcentrated (an HHI of
less than 1000) and, accordingly, the Merger has no anti-competitive impact with
respect to Total Capacity.
With respect to the Uncommitted Capacity measure, CSW Energy has 705 MW of
uncommitted capacity and AEP has 495 MW of uncommitted capacity. The combination
of the uncommitted capacity represents less than a 15 percent combined market
share. Dr. Hieronymus concluded that the market of Uncommitted Capacity is
unconcentrated and mergers in such markets are presumed to have no
anti-competitive impact.
With respect to the Economic Capacity measure, Dr. Hieronymus concluded
that when the Applicants' mitigation proposal is taken into account, the Merger
significantly deconcentrates the CSW SPP and ERCOT markets and results in HHI
changes below the FERC Order 592 threshold in all but a handful of destination
markets. (The exceptions involve destination markets in which the Combined
Company will have a miniscule market share because the Applicants' use
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<PAGE> 53
of the 250 MW Contract Path will serve to increase the already high market share
of one or more incumbent sellers that are unrelated to either Applicant.)
With respect to the Available Economic Capacity measure, Dr. Hieronymus
concluded that, for the most part, CSW's SPP and ERCOT markets are
deconcentrated. The AEP market is either deconcentrated or reflects zero HHI
changes in all time periods. The HHI changes for almost all of the other
relevant destination markets and time periods are below the FERC Order No. 592
threshold or are zero or are negative (meaning that the market is
deconcentrated). The few exceptions are in destination markets in which the
Applicants have little or no post-merger market share.
With the inclusion of the 250 MW Contract Path to interconnect the
Applicants' systems, a few additional failures under the screening analysis
resulted for the Economic Capacity Measure in the SPP and ERCOT markets. As to
those markets that did not fall below the minimum benchmark, Applicants, in
their application filed with the FERC, as supplemented, proposed mitigation
measures to offset any increase in market concentration so as to reduce the HHI
to fall within safe harbor levels. AEP and CSW propose to divest ownership of
550 MW of generation capacity (300 MW in the SPP and 250 MW in the ERCOT) by
means of auction. The Texas Decision approved Applicants' agreement to divest
1604 MW of generating assets located in ERCOT, which includes the 250 MW of
generating assets located in ERCOT that will be divested as part of the proposed
FERC mitigation measures.
The auction process for the ERCOT and SPP generation capacity is
conditioned upon there being no violation of the pooling-of-interests accounting
treatment used for the Merger. If it is determined that the ERCOT divestiture
can proceed immediately after the Merger closes without jeopardizing
pooling-of-interests accounting treatment for the Merger, sale of the plants
would begin no later than 90 days after the Merger closes. Absent that
determination, the divestiture would occur approximately two years after the
Merger closes to satisfy the requirements to use pooling-of-interests accounting
treatment. The 300 MW of generation to be divested in SPP is also conditioned
upon the plant no longer being required to meet PSO's native load demand
requirements following electric industry restructuring in Oklahoma and no longer
being required to satisfy SPP reliability criteria. Until these conditions are
met, the Combined Company will sell 300 MW hours of energy per hour in a system
power sale. The divestiture process for the ERCOT capacity will begin after the
completion of the Merger, unless the Commission determines that a sale within
two years of the Merger will cause the pooling-of-interests accounting treatment
to be unavailable. The proposed sales and subsequent divestitures are,
therefore, specifically structured to meet any concerns that the increases in
market concentration in the SPP and ERCOT markets, without correction, could
have anti-competitive effects on those markets.
In interpreting the estimated market shares and HHIs, it is important to
recognize that non-firm energy markets have a number of characteristics that
make the exercise of market power, either jointly or unilaterally, extremely
unlikely. In particular, the numerous ways energy transactions can be packaged,
the diversity of the participants in an evolving and increasingly
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<PAGE> 54
competitive market, and the fact that buyers are also sellers at various times
will make it exceedingly difficult for the Combined Company to exercise market
power through coordinated behavior.
As a further mitigation measure, Applicants agreed to waive the Combined
Company's priority with respect to its use of the HVDC ties. As noted in Item
I.B. above, the waiver applies to unplanned (i.e., non-firm) transactions in
ERCOT and non-firm transactions in SPP.
In sum, it is clear that the Merger will have little or no effect on
competition in the relevant product markets.
(y) Vertical Markets
The Merger raises no vertical concerns. AEP and CSW are not transmission
competitors and each operates under FERC Order No. 888 OATTs. AEP and CSW have
filed a joint Order No. 888 compliance tariff applicable to the Combined System
to be made effective as of the Merger closing date. Hence, Applicants are not in
a position to favor each other in operating their transmission systems.
As part of the FERC Stipulation and settlements with the staffs of various
state commissions, AEP and CSW each have committed to join an ISO or RTO, thus
eliminating any remaining concerns regarding the transmission facilities' impact
on competition. Through the ISO or RTO, the transmission facilities will be
operated for the benefit of the system users in a competitive and
non-discriminatory manner. In this regard, on June 3, 1999, AEP joined with four
other utilities in filing the Alliance RTO Application, which was conditionally
approved by FERC on December 20, 1999. CSW is participating in the ERCOT
independent regional transmission plan for the portion of its system that is
within ERCOT and is participating in discussions with other interested parties
about the formation of an RTO that would include utility systems in the SPP. The
Texas Decision affirmed Applicants' agreement to obtain the Texas Commission's
prior approval before withdrawing from either ERCOT or the SPP.
The Merger raises no vertical issues relating to ownership or control of
scarce generating capacity. There are a number of projects under development and
construction in Texas which will be capable of selling into ERCOT and/or the
SPP, including an 800 MW merchant plant located in Grimes County; a 350 MW
merchant plant located in Uvalde County; a 300-400 MW gas-fired cogeneration
facility located at Reynolds Metals' Sherwin alumina production plant near
Corpus Christi; a 1,100 MW gas-fired, combined cycle plant whose output will be
sold to Texas Utilities for two years; a 1,000 MW gas-fired combined cycle
facility located in Edinburg, Texas; a 700 MW merchant plant is planned for
Magic Valley Electric Cooperative; a 510 MW addition is planned for a
cogeneration facility located in Pasadena, Texas; a 500 MW gas-fired combined
cycle facility located in Hidalgo County, Texas.(11) By utilizing the Combined
Company's OATT, customers within the Combined Company's service territory will
be able to
- ----------
(11) Power Generation Markets Quarterly, First Quarter 1999.
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<PAGE> 55
access numerous suppliers that independently have constructed substantial
generating capacity in the past and that have located both within and outside
the service territory. In the longer term, with the introduction of retail
competition, it is expected that retail customers will have access to energy
service providers with different generation sources and mixes.
In addition, Applicants submitted to the FERC testimony by J. Stephen
Henderson demonstrating that, irrespective of the existence of an ISO or RTO,
the Merger will not create any ability or incentive for the Combined Company to
(1) use AEP's transmission system to limit competition in relevant markets into
which CSW sells electricity, or (2) use CSW's transmission system to limit
competition in relevant markets into which AEP sells electricity. The
Administrative Law Judge at FERC concluded that Mr. Henderson disposed of fears
of vertical market power being vested in the Applicants (see Exhibit D-1.7, page
9). A copy of Mr. Henderson's testimony is filed as an exhibit to Exhibit D-1.2
and is incorporated by reference. AEP and CSW also presented testimony by
Raymond Maliszewski explaining, among other things, that the configuration of
the AEP System does not permit AEP to affect adversely load flows on third party
systems by departing from economic dispatch of the AEP System. A copy of Mr.
Maliszewski's testimony is filed herewith as Exhibit D-1.2.
In sum, Dr. Hieronymus' testimony demonstrates that taking into account
the Combined Company's mitigation measures, the Merger presents no competitive
problems. The Administrative Law Judge at FERC found that the Merger will
produce no adverse competitive effects. A final decision from FERC approving the
Merger is expected no later than March, 2000. See Madison Gas & Electric (the
Commission is entitled to defer to FERC's expertise in evaluating the
competitive aspects of a merger). To the extent the Commission finds that there
is any concentration of control resulting from the Merger, Applicants believe
any such concentration of control is far outweighed by the benefits accruing to
the public, investors and consumers from the Merger, as more fully discussed in
Item 3.B.2 below. Thus, the Merger will not "tend toward . . . the concentration
of control" of public utility companies, of a kind or to an extent detrimental
to the public interest or the interests of investors or customers within the
meaning of Section 10(b)(1).
2. Section 10(b)(2)
Section 10(b)(2) of the 1935 Act requires the Commission to approve the
Merger unless it finds that the consideration, including all fees, commissions
and other remuneration, is unreasonable or does not bear a fair relation to the
sums invested in, or the earning capacity of the utility assets underlying the
securities to be acquired.
a. Reasonableness of Consideration
Section 10(b)(2) "does not demand a mathematical equivalence of values for
the terms of the exchange." Entergy, supra. Prices arrived at through arm's
length negotiations are particularly persuasive evidence that the Section
10(b)(2) requirement is met. See, e.g., Northeast I, supra, (citing Ohio Power,
HCAR No. 16753 (June 8, 1970)). Moreover, the assistance of independent
53
<PAGE> 56
consultants in setting consideration is deemed to be evidence that the
requirement is met. See, e.g., Northeast I, supra (citing Southern Co., HCAR No.
24579 (Feb. 12, 1988)). The Commission also "independently analyze[s] the
financial and operating performances of [the combining entities]" with respect
to such factors as relative market values and dividends per share. Centerior,
supra. Finally, the Commission considers whether the shareholders have approved
the acquisition. Entergy, supra.
Under the standards applied by the Commission in previous utility mergers,
the consideration to be paid by AEP in the Merger is reasonable and bears a fair
relation to the earning capacity of the utility assets underlying the CSW Common
Stock to be acquired, in compliance with Section 10(b)(2). Based on the Exchange
Ratio set forth in the Merger Agreement, the consideration offered by AEP will
be AEP Common Stock which had a market value on December 19, 1997, the last
trading day before the Merger was announced, of approximately $6.6 billion, or
approximately $31.20 per share of CSW Common Stock, which was approximately 20%
above the closing price of CSW Common Stock on December 19, 1997. Applicants'
belief that the consideration is fair and reasonable is based on the following
reasons, each of which is discussed in detail below:
- Arm's length negotiations between AEP and CSW conducted in a
competitive context resulted in the proposed Exchange Ratio;
- An opinion from AEP's financial adviser, Salomon, states that the
consideration to be paid by AEP with respect to the Merger is fair,
from a financial point of view, to AEP;
- An opinion from CSW's financial adviser, Morgan Stanley, states that
the consideration to be received by CSW's shareholders with respect
to the Merger is fair, from a financial point of view, to CSW's
shareholders;
- Valuation analysis demonstrates the fairness of consideration as
evidenced by the comparative market prices of, and dividends paid
on, the AEP and CSW Common Stock;
- The Applicants' shareholders approved the shareholder actions
necessary to effect the Merger; and
- The inclusion of required closing conditions in the Merger Agreement
serves to assure that the Merger will be consummated on terms that
are fair to Applicants and their shareholders.
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<PAGE> 57
(i) Competitive Negotiations
The chief executive officers of AEP and CSW had informal discussions on
several occasions from January 1997 to March 1997 regarding a merger of the
companies. With CSW's stock price depressed in late April 1997 as a result, in
the opinion of CSW management, of adverse action by the Texas Commission, CSW
management terminated discussions with AEP.
From May through September 1997, CSW management continued to explore a
variety of strategic alternatives. As part of this analysis, CSW management, in
consultation with its advisers, developed a list of screening criteria for use
in analyzing potential merger partners. CSW also considered other strategic
alternatives which could be pursued without a business combination. At a meeting
of the CSW Board of Directors on September 27, 1997, management recommended to
the CSW Board of Directors that CSW seek a merger that could enhance CSW's
ability to implement its long-term vision. The CSW Board of Directors
unanimously authorized CSW management to pursue its search for an appropriate
merger partner while continuing to evaluate CSW's stand-alone options.
In September 1997, the chief executive officers of AEP and CSW resumed
their discussions regarding a stock-for-stock merger. During the ensuing months,
CSW's management also held preliminary discussions, and exchanged non-public
information, with three other electric utilities regarding a possible business
combination and continued to evaluate other stand-alone alternatives. CSW
management met with the CSW Board of Directors and a committee of the CSW Board
of Directors on many occasions during October-December 1997 to update the
directors and receive direction on the course of their discussions.
On November 24, 1997, CSW management and CSW's advisers met with a
committee of the CSW Board of Directors to discuss the progress of the strategic
alternative evaluation process. The committee authorized CSW management to send
to four strategic merger candidates a letter requesting each to advise CSW as to
whether, and on what terms, it was interested in pursuing a strategic
combination with CSW. On December 11, 1997, CSW received affirmative responses
to the request letters from AEP and two of the three other companies.
On December 12, 1997, CSW management and advisers met with a committee of
the CSW Board of Directors to discuss the responses and the status of the
strategic merger candidate evaluation process. After analyzing the responses and
CSW's other stand-alone alternatives, the committee determined that AEP appeared
to be the best strategic merger partner for CSW and that a merger with AEP on
the right terms would be more likely to restore and enhance long-term
stockholder value than any of the other merger or stand-alone strategic
alternatives.
Following negotiations between the chief executive officers of each
company, CSW and AEP agreed to proceed with merger negotiations on the basis of
a proposed exchange ratio of 0.60 shares of AEP Common Stock for each share of
CSW Common Stock. The Board of
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<PAGE> 58
Directors of both companies approved the Merger Agreement in meetings on
December 21, 1997, and the Merger Agreement was signed that afternoon.
The Exchange Ratio was agreed to by the Applicants after extensive
deliberations between the two companies involving senior management personnel
assisted by financial and legal advisers skilled in mergers and acquisitions
transactions. Moreover, the negotiations were carried out in a competitive
context with other companies.
For further information regarding the background of the proposed Merger
between AEP and CSW, reference is made to the Joint Proxy Statement and
Prospectus filed as Exhibit C-2 and incorporated herein by reference.
(ii) Fairness Opinions
As discussed above, the Boards of Directors of AEP and CSW approved the
Merger Agreement and the transactions contemplated thereby. Prior to such
approvals, the Boards received opinions from AEP's and CSW's respective
financial advisers as to the fairness of the proposed consideration. AEP's Board
of Directors received a written opinion from Salomon that, based upon specified
procedures and assumptions, the consideration to be paid by AEP with respect to
the proposed Merger is fair, from a financial point of view, to AEP. CSW's Board
of Directors received a written opinion from Morgan Stanley that the proposed
consideration is fair, from a financial point of view, to the shareholders of
CSW. No limitations were imposed by the AEP Board or the CSW Board upon Salomon
or Morgan Stanley, respectively, with respect to the investigations made or
procedures followed by their respective financial advisers.
In arriving at their respective opinions, Salomon and Morgan Stanley
reviewed (i) the terms of the Merger Agreement; (ii) certain publicly available
business and financial information relating to AEP and CSW; (iii) certain other
internal information concerning AEP and CSW, including financial projections
provided to them by AEP and CSW; (iv) certain publicly available information
concerning the trading of, and the trading market for AEP's and CSW's Common
Stock; (v) certain publicly available information with respect to other
companies they believed to be comparable to AEP and CSW and the trading markets
for such other companies' securities; and (vi) certain publicly available
information concerning the nature and terms of other transactions they
considered relevant to their inquiry. They also met with officers and employees
of AEP and CSW to discuss the foregoing as well as other matters relevant to the
Merger. Copies of the fairness opinions are filed as Annexes II and III to
Exhibit C-2 and are incorporated by reference.
Salomon's fairness opinion was based on eight valuation analyses relating
to, respectively, Discounted Cash Flow Analysis-CSW; Comparable Company
Analysis-CSW; Analysis of Selected Utility Company Mergers and Acquisitions;
Discounted Cash Flow Analysis-AEP; Comparable Company Analysis-AEP; Historical
Trading Ratios Analysis; Contribution Analysis; and Pro Forma Analysis of the
Merger. These analyses supported the
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<PAGE> 59
fairness of the proposed consideration, from a financial perspective, to be paid
by AEP and are summarized below:
Discounted Cash Flow Analysis-CSW. This analysis was based on certain
operating and financial assumptions for CSW in years 1997 to 2006 provided
by CSW and adjusted by the management of AEP. From this analysis, Salomon
derived a range of the implied equity value per share of CSW Common Stock
of approximately $25 to $29. In addition, Salomon derived a per share
present value of the expected Merger savings of $5. Thus, Salomon derived
a reference range for the implied value per share of CSW Common Stock,
including savings, of approximately $30 to $34.
Comparable Company Analysis-CSW. Salomon reviewed certain publicly
available financial, operating, and stock market information for CSW and
five other publicly-traded utility companies Salomon considered comparable
to CSW. Salomon derived the implied value of the CSW shares on (1) a
stand-alone basis ($21 to $25 per share); (2) with the Merger savings ($26
to $30 per share); and (3) including a 30% control premium, but no Merger
savings ($27.50 to $32.50 per share).
Analysis of Selected Utility Company Mergers and Acquisitions. Salomon
reviewed a set of completed and proposed utility mergers announced since
August 1996. Salomon calculated multiples based on the offer price for
each target company to such company's respective pre-announcement market
price, book value, earnings and cash flow per share. From this analysis,
Salomon derived a reference range for the implied equity value per CSW
share of $27 to $35. Discounted Cash Flow Analysis-AEP. This analysis was
based on certain operating and financial assumptions for AEP in years 1997
to 2006 provided by AEP. From this analysis, Salomon derived a range of
the implied equity value per share of AEP Common Stock of approximately
$42 to $49. Comparable Company Analysis-AEP. Salomon reviewed certain
publicly available financial, operating, and stock market information for
AEP and five other publicly-traded utility companies Salomon considered
comparable to AEP. Salomon derived a range of the implied equity value per
share of AEP Common Stock of approximately $44 to $52.
Historical Trading Ratios Analysis. Salomon also reviewed the daily
closing prices of CSW Common Stock and AEP Common Stock during the period
from December 15, 1992 through December 15, 1997 and the historical
trading ratios over such period. During that period the average historical
trading ratio was 0.70. The ratio on December 15, 1997 was 0.52.
Contribution Analysis. Salomon reviewed the relative contributions of each
of AEP and CSW to estimated net income and other indicators of the
Combined Company for each of the years 1997 to 2006. This analysis showed
that CSW is expected to contribute a percentage of the Combined Company's
net income ranging from approximately 34% to 40% in 1997 to 2003 before
leveling off at 39% in the years 2004 to 2006. CSW stockholders would own
approximately 40% of the outstanding shares of the Company based on the
Exchange Ratio.
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<PAGE> 60
Pro Forma Analysis of the Merger. Salomon also analyzed certain pro forma
effects resulting from the proposed combination for the years 2000 through
2006. This analysis was based on financial and operating assumptions for
AEP and CSW, as provided to Salomon by AEP, and assumed the realization of
the cost savings projected by AEP management to result from the Merger.
Based on such analysis, Salomon concluded that the Merger would be
somewhat dilutive to AEP shareholders for the years 2000-2002 and somewhat
accretive for the remaining years of the forecast. Salomon noted that the
transaction would generally produce earnings per share accretion of 10% or
more each year for CSW shareholders, but would result in a lower dividend
per original CSW share of more than 10% through 2003, the reduction
continuing to decline thereafter.
(iii) Comparative market prices of and dividends paid on common
stock.
Market prices at which securities are traded have always been strong
indicators as to values. As shown below, most quarterly price data for CSW
Common Stock and AEP Common Stock, high and low, for the years 1996 and 1997
provide support for the calculation of the Exchange Ratio.
<TABLE>
<CAPTION>
AEP CSW
- --------------------------------------------------------------------------------------------------------------
High Low Dividends High Low Dividends
- --------------------------------------------------------------------------------------------------------------
1996
<S> <C> <C> <C> <C> <C> <C>
1st Qtr ......... 44-3/4 40-1/8 0.60 28-1/2 26-3/8 0.435
2nd Qtr ......... 42-3/4 38-5/8 0.60 28-7/8 26-1/2 0.435
3rd Qtr ......... 43-1/8 40 0.60 28-1/2 25-3/4 0.435
4th Qtr ......... 42-1/2 39-1/2 0.60 28 25-1/2 0.435
- --------------------------------------------------------------------------------------------------------------
1997
1st Qtr ......... 43-3/16 40 0.60 25-3/4 21-1/4 0.435
2nd Qtr ......... 42-1/2 39-1/8 0.60 22-7/8 18-1/4 0.435
3rd Qtr ......... 46-5/8 41-1/2 0.60 22-7/16 19-3/4 0.435
4th Qtr ......... 52 45-1/4 0.60 27-5/16 20-5/8 0.435
- --------------------------------------------------------------------------------------------------------------
</TABLE>
(iv) Shareholder Approval
In addition, the holders of AEP Common Stock and the holders of CSW Common
Stock overwhelmingly approved the shareholder actions necessary to effect the
Merger. At the Annual Meeting of Shareholders of AEP held on May 27, 1998,
holders of approximately (i) 71% of all outstanding AEP Common Stock approved an
amendment to the Restated Certificate of Incorporation of AEP increasing the
number of authorized shares of AEP Common Stock, and (ii) 72% of all outstanding
AEP Common Stock approved the issuance of the AEP Common Stock, each necessary
to effect the Merger. Holders of approximately 82% of all outstanding CSW Common
Stock approved the Merger at the Annual Meeting of Stockholders of CSW held on
May 28, 1998.
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(v) Merger Agreement
Finally, the Merger Agreement contains a number of closing conditions that
help ensure the continued reasonableness of the consideration. Under Section
8.1(g), it is a condition precedent to closing, applicable to both AEP and CSW,
that "there shall not have occurred and remain in effect a Divestiture Event
with respect to [either company]."(12) Pursuant to Sections 8.2 and 8.3, AEP and
CSW are each required to affirm that all representations made with respect to
the Merger Agreement are true and correct as of the date of closing, including
the representation that no Material Adverse Effect(13) shall have occurred and
that there shall exist no fact or circumstance which may reasonably be expected
to give rise to a Material Adverse Effect. Other closing conditions ensure that
the Merger will not be consummated in the event of onerous or burdensome
regulatory orders or conditions.
b. Reasonableness of Fees
The various categories of fees, commissions and expenses in connection
with the transaction and regulatory processing costs for the Merger are set
forth in Item 2 to this Application-Declaration. Applicants expect to incur
total transaction and regulatory related costs of approximately $53 million,
including financial advisory fees of approximately $31 million.
Applicants believe that these estimated fees and expenses bear a fair
relation to the value of CSW and the savings to be achieved by the Merger and
are fair and reasonable in light of the size and complexity of the Merger.
Northeast Utilities, HCAR No. 25548 (June 3, 1992), modified on other grounds,
HCAR No. 25550 (June 4, 1992) [hereinafter "Northeast II"] (Commission considers
whether fees and expenses bear a fair relation to the value of the company to be
acquired and the savings to be achieved by the acquisition). Based on the price
of AEP Common Stock on December 19, 1997, the transaction would be valued at
$6.6 billion. As discussed in Item 3.B.2 below, net nonproduction savings of
nearly $2 billion and net fuel-related savings of approximately $98 million are
projected over the first ten years after the Merger.
Moreover, the estimated overall fees are reasonable compared to the
overall fees approved by the Commission in other merger transactions. The total
fees of $53 million to be incurred by Applicants represent approximately 0.8% of
the value of consideration to be paid by AEP, based on the price of AEP Common
Stock on December 19, 1997. The Commission has
- ----------
(12) "Divestiture Event" means "any Law, Regulation or Order adopted or
issued by a Governmental Authority that requires the divestiture of a
substantial portion of the generating assets of . . ." CSW or AEP.
(13) "Material Adverse Effect" means "any change or effect that is
material and adverse to the business, condition (financial or otherwise) or
results of operations or prospects of a specified Person and its subsidiaries,
if any, taken as a whole; provided, however, that, as used in this definition
the word material shall have the meaning accorded thereto in Section 11 of the
Securities Act."
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<PAGE> 62
approved fees, commissions and expenses of $46.5 million in connection with the
acquisition of PSNH by Northeast, representing approximately 2% of the value of
the assets to be acquired (Northeast I; Northeast II); $47.12 million in
connection with the reorganization of Cincinnati Gas and Electric and PSI
Resources as subsidiaries of CINergy (CINergy Corp., HCAR No. 26146 (Oct. 21,
1994) [hereinafter "CINergy"]) and $38 million in fees, commissions and expenses
in connection with Entergy's acquisition of Gulf States Utilities Company,
representing approximately 1.7% of the value of the consideration paid to Gulf
States' shareholders (Entergy, supra).
The investment banking fees of approximately $31 million to be incurred by
Applicants represent approximately 0.47% of the value of consideration to be
paid by AEP, based on the price of AEP Common Stock on December 19, 1997. These
fees incurred by Applicants resulted from a marketplace in which investment
banking firms actively compete with each other to act as financial advisers to
merger participants. The Commission has previously approved financial advisory
fees of approximately $10.6 million, representing approximately 0.46% of the
value of the assets to be acquired (Northeast I, supra and Northeast II, supra),
financial advisory fees representing approximately 0.96% of the aggregate value
of the acquisition, (Southern Co., HCAR No. 24579 (Feb. 12, 1988), modified on
other grounds, HCAR No. 24579A (February 26, 1988), and Amendment No. 9 to
Southern Form U-1 (April 13, 1988)), and financial advisory fees of $8.3
million, representing approximately 0.36% of the value of the consideration paid
to Gulf States' shareholders (Entergy, supra and Amendment No. 24 to Entergy
Form U-1 (Nov. 18, 1993)).
For all of the above reasons, the consideration and fees to be paid are
fair and reasonable in compliance with Section 10(b)(2).
3. Section 10(b)(3)
Section 10(b)(3) of the 1935 Act requires the Commission to approve a
proposed acquisition unless the acquisition would unduly complicate the capital
structure of the holding company system, or would be detrimental to the public
interest, the interest of investors or consumers or the proper functioning of
such holding company system.
a. Capital Structure
The Commission has found that an acquisition does not unduly complicate
the capital structure of the holding company system where the effect of a
proposed acquisition on the acquirer's capital structure is negligible and the
debt to equity ratio due to the acquisition is well within "the 65/30%
debt/common equity ratio generally prescribed by the Commission." Entergy, supra
(citing Northeast I). The Commission has approved common equity to total
capitalization ratios as low as 27.6%. See Northeast I, supra.
In this regard, the proposed combination of AEP and CSW will not unduly
complicate the capital structure of the Combined System. The only changes to the
capital structure of AEP will be the acquisition by AEP
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<PAGE> 63
of CSW Common Stock and the addition of the capital structure of CSW to AEP's
capital structure. CSW and its subsidiaries have publicly held debt and have
publicly held preferred stock or preferred trust securities, and all CSW Common
Stock will be held by AEP and incorporated within AEP's consolidated financial
statements. At December 31, 1998, the respective capital structures of AEP and
CSW were as follows:
<TABLE>
<CAPTION>
AEP CSW
(in $ millions) (in $ millions)
<S> <C> <C> <C> <C>
Common Stock Equity ............ $ 4,842 40.28% $ 3,624 45.75%
Preferred Stock ................ 174 1.44% 176 2.22%
Long-Term Debt ................. 7,006 58.28% 3,785 47.80%
Trust Preferred Securities ..... -0- -0- 335 4.23%
Total ......................... $12,022 100.00% $ 7,920 100.00%
</TABLE>
If the Merger had been consummated on December 31, 1998, the pro forma
consolidated capital structure of the Combined Company as of such date
(according to generally accepted accounting principles, assuming that the Merger
is treated as a "pooling-of-interests" under Accounting Principles Board Opinion
No. 16) would have been as follows:
<TABLE>
<CAPTION>
Combined Company Pro Forma
(in $ millions)
<S> <C> <C>
Common Stock Equity ......................... $ 8,466 42.34%
Preferred Stock ............................. 350 1.75%
Long-Term Debt (a) .......................... 10,844 54.23%
Trust Preferred Securities .................. 335 1.68%
Total ...................................... $19,995 100.00%
</TABLE>
(a) Includes $53 million of transactions and regulatory processing costs.
As can be seen from the above tables, the debt to equity ratio is not
altered to any considerable degree by the Merger. The Combined Company's pro
forma consolidated common equity to total capitalization ratio of 42.34% is
substantially higher than Northeast Utilities' recently approved 27.6% common
equity position and comfortably exceeds the "traditionally acceptable 30%
level." Northeast I, supra.
Finally, the common stock that AEP proposes to issue in the Merger has the
same par value, same rights (including voting rights) and preference as to
dividends and distributions as the AEP Common Stock presently outstanding. All
of the issued and outstanding CSW Common Stock will be owned by AEP as a result
of the Merger. As such, there will be no publicly held minority common stock
interest in CSW following the Merger. Thus, the Merger does not complicate the
capital structure of AEP.
b. Public Interest, Interest of Investors and Consumers, and Proper
Functioning of Holding Company System
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Section 10(b)(3) also requires the Commission to determine whether the
proposed Merger will be detrimental to the public interest, the interest of
investors or consumers or the proper functioning of the Combined System.
As discussed in greater detail in Item 3.B.2 below, the Merger will enable
the Combined Company to operate more efficiently and economically than either
AEP or CSW could operate independently of the Merger. The Merger will result in
substantial, otherwise unavailable, benefits to the public and to consumers and
investors of both companies -- specifically, savings through labor cost savings,
facilities consolidation, corporate and administrative programs, non-fuel
purchasing economies, and efficiencies from the combined utility operations.
These savings will be passed on to shareholders and consumers. The shareholders,
whose interests are protected by the disclosure requirements of the Securities
Act of 1933 and the Securities and Exchange Act of 1934, have overwhelmingly
approved the shareholder actions necessary to effect the Merger. See Southern,
supra (stating that "[c]oncerns with respect to investors have been largely
addressed by developments in the federal securities laws and in the securities
markets themselves.") The interests of consumers are protected by both state and
federal regulation.
Simply stated, the Merger will create an entity that will be poised to
respond effectively to the fundamental changes that have taken and will continue
to take place in the markets for electric power as such markets are being
deregulated and restructured and will create an entity prepared to compete
effectively for consumer's business. As such, consumers, investors, and the
public will be the ultimate beneficiaries of the Merger.
In sum, because the Merger does not add any complexity to AEP's capital
structure and is in the public interest and the interests of investors and
consumers, the requirements of Section 10(b)(3) are met.
B. Section 10(c)
Section 10(c) of the 1935 Act establishes additional standards for
approval of the Merger. Under Section 10(c), the Commission cannot approve:
(1) an acquisition of securities or utility assets, or of any other
interest, which is unlawful under the provisions of Section 8 or is detrimental
to the carrying out of the provisions of Section 11; or
(2) the acquisition of securities or utility assets of a public utility or
holding company unless the Commission finds that such acquisition will serve the
public interest by tending towards the economical and efficient development of
an integrated public utility system.
1. Section 10(c)(1)
Section 10(c)(1) requires that the proposed acquisition be lawful under
the provisions of Section 8 of the 1935 Act. Section 8 prohibits an acquisition
by a registered holding company of
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an interest in an electric and gas utility serving substantially the same area
without the express approval of the state commission when that state's law
prohibits or requires approval of the acquisition. Because neither CSW nor AEP
has any direct or indirect interest in any gas utility company, this section is
not applicable to the Merger.
Section 10(c)(1) also requires that the Merger not be detrimental to the
carrying out of the provisions of Section 11. Section 11(b)(1) generally
requires a registered holding company system to limit its operations "to a
single integrated public-utility system, and to such other businesses as are
reasonably incidental, or economically necessary or appropriate to the
operations of such integrated public-utility system." Section 11(b)(2) directs
the Commission "to ensure that the corporate structure or continued existence of
any company in the holding-company system does not unduly or unnecessarily
complicate the structure, or unfairly or inequitably distribute voting power
among security holders, of such holding-company system." The following analysis
demonstrates that the Merger meets the standards of Section 11.
a. Section 11(b)(1) (Single integrated public utility system)
The Commission has found that the system of each of the Applicants is a
single integrated electric utility system. See AEP, supra (finding that AEP is a
single integrated system); Central and South West Corp., HCAR No. 22439 (April
1, 1982) (terminating a Section 11(b)(1) hearing and upholding a 1945
determination by the Commission that CSW comprises one integrated public utility
system). The following analysis supports a determination by the Commission that
the Merger of these two utility systems will result in a single integrated
electric utility system under Section 11(b)(1).
Section 2(a)(29)(A) of the 1935 Act defines an integrated public utility
system, as applied to an electric utility system, as:
a system consisting of one or more units of generating plants and/or
transmission lines and/or distribution facilities, whose utility assets,
whether owned by one or more electric utility companies, are physically
interconnected or capable of physical interconnection and which under
normal conditions may be economically operated as a single interconnected
and coordinated system confined in its operations to a single area or
region, in one or more States, not so large as to impair (considering the
state of the art and the area or region affected) the advantages of
localized management, efficient operation, and the effectiveness of
regulation.
Under this definition, the Commission has established four standards that
must be met before the Commission will find that an integrated public utility
system will result from a proposed merger of two separate systems:
(i) the utility assets of the systems must be physically interconnected
or capable of physical interconnection;
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(ii) the utility assets, under normal conditions, must be economically
operated as a single interconnected and coordinated system;
(iii) the system must be confined in its operations to a single area or
region; and
(iv) the system must not be so large as to impair (considering the state
of the art and the area or region affected) the advantages of
localized management, efficient operation, and the effectiveness of
regulation.
See, e.g., Environmental Action, Inc., v. SEC, 895 F.2d 1255, 1263 (9th Cir.
1990) (citing In re Electric Energy Inc., 38 SEC 658, 668 (1958)). As
demonstrated below, the Merger meets each of these standards.
The Commission must interpret the statutory integration standards "to meet
the problems and eliminate the evils enumerated in [the 1935 Act.]" Section
1(c). In so interpreting the integration standards, the Commission must balance
the 1935 Act's various objectives. See, e.g., Union Electric, supra (the
Commission noted that in the past it had "exercise[d] [its] discretion so as to
allow the expeditious consummation of plans that would make for financial
simplification even though they fell far short of full compliance with the Act's
integration standards" because "with respect to the enforcement of this complex
multifaceted and far-reaching statute" it had "found it necessary or appropriate
to subordinate some statutory objectives to others."). The various aspects of
the integration standard cannot be considered independently of one another and
the other objectives of the 1935 Act. See, e.g., Middle West Corp., HCAR No.
4846 (Jan. 24, 1944) (the Commission noted that while it was difficult to reach
the conclusion that the systems constituted a single system given the geographic
spread of the properties, the integration test was met due to the "contemplated
savings resulting from closely coordinated operation and joint planning with
respect to the routing of power and the installation of facilities."); Middle
West Corp., HCAR No. 5606 (Feb. 16, 1945) (the Commission found that the
combined system was not too large "in light of demonstrated disadvantages of
lack of coordination."); Sempra Energy, HCAR No. 26971 (Feb. 1, 1999)
[hereinafter "Sempra"], citing North American Co., 18 SEC 459, 463 (1945)(in
connection with evaluating the integration standard for gas utility systems, the
Commission has "read each standard of section 2(a)(29)(B) in connection with the
other provisions of the section"). Where the acquisition will result in
significant economies and efficiencies to the benefit of the public, investors
and consumers, Commission precedent supports a flexible interpretation of the
integration standards to further the very interests that the 1935 Act was meant
to protect.
The Commission has recognized that the 1935 Act "creates a system of
pervasive and continuing economic regulation that must in some measure at least
be refashioned from time to time to keep pace with changing economic and
regulatory climates." Southern, supra (quoting Union Electric, supra). The
Commission interprets the 1935 Act and its integration standards "in light of []
changed and changing circumstances." Sempra, supra (interpreting the integration
standards of the 1935 Act in light of developments in the gas industry). Accord,
NIPSCO Industries, Inc., HCAR No. 26975 (Feb. 10, 1999) [hereinafter "NIPSCO"].
The Commission has
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cited with favor U.S. Supreme Court and Circuit Court of Appeals cases(14) that
recognized the need of an agency to "adapt [its] rules and policies to the
demands of changing circumstances"(15) and to "treat experience not as a jailer
but as a teacher."(16)
As the definition of an integrated public utility system suggests, and as
the Commission has previously observed, Section 11 is not intended to impose
"rigid concepts" but rather creates a "flexible" standard designed "to
accommodate changes in the electric utility industry." UNITIL Corp., HCAR No.
25524 (April 24, 1992) [hereinafter "Unitil"]; see also Yankee Atomic Elec. Co.,
HCAR No. 13048 (Nov. 25, 1955) [hereinafter "Yankee Atomic"] ("We think it is
clear from the language of Section 2(a)(29)(A), which defines an integrated
public utility system, that Congress did not intend to imposed [sic] rigid
concepts with respect thereto." (citations omitted)). Section 2(a)(29)(A)
expressly directs the Commission to consider the "state of the art" in analyzing
size and to apply "normal conditions" as the standard for determining whether a
system may be economically operated as a single coordinated system. The
Commission is not constrained by its past decisions interpreting the integration
standards based on a different "state of the art." See AEP, supra (noting that
the state of the art -- technological advances in generation and transmission,
unavailable thirty years prior -- served to distinguish a prior case and
justified "large systems spanning several states.")
The concept of what constitutes an integrated public utility system has
evolved in light of the dramatic changes in the law, technology and structure of
the industry since the passage of the 1935 Act over 60 years ago. In recent
years, the "state of the art" has changed enormously. As the Energy Information
Administration of the Department of Energy aptly noted, "The era of competition
in the electric industry is upon us." Energy Information Administration,
Department of Energy, The Changing Structure of the Electric Power Industry: An
Update (last modified May 30, 1997)
<http://www.eia.doe.gov/cneaf/electricity/chg_str/intro.html>.
The initial groundwork for competition was laid by the passage of PURPA in
1978, which opened wholesale markets to certain non-utility producers. PURPA
created a new class of non-utility generators, QFs, from which utilities were
required to buy power. The passage of the Energy Act in 1992 marked another
significant step towards the deregulation of the electric power industry. The
Energy Act was designed, among other things, to foster competition in the
wholesale market through (a) amendments to the 1935 Act that facilitated and
encouraged the ownership and operation of generating facilities by EWGs (which
may include IPPs as well as affiliates of electric utilities) and (b) amendments
to the FPA, authorizing the FERC under certain conditions to order utilities
that own transmission facilities to provide wholesale transmission services for
other utilities and entities generating electric power. In order to
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(14) Rust v. Sullivan, 500 U.S. 173 (1991); American Trucking Assns., Inc.
v. Atchison, T.&S.F.R. Co., 387 U.S. 397 (1967); Shawmut Assn. v. SEC, 146 F.2d
791 (1st Cir. 1945).
(15) NIPSCO, supra, citing Rust v. Sullivan at 186-187. Accord, Sempra,
supra at n. 23.
(16) NIPSCO, supra, citing Shawmut Assn. v. SEC at 796-97. Accord, Sempra,
supra at n. 23.
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facilitate the development of non-utility generation, many states, including
Texas, Louisiana and Ohio, developed integrated resource planning requirements
that require utilities to focus on both supply-side and demand-side resources
and to competitively bid their resource procurement requirements to obtain the
lowest cost available. As a result of these initiatives at both the federal and
state levels, the share of nationwide generating capacity from non-utility
generators has more than tripled from 3.6 percent in 1987 to 11.5 percent in
1999. In fact, since 1990, non-utility generators have contributed half of all
new investment in generating facilities. See Edison Electric Institute,
Directory of Electric Power Producers, 106th ed. (1999).
FERC Order Nos. 888 and 889, issued in April 1996, taken together provide
that public utilities must file OATTs permitting open access to transmission and
must functionally or actually unbundle their transmission services, by requiring
them to use their own transmission tariffs in making off-system and third-party
sales. Order No. 888 was intended to facilitate third-party utilization of the
transmission grid in order to develop a more competitive market for wholesale
power transactions. Under Order No. 888, a utility must transmit power for third
parties upon their request, on either a firm or non-firm basis. If the
transmitting utility does not have sufficient capacity to transmit the power on
a firm basis, it must either offer to expand its transmission system to
accommodate the request or, if appropriate, to redispatch generation to relieve
constraints and thereby make capacity available. In the interim, a utility must
offer transmission on a non-firm basis to the requesting entity.
In response to deregulation in the wholesale market for electricity, most
state legislatures and regulatory commissions either have adopted or currently
are considering the adoption of "retail customer choice" provisions. In general
terms, these initiatives require the electric utility to transmit electric power
over its transmission and distribution system to a retail customer in its
service territory. A requirement to transmit directly to retail customers
permits retail electric customers to purchase electric power, at the election of
such customers, either from the electric utility in whose service area they
reside or from another electric service provider or directly from an electric
generator source.
As of the date of this filing, state electric restructuring plans have
been adopted by the state public utility commissions or legislatures in
approximately twenty-four states, and all but a few states currently are
studying or taking action aimed at restructuring their electric markets. Of the
states in which the Combined Company will operate, restructuring legislation has
been adopted in Oklahoma, Virginia, Arkansas, Texas, and Ohio. Investigations
have been commenced which are expected to lead to restructuring plans in the
remaining states in which the Combined Company will operate.(17) Attached as
Appendix A is a summary of the status of state electric restructuring activities
in the states in which the Combined Company will operate.
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(17) Again, the state restructuring initiatives are not the subject of
this Application. The Combined Company will seek such additional approvals, as
may be required, in connection with state-mandated restructuring.
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In conjunction with the implementation of retail restructuring, many
states are requiring that utilities divest themselves of utility generating
assets. For example, in Texas, no power generation company may own and/or
control more than 20% of the installed generation capacity in ERCOT. In
Arkansas, the Arkansas Commission can force divestiture of generation assets to
alleviate market power. As a result of these actions, since August 1997, more
than 50,000 MW of generating capacity has been sold (or is currently under
contract to be sold) by utilities, and an additional 30,000 MW is currently for
sale. In total this represents more than 10 percent of U.S. generating
capacity.(18)
Taken together, these fundamental changes in the legal and regulatory
framework governing the electric utility industry are producing the following
structural changes:
- FERC Order No. 888 and the concomitant development of ISOs and
FERC's recent Notice of Proposed Rulemaking regarding the
development of RTOs are moving the electric power industry to a
disaggregation of control over generation and transmission.
Utilities that retain control of their generation capacity are
ceding significant control over their transmission capacity, and
vice-versa. Consequently, the "1935 model" of an integrated public
utility holding company as one that combines generation and
transmission is being supplanted by a different model in which the
two functions are separated.
- One goal of the above-described disaggregation is to eliminate
ownership of transmission facilities as a barrier to entry into
power markets for those who are ready to compete for customers
traditionally served by electric utilities. If nondiscriminatory
access to transmission facilities is guaranteed, distance will be
significantly reduced as a barrier to competition.
- An electricity futures market and electricity spot markets, as well
as newly formed entities, such as power marketers, brokers, ISOs and
RTOs, have emerged as new market structures and participants. More
than 570 marketers have registered with the FERC to trade in
electric power. See Edison Electric Institute, Directory of Power
Producers, 106th ed. (1999).
One way in which investor-owned utilities are seeking to improve their
position in today's increasingly competitive market is through mergers and
acquisitions. Between 1986 and 1996, thirty-nine electric investor-owned
utilities merged with other utilities in the industry. Energy Information
Administration, Department of Energy, The Restructuring of the Electric Power
Industry: A Capsule of Issues and Events (Feb. 10, 1998). Between 1992 and the
first half of 1998, 48 investor-owned electric utilities have been involved in
the domestic merger and acquisition process. Edison Electric Institute, "Merger
& Acquisitions," EEI Financial Information (August 28, 1998). AEP and CSW are
seeking to merge to further their mutual strategy of adapting to these historic
changes in the electric utility industry.
- ----------
(18) RTO NOPR at page 33, 690.
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Finally, recent years have witnessed technological advances unforeseeable
in 1935. Developments in telecommunications and computer technology, along with
parallel technological breakthroughs in transportation, have dramatically
reduced, if not eliminated, distance as a significant barrier to centralized
management and coordinated operation of any enterprise. It is a truism that
today's "global village" is a much smaller place than the world of 1935.
Developments in the transportation industry have greatly reduced travel times.
And information travels instantly. Computers provide "real time" information to
central management, providing it with comprehensive, timely information and the
capacity to assert central control over diverse operations.
In 1935, "an electric utility system generally included local generation,
transmission and distribution, [and] little long-distance transmission . . ."
Unitil, supra. Power plants were relatively small and isolated, and there was no
economical way to transmit power over any great distance. 1995 Report at 1, n. 1
(citation omitted). In today's world, "improved transmission and monitoring
technologies have increased the feasible geographic bounds for supply choice; a
geographic radius of 1,000 miles or more is currently considered reasonable for
choosing among supply options."(19)
Technological advances have occurred with respect to the "size" of
transmission lines. The building and expansion of the bulk power transmission
networks (345 Kv to 765 Kv lines) throughout the United States has allowed for
the transfer of large amounts of power over great distances. The construction of
such facilities has increasingly made it possible for electric utilities with
service territories over large geographic areas to share resources in providing
more reliable and economic service to their customers. There were less than 100
circuit miles of 345 Kv lines prior to 1950 and less than 100 circuit miles of
500 Kv lines prior to 1960. Electric Power Research Institute, Transmission Line
Reference Book (2d ed., revised, 1987) at 15 [hereinafter "Transmission Line"].
The first 765 Kv lines in the United States were built for AEP and were
energized in 1970. Id. at 14. Transmission lines above 189 Kv have grown from
7,800 circuit miles in 1950 to 151,700 circuit miles in 1995. Edison Electric
Institute, EEI Pocketbook of Electric Utility Industry Statistics (42d ed. 1997)
at 38. The contribution percentage of these
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(19) Rodney E. Stevenson & David W. Penn, "Discretionary Evolution:
Restructuring the Electric Utility Industry," Land Economics, Vol. 71, No. 3
(Aug. 1, 1995). See also Paul L. Joskow, "Electricity Sectors in Transition,"
The Energy Journal, Vol. 19, No. 2 (Apr. 1, 1998) (noting the changes occurring
to the "traditional industrial structures" due to "technological advances that
have expanded the geographic expanse over which integrated AC networks can be
controlled reliably . . ."); Jason Makansi & Robert Swanekamp, eds., "Powerplant
IT Benchmarks Power to Process Industries," Power Magazine, Vol. 140, No. 5 (May
1, 1996) (reporting that in order to "adapt[] organizational structures to the
IT systems" utilities are organizing "tactical group[s] . . . around [a central
information "hub"], not around individual plants, geography, etc"); "Automation
Developments," Transmission & Distribution World (Apr. 30, 1998) (identifying
Allegheny Power's recent purchase of "a computerized maintenance management
system (CMMS) program to help it with utility-wide substation maintenance of a
grid that spans 29,000 sq miles (75,000 sq km), seven regional offices and 41
service centers [and serves] customers in portions of Maryland, Ohio,
Pennsylvania, Virginia and West Virginia")
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lines above 189 Kv as compared to all transmission lines above 22 Kv has grown
from 3.3 % in 1950 to 22.6 % in 1995. Id.
Technological advances have also occurred with respect to the "type" of
transmission lines. The application of HVDC technology provides the ability to
transmit bulk power over longer distances with less energy loss and normally
with a smaller investment than with alternating current ("AC") transmission
lines. This technology provides an economical way to interconnect separated AC
power grids and enables power transfers to occur between these systems such that
it not only provides for improved economies, but also provides improvements in
reliability. HVDC technology was not commercially applied in the United States
for bulk power transfers until 1970, with the operation of the Pacific Intertie,
Stage 1 USA. Transmission Line at 17. From 1968 to 1981, there were 11,326 MWs
of HVDC capacity added in North America. Id. HVDC capacity has continued to be
added in different areas of the United States since 1981. In fact, the CSW
System constructed and placed in service a 220 MW HVDC interconnection
betweenthe SPP and ERCOT in December 1984. In August 1995, another HVDC
interconnection rated at 600 MW owned by CSW and several other electric utility
partners was placed in service between the same two power pools, but at a
different location.
The application of phase shifting transformers, series compensation, and
flexible alternating current transmission system ("FACTS") technology has also
provided the ability to improve and control the transfer of power and energy
across expansive transmission networks. Their use historically has been more
selective because of the operational problems that accompany their day- to-day
use. However, over the years with improvements in technology and operating
experience, their application is becoming more common. New flexible alternating
FACTS technology can increase the capacity of existing transmission lines by
approximately 20 to 40 percent. Electricity: Innovation and Competition, Hearing
Before the Subcomm. of Energy and Power of the House Comm. on Commerce, 105th
Cong. 38 (1997) (statement of Robert B. Schainker, Manager, Substations,
Transmissions and Substation Business Area Power Delivery Group, Electric Power
Research Institute). Such technology "help[s] electric utilities operate their
bulk power networks closer to their inherent thermal limits, while maintaining
and/or improving network security and reliability." Id.
Advances in telecommunications and computer technology have improved the
ability to economically dispatch power systems and control power flow across
such systems. Improvements in telecommunication technology and the growth in
coverage area of telecommunications systems have allowed for the quick and
reliable transfer of data necessary to control and dispatch from a single
location generation that can be scattered over large geographic areas. During
the last 10 to 15 years, the expansion of microwave and fiber optic networks has
provided utilities the ability to transfer information at much greater speeds,
with improved quality, and greater reliability. Prior to the 1970s, data was
transferred at baud rates as low as 75 baud (bit per second), sometimes being
transmitted over the power lines themselves. Today, data transferred from the
field to central control centers is at a minimum 1200-baud rate to accomplish 2
second scan rates. Larger data transfers between control centers are normally
accomplished at transfer rates from 56 kbaud to 224 kbaud.
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Computer technology necessary to economically dispatch power systems and
to control power flow across the bulk power transmission system has advanced
significantly since 1935, especially within the last ten years. The improvements
provided by fast and reliable telecommunication network allow for the control
and economic dispatch of power systems that extend over large geographic areas,
providing system operators an almost real time ability to monitor and control
the power system. Current control systems include software programs that can
help the operator analyze the real time operation of the power system and look
for potential problems before they occur. These complex programs have the
ability to suggest corrective measures and, in some cases, implement responses
without system operator participation. Such programs provide utilities greater
ability to obtain more capability out of their existing electric system, improve
system reliability, and improve economies. See, e.g., discussion of Central
Dispatch Planning and Central Economic Dispatch in Item 1.B.3.a, supra.
In addition, significant improvements in transmission and resource
planning have occurred since 1935. There are several software packages available
today that enable the system planner to model the operation of most of the
equipment used on a power system. Studies can be performed that not only
evaluate power transfer capabilities, but also allow the system planner to add
different types of equipment to determine their impact on increasing power
transfer capabilities. Development of such software has enabled the system
planner to determine what equipment functions best as well as where and when it
should be installed. Further technological advances can be expected in the
future as "power engineers" explore the potential for computers to optimize the
efficiency and reliability of the North American power network. Leslie Lamarre,
"The Digital Revolution," EPRI Journal, Jan./Feb. 1998.
The fundamental changes in technology outlined above dramatically alter
the "state of the art" which Congress, more than sixty years ago, directed the
Commission to consider. Such fundamental changes led the Division, in the 1995
Report, to state that it intends to apply a more flexible interpretation of the
integration requirements under the 1935 Act; and the Division recommended that
the Commission "respond realistically to the changes in the utility industry and
interpret more flexibly each piece of the integration equation." 1995 Report at
67. The Division further noted that in considering the integration requirements,
the Commission should place more focus on the acquisition's "demonstrated
economies and efficiencies." Id. at 69.
Each of the four integration standards is discussed below.
(i) Interconnection
The Combined System will be physically interconnected or capable of
interconnection. The required method of interconnection is not defined in the
1935 Act. The Commission has recognized that the interconnection requirement
should be applied flexibly to allow for methods of interconnection beyond simply
a transmission line owned by the merging utilities. In this regard, the
Commission has found (which finding was upheld on appeal) sufficient a
"three-year 'firm contract' to use a transmission line owned by two unrelated
parties." WPL Holdings at
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2262-63, aff'd, Madison Gas & Electric; Conectiv Inc., 66 S.E.C. Docket 1260
(1998) [hereinafter "WPL Holdings"] ("Delmarva and [Atlantic City Electric] are
interconnected through their undivided interests in, and/or rights to use, the
same regional generation facilities and extra-high voltage transmission
facilities, as well as through their contractual rights to use the transmission
facilities of other members of the PJM regional power pool") [hereinafter
Conectiv]; Northeast I, supra (interconnection standard met where combining
entities reached an agreement to obtain service by utilities with a transmission
line interconnecting the two systems); Centerior, supra (interconnection
standard met where merging systems could be interconnected through a power
transmission line, owned by an unaffiliated company, that each had the right to
use).
The Commission has long noted that electric utility systems could be
integrated without direct interconnections. E.g., Unitil (interconnection by
contractual right to use third-party's transmission even though no particular
lines would transfer power). In Unitil, the Commission found that three
noncontiguous electric distribution territories were sufficiently capable of
interconnection due to contractual rights to use a third-party's transmission
service, even though no particular lines would transfer power among the
companies. Unitil at 564-66. The description of the transmission arrangements in
Unitil -- "power will be delivered through a non-affiliate system and a
transmission charge will be paid" id. at 566) -- is analogous to the
transmission service requested across Ameren.
The Division has recommended that the Commission "respond realistically to
the changes in the utility industry and interpret more flexibly each piece of
the integration equation," including the physical integration requirement. 1995
Report at 67. The means through which two utilities are physically capable of
sharing power has expanded with changes in the industry. Utility companies can
now share power through power pool arrangements, reliability councils, RTOs, and
ISOs.
As noted in Item 1.B.3 above, AEP and CSW will interconnect their systems
through the 250 MW Contract Path across the Ameren system. Under Commission
precedent, this satisfies the interconnection requirement of Section
2(a)(29)(A). Moreover, the Applicants have the ability through the Ameren OATT
to renew the Contract Path. Thus, the Contract Path provides the Applicants
with the means to meet the interconnection standard under the Act and, at the
same time, preserves flexibility to enter into more favorable arrangements
should they become available during the four-year term of the Ameren contract.
As noted above, the electric industry is in the process of dynamic change; there
is growing pressure on public utilities to restructure and increasing
competition in the marketplace. Applicants believe that within the next four
years there may be transmission interconnection alternatives available as a
result of these changes and that the Commission therefore should find the
Contract Path to be sufficient. Although the precise method of interconnection
has not yet been determined four years into the future, the Applicants commit to
continue to meet the interconnection requirement at that time.
As noted in Item 1.B.3., Applicants have committed to limit their
reservation of firm transmission service from east to west to 250 MW unless the
FERC authorizes them to go above
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this limit.(20) See Dr. Hieronymus' testimony filed as an exhibit to Exhibit
D-1.2. This is sufficient to allow the Combined System to be physically
interconnected or capable of physical interconnection, which is the standard
applied under the Act. 15 U.S.C.ss.79b(a)(29)(A). Accord WPL Holdings, supra,
wherein the Commission held that interconnection through a 200 MW firm
transmission contract met the standards of the Act.
Capacity exchanges will be made between the east zone and the west zone
for periods of one year or less when one zone has capacity available for sale
and the other zone needs capacity to meet its reserve requirements, and when the
selling region's capacity market price is lower than the buying region's cost of
installing capacity or purchasing such capacity in the market. In this regard,
the production cost modeling studies conducted by the Applicants indicate that,
during the first ten years of post-Merger operations, the Combined Company will
be able to economically transfer 250 MW from the east zone to the west zone 87.5
% of the time and from the west zone to the east zone 4.3% of the time.(21) See
Testimony of J. Craig Baker at page 24.
As discussed above in Item 1.B.3, Applicants' goal ultimately is to
further enhance the interconnection of the Combined System through participation
in a regional RTO (subject to the need of the CSW-ERCOT companies to continue
participation in the ERCOT ISO). Assuming that the Combined Company belongs to a
single RTO, the RTO will have the capability to use the other members'
transmission lines to transmit power within the Combined System. The effect is
the same even if the Combined Company belongs to separate but contiguous RTOs,
provided the RTOs are not permitted to erect economic barriers between them.(22)
In this regard, the Commission has found that the transmission rights associated
with being a member of an ISO help to satisfy the interconnection requirement.
Conectiv, supra.
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(20) Applicants have committed to limit their reservation of firm
transmission service to avoid potential anticompetitive effects as a result of
the Merger, which is an additional consideration under the 1935 Act. In applying
the 1935 Act, the Commission must "weigh policies [of the 1935 Act] against each
other and against the needs of particular situations." Union Electric, supra.
The limitations to which the applicants have agreed represent a reconciliation
of the various objectives of the 1935 Act in furtherance of the interests which
the 1935 Act was meant to protect, those of investors, consumers and the public.
(21) The underlying study, the results of which are set forth in Exhibit
D-2.1, focused on production costs and the cost of transmission over the
Contract Path, and did not factor in the potential for the wholesale market to
address production cost differences between the east and west zones. Applicants
have not conducted a study solely for the purpose of determining the effect of
various wholesale market conditions upon Contract Path utilization.
(22) In this regard, the Commission has previously approved a merger where
the merging utilities were in more than one reliability council. See New Century
Energies, supra (approving a merger in which one of the merging utility systems
was located in the southwest corner of the eastern United States electricity
grid and was a member of the Southwest Power Pool, a regional reliability
coordinating organization in the eastern grid, and the other merging utility
system was located in the western United States electrical grid and was a member
of the Western Systems Coordinating Council, a reliability council for members
in the western United States electrical grid).
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(ii) Single Interconnected and Coordinated System
Under normal conditions, the Combined System will be "economically
operated as a single interconnected and coordinated system" as required by the
second clause of Section 2(a)(29)(A). The Commission has noted that, through
this standard, Congress "intended that the utility properties be so connected
and operated that there is coordination among all parts, and that those parts
bear an integral operating relationship to one another." Conectiv, supra, citing
The North American Co., HCAR No. 3466 (April 14, 1942), aff'd, 133 F.2d 148 (2d
Cir.1943), aff'd on constitutional issues, 327 U.S. 686 (1946). Cf. Section
1(b)(4) of the Act which cites, as one of the problems the Act was intended to
address, the harm to the public interest and the interest of investors and
consumers "[w]hen the growth and extension of holding companies bear[] no
relation to economy of management and operation or the integration and
coordination of related operating properties."
The Commission and the courts have emphasized this aspect of the
coordination requirement in recent decisions. In 1992, in a matter involving
Entergy, intervenors argued that the system would no longer be "economically
operated", as required by the second clause of Section 2(a)(29)(A), as the
result of the transfer of spun-off certain generating facilities from system
utilities to an unregulated affiliate. The problem, identified by intervenors,
was that power from these facilities would no longer be offered first for
in-system use. The Court of Appeals for the District of Columbia Circuit noted
that:
Although that reading might be consistent with the words of section 11
[and, by implication, Section 2(a)(29)(A)], it is by no means the required
one. The Commission reads "economically" to impose a less stringent
requirement, i.e., that facilities, in addition to their physical
interconnection, be consolidated so as to take advantage of efficiencies.
We are satisfied that the Commission's interpretation neither contravenes
Congress's intent nor is "unreasonable."
City of New Orleans v. SEC, 969 F.2d 1163 (July 17, 1992), citing Chevron U.S.A.
Inc. v. Natural Resources Defense Council, Inc., 467 U.S. 837 (1984) (emphasis
added). In this regard, the Court of Appeals anticipated the situation that is
faced by system operators today, in which there is a "tool kit" of resources
that can be used to obtain the maximum benefits for the Combined System.
The emphasis on economical operation of the system as a whole was
reinforced by the 1999 Madison Gas decision, in which the D.C. Circuit expressly
found that "section 2(a)(29)(A) requires that a system's combined `assets' (and
not the interconnection in particular) be economically operated." Madison Gas,
supra.
The coordination requirement was recently addressed in Unitil, supra. In
that case, the Commission concluded that the merged system was sufficiently
coordinated by means of factors
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which will also be present in the Combined System, specifically, "centralized
dispatch and . . . [the] coordinated planning, construction, operation and
maintenance of generation and transmission facilities." Unitil, at 565
(footnotes omitted).(23) In its analysis of the coordination requirement, the
Unitil decision places particular emphasis on the importance of centralized
dispatch:
Section 2(a)(29) further requires that the utility . . . be
"economically operated as a single interconnected and coordinated
system." The Commission has interpreted this language to refer to
the physical operation of utility assets as a system in which . . .
the generation and/or flow of current within the system may be
centrally controlled and allocated as need or economy directs.
Unitil, at 566 (footnote omitted).(24) Through this standard, Congress "intended
that the utility properties be so connected and operated that there is
coordination among all parts, and that those parts bear an integral operating
relationship to one another." Id. (citing Cities Services Co., 14 SEC 28, 55
(1943)).
As explained more fully herein, there will be "joint dispatch" of the
generating units of the Combined System within the meaning of Commission
precedent. It is important to note, however, that federal deregulation and state
restructuring initiatives have dramatically altered the way in which the
electric utility industry coordinates and integrates electric utility
operations. As a result, joint dispatch is but one aspect of the economic
operation of a single interconnected and coordinated system. Accordingly, this
filing addresses means, in addition to simple joint dispatch, of coordinating
the operations of the Combined System.
(a) Joint Dispatch
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(23) See also Electric Energy, Inc., 38 SEC 658, 670-71 (1958) (acquired company
satisfies "coordinated system" standard if its "generation, transmission and
distribution" functions can be efficiently coordinated with the existing system
through communications equipment, joint dispatch and joint planning).
(24) This passage from Unitil also stresses the need for "flexible
considerations" in applying the Act's integration requirements. Unitil, at 566.
For example, in Unitil, the Commission found that participation in a power pool
was sufficient to meet the economic integration standards even though the
"definition [of economic integration] reflects an assumption that the holding
company would coordinate the operations of the integrated system." Similarly, in
approving the acquisition of PSNH by Northeast, the Commission noted that "the
operation of the generating and transmission facilities of PSNH and the
Northeast operating companies is coordinated and centrally dispatched under the
NEPOOL Agreement [a regional power pool agreement]." Northeast I, supra at n.
85. In Conectiv, supra, the Commission noted that in addition to coordinated
operation through an ISO, Conectiv would also have a central operating
transmission and generation control center for the essentially local functions
of the Conectiv system, thereby meeting the standard.
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AEP and CSW will have joint dispatch which will be implemented by means of
a System Integration Agreement and the System Transmission Integration
Agreement, along with the use of Central Dispatch Planning and Central Economic
Dispatch software programs. It should be noted that the term "joint dispatch" is
nowhere defined in the Act or the rules thereunder. Consistent with the
precedent discussed above, the term "joint dispatch" in this application refers
to the ability of an integrated system to dispatch its generation on a
least-cost basis, taking into account various operating conditions, to achieve
the maximum efficiencies in the operation of the subject assets.
In the instant case, a single control center will schedule the generating
resources of the Combined System on a day-ahead and an hour-ahead basis. The
joint dispatch of all of the power supply resources of the Combined System will
be controlled by this center. The generating resources of the Combined System
will be jointly dispatched on a least-cost basis. Subject to currently
prevailing constraints, unit commitment will be performed to meet the Combined
System's obligations, taking into account the specific obligations within each
control area.(25) The control areas will be jointly dispatched in real time to
minimize total generation costs for the Combined System, subject to currently
prevailing transmission constraints. The Combined System will have firm
transmission rights over the Contract Path.
The joint dispatch of the Combined System will be performed in two steps.
o The first step is unit commitment. In this step, the system
operator projects the system peak load requirements for a
period and, to meet that requirement, schedules available
generating units to be on-line in economic order subject to
any operational or other constraints. The system operator will
not load the less economic units unless the load requires
them. The system operator will also examine the energy market
to determine if reliable energy can be purchased at lower cost
in order to avoid loading higher cost generating sources.
o The second step is the incremental loading of the on-line
generation sources and purchases. This step is performed
continuously as each unit's available generation is dispatched
above its minimum load in order to match the generation to the
load. Generation of the Combined System's various units will
be dispatched from lowest to highest cost. The joint dispatch
will be consistent with available firm transmission, including
the HVDC ties connecting the ERCOT and non-ERCOT components of
the west zone and the Contract Path between the east zone and
the west zone.
See Testimony of J. Craig Baker, filed as Exhibit D-1.2. Following the Merger,
there will be
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(25) In determining the Combined System's generation dispatch priorities,
each zone's most economic generation will be used to serve its native load
customers and previously committed firm load contracts.
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two data relay centers, one in Dallas and the other in Columbus. A computer
system (EMS) will control both the CSW and the AEP generating units to the
desired economic base points adjusted for frequency control requirements of the
respective control areas. These centers will be staffed with personnel 24 hours
a day, 365 days a year. Merger transition teams are currently designing the
organization structure and job responsibilities.
AEPSC will engage in the joint dispatch of the Combined System through
Central Dispatch Planning and Central Economic Dispatch of the generation units
of the Combined System. Through Central Dispatch Planning, the coordination of
each generation unit in the Combined System will be scheduled on a day-ahead
basis. Central Economic Dispatch will compute at regular intervals (currently
every four seconds) the most economic generation base points as dictated by
current operating conditions and will adjust the dispatch of each generating
unit in the Combined System. Taken together, the software programs are designed
to forecast and economically dispatch all generation resources to meet the load
requirements of the Combined System every four seconds, twenty-four hours a day.
The Central Economic Dispatch program will be the current CSW dispatch
program, modified to take into account the internal transmission capabilities of
the Combined System.(26) It will jointly dispatch all of the generators of the
Combined System by calculating at regular intervals (currently every four
seconds) the most economic generation dispatch base points resulting from
current operating conditions. These conditions include, but are not limited to,
the amount of load to be served, cost of fuel, current loading of the
generators, reserve obligations, fuel constraints and transmission capabilities.
After the economic-based points have been calculated on a joint basis, the EMS
will transmit that information to the data relay centers in Dallas and Columbus.
The respective data relay centers will send this information to the Combined
System's generating units, thereby assuring the desired economic base points
adjusted for frequency control requirements of the control areas. The economic
base points for the generators located in the eastern zone will be transmitted
to the data relay center in Columbus via a high-speed data link.
The Central Economic Dispatch program is designed to achieve the most
economic dispatch of the total generation of the Combined System. This program
must honor certain physical conditions of the system. The generation dispatch is
controlled in order not to overload transmission lines or exceed the capability
of the interconnections. The program must also honor limitations on generating
units, as they appear from time to time.
Capacity exchanges will be made between the east zone and the west zone
for periods of one year or less when one zone has capacity available for sale
and the other zone needs capacity to meet its reserve requirements, and when the
selling region's capacity market price is lower than the buying region's cost of
installing capacity or purchasing such capacity in the market. In this regard,
the production cost modeling studies conducted by Applicants indicate that,
during
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(26) This dispatch system is currently used by CSW to coordinate its SPP
and ERCOT operations.
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the first ten years of post-Merger operations, the Combined Company will almost
always be able to economically transfer 250 MW between the east and west zones
(resulting in a 91.9% utilization of the Contract Path). When economic energy is
expected to flow that would exceed the 250 MW Contract Path, then non-firm
transmission service would be requested from third parties to accomplish the
joint dispatch. As explained in the Application, the Combined System will make
use of its rights to nominate secondary points of receipt and delivery under its
transmission service agreements with WR and Ameren for transfers of capacity
from the west zone to the east zone. For transfers of economic energy in excess
of the Contract Path, Applicants will use the OATT of neighboring utilities to
effect delivery. The transfer limits of the Central Economic Dispatch program
would be adjusted to reflect the transmission conditions occurring in real-time.
The System Integration Agreement gives legal effect to the foregoing technical
description.
(b) Other Aspects of Coordination
Applicants will coordinate the operations of the Combined System in other
ways. As noted above, industry restructuring and deregulation have made obsolete
a view that looks solely to joint dispatch as a measure of coordination and
integration. Accordingly, Applicants intend, within the bounds of regulatory
constraints, other more modern means of coordinating the Combined System. Thus,
(i) joint marketing and trading efforts will take advantage of the Combined
System's generation capacity, wholesale customer base, diversity of weather,
time and fuel supply; (ii) AEPSC will coordinate the design and purchase of new
generating facilities, the operation and maintenance of generating capacity
resources, centralized trading and marketing activities, the acquisition and
provision of transmission services needed for inter-zone power transfers,
billing and administration, and other administrative services; and (iii)
information system networks, customer service, procurement organizations,
organizational structures for power generation, energy delivery and customer
relations, and support services will all be centrally coordinated.
(1) Coordinated Trading Operations
The Combined System will coordinate through its joint marketing and
trading efforts, both as a buyer and as a seller. System dispatchers will
continually monitor the generation needs and supply of the Combined System. The
rapidly evolving wholesale power markets surrounding the energy industry will
allow the Combined System to operate its generation assets as a single system by
buying and selling power to decrease the overall production costs of the
Combined System. The diversity of generation capacity, wholesale customer base,
weather, time, fuel supply and localized economic conditions of the Combined
System will create opportunities to allocate resources more efficiently. This
can be accomplished in a number of ways in addition to physically moving power
from one zone to another.
For example, power can be delivered to and from various parts of the
Combined System by neighboring utilities using their respective transmission
systems. Upon consummation of the Merger, joint purchases can be made and
dispatched to the operating companies in a manner that would achieve the
greatest benefits. Weather diversity would make these purchases more
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economically efficient as changes in daily and hourly load forecasts can be
accommodated by joint purchasing and coordinated dispatch. This ability to
diversify supply over a broader region with diverse weather and time zones is
another way that companies can achieve the benefits of economic integration in a
market-based commodity like electricity. In addition, the Combined System also
anticipates making use of the competitive power markets to maximize efficiency
and coordination on the Combined System.
The trading and marketing operations of the Combined System will be
conducted by, and on behalf of, the regulated side of the business. Briefly
stated, power trading and the generation business have a synergistic
relationship. Trading assists the generation function in terms of price
discovery and "finding" the customer. It provides an opportunity to create value
when, for example, there is a difference between gas and electric prices.
Trading will also enable the Combined System to manage risk that might otherwise
be associated with a change in market prices. Ownership of generation provides,
among other things, industry expertise and knowledge that enable the traders to
make more-informed decisions, for the benefit of both shareholders and
customers.
As noted previously, in the past, electric utility companies operated as
self-contained, regulated monopolies that sold their product almost exclusively
to their captive retail customers. By and large, a traditional utility's
customers were limited to those end-users situated in that utility's service
territory. A traditional utility created the most value for its shareholders by
incurring the least possible costs to generate just enough electricity to serve
its native load. Achieving a constant uniform cost of production across a system
necessarily resulted in the greatest return for investors. Federal deregulation
and state restructuring have materially altered this paradigm. Today there is a
vibrant market for electricity. A utility sells electricity not only to the
customers located in its service area, but also to wholesale customers.
The importance of trading operations was magnified by passage of the
Energy Act and the issuance of FERC Order Nos. 888 and 889. One commentator has
recently described the resulting markets as follows:
What resulted is a highly competitive and sophisticated 24-hour power
market. . . . Next we examine what a happens in "real-time." . . .
Economic power schedulers, working in the front office, monitor the
utility's entire real-time system, making sure that the planners have
accurately matched the power supply assets with the hourly demand or
native load. Economic power schedulers also make sure that the planners
have utilized the least expensive power supply assets. Schedulers may also
make adjustments to the power plan in order to maximize the goals of
reducing costs providing customers with the lowest possible wholesale
prices. To make these adjustments economic power schedulers rely on
available power supply assets and the hourly or "spot" market. Unexpected
changes in the weather, mechanical problems at the generating station and
congestion on the transmission grid are only a few of the factors that can
result in deviations from the planner's schedule. Let's assume the
scheduler needs an additional 10 MW of power for two hours, one hour from
now. He or she . . . may consult a data screen that displays the
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real-time spot-market price and the incremental cost of generation or the
cost of producing the additional or next 10 MW of electricity.
If the incremental cost of generation is less than the market price, the
power scheduler may ask the generating plant to increase production or
start a peaking unit. If the price of power from pre-existing contracts is
less than the spot market price or generation, the scheduler may draw upon
the amount of electricity stipulated in the contract. But if the spot
market price is less than the incremental cost of generation or contract
power, the scheduler may notify the traders in the "front office." They
immediately go to the spot market and begin the buying process.
The economic power scheduler may also find that the utility is "long" on
power or has excess capacity for several hours. The traders may now begin
the selling process. Trading in the spot market has the same requirements
as day-ahead, weekly and monthly trading except that it happens at a much
faster pace. Spot market trading averages less than 20 minutes for
securing a buyer or seller scheduling transmission or obtaining an NERC
tag, applying competitive intelligence and price and credit risk
management, confirming the trade and notifying billing, finance and
accounting in the "back office."
Nelson, Kenneth C., "The New World of Power Marketing," Management Quarterly, v.
40, pp. 13-32 (Spring 1999).
To summarize, today a utility creates value by selling as much electricity
as it can do so profitably, after meeting the requirements of native load.
Whether electricity can be sold profitably is controlled by a variety of
factors: the prevailing price of electricity, the location of the potential
customer, the price of fuel, and other factors. As these factors have proven to
be volatile, many utilities have created trading groups composed of individuals
with specialized, sophisticated skill sets necessary to predict market behavior
and to devise appropriate trading strategies. These trading strategies
necessarily have an impact on that particular utility's generation plans. In
other words, if the price of electricity is such that a utility can sell
electricity profitably, the trading group will direct that utility's generating
units to generate electricity to capacity. If, on the other hand, the price of
electricity is so low that it is cheaper to purchase electricity to meet native
load instead of incurring production costs, then that trading group will direct
its generating units to curtail operations.
(2) Coordinated Operations
The Combined System will also be coordinated in a variety of ways beyond
simply the coordination of the generation and transmission within the system.
Among other things, AEPSC, as the designated agent under the System Integration
Agreement, will coordinate the planning and design or purchase of new power
resources; the operation and maintenance of generating units; joint dispatch;
centralized trading and marketing activities, the acquisition and provision of
transmission services needed for inter-zone power transfers, and billing and
administration. All
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of these functions are to be provided on a Combined System basis, treating the
east zone and the west zone on an integrated basis.
(3) Coordinated Administrative and General Services
The coordination and integration of the Combined System is expected to be
further achieved through the coordination and integration of information system
networks; customer service; procurement organizations; organizational structures
for power generation, nuclear generation, and energy delivery and customer
relations; and support services. Many administrative and general services will
be performed for the Combined System by AEPSC.
In applying the integration standard, the Commission has historically
looked beyond simply the coordination of generation and transmission within the
system to the coordination of other activities.(27) As noted above, the Court of
Appeals for the District of Columbia Circuit has recently made clear that the
Commission can appropriately look to "a system's combined 'assets' (and not the
interconnection in particular)" in determining whether the coordination
requirement is met. Madison Gas, supra at n.4. At issue in that matter was the
cost of the interconnection in view of the estimated production cost savings
from a proposed merger. In Madison Gas, the Court of Appeals determined that in
analyzing whether a system will be economically coordinated, the focus must be
on whether the acquisition "as a whole" will "tend toward efficiency and
economy." Id.(28)
The Merger will clearly meet this standard. As explained in the
Application, CSW and AEP estimate that the net savings from the Merger will
exceed $2 billion over 10 years. All aspects of the Combined System will be
centrally and efficiently planned and operated. As with the integrated systems
in other Application-Declarations approved by the Commission, the Combined
System in this matter will be capable of being economically operated as a single
interconnected and coordinated system as demonstrated by the variety of means
through which
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(27) See, e.g., General Public Utilities Corp., HCAR No. 13116 (Mar. 2,
1956) (integration is accomplished through power dispatching by a central load
dispatcher as well as through coordination of maintenance and construction
requirements); Middle South Utilities, Inc., HCAR No. 11782 (March 20, 1953),
petition to reopen denied, HCAR No. 12978 (Sept. 13, 1955), rev'd sub nom.
Louisiana Public Service Comm'n v. SEC, 235 F.2d 167 (5th Cir. 1956), rev'd, 353
U.S. 368 (1957), reh'g denied, 354 U.S. 928 (1957) (integration is accomplished
through an operating committee which coordinates not only the scheduling of
generation and system dispatch, but also makes and keeps records and necessary
reports, coordinates construction programs and provides for all other
interrelated operations involved in the coordination of generation and
transmission); North American Company, HCAR No. 10320 (Dec. 28, 1950) (economic
integration is demonstrated by the exchange of power, the coordination of future
power demand, the sharing of extensive experience with regard to engineering and
other operating problems, and the furnishing of financial aid to the company
being acquired).
(28) The Court of Appeals further noted that "[b]y its terms, however,
section 10(c)(1) does not require that new acquisitions comply to the letter
with section 11." Id. at 1144.
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its operations will be coordinated and the efficiencies and economies expected
to be realized by the Merger.
(iii) Single Area or Region
As required by Section 2(a)(29)(A), the Combined System's operations will
be confined to a "single area or region in one or more States." As Mr. Ganson
Purcell, Chairman of the Securities and Exchange Commission, testified before
the Subcommittee of the House Committee on Interstate and Foreign Commerce in
1946 concerning this standard of the Act:
I wish to make it clear that the Act does not require that an integrated
utility system be broken up, whether or not it crosses State lines, or
that a holding company necessary to integrate the properties of several
operating companies be abolished. . . .(29)
He further stated:
[T]he Commission has not imposed any narrow limit on the concept of what
is an integrated utility system. Recently, . . . we found that . . . [a]
system serving 1700 communities in seven states[] was an integrated
electric utility system. . . .(30)
No absolute size limitation is specified. While the terms "area" and
"region" are not defined in the 1935 Act, it is clear that the "single area or
region" requirement does not mandate that a system's operations be confined to a
small geographic area. The terms "area" or "region," by their nature, are
capable of flexible interpretation, which permits the Commission to respond to
the current state of the industry and allows the Commission to give the terms
practical meaning and effect.(31)
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(29) Study of Operations Pursuant to the Public Utility Holding Company
Act of 1935: Part 3: Hearings Before the House Subcomm. on Securities of the
House Comm. on Interstate and Foreign Commerce, 79th Cong. 856 (1946) (statement
of Ganson Purcell, Chairman of the Securities and Exchange Commission).
(30) Id. at 857 (referring to American Gas and Electric system).
(31) Another way to analyze what should constitute an "area" or "region"
is to examine how potential competitors of the Combined Company operate in the
marketplace. In its 1998 Annual Report, Enron Corporation described itself as
the "premier integrated energy merchant in the rapidly growing competitive North
American wholesale energy market." Enron 1998 Annual Report, p. 13. In the same
section of the report, Enron states that it has generation under construction in
Mississippi and Tennessee, has acquired generation within ten miles of New York
City, and has gas storage available in Houston, with the ability to move
electricity and gas from Houston to the East Coast or Midwest "on a moment's
notice" (id., p. 14). The Report also contains a multi-colored map of "Wholesale
Energy Operations and Services, North America" showing a nationwide network of
gas pipelines and electric grid, with generation assets stretching from
California to New York. Enron is operating on a hemispheric basis, with
operations in Canada and the United States, and with offices in Mexico. From
Enron's perspective, the appropriate "area or region" is at least as large as
the entire United States.
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The Commission has found that the single area or region test should be
applied flexibly when doing so does not undercut the policies of the 1935 Act
"against 'scatteration' -- the ownership of widely dispersed utility properties
which do not lend themselves to efficient operation and effective state
regulation." NIPSCO, supra (applying single area or region requirement with
respect to gas utility system); accord, Sempra, supra. The 1935 Act provides,
and the Commission recognizes, that the question of size must be informed by
practical considerations, including its effect, if any, on the "advantages of
localized management, efficient operation, and the effectiveness of
regulation"(32) in light of "the state of the art and the area or region
affected" as discussed in Item 3.B.1.a.(iv) below.(33)
- --------------------------------------------------------------------------------
Other companies similarly view the appropriate marketplace on a nationwide
basis. For example, the Southern Company has electricity generation and/or
distribution operations in nine states, including Alabama, Georgia, Florida,
Mississippi, Virginia, Indiana, Massachusetts, Texas and California, and is
constructing new gas distribution projects in North Carolina and Maine. Entergy
Corporation provides services in several states, including supplying electricity
in Arkansas, Louisiana, Mississippi and Texas, as well as in Massachusetts via
its nuclear power subsidiary. Duke Energy Corporation, headquartered in
Charlotte, North Carolina, furnishes energy-related services in North and South
Carolina, is currently developing electric generation plants in Connecticut,
Missouri, Florida, California, Texas and Virginia, and offers energy trading and
marketing services in New York, Rhode Island, Pennsylvania, Indiana, Georgia,
South Carolina, Texas, Oklahoma, New Mexico, Nevada and Utah. Edison
International, in addition to its utility operating company subsidiary located
in California, has twenty-three energy generation facilities located in Northern
California, New Jersey, New York, Illinois, Pennsylvania, Florida, Washington,
West Virginia and Nevada. PP&L, Inc., headquartered in Pennsylvania, provides
energy related services in Pennsylvania, New Jersey, Maryland, Ohio, Delaware,
West Virginia, Virginia and various New England states, recently acquired
generation facilities in Maine, Oregon and Montana, and is developing power
plants in Arizona and Connecticut. NRG Energy has generation facilities in
California, Colorado, Connecticut, Florida, Illinois, Maine, Massachusetts,
Michigan, Minnesota, New Hampshire, New Jersey, New York, North Carolina,
Oklahoma, Pennsylvania, South Carolina, Utah, Virginia and Washington, and is
developing generation facilities in Louisiana. Sempra owns a gas and electric
utility company in California, has generation facilities in Connecticut, and has
a gas pipeline in North Carolina.
Other utilities view the marketplace on a global basis without regard to
national borders. The FERC recently approved the acquisition of PacifiCorp by
ScottishPower p.l.c. and the acquisition of New England Electric System (and the
potentially indirect acquisition of Energy Utilities) by National Grid Group
p.l.c., utilities located outside the United States. British Energy, through its
interest in Amergen Energy, has indirectly acquired the Pilgrim Nuclear Plant
from Boston Energy, the Three Mile Island Unit 1 from General Public Utility
Systems, and the Clinton Nuclear Plant from Illinois Power Company.
(32) NIPSCO, supra (in analyzing the single area or region requirement for
gas utility properties, the Commission noted that the acquisition would not have
"an adverse effect upon localized management, efficient operation or effective
operation."); accord, Sempra, supra.
(33) In fact, as discussed in note 12 above, Applicants submit that the
integrated utility system requirement could be interpreted to involve only a
three-part test, with the last two tests read as one.
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In considering size, the Commission has consistently found that utility
systems spanning multiple states satisfy the single area or region requirement
of the 1935 Act. For example, the Entergy system covers portions of four states
(Entergy, supra), the Southern system provides electric service to customers in
portions of four states (Southern Co., HCAR No. 24579 (Feb. 12, 1988)), and the
principal integrated system of NCE covers portions of five states (with all of
its electric operations serving customers in six states) and operates in two
reliability councils (New Century Energies supra (citation omitted)). Other
registered holding companies also operate in multiple states. For example, the
Allegheny Energy, Inc. system provides electricity to customers in parts of five
states (Filings under the Public Utility Holding Company Act of 1935, HCAR No.
26846 (March 20, 1998)). As early as 1945, the Commission found that AEP's
operations in seven states were confined to a single region or area. American
Gas and Electric Co., HCAR No. 6333 (Dec. 26, 1945). In addition, in light of
the present state of the industry, other utility systems, although they are not
registered utility holding companies, span multiple states.(34) For example, the
PacifiCorp system covers portions of seven states (Annual Report of PacifiCorp
on Form 10-K for the year ended December 31, 1997), and the UtiliCorp system
covers portions of nine states (Form U-1 filed as of July 2, 1998).
In addition to not specifying an absolute size for an "area" or "region,"
the 1935 Act likewise does not provide any specific parameters with respect to
the term "single" in the "single area or region" test. In considering distance,
the Commission has found that the combining systems need not be contiguous in
order for the requirement to be met. See, e.g., Conectiv, supra; cf. New Century
Energies, supra (finding that electric utilities located in two different power
pools, in two different reliability councils, in both the Eastern and Western
Interconnects, and with a physical separation of 300 miles were in same area or
region); Electric Energy, Inc., HCAR No. 13781 (Nov. 28, 1958) (utility assets
were within the same area or region as the acquirer's service area despite a
distance of 100 miles crossing two states); Mississippi Valley Generating Co.,
HCAR No. 12794 (Feb. 9, 1955) (single area or region test met where generating
station was located 150 air miles from the territory served by the acquiring
company).
In tandem with not specifying the absolute size of an "area" or "region,"
the 1935 Act makes no reference to a set of pre-defined regions with specific
boundaries. It follows that the concept of region is not constrained by
geographical boundaries such as rivers or mountains; nor is it constrained by
regional designations which are part of the common vocabulary (e.g., northeast,
southwest, or midwest).
The Commission's determination of whether the requirement is met is made
in light of "the existing state of the art of generation and transmission and
the demonstrated economic advantages of the proposed arrangement." Connecticut
Yankee Atomic Power Co., HCAR No. 14968 (Nov. 15, 1963); see also, Vermont
Yankee Nuclear Power Corp., HCAR No. 15958 (Feb.
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(34) In this regard, Applicants believe that the continued economic
viability of large utility holding company systems suggests their efficient
operation and, accordingly, these systems should be evaluated on the same basis
as comparably large utility systems not regulated as registered utility holding
companies under the 1935 Act.
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6, 1968), rev'd and remanded on other grounds, Municipal Elec. Ass'n v. SEC.,
413 F.2d 1052 (D.C. Cir. 1969). The Commission has applied flexibly the
requirement based on the facts and circumstances involved and the practicalities
of the situation at hand. See, e.g., Yankee Atomic, supra.
The Division has recommended that the Commission "interpret the 'single
area or region' requirement flexibly, recognizing technological advances,
consistent with the purposes and provisions of the Act" and that the Commission
place "more emphasis on whether an acquisition will be economical." 1995 Report
at 66, 69. The Division has recognized that "recent institutional, legal and
technological changes . . . have reduced the relative importance of . . .
geographical limitations by permitting greater control, coordination and
efficiencies" and "have expanded the means for achieving the interconnection and
economic operation and coordination of utilities with non-contiguous service
territories." 1995 Report at 69. It has also recognized that the concept of
"geographic integration" has been affected by "technological advances on the
ability to transmit electric energy economically over longer distances, and
other developments in the industry, such as brokers and marketers." Id. Such
advances and developments are breaking down traditional boundaries and concepts
of regions. The Commission has confirmed its support for the Division's study,
citing, in particular, the Division's recommendation that the Commission
"continue to interpret the 'single area or region' requirement of [the 1935 Act]
to take into account technological advances." NIPSCO, supra; accord, Sempra,
supra.
Prior to the Merger, the AEP System and the CSW System will be separated
by only 150 miles at their closest point, a distance which the Commission has
previously found acceptable under the single area or region test. The Combined
Company will operate in eleven contiguous states located in the mid-America
region of the United States, connected in the middle by the states of Arkansas
and Tennessee.(35)
Moreover, that the Combined Company meets the single region test is
further supported by adopting a definition of region used by the Commission for
purposes of its size analysis under Section 10(b)(1). In Entergy, supra, the
Commission adopted the applicants' definition of the relevant region for Section
10(b)(1) purposes to include themselves and those electric utilities directly
interconnected with either or both. In today's increasingly competitive world,
AEP and CSW do not operate as isolated companies and their geographic region
should be analyzed in terms of their most accessible markets -- the
Interconnected Utilities. The service territories of these Interconnected
Utilities surround the Combined System and effectively close the distance
between the former AEP and CSW, bringing them even closer together.
The Merger represents a logical extension of the AEP System's existing
service territory in light of contemporary circumstances. As the Commission has
recognized, the concept of area
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(35) The concept of a geographic region, which includes the states in
which AEP and CSW are based (Ohio and Texas), exists within the electric
industry. In 1956, state regulators from 14 states, including Ohio and Texas,
formed the Mid-America Regulatory Conference. See Mid-America Regulatory
Conference, A History, 1956-1995.
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or region is not a static one and must be refashioned to take into account the
present realities of the electric industry, consistent with the purposes of the
1935 Act. These present realities have effectively shrunk the world in which the
industry operates and support a finding that the concept of a region can
encompass four additional states more than 50 years after the Commission's
finding that the current seven-state AEP System operates within an area or
region.
As the restructuring of the electric industry progresses, traditional
boundaries will become more blurred and the contours of regional markets will
change. Structural changes in a closely-related industry subject to similar
regulatory regimes, the natural gas industry, are influencing the restructuring
of the electricity industry and further breaking down traditional
boundaries.(36) Natural gas marketers, a new participant in the gas industry,
broke up old pipeline customer networks and demanded open access conditions,
fueling the industry's restructuring. See "Restructuring Energy Industries:
Lessons from Natural Gas," Energy Information Administration, Natural Gas
Monthly, May 1997 [hereinafter "Natural Gas Monthly"]. With the restructuring of
the gas industry, regional markets have become "interrelated" and the "stages
and operations of the natural gas industry have been integrated to an
unprecedented degree across North America." Natural Gas 1996 at 97. One of the
most recent innovations in the natural gas marketplace is the development of
market centers and hubs. Id. at x. At least 39 such centers were operating in
the United States and Canada by 1996, providing numerous interconnections and
routes to move gas from production areas to markets. Id. These market centers
have "made it easier for buyers to access the least expensive source of supply
and helped sellers to allocate gas to the highest bidding buyer." Id. at 78.
Developments in the natural gas industry that have eroded traditional
boundaries are being duplicated today in the electricity industry.(37) Many gas
marketers are moving into the new
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(36) Restructuring of the natural gas industry started more than 10 years
ago, introducing competitive market forces into the industry's operations. See
Energy Information Administration, Office of Oil and Gas, Department of Energy,
Natural Gas 1996: Issues and Trends (December 1996) at xiii [hereinafter
"Natural Gas 1996"]. With the unbundling of pipeline company transportation and
sale services and the decontrol of natural gas wellhead prices over the last 20
years, the gas industry has responded by entering into new contractual
relationships, developing new services and new tools for managing risk and
creating a new participant -- the natural gas marketer. Id. at 1. Regulatory
restraints have been increasingly removed from the sale and transport of natural
gas, increasing the choices of participants in the natural gas industry, from
suppliers to consumers. Id. at ix. Energy markets for natural gas have become
increasingly competitive. Id. Regulatory changes seen in the interstate market
are being brought to the level of local distribution as state regulators promote
consumer choice in retail gas markets. Id. at 1, 113.
(37) The breakdown of traditional boundaries is also seen in industries
beyond the utility industry. Technological advances, regulatory and legal
changes facilitating nationwide holding company acquisitions and nationwide
branching, and the entrance of nonbank providers of financial services have lead
to structural changes in the banking industry resulting in a trend toward
consolidation. In 1997, the number of interstate bank-to-bank mergers totaled
189. Bank Mergers: Hearings Before the House Banking and Financial Services
Comm., 105th Cong. 18-21 (1998) (statement of John D. Hawke, Jr., Treasury
Department Under Secretary for Domestic Finance). Similarly, the procompetitive,
deregulatory
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electricity markets, and the development of financial instruments used in the
gas industry, such as spot, forward, futures, and options contracts, are being
imported into the electricity industry. Natural Gas 1996 at xiii. Electric
utilities are in the process of divesting or separating their transmission and
distribution assets from their generation assets. As a result of federal and
state electric industry restructuring legislation, more than 570 energy
marketing companies have registered with the FERC and are currently competing
with electric utilities to market electricity on a wholesale and retail basis to
customers who were previously an electric utilities' captive customers. Edison
Electric Institute, Directory of Electric Power Producers, 106th ed. (1999). In
short, as it has for the natural gas industry, the Commission can easily
interpret the concept of "area or region" to include an area or region in which
the merging companies both buy or sell electricity.
Given the proximity of the AEP System to the CSW System and the present
technological ability to economically transmit power over longer distances, and
given that the Combined System will be economically operated as a single
integrated and coordinated system as described in Item 1.B.3, the Combined
Company satisfies the 1935 Act's requirement with respect to operating in a
"single area or region." The demonstrated economic advantages of the Merger
resulting in nearly $2 billion in net non-production savings and $98 million in
net fuel-related savings (as described below) also support the finding that the
single area or region test is met, consistent with the Commission's tradition of
balancing the various objectives of the 1935 Act. As discussed immediately
below, the size of the area or region in which the Combined Company will operate
will not result in the evils which the 1935 Act was meant to eliminate; namely,
it does not impair the advantages of localized management, efficient operation
or effective regulation.
(iv) Localized Management, Efficient Operation and Effective Regulation
Section 2(a)(29)(A), like Section 10(b)(1) discussed above, requires the
Commission to consider the size of the combined system. Section 2(a)(29)(A) has
been interpreted to require that the combined system must not be so large as to
impair (considering the state of the art and the area or region affected) the
advantages of localized management, efficient operation, and the effectiveness
of regulation. As the Commission stated in AEP, supra:
[N]either section can be said to impose any precise limits on holding
company growth. Both sections are couched in discretionary terms. They
require the Commission to exercise its best judgment as to the maximum
size of a holding company in a particular area, considering the state of
the art and the area or region affected. In exercising its
- --------------------------------------------------------------------------------
framework established by Congress in the Telecommunication Act of 1996 has
removed the legal and economic barriers to the entry of telecommunications firms
into many markets. The Bell Atlantic-NYNEX merger approved under the
Telecommunications Act by the FCC resulted in Bell Atlantic serving 13 states.
The Effects of Consolidation on the State of Competition in the
Telecommunications Industry: Oversight Hearings Before the House Judiciary
Comm., 105th Cong. 1-2 (1998) (submitted statement of Susan Ness, Commissioner
of the Federal Communication Commission).
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discretion, the Commission must balance the various objectives of the 1935
Act. The Commission stated in Commonwealth & Southern Corp., HCAR No. 7615
(Aug. 1, 1947):
We do not, in applying particular size standards, lose sight of the
objectives of other criteria. There must be a reconciliation of all objectives
to the end of accomplishing a satisfactory administration of the [1935] Act.
Thus we do not disregard operating efficiency in our determination of whether
size is excessive from the viewpoint of localized management or effectiveness of
regulation.
As will be discussed below, difficult balancing decisions need not be made
because each prong of this standard is easily met. The size of the Combined
System does not impair the advantages of localized management, efficient
operation or the effectiveness of regulation. The Merger actually increases the
efficiency of operations.
- Localized Management
The Commission has found that an acquisition does not impair the
advantages of localized management where the new holding company's
"management [would be] drawn from the present management" (Centerior,
supra), or where the acquired company's management would remain
substantially intact (AEP, supra). The Commission has noted that the
distance of corporate headquarters from local management was a "less
important factor in determining what is in the public interest" given the
"present-day ease of communication and transportation." AEP, supra. The
Commission also evaluates localized management in terms of whether a
merged system will be "responsive to local needs." AEP, supra.
The management of the Combined Company will be drawn primarily from the
existing management of AEP and CSW and their subsidiaries. AEP will
continue to maintain its system headquarters in Columbus, Ohio and will
maintain the management structure of its combined subsidiary companies
(including the electric operating and other subsidiary companies of CSW)
essentially intact. CSW and AEP have operated with virtual service company
management which has located management personnel in a number of operating
locations throughout the service territories. In 1996, AEP reorganized
into a centralized management structure with localized management
remaining essentially in place, with the exception of the electric utility
subsidiary headquarters operating management teams being realigned into
either the Power Generation, Nuclear Generation, and Energy Delivery and
Customer Relations business units. CSW completed a similar reorganization
process in 1994.
For example, at AEP, the subsidiary companies' generation operations were
realigned into the Power Generation and Nuclear Generation business units
while the transmission and distribution operations were realigned into the
Energy Delivery business unit. As part of this realignment, transmission
operations were structured with a centralized
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management and engineering organization which oversees three transmission
operating regions. The distribution operations were structured with a
centralized management and engineering structure which oversees 30
distribution districts which report to one of eight distribution regions.
Customer services functions were also realigned under the Energy Delivery
and Customer Relations business unit into a regional structure with four
customer call centers, a single customer information system and
centralized management of the customer service operations.
As part of these individual reorganization efforts, the electric utility
subsidiaries of AEP began doing business under the AEP brand without
altering their separate legal identities, assets and liabilities,
franchises and certificates of public convenience and necessity. Likewise,
the electric utility subsidiaries of CSW retained their separate corporate
identities, assets and liabilities, franchises and certificates of public
convenience and necessity.
The Applicants expect that the impact of the Merger will be predominantly
confined to the merging of CSWS into AEPSC and the establishment of a
business unit and management structure which looks very much like the
existing structures of AEP and CSW. The electric utility subsidiaries will
continue to operate through the regional offices with local service
personnel and line crews available to respond to customers needs. The
Combined Company will preserve the well established delegations of
authority -- currently in place at AEP and CSW -- which permit the local,
district and regional management teams to budget for, operate and maintain
the electric distribution system, to procure materials and supplies and to
schedule work forces in order to continue to provide the high quality of
service which the customers of AEP and CSW have enjoyed in the past.
The orders of the Oklahoma Commission, the Arkansas Commission, the
Indiana Commission, the Kentucky Commission, the Louisiana Commission, and
the Michigan Commission approving the Merger, as well as the order of the
Texas Commission finding the Merger consistent with the public interest,
impose an extensive list of service quality standards on the utility
operating companies operating within their states. In Oklahoma and
Michigan, the Oklahoma Commission and the Michigan Commission established
standards with respect to (i) customer service center calls, (ii)
responses to requests for service, (iii) billing adjustments, (iv)
customer satisfaction, and (v) reliability performance. The Louisiana
Commission, in a service quality inquiry proceeding, has recently
established customer service, staffing, and tree standards for SWEPCO. In
Arkansas, Louisiana, Indiana, Kentucky, and Michigan, the state
commissions required that the Combined Company maintain or improve
historical reliability performance levels. Moreover, the Texas Commission
and the Louisiana Commission have recently been active in promoting
utilities' responsiveness to customers and are expected to closely monitor
the Combined Company's performance in this regard. See, e.g., Public
Utility Commission of Texas Substantive Rule 25.21 et seq.; Louisiana
Public Service Commission General Order of April 30, 1998.
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Likewise, the order of the Texas Commission approved service quality
standards and provisions to ensure the continuity of CSW's local
management and organizational structure following the Merger. For example,
in Texas Applicants have agreed to (i) freeze CSW operating company field
positions and customer service jobs until October of 2000, (ii) maintain a
bargaining and decision-making presence in the CSW region with authority
to enter binding agreements with wholesale customers up to at least $3
million, (iii) designate an employee who will act as a contact to the
Texas Commission and consumer advocates seeking information regarding
affiliate transactions and personnel transfers, and (iv) designate an
employee or agent in Texas who will act as a contact for retail consumers
regarding service and reliability concerns. In short, the customer service
and field operations management structures of AEP and CSW, which are
responsive to local needs, will be left essentially intact after the
Merger. Accordingly, the advantages of localized management will not be
impaired.
- Efficient Operation
As discussed above in the analysis of Section 10(b)(1), the size of the
Combined Company will not impede efficient operation; rather, the Merger
will result in significant economies and efficiencies as described in Item
3.B.2 below. Economic dispatch (as described in Item 1.B.3) is more
efficiently performed on a centralized basis because of economies of
scale, standardized operating and maintenance practices and closer
coordination of system-wide matters.
Both AEP and CSW have efficient generating facilities that were recently
noted by Public Utilities Fortnightly as being the fourth and sixth most
efficient in the utility industry (September 1, 1998 report). In addition,
AEP and CSW have consistently been rated in the top five utilities in the
American Society for Quality and The University of Michigan Business
Schools American Customer Satisfaction Index (ACSI). In the 1997 ACSI
survey results which were published in the February 16, 1998 issue of
Fortune Magazine, CSW tied for second place and AEP tied for third place,
out of more than 20 utilities surveyed. Because the Merger is expected to
have little impact on field personnel in either power generation or
transmission and distribution, AEP and CSW expect that the Combined
Company will to continue to perform at these high efficiency levels.
The divestiture of the Texas and Oklahoma generating assets will not
adversely affect the Combined Company's ability to operate on an efficient
basis. The Combined Company will jointly dispatch generating units under
its control, make economic purchases of power, and supply power to its
customers. The fact that certain generating capacity will
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no longer be controlled by the Combined Company will not change the
centrally coordinated, least-cost approach to operating the combined
system.(38)
- Effective Regulation
The Merger will not impair the effectiveness of regulation at either the
federal or state level.
On the federal level, the Combined Company will continue to be regulated
by the Commission. The electric utility subsidiaries of the Combined
Company will continue to be regulated by the FERC with respect to
interstate electric sales for resale and transmission services, by the NRC
with respect to the operation of nuclear facilities, and by the FCC with
respect to certain communications licenses. The jurisdiction of other
federal regulators is also not affected.
FERC declined to set the issue of effectiveness of regulation for hearing.
Indeed, the FERC concluded that Applicants had adequately addressed the
FERC's concerns about its own jurisdiction and that state commissions
could "impose in their own proceedings appropriate conditions to ensure
that there is no impairment of effective regulation at the state level."
85 FERC at 61,821-822. Thus, FERC has already concluded that the Merger
will not impair the effectiveness of regulation and that the issue does
not merit further investigation.
On the state level, the Commission has found that the effectiveness of
regulation is not impaired where the same state regulators have
jurisdiction both before and after a merger. See, e.g., Conectiv, supra;
GPU, supra. In finding that regulation is not impaired, the Commission has
also emphasized that the various state regulators have approved the
combination. Entergy, supra. The electric utility subsidiaries of CSW will
continue to be regulated by the state commissions of Arkansas, Louisiana,
Oklahoma and Texas with respect to retail rates, service and related
matters. The electric utility subsidiaries of AEP will continue to be
regulated by the state commissions of Indiana, Kentucky, Michigan, Ohio,
Tennessee, Virginia, and West Virginia with respect to retail rates,
service and related matters.(39)
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(38) In fact, under the recent order of the Texas Commission, most of the
generating capacity being divested will be subject to recall by the Combined
Company during peak months to ensure that adequate capacity is available to
serve native load. See Texas Order, page 15.
(39) The AEP and CSW management structures are designed to facilitate
communications and relationships with state regulators. Each company has
established State offices which have responsibility for regulatory,
environmental, and corporate communications and have other external relations
purposes. These state offices provide a single point of contact with each of the
state regulatory and environmental offices and have the responsibility for
handling all regulatory contacts, including making regulatory filings and
answering customer inquiries to the regulatory commissions. It is expected that
these offices will be left essentially intact after the Merger.
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The FERC's conclusion that the states will take appropriate action to
protect their jurisdiction was correct.(40) The best evidence of this is
that none of the state commissions which regulate the AEP and CSW utility
subsidiaries has raised as an objection impairment of its ability to
regulate the Combined Company after the Merger, or any other objection, in
submissions to the Commission. In fact, the order of the Texas Commission
approved several provisions designed to ensure the effectiveness of its
regulatory authority over the Combined Company's operations in Texas.
Among other things, these provisions include (i) a requirement that the
Combined Company continue to comply with the Texas Commission's
transmission pricing rules in ERCOT, (ii) a commitment by the Combined
Company not to withdraw from either ERCOT or the SPP without the Texas
Commission's prior approval, and (iii) a commitment that the Combined
Company will not contend in any forum that the jurisdiction of the Texas
Commission over any of CSW's operating companies located in Texas changed
as a result of the Merger. Thus, rather than impairing the Texas
Commission's regulatory authority, the order specifically safeguards that
authority.
Moreover, the Merger Agreement requires approvals from all regulatory
authorities having jurisdiction over the Merger as a condition to the
consummation of the Merger. The Merger has been approved by the state
commissions in Oklahoma, Arkansas, Louisiana, Indiana, Kentucky, and
Michigan, and the order of the Texas Commission finds that the Merger is
consistent with the public interest. Applicants are working closely with
other regulators (both state and federal) to obtain the remaining
approvals (as described below in Item 4).
b. Section 11(b)(1) (Acquisition of Non-Utility Interests)
Section 11(b)(1) of the 1935 Act also requires that a registered holding
company limit its operations to a single integrated public utility system and
"such other businesses as are reasonably incidental, or economically necessary
or appropriate to the operations of such integrated public-utility system." Each
of CSW's non-utility business interests conforms to the "other business"
standards of the 1935 Act as previously determined by the Commission. The
indirect acquisition by AEP of CSW's non-utility businesses in no way affects
the functional relationship of these businesses to the Combined Company's core
electric business following the Merger. See Item 3.F below for a detailed
discussion on the acquisition by AEP of CSW's non-utility businesses.
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(40) The Oklahoma, Kentucky, Arkansas, and Indiana Commissions conditioned
the approval of the Merger on Applicants' agreement not to assert in proceedings
before that state commission, or in court proceedings involving orders of that
state commission, that the authority of the Commission as interpreted in Ohio
Power v. F.E.R.C., 554 F.2d 779 (D.C. Cir. 1992) cert. denied, 498 U.S. 73
(1992) impairs that state commission's ability to examine the reasonableness of
non-power affiliate costs to be passed through to that state's retail consumers.
The order of the Texas Commission contains a similar provision.
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c. Section 11(b)(2)
Section 11(b)(2) of the 1935 Act directs the Commission "to ensure that
the corporate structure or continued existence of any company in the
holding-company system does not unduly or unnecessarily complicate the
structure, or unfairly or inequitably distribute voting power among security
holders, of such holding-company system." The Merger is consistent with Section
11(b)(2). The resulting capital structure is not unduly complicated as discussed
in Item 3.A.3 above. See, e.g., Sierra Pacific Resources, HCAR No. 24566 (Jan.
28, 1988), aff'd Environmental Action, Inc., 895 F.2d 1255 (D.C. Cir. 1990)
(Commission incorporates its Section 10(b)(3) capital structure analysis into
its Section 11(b)(2) corporate structure analysis). Voting power is equitably
and fairly distributed among the security holders of each of AEP and CSW and
their current subsidiaries, all of which have been approved by the Commission in
previous proceedings. The shareholders of AEP and CSW, respectively, have
overwhelmingly approved the shareholder actions necessary to effect the Merger
or the Merger itself.
Immediately following the Merger, AEP will be a registered holding company
with respect to CSW, which, in turn, will be a registered holding company with
respect to the electric utility subsidiaries and other subsidiaries it currently
owns (with the exception of CSWS, which will be merged into AEPSC, and CSW
Credit, which will be directly held by the Combined Company). See Exhibit E-6.
Although it is intended that these interests will be restructured, the final
ownership structure has not yet been determined. Accordingly, Applicants request
that CSW survive as a holding company interposed between AEP and the electric
utility subsidiaries and a portion of the other subsidiaries it currently owns
for a period of up to eight years following the closing of the Merger.
Applicants have determined that the proposed corporate structure of the
Combined Company following the Merger will be in the best interests of the
Combined Company's shareholders and ratepayers. The continued existence of CSW
as an intermediate holding company will result in AEP having a tax basis in CSW
equal to the aggregate tax basis of the CSW shareholders in CSW prior to the
Merger. This tax basis would be lost if CSW were not retained as an intermediate
holding company. See Exhibit J for an explanation of certain relevant tax basis
issues. Retaining the appropriate tax basis in CSW will allow AEP to realize
significant tax savings in the event that AEP were to divest CSW assets in a
future taxable transaction (although AEP does not at present have any plan to
divest CSW assets). Because the costs and complications associated with the
survival of CSW as an intermediate holding company are minimal, AEP and CSW
management have determined that the transitional structure will contribute to
the positive future financial condition of the Combined Company and will
maximize shareholder value.
Although CSW will have an important economic purpose following the Merger,
CSW will have minimal operational functions. As an intermediate holding company,
CSW largely will be a conduit between AEP and its subsidiaries with respect to
capital contributions, if any, and dividends. The future management of the
Combined Company does not anticipate that CSW
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will be involved in any intra-system financing other than maintaining its
current guarantees on the debts of its subsidiaries and participating in the
Money Pool (as previously authorized by the Commission) during the transitional
period after the Merger to the extent necessary. Moreover, the future management
of the Combined Company does not anticipate that CSW will engage in securities
transactions (except as noted in the previous sentence); acquire securities,
utility assets or other interests; or enter into or take any step in the
performance of any service, sales, or construction contract. CSW will continue
to make, keep and preserve accounts and records and make any required reports to
the Commission and other appropriate agencies.
Under Section 10(c)(1) of the 1935 Act, the Commission must ensure that a
proposed acquisition subject to the Act will not be 'detrimental to the carrying
out of the provisions of Section 11.' Section 11(b)(2) mandates a simple
corporate structure for a registered holding company system. See, e.g., TUC
Holding Co., HCAR No. 26749, n. 20 (Aug. 1, 1997). Section 11(b)(2) includes two
principal restrictions. First, the Section requires registered holding companies
to take such action as the Commission finds necessary to ensure that registered
holding company systems ultimately are restructured to include no more than two
tiers of holding companies. Second, the Section directs the Commission to
evaluate the facts and circumstances 'to ensure that the corporate structure or
continued existence of any company in the holding-company system does not unduly
or unnecessarily complicate the structure . . . of such holding-company system.'
As discussed below, the transitional corporate structure of the Combined
Company, in which AEP and CSW will survive as first and second tier holding
companies, respectively, in the Combined Company's holding company system, will
be consistent with therequirements of Section 11(b)(2).4 Corporate structures
including two tiers of holding companies are specifically envisioned under the
1935 Act and its Rules, and, in this case, the existence of two registered
holding companies in one system will not result in unnecessary or undue
complications. To the contrary, the minimal complications that may be introduced
by the continued existence of CSW are necessary and appropriate in serving the
interests of the Combined Company, its shareholders and ratepayers.
(i) The Existence of Two Tiers of Registered Holding Companies in
a Single Integrated Public-Utility System Is Not Prohibited
under the 1935 Act
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(41) Applicants note that SWEPCO, a wholly owned electric public-utility
operating subsidiary of CSW, is technically a registered holding company under
the 1935 Act by virtue of its 47.6% ownership interest in a company (which
technically is an 'electric utility company' under the 1935 Act) whose assets at
the end of 1997 accounted for approximately .02% of SWEPCO's total assets (based
on SWEPCO's and its subsidiary's total assets at year-end December 31, 1997, and
November 30, 1997, respectively). Applicants acknowledge that questions could
be raised under Section 11(b)(2) if SWEPCO were to remain a holding company
within the Combined Company following the Merger. Accordingly, Applicants hereby
commit to take appropriate action to eliminate SWEPCO's holding company status
following the Merger.
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The 1935 Act was passed, in large part, to curb abuses identified by
Congress arising out of 'the utilization of highly-pyramided and complex holding
company systems as a means of controlling and exploiting utility operating
companies, as well as companies in non-utility fields . . . .' Vermont Yankee
Nuclear Power Corp., HCAR No. 15958 (Feb. 6, 1968), rev'd and remanded on other
grounds, Municipal Elec. Ass'n v. SEC, 413 F.2d 1052 (D.C. Cir. 1969)
[hereinafter 'Vermont Yankee']. Holding companies 'piled on top of holding
companies result[ed] in highly leveraged corporate structures of extraordinary
complexity.' AEP.
In addressing these perceived abuses, however, Congress did not prohibit
holding companies entirely. Rather, it required the Commission to take such
action as necessary to ensure that each registered holding company system be
restructured to include nomore than two tiers of holding companies through the
'great-grandfather clause' of Section 11(b)(2).(42) The legislative history of
the 1935 Act confirms that Congress's express authorization of two tiers of
holding companies in a registered holding company system was consistent with its
intent in passing the 1935 Act. While the version of the 1935 Act originally
passed by the Senate contained a provision, Section 11(b)(3), that required that
within five years all holding companies should cease to be holding companies
unless the equivalent of a certificate of convenience and necessity were
obtained from the Federal Power Commission, see American Power & Light Co. v.
SEC, 329 U.S. 90, 146, 147 (1946) (citing to S. 2796, 74th Cong., 1st Sess.),
the bill that became law replaced this section with the 'great-grandfather
clause' of Section 11(b)(2). See 79 Cong. Rec. 14620 (August 24, 1935).
The 1935 Act is silent regarding whether a registered holding company
system with two tiers of holding companies is limited to one registered holding
company. However, the Commission's Rules promulgated under the 1935 Act
expressly envision a holding company system with more than one registered
holding company. Rule 1(c) provides that 'where any holding company system
includes more than one registered holding company, the annual report shall be
filed by the top registered holding company in such system.' Similarly, the
instructions to Form U5S (relating to holding company annual reports) track the
requirements of Rule 1(c), defining 'holding company system' to mean 'the parent
registered holding company together with all its subsidiary companies, including
all subsidiary registered holding companies.'(43) See also,
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(42) The 'great-grandfather clause' of Section 11(b)(2) provides that 'the
Commission shall require each registered holding company (and any company in the
same holding-company system with such holding company) to take such action as
the Commission shall find necessary in order that such holding company shall
cease to be a holding company with respect to each of its subsidiary companies
which itself has a subsidiary company which is a holding company.' See also,
Entergy, supra, ('Section 11(b)(2) allows three tiers of companies in a
registered holding company system.').
(43) Rule 1, adopted in 1941, was amended in 1951 to include the current
formulation of subsection (c). HCAR No. 10432 (Mar. 12, 1951). Prior to 1951,
each registered holding company in a holding company system was required to file
its own separate annual report on Form U5S.Id. The current formulation of Rule
1(c) was adopted one year before the Commission 'largely completed' its task of
'simplifying and reorganizing the complex financial and corporate structures of
holding company systems as required by section 11.' See 1995 Report at viii.
Since 1951, the Commission has amended Rule 1 twice, without altering the
language of Rule 1(c). See HCAR No. 17435 (Jan. 25, 1972) (imposing a
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Rule 87(c) (providing that, in the context of service, sales, and construction
contracts, it is Rule 85, as opposed to Rule 87, that is applicable to a
'subsidiary which is itself a registered holding company'). In summary, the
transitional corporate structure of the Combined Company, which includes AEP as
the top registered holding company and CSW as a subsidiary registered holding
company, satisfies the first requirement of Section 11(b)(2).
(ii) The Existence of CSW Will Not Unduly or Unnecessarily
Complicate the Structure of the Holding Company System
The second prong of Section 11(b)(2) requires that the Commission ensure
that 'the corporate structure or continued existence of any company in the
holding-company system does not unduly or unnecessarily complicate the structure
. . . of such holding-company system.' The existence of a subsidiary holding
company does not run afoul of Section 11(b)(2) merely because it causes the
structure of the holding company system to be more complicated. Rather, the
existence of a company violates Section 11(b)(2) only if it causes unnecessary
or undue complications. The Commission has interpreted Section 11(b)(2) to
require the elimination of any holding company that serves no useful purpose or
economic function. See, e.g., WPL Holdings, Inc., HCAR No. 25377 (Sept. 18,
1991); Peoples Gas Light and Coke Co., HCAR No. 15929 (Dec. 22, 1967); Voting
Trustees of Granite City Generating Co., HCAR No. 14739 (Nov. 5, 1962).
In prior proceedings, the Commission has determined that the existence of
a second tier holding company satisfies the Section 11(b)(2) test. See, e.g.,
Entergy, supra (the Commission found that the addition of an exempt sub-holding
company to a registered holding company system did not create an undue or
unnecessary corporate complexity); Cinergy Corp, HCAR No. 26146 (Oct. 21, 1994)
(the Commission approved a merger where a registered holding company would be
the parent of an exempt holding company). Moreover, the Commission has in other
circumstances allowed a holding company system with two tiers of registered
holding companies. See Annual Report on U5S of Central and South West
Corporation and Southwestern Electric Power Company for year ended December 31,
1997 (Central and South West Corporation and its wholly owned subsidiary,
Southwestern Electric Power Company, are both registered holding companies);
Citizens Utilities Company, HCAR No. 25331 (June 14, 1991) (Louisiana General
Services, Inc. and its wholly owned subsidiary, LGS Pipeline, Inc., were both
exempt, registered holding companies prior to a merger).
In this case, the temporary survival of CSW as a holding company will
result in minimal complications. CSW will not perform any significant
operational functions. Although it will
- --------------------------------------------------------------------------------
filing fee for Form U5S); HCAR No. 26575 (Sept. 17, 1996) (removing the filing
fee). As late as 1984, the Commission, in adopting amendments to Form U5S,
specifically recognized the existence of Rule 1(c) and its requirement that the
'annual report be signed by each registered holding company in the system.' HCAR
No. 23214 (Feb. 2, 1984) (emphasis added) (amending Form U5S to clarify that an
exempt subsidiary holding company, as opposed to a registered subsidiary holding
company, need not sign the annual report.).
95
<PAGE> 98
continue to guarantee the indebtedness of its subsidiaries and make borrowings
to fund the Money Pool and for other subsidiaries as previously authorized by
the Commission to the extent necessary during the transitional period following
the Merger, it will largely function as a conduit between the Combined Company
and the CSW subsidiaries. The Applicants anticipate that CSW will not engage in
securities transactions (except as noted in the previous sentence); acquire
securities, utility assets or other interests; or enter into or take any step in
the performance of any service, sales, or construction contract. One of the
complications that might have arisen, the need to file two annual reports, has
been eliminated by Rule 1(c).
These minimal complications are neither 'unnecessary' nor 'undue.' To the
contrary, any minor complications, and any negligible expenses resulting
therefrom, are necessary to assure appropriate tax and accounting treatment and
to preserve the potential for significant tax savings. The survival of CSW will
benefit the Combined Company's shareholders and its ratepayers. The transitional
structure certainly will not result in a 'highly-pyramided and complex holding
company system' at odds with the purposes of the 1935 Act.(44) Vermont Yankee,
supra.
In sum, the 1935 Act itself and the Rules thereunder, the policies behind
the Act, and the basic Commission interpretations of Section 11(b)(2), all point
to an obvious conclusion: the transitional survival of CSW is consistent with
the standards of Section 11(b)(2). Nevertheless, additional discussion of the
role of tax considerations under the Commission's interpretation of the 1935 Act
is helpful in light of several cases decided by the Commission in the
early-1950s and before. Not only are these cases distinguishable from the case
at hand, but other cases serve to support the conclusion that the Applicants
meet the standards of Section 11(b)(2).
(iii) CSW Will Perform a Useful Economic Purpose by Preserving
Appropriate Tax Treatment Resulting from the Merger, and its
Survival for Such Purpose Does Not Delay or Disrupt the
Commission's Administration of the 1935 Act
The structuring of business activities for tax planning purposes is not
inimical to public policy considerations and is a legitimate goal under the 1935
Act. As the Commission has held,
- ----------
(44) The Commission has in recent years recognized that registered holding
companies may organize subsidiaries, including intermediate subsidiaries, for
various business and legal purposes. See, e.g., Exemption of Acquisition by
Registered Public-Utility Holding Companies, HCAR No. 26667 (Feb. 14, 1997)
(modifying proposed Rule 58 to allow a registered holding company system to use
an intermediate subsidiary to invest in energy-related companies, noting that
use of such an intermediate subsidiary "could further insulate the holding
company and its other subsidiaries . . . from any direct losses that could occur
with respect to Rule 58 investments"); 1995 Report at 94 (noting that in the
1980s and 1990s, registered holding companies expanded their use of separate
subsidiaries to engage in other activities, including the formation of EWGs and
FUCOs); Cinergy, HCAR No. 26376 (Sept. 21, 1995) (authorizing the acquisition of
subsidiaries organized, in part, for tax planning purposes). Similarly,
Applicants' proposal to retain CSW as an intermediate holding company is for a
legitimate business purpose, to preserve appropriate tax treatment of certain
corporate transactions that may occur in the future.
96
<PAGE> 99
the realization of tax savings through a transaction often helps to satisfy the
requirements of the 1935 Act. See, e.g., Columbia Gas System, HCAR No. 26536
(June 25, 1996) (Commission noted that the applicants expected the merger to
produce economies and efficiencies, including the realization of state tax
benefits); TransTok, HCAR No. 26421 (Nov. 30, 1995) (Commission noted that the
benefits and efficiencies of the merger included annual tax savings); New
England Power Association, 1 SEC 473 (May 16, 1936) (Commission noted that the
acquisition should result in tax and other economies). The Commission has
authorized the acquisition of subsidiaries organized, among other things, 'as a
part of tax planning in order to limit [a registered holding company's] exposure
to U.S. and foreign taxes.' Cinergy, HCAR No. 26376 (Sept. 21, 1995); see also,
Allegheny Power System, HCAR No. 26401 (Oct. 27, 1995).
The Commission has found that an entity can serve a useful purpose or
function through its ability to provide shareholders with tax advantages. See
Standard Power and Light Corporation, HCAR No. 13101 (Feb. 16, 1956), enforced,
United States District Court for District of Delaware (Order, Mar. 13, 1956)
(the Commission modified its order directing a registered holding company to
liquidate and dissolve, where the holding company could transform itself into an
investment company and serve a useful purpose by providing shareholders with tax
advantages). Moreover, the Commission has implied that a useful purpose for a
holding company is to facilitate tax advantages by citing the lack of tax
advantages as a factor in its determination that a holding company should be
dissolved. United Light & Power Company, HCAR No. 6603 (Apr. 30, 1946) (the
Commission found that 'there [wa]s no need for the continued existence' of a
registered holding company, in part, because the holding company's existence no
longer offered tax advantages due to changes in the tax laws).
The Commission has 'recognized the importance of tax considerations' under
Section 11 and has 'sought to cooperate in achieving that type of rearrangement
[under Section 11] which imposes the least tax burden on the company and the
security holders, so long as the choice does not result in frustrating the Act
or in delaying the attainment of its objectives.' Engineers Public Service Co.,
HCAR No. 7041 (Dec. 19, 1946); cf. Standard Power & Light, HCAR No. 12208 (Nov.
9, 1953) (Commission allowed holding company, subject to a liquidation and
divestment order, to divest itself of only a portion of the interests in its
subsidiary to preserve tax advantages because such a plan did not, under the
circumstances, delay or interfere with compliance with the 1935 Act). The
existence of tax savings is a compelling reason to maintain a given structure
under Section 11(b)(2), provided that 'the continued existence of this
[security] structure will not be detrimental to the public interest or the
interest of investors or consumers.' Community Gas and Power Company, HCAR No.
4915 (Mar. 4, 1944).
The continued existence of CSW will serve a useful function in the holding
company system by facilitating appropriate tax treatment and by preserving
potentially significant tax savings. These savings are a compelling reason for
the transitional survival of the CSW holding company, and the existence of CSW
will not be detrimental to the public interest, the interest of investors or
consumers, or the Commission's administration of the 1935 Act.
97
<PAGE> 100
Finally, it should be noted that in a few proceedings in the 1940's to
early-1950's, the Commission determined that potential tax benefits (to only or
potentially only a portion of the shareholders and, in one case, where the
benefits could be achieved by other means), taken alone, were not sufficient to
justify relief from dissolution findings and orders or commitments that had been
made in the early stages of implementation of the 1935 Act. See Engineers Public
Service Company, HCAR No. 7041 (Dec. 19, 1946); Electric Bond and Share Company,
HCAR No. 11004 (Feb. 6, 1952); International Hydro-Electric System, HCAR No.
9535 (Dec. 6, 1949), aff'd sub nom., Protective Committee For Class A
Stockholders v. SEC, 184 F.2d 646 (2nd Cir. 1950).(45) These decisions are not
apposite here, however, where the Commission has not identified any unnecessary
or undue complication that would result from the post-Merger transition
structure the potential tax savings would inure to the Combined Company itself
for the benefit of all shareholders alike.
The temporary survival of CSW as a registered holding company to further
the interests of the Combined Company, its shareholders and ratepayers, will
meet all of the standards of the 1935 Act. The transitional corporate structure
will not create unnecessary or undue complications under Section 11(b)(2), and
the significant, potential tax savings outweigh any negligible complications and
costs associated with CSW's survival.
2. Section 10(c)(2)
Section 10(c)(2) requires that the Commission approve a proposed
transaction if it will serve the public interest by tending towards the
economical and efficient development of an integrated public utility system. For
the reasons discussed above, the Combined System will be integrated. The Merger
will also tend towards the economic and efficient development of the Combined
System. This Section 10(c)(2) standard is met where the likely benefits of the
acquisition exceed its likely costs. City of Holyoke, supra.
The projected savings have not changed since the initial filing of this
Application. Applicants continue to project $1,966 million of net non-fuel cost
savings over the ten-year period immediately following consummation of the
Merger. The State settlements have not affected these estimates because the
States that have approved the Merger have accepted the Applicants' proposal to
guarantee ratepayers certain Merger-related savings, regardless of whether these
savings are actually achieved. The Applicants have also committed not to pass
merger costs in excess of merger savings on to ratepayers. Based upon the
resolution of issues related to the allocation of Merger-related savings between
customers and shareholders of the
- ----------
(45) In Portland Electric Power Company, HCAR No. 6365 (Jan. 14, 1946),
supplemented on other grounds, 24 SEC 423 (1946), approved by, United States
District Court for District of Oregon (Order, June 29, 1946), aff'd 162 F.2d 618
(9th Cir. 1947), the Commission, reviewing proposed plans of reorganization
under Section 11(f), found that the continued existence of a shell holding
company solely for the purpose of seeking tax advantages not then available
under applicable law was inimical to the standards of Section 11(b)(2). Here, by
contrast, the economic and tax benefits sought by the retention of CSW as a
sub-holding company will accrue under the presently existing tax laws.
98
<PAGE> 101
Combined Company in the states which have approved the Merger, Applicants have
guaranteed that approximately 55% of the projected savings from the Merger will
be passed through to the respective customers of each of the Combined Company's
utility operating companies. In addition, FERC-jurisdictional customers will
receive the benefits of Merger savings in future rate proceedings or through
their current formula rates.
Applicants also anticipate net fuel-related savings of approximately $98
million over this same period that will be passed on to customers. J. Craig
Baker's testimony before the FERC (a copy of which is included in Exhibit D-1.1
and is incorporated by reference) explains that these savings will result from
the joint dispatch of energy by the Combined Company. In this regard,
fuel-related savings will result from the economic transfer of energy between
the east zone and the west zone companies in order to displace relatively higher
cost generation in one zone with relatively lower cost generation from the other
zone. At the present time, the east zone operating companies and the west zone
operating companies, respectively, interchange power within their zones under
the terms of their respective operating agreements for the purpose of minimizing
generation costs. Through the Merger, the Combined System will create additional
opportunities for cost-effective energy transfers. In addition, based on the
projected resource needs of both companies over the 1999-2002 time period, it
appears that capacity transfers of up to 250 MW from the east zone to the west
zone could be made.(46) Thus, the Merger will allow the Combined Company to
realize the "opportunities for economies of scale, the elimination of duplicate
facilities and activities, the sharing of production capacity and reserves and
generally more efficient operations" described by the Commission in AEP, supra.
The nonproduction cost savings resulting from the Merger are set forth in
the testimony of Thomas J. Flaherty before the Texas Commission, a copy of which
is included in Exhibit D-5.1 and incorporated by reference. As explained by Mr.
Flaherty, the Combined Company is expected to achieve the following
nonproduction costs savings:
<TABLE>
<CAPTION>
Savings Category Millions
<S> <C>
Elimination of Duplicate Corporate and Operations Support Staffing (a) $ 996
Elimination of Duplicate Corporate and Administrative Programs
Administrative and General Overhead (b) 74
Advertising 20
Association Dues 4
Benefits 85
Credit Facilities 1
Directors' Fees 6
Facilities 81
Information Services (c) 440
Insurance 71
Professional Services (d) 213
</TABLE>
- ----------
(46) Because of the volatility in the marketplace for firm capacity,
Applicants have not attempted to quantify the capacity savings or reflect them
in the fuel-related savings at this time.
99
<PAGE> 102
<TABLE>
<S> <C>
Research and Development 11
Shareholder Services 9
Telecommunications 29
Purchasing Economies (Not Fuel-related) (e) 367
Total Savings 2,407
Less: Costs to Achieve (f) (248)
Pre-merger Initiatives (193)
Net Savings $ 1,966
</TABLE>
(a) The position reductions are attributable to the Merger. The reduction
opportunities arise from overlap and duplication in functional
performance, rather than from stand-alone initiatives unrelated to the
Merger. The total corporate and operations support position reductions
were estimated to be 1,061 positions.
(b) These costs are variable with the total number of positions and change as
the number of positions increase or decrease. As position reductions are
achieved through the Merger, miscellaneous overhead expenses are also
reduced.
(c) When the Merger is consummated, the Combined Company plans to consolidate
the respective IS departments which will eliminate duplicative system
development hardware, software and consolidate data center costs.
(d) The savings calculated were generated from the reduction of the combined
audit fees, legal fees, and general consulting services.
(e) Savings represent an estimated 7-8% reduction in total material costs due
to larger purchasing volumes and the availability of greater purchasing
power. This amount was determined based on the experience of other
companies, review of certain component per unit costs, management's
knowledge of vendors and potential approaches to material standardization
and vendor concentration.
(f) Does not include contingent change in control payments.
Assuming a March 31, 1999 closing, AEP and CSW estimate available
synergies and cost savings resulting from the Merger, net of costs necessary to
achieve these reductions, for each of the first ten years following the Merger
of approximately $17 million (9 months), $102 million, $135 million, $162
million, $181 million, $243 million, $255 million, $259 million, $267 million,
$275 million and $70 million (3 months), respectively, for a total of $1,966
million. The savings in the first five years are expected to be lower than in
the later years due to the costs incurred to achieve the savings. Of the $1,966
million in total anticipated net savings, Applicants estimate that approximately
$713 million of the total savings will be allocated to the west zone and
approximately $1,253 million will be allocated to the east zone. Moreover, even
though the savings are shown over 10 years only, it is expected that some of
these savings will continue to be realized over a much longer period. See
Testimony of Thomas J. Flaherty included in Exhibit D-5.1.
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<PAGE> 103
The allocation of savings among the operating companies was made using a
Synergies Analysis prepared by Applicants and explained in more detail in the
testimony of Thomas Flaherty filed with the Texas Commission. First, savings
were categorized as either labor or non-labor. Labor savings were then further
categorized into a functional area and a sub-functional area. For example, in
his testimony filed with the Texas Commission, Mr. Russell Davis first
identified savings for the finance area. Within that area, savings were then
sub-categorized by payroll, accounts payable, general accounting, and other
activities. Each of these subcategories was given a work order and assigned an
allocation factor. General accounting, for example, received an allocation
factor based on the number of general ledger transactions. In this way, the
savings identified by work order and allocation factor were allocated to the
appropriate subsidiaries.
With respect to non-labor savings, the Synergies Analysis allocated
savings in the same manner as labor savings by categorizing savings into
functional and sub-functional areas. For example, the savings for professional
services are split into the sub-categories of legal, auditing, accounting and
finance, engineering and other. A synergy savings work order was assigned to
each functional and sub-functional area based on an analysis of the companies
benefiting from each area of savings. An allocation factor was assigned to each
work order based on an analysis of the savings. For example, professional
service savings for production engineering used the allocation factor "megawatts
of generating capacity." The Synergies Analysis then allocated the identified
savings to either the electric operating companies, the non-regulated
subsidiaries, or the service company.
In addition, Applicants allocated the costs to be incurred by Applicants
in order to achieve savings to their subsidiary companies on a pro-rata basis.
If for example, CPL received 12% of the savings, then CPL would pay 12% of the
costs to achieve the savings and other related costs. The following table
provides the amount of estimated Merger savings which has been allocated to each
of AEP's and CSW's subsidiaries:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------
Company Name Total Savings less Pre-Merger
Initiatives and Cost to Achieve
('000)
- ------------------------------------------------------------------------------
<S> <C>
AEP Regulated Savings
- ------------------------------------------------------------------------------
KgPCo 9,090
- ------------------------------------------------------------------------------
APCo 324,532
- ------------------------------------------------------------------------------
KPCo 76,134
- ------------------------------------------------------------------------------
I&M 241,254
- ------------------------------------------------------------------------------
WPCo 9,298
- ------------------------------------------------------------------------------
OPCo 305,628
- ------------------------------------------------------------------------------
CSPCo 184,372
- ------------------------------------------------------------------------------
AEG 24
- ------------------------------------------------------------------------------
Cardinal Operating Company 1,872
- ------------------------------------------------------------------------------
Central Operating Company 12
- ------------------------------------------------------------------------------
</TABLE>
101
<PAGE> 104
<TABLE>
<S> <C>
- ------------------------------------------------------------------------------
Indiana-Kentucky Power Company 334
- ------------------------------------------------------------------------------
Ohio Valley Electric Cooperative 440
- ------------------------------------------------------------------------------
Buckeye Power Company 3,266
- ------------------------------------------------------------------------------
Central Appalachian Coal Co. --
- ------------------------------------------------------------------------------
Central Coal Co. 2
- ------------------------------------------------------------------------------
Central Ohio Coal Company 5,732
- ------------------------------------------------------------------------------
Windsor Coal Co. 6,776
- ------------------------------------------------------------------------------
Southern Ohio Coal Co. 22,384
- ------------------------------------------------------------------------------
Southern Appalachian Coal Co. --
- ------------------------------------------------------------------------------
Cedar Coal Co. 6
- ------------------------------------------------------------------------------
Water Transportation Division 5,218
- ------------------------------------------------------------------------------
Cook Coal Terminal 1,320
- ------------------------------------------------------------------------------
Price River Coal Co. --
- ------------------------------------------------------------------------------
Blackhawk Coal Co. 6
- ------------------------------------------------------------------------------
Simco, Inc. 2
- ------------------------------------------------------------------------------
Conesville Coal Prep Co. 1,202
- ------------------------------------------------------------------------------
Sporn Plant Joint Books 2,920
- ------------------------------------------------------------------------------
Amos Plant Joint Books 2,910
- ------------------------------------------------------------------------------
Rockport Plant Joint Books 1,318
- ------------------------------------------------------------------------------
Gavin FGD 364
- ------------------------------------------------------------------------------
Tidd Plant PFBC Project --
- ------------------------------------------------------------------------------
Sporn Plant - OPCo Share --
- ------------------------------------------------------------------------------
Amos Plant - OPCo Share --
- ------------------------------------------------------------------------------
Rockport - I&M Share --
- ------------------------------------------------------------------------------
Rockport - AEG Share --
- ------------------------------------------------------------------------------
Carolina Power & Light 7,628
- ------------------------------------------------------------------------------
Non-affiliated 36
- ------------------------------------------------------------------------------
AEP Non-Regulated Savings 38,492
- ------------------------------------------------------------------------------
Total AEP Savings 1,252,572
- ------------------------------------------------------------------------------
- ------------------------------------------------------------------------------
CSW Regulated Savings
- ------------------------------------------------------------------------------
CPL 237,026
- ------------------------------------------------------------------------------
Energy Consulting SVCS 273
- ------------------------------------------------------------------------------
Joint Fuels Project 274
- ------------------------------------------------------------------------------
External Lab Services 24
- ------------------------------------------------------------------------------
PSO 159,773
- ------------------------------------------------------------------------------
SWEPCO 175,534
- ------------------------------------------------------------------------------
WTU 84,222
- ------------------------------------------------------------------------------
CSW Non-Regulated Savings 55,668
- ------------------------------------------------------------------------------
Total CSW Savings 712,794
- ------------------------------------------------------------------------------
Total Savings Less Cost to Achieve and Pre-Merger Initiatives 1,965,339
- ------------------------------------------------------------------------------
</TABLE>
102
<PAGE> 105
The Applicants' estimates of Merger savings have been provided to the
staffs of all eleven state commissions which will have retail rate jurisdiction
over the Combined Company (Arkansas, Indiana, Kentucky, Ohio, West Virginia,
Michigan, Tennessee, Virginia, Louisiana, Oklahoma and Texas). In each of those
states, the Applicants have responded to discovery requests from participants,
and have defended the proposed level of savings as being achievable. In each of
those states, the Applicants have either received state commission orders or
entered into stipulations with the commission's staff (and other parties) which
establish the level of savings that will be shared with ratepayers and which
guarantee to consumers the savings regardless of whether they are achieved. The
amount of the savings as well as Applicants' plans for allocating the savings
have been approved by the state commissions of Arkansas, Louisiana, Indiana,
Kentucky, Oklahoma, Texas, and Michigan.
Based upon the resolution of issues related to the allocation of Merger
related savings between customers and shareholders of the Combined Company in
the states which have approved the Merger, Applicants have guaranteed that
approximately 55% of the projected savings from the Merger will be passed
through to the respective customers of each of the Combined Company's utility
operating companies. For example, the Texas Commission approved rate reductions
totaling $221 million over six years for CSW's three utility subsidiaries
operating in the state. Similarly, the Oklahoma Commission issued an order
approving the Merger as being in the "public interest," freezing base rates
through 2003 and requiring 55% of Oklahoma's share of Merger-related savings to
be recovered by ratepayers in Oklahoma. In addition, Applicants have agreed to
make a $5,000,000 reduction to the revenue requirement otherwise determined by
the Oklahoma Commission to be reasonable in the event they seek a rate review
any time after January 1, 2003 through the end of the fifth year after the
effective date of the Merger.
The Arkansas Commission issued an order approving the Merger as being in
the "public interest" and providing a total rate cut of $6 million over the
five-year period following the Merger.
In Louisiana, Applicants agreed to a base rate freeze for 5 years and a
nonfuel savings sharing mechanism ("SSM") for eight years, which is a
formula-based methodology to be used to quantify merger savings. During the
first 14 months following the consummation of the Merger, the Combined Company
will retain 100% of the Merger savings and may use savings to reduce deferrals
of the Merger costs. Beginning in the 15th month, 50% of the Merger savings as
computed pursuant to the SSM will be passed through to consumers in Louisiana.
The SSM will be updated annually and continue for the remainder of the
eight-year period following the Merger's consummation. Applicants have estimated
that the customer rate credits in Louisiana will total more than $18 million
over the eight-year period.
Likewise, Merger-related savings plans have been approved by the state
commissions of Indiana, Michigan, and Kentucky. The order of the Indiana
Commission provides for a credit to ratepayers of approximately 55% of the
$121.2 million, or $66.6 million, of Merger savings expected to be achieved over
the first eight years following the Merger. The order of the Indiana
103
<PAGE> 106
Commission further provides for an extension of an existing rate freeze to
January 1, 2005. The order of the Kentucky Commission establishes merger savings
of approximately $51.6 million over the first eight years following the Merger,
with consumers receiving the benefit of approximately $28.4 million, or 55% of
the total savings. In addition, the order of the Kentucky Commission provides
that Kentucky Power, AEP's utility subsidiary, will not request an increase in
its existing base rates until the later of January 1, 2003, or three years from
the effective date of the Merger. The order of the Michigan Commission provides
for a credit to ratepayers of 55% of the $25.4 million, or approximately $14
million, of the total savings. Once the Merger is consummated, Michigan
customers will receive their share of the savings through credits of
approximately 1 percent to 1.5 percent every year for at least eight years. In
addition, the order of the Michigan Commission provides that I&M, AEP's utility
subsidiary, will not request an increase in its existing base rates until
January 1, 2005. Although specific determinations of the net savings to each
group in the remaining states cannot be finalized until all regulatory
proceedings have been completed, it is expected that each group will realize
approximately 55% of the net savings.
In the states that have approved the Merger, Applicants have agreed to
mechanisms for sharing the savings which utilize the Applicants' estimate and
provide guaranteed net rate reduction riders for periods ranging from five to
eight years. In other words, if the Applicants do not achieve the estimated
level of savings, the consumers will nonetheless obtain the benefits of the
estimated Merger savings. This provides the requisite incentive for Applicants
to achieve the estimated Merger savings.
The Oklahoma Commission and the Texas Commission approved Applicants'
divestiture of generation assets based upon the mitigation measures that
Applicants proposed to protect ratepayers. The order of the Texas Commission
approved several significant provisions designed to protect consumers from the
economic effects of the divestiture, including (i) a requirement that proceeds
from the CPL divestiture be used to reduce stranded costs of the Combined
Company, (ii) a provision that limits any adverse impact on consumers related to
the divestiture of the units, and, most significantly, (iii) a provision that
guarantees rate reductions totaling $221 million to the Combined Company's
ratepayers in Texas over the six years following the Merger.
In Oklahoma, as part of the stipulation approved by the Oklahoma
Commission, the Applicants committed to hold Oklahoma retail consumers harmless
from adverse effects related to CSW's divestiture of 300 MW of generation
capacity in Oklahoma. Applicants agreed to make an "after the fact" calculation
of margins both before and after the divestiture. If negative margins result,
Oklahoma consumers will be held harmless from the additional costs associated
with the divestiture.
These expected savings exceed the anticipated savings in a number of other
acquisitions approved by the Commission. See, e.g., New Century Energies, supra
(expected savings of $770 million over 10 years); Entergy, supra (expected
savings of $1.67 billion over ten years); Northeast I, supra (estimated savings
of $837 million over 11 years); IE Industries, HCAR No.
104
<PAGE> 107
25325 (June 3, 1991) (expected savings of $91 million over ten years); CINergy,
supra (estimated savings of approximately $895 million over ten years).
The Commission has long recognized that, in reviewing an application under
Section 10(c)(2), it is appropriate to consider "not only benefits resulting
from the combination of utility assets, but also financial and organizational
economies and efficiencies." WPL Holdings, supra; see also Chevron Holdings,
Inc., HCAR No. 27122 (Dec. 27, 1999); Roanoke Gas Co., HCAR No. 26966 (April 1,
1999); BEC Energy, HCAR No. 26874 (May 15, 1999); Western Resources, Inc., HCAR
No. 26783 (Nov. 24, 1997); KU Energy Corp., HCAR No. 25409 (Nov. 13, 1991). As
the Commission has observed, with reference to the requirement of Section
10(c)(2) that a proposed combination yield economies and efficiencies, "specific
dollar forecasts of future savings are not necessarily required; a demonstrated
potential for economies will suffice even when these are not precisely
quantifiable." Centerior, supra (citation omitted). If economies and
efficiencies are anticipated from the transaction as a whole, the Commission is
justified in approving it. See Madison Gas, at page 9 ("The Act, however,
requires that the 'acquisition' as a whole, not merely the construction of an
interconnection, tend toward efficiency and economy."); cf. Union Electric
Company, 45 SEC 489, 495-96 (1974) (approving acquisition of assets not
physically connected to the rest of the system since the acquisition would
"contribute in the main to the development of an integrated system."); New
Century Energies, supra, at pp. 9-10 (approving the acquisition of utility
assets not physically interconnected where "their combination will result in a
larger, financially stronger company, that, through the pooling of resources and
expertise, will be able to achieve increased financial stability and strength,
greater opportunities for earnings and dividend growth, reduction of operating
costs, deferral of certain capital expenditures, efficiencies of operations,
better use of facilities for the benefit of customers, seasonal diversity of
demand, improved ability to use new technologies, greater retail and industrial
sales diversity and improved capability to make wholesale power purchases and
sales.")
Two of these principal additional benefits relate to the Combined
Company's generation mix and system reliability. The Merger will result in a
more balanced generation mix that is less susceptible to fuel price volatility
and supply interruptions. In addition, the Combined System will be better
situated to provide more reliable electric service than is possible for AEP and
CSW on a stand-alone basis. For example, the Combined System will share in a
larger generating base after the Merger. As a result, the Combined System will
have more generating resources to call on when units are down for maintenance or
due to an unscheduled outage. In addition, each of AEP and CSW has a higher risk
of unserved load than would be the case for the Combined System, since each of
AEP and CSW on a stand-alone basis has access to fewer interconnections to
neighboring systems for emergency support.
C. SECTION 10(f)
105
<PAGE> 108
Section 10(f) provides that:
The Commission shall not approve any acquisition as to which an
application is made under this section unless it appears to the
satisfaction of the Commission that such State laws as may apply in
respect of such acquisition have been complied with, except where the
Commission finds that compliance with such State laws would be detrimental
to the carrying out of the provisions of section 11.
Each of AEP's and CSW's obligation to consummate the Merger is
conditioned, among other things, on the receipt of all requisite state
regulatory approvals. State regulatory approvals have been obtained from the
Oklahoma Commission, the Arkansas Commission, the Indiana Commission, the
Louisiana Commission, the Kentucky Commission, and the Michigan Commission. An
order has been issued by the Texas Commission which found the Merger to be
consistent with the public interest. See Item 4, infra, for further discussion
of regulatory approvals and the standard of review applicable to such approval.
When the other approvals have been obtained, the Merger will comply with Section
10(f).
D. INTRA-SYSTEM FINANCING AND OTHER COMMISSION AUTHORIZATIONS.
In order to maximize the efficiencies resulting from the Merger, the
Applicants seek authority for the Combined Company to reorganize, consolidate
and, where necessary, restate certain of the intra-system financing and other
authorizations previously issued by this Commission to each of AEP, CSW, and
their respective subsidiaries, as discussed in more detail below.
Applicants request approval, effective upon consummation of the Merger, to
merge CSWS with and into AEPSC. Applicants request that, upon the merger of CSWS
into AEPSC, AEPSC succeed to certain of the authority of CSWS as set forth in
various Commission orders (which orders are summarized in Exhibit I-1 attached
hereto) and that such activities with respect to CSWS include AEPSC.
Certain of the non-utility businesses of CSW (each a 'CSW Non-utility
Business') conduct activities that are substantially equivalent to the
activities of one or more non-utility subsidiaries of AEP (each an 'AEP
Non-utility Business'). Applicants request approval, as deemed appropriate by
management, for the Combined Company to directly or indirectly acquire, and for
CSW to transfer to the Combined Company, CSW Non-utility Businesses through: (1)
merger of one or more CSW Non-utility Businesses with one or more wholly owned
non-utility subsidiaries (either presently existing and performing substantially
equivalent activities or to be formed, if appropriate) of the Combined Company
(each a 'Combined Non-utility Business'), (2) the dividending or distribution of
the common stock of one or more CSW Non-utility Businesses from CSW to the
Combined Company, or (3) the acquisition of the assets or common stock of one or
more CSW Non-utility Businesses by one or more Combined Non-utility Businesses.
Applicants request approval, if management deems appropriate, to consolidate
each CSW Non-utility Business with its corresponding AEP Non-utility Business
into a single
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Combined Non-utility Business directly or indirectly owned by the Combined
Company. Applicants request approval for the Combined Company to transfer to
CSW, and CSW to acquire, any AEP Non-utility Business or to consolidate any AEP
Non-utility businesses with and into any like CSW Non-utility Business
consistent with the foregoing principles and authority. Applicants request that
upon consolidation, each resulting Combined Non-utility Business succeed to all
of the authority of each corresponding CSW Non-utility Business and AEP
Non-utility Business, respectively, as set forth in previously issued Commission
orders. The determination of the appropriate corporate structure of the Combined
Company is the subject of currently convoked Merger transition teams.
Pursuant to American Elec. Power Co., HCAR No. 26864 (Apr. 27, 1998) and
American Elec. Power Co., HCAR No. 26516 (May 10, 1996), this Commission
authorized AEP to issue and sell securities up to 100% of its consolidated
retained earnings for investment in EWGs and FUCOs. Pursuant to Central and
South West Corp. et al., HCAR No. 26653 (Jan. 24, 1997), this Commission
authorized CSW to issue and sell securities up to 100% of its consolidated
retained earnings for investment in EWGs and FUCOs. Applicants propose that,
upon consummation of the Merger, the authority of CSW to issue and sell
securities in an amount up to 100% of its consolidated retained earnings for
investment in EWGs and FUCOs as provided by Central and South West Corp. et al.,
HCAR No. 26653 (Jan. 24, 1997) shall cease. To the extent that AEP and CSW were
authorized, pursuant to Sections 32 and 33 of the 1935 Act and the rules
thereunder, to invest up to 100% of their consolidated retained earnings in EWG
and FUCO interests, the Combined Company should also be authorized to invest up
to 100% of its combined consolidated retained earnings in EWG and FUCO
interests. Applicants therefore propose that, upon consummation of the Merger,
the authority of the Combined Company to issue and sell securities in an amount
up to 100% of its consolidated retained earnings for investment in EWGs and
FUCOs shall be the same as that provided by American Elec. Power Co., HCAR No.
26864 (Apr. 27, 1998) and American Elec. Power Co., HCAR No. 26516 (May 10,
1996), except that for purposes of determining the amount of consolidated
retained earnings as contemplated by American Elec. Power Co., HCAR No. 26864
(Apr. 27, 1998) and American Elec. Power Co., HCAR No. 26516 (May 10, 1996),
'consolidated retained earnings' shall consist of the consolidated retained
earnings of the Combined Company.
Currently, the CSW System uses short-term debt, primarily commercial
paper, to meet working capital requirements and other interim capital needs. In
addition, to improve efficiency, CSW has established a system money pool (the
'Money Pool') to coordinate short-term borrowings for CSW, its U.S. electric
utility subsidiary companies and CSWS, as set forth in various Commission orders
(which orders are summarized in Exhibit I-2 attached hereto). AEP has no
equivalent to the Money Pool. Applicants hereby request authorization, upon
consummation of the Merger and on the same terms and conditions as set forth in
the orders summarized in Exhibit I-2, to permit: (1) the Combined Company, AEP's
U.S. electric subsidiary companies and other subsidiaries(47) and AEPSC to
participate in the Money Pool, and (2) the
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(47) The other subsidiaries include Cedar Coal Co., Central Appalachian
Coal Co., Central Coal Co., Central Ohio Coal Co., Colomet, Inc., Simco Inc.,
Southern Appalachian Coal Co., Southern Ohio Coal Co., Windsor Coal Co.,
Blackhawk Coal Co., Conesville Coal Preparation Company, Franklin
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Combined Company to manage and to fund the Money Pool. Exhibit I-2 summarizes
the existing authority associated with the Money Pool and states the additional
authority requested for the Money Pool upon consummation of the Merger.
Applicants request that following the Merger, both the Combined Company and CSW
(for a transitional period) will have in aggregate the authority that CSW has
with respect to those orders summarized in Exhibit I-2.
CSW Credit purchases, without recourse, the accounts receivable of CSW's
U.S. electric utility subsidiary companies and certain non-affiliated utility
companies. The sale of accounts receivable provides CSW's U.S. electric utility
subsidiary companies with cash immediately, thereby reducing working capital
needs and revenue requirements. In addition, because CSW Credit's capital
structure is more highly leveraged than that of the CSW U.S. electric utility
subsidiaries and due to CSW Credit's higher short-term debt ratings, CSW's
overall cost of capital is lower. CSW Credit issues commercial paper to meet its
financing needs. Applicants hereby request approval, effective upon consummation
of the Merger, for the Combined Company to directly acquire, and for CSW to
transfer to the Combined Company, the business of CSW Credit through: (1) the
merger of CSW Credit with a subsidiary of the Combined Company to be formed, if
appropriate, (2) the dividending or distribution of the common stock of CSW
Credit from CSW to the Combined Company, or (3) the acquisition of the assets or
common stock of CSW Credit by a subsidiary of the Combined Company to be formed,
if appropriate. Applicants request that, upon the acquisition of the business of
CSW Credit by the Combined Company, the resulting company ('New Credit') succeed
to all of the authority of CSW Credit as set forth in various Commission orders
(which orders are summarized in Exhibit I-3 attached hereto). Exhibit I-3
summarizes the existing authority of CSW Credit and states the authority
requested for New Credit.
CSW has supported the financing and other activities of its subsidiaries
through obtaining Commission approval to issue and guarantee certain
indebtedness. After the Merger it may be more efficient or even commercially
necessary for the Combined Company to support certain of the financing
arrangements and business activity previously supported by CSW. Applicants
hereby request approval for the Combined Company, upon consummation of the
Merger, to support those financing and other activities presently supported by
CSW, including the issuance and guaranteeing of indebtedness, pursuant to those
orders of the Commission summarized in Exhibit I-4. Exhibit I-4 describes the
existing authority of CSW which Applicants seek to duplicate in favor of the
Combined Company. It is Applicants' intention that, following the Merger, both
the Combined Company and CSW will simultaneously have in aggregate the authority
that CSW currently has with respect to those orders summarized in Exhibit I-4.
The Combined Company does not seek to widen such authority which will
necessarily remain limited to the orders described in Exhibit I-4. The practical
effect of this approval would be to insert the
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Real Estate Company, Indiana Franklin Realty Company and West Virginia Power
Co., and are referred to herein as the "Coal Subsidiaries." Each of the Coal
Subsidiaries is a wholly owned subsidiary of one or more AEP U.S. electric
subsidiary companies, except Franklin Real Estate Company, which is a direct
subsidiary of AEP, and Indiana Franklin Realty Company, which is a subsidiary of
Franklin Real Estate Company.
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Combined Company alongside CSW in virtually all instances where CSW is mentioned
in such orders.
Pursuant to Central and South West Corp., HCAR No. 26616 (Nov. 27, 1996),
this Commission confirmed previous authority and granted additional authority
such that CSW was authorized, through December 31, 2001, to offer 10,000,000
shares of CSW Common Stock pursuant to its Dividend Reinvestment and Stock
Purchase Plan, of which approximately 2,000,000 remain unissued. Pursuant to
American Elec. Power Co., HCAR No. 26553 (Aug. 13, 1996) this Commission
confirmed previous authority and granted additional authority such that AEP was
authorized, through December 31, 2000, to offer 54,000,000 shares of AEP Common
Stock pursuant to its Dividend Reinvestment and Direct Stock Purchase Plan.
Applicants hereby request that, as soon as practicable upon consummation of the
Merger, (1) the authority of CSW's Dividend Reinvestment and Stock Purchase Plan
be terminated, and (2) the Combined Company be authorized to issue 55,200,000
shares of AEP Common Stock through December 31, 2000 pursuant to its Dividend
Reinvestment and Direct Stock Purchase Plan consistent otherwise with all the
terms and conditions set forth in American Elec. Power Co., HCAR No. 26553 (Aug.
13, 1996).
Pursuant to Central and South West Corp., HCAR No. 26413 (Nov. 21, 1995),
this Commission confirmed previous authority and granted additional authority
such that CSW was authorized to issue and sell a total of 5,000,000 shares of
CSW Common Stock to the trustee of the Central and South West Thrift Plan, of
which approximately 4,400,000 remain unissued. Pursuant to American Elec. Power
Co., HCAR No. 26786 (Dec. 1, 1997), this Commission confirmed previous authority
and granted additional authority such that AEP was authorized, through December
31, 2001, to sell 8,800,000 shares of AEP Common Stock to the trustee of the
American Electric Power System Employees Savings Plan. Applicants hereby request
that, upon consummation of the Merger, (1) the authority of CSW to issue shares
of CSW Common Stock to the Central and South West Thrift Plan be terminated, and
(2) the Combined Company be authorized to issue 11,440,000 shares of AEP Common
Stock through December 31, 2001 in connection with the American Electric Power
System Employees Savings Plan and the Central and South West Thrift Plan (for a
transitional period) consistent otherwise with all the terms and conditions set
forth in American Elec. Power Co., HCAR No. 26786 (Dec. 1, 1997) and Central and
South West Corp., HCAR No. 26413 (Nov. 21, 1995), respectively.
Pursuant to Central and South West Corp., HCAR No. 25511 (Apr. 7, 1992),
this Commission authorized CSW to adopt the Central and South West Corporation
1992 Long Term Incentive Plan pursuant to which certain key employees would be
eligible, through December 31, 2001, to receive certain performance and
equity-based awards including (a) stock options, (b) stock appreciation rights,
(c) performance units, (d) phantom stock, and (e) restricted shares of common
stock. Applicants hereby request that, upon consummation of the Merger, the
Combined Company succeed to the authority of CSW to permit it (i) to honor the
awards granted by CSW prior to the consummation of the Merger, (ii) to
administer the plan (subject to any necessary shareholder or regulatory
approval) on a Combined Company basis and grant any remaining awards, and (iii)
to reserve and issue sufficient shares of AEP Common Stock
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pursuant to subparagraphs (i) and (ii) above in connection with the Central and
South West Corporation 1992 Long Term Incentive Plan consistent otherwise with
all the terms and conditions set forth in Central and South West Corp., HCAR No.
25511 (Apr. 7, 1992).
E. SERVICE AGREEMENT; APPROVAL OF METHODOLOGY FOR ALLOCATING COSTS
UNDER
As described in Item 1.B.1 above, AEPSC is a service company that,
pursuant to service agreements with each of the subsidiary companies of AEP,
provides various technical, engineering, accounting, administrative, financial,
purchasing, computing, managerial, operational and legal services to each of the
AEP subsidiary companies. Pursuant to the service agreements, these services are
provided at cost. The Commission has previously determined that AEPSC is so
organized and its business is so conducted as to meet the requirements of
Section 13(b) of the 1935 Act and Rule 88 thereunder. Amer. Elec. Power Service
Corp., HCAR No. 21922 (Feb. 19, 1981) (order authorizing service agreement
between service company and operating subsidiaries).
Similarly, CSWS is a service company which, pursuant to service agreements
signed with each of the subsidiary companies of CSW, provides various technical,
engineering, accounting, administrative, financial, purchasing, computing,
managerial, operational and legal services to each of the CSW subsidiary
companies. Pursuant to the service agreements, these services are provided at
cost. The Commission has also previously determined that CSWS is so organized
and its business is so conducted as to meet the requirements of Section 13(b) of
the 1935 Act and Rule 88 thereunder. Central and South West Corp., HCAR No.
26293 (May 18, 1995).
Upon consummation of the Merger, CSWS will be merged with AEPSC, and AEPSC
will be the surviving service company for the Combined System. Applicants intend
that AEPSC will enter into an amended service agreement with AEP's subsidiary
companies and CSW's subsidiary companies. The proposed amended service agreement
is filed as Exhibit B-2. Under the amended service agreement, AEPSC will provide
the managerial, administrative, financial, technical, and other services
previously provided by the two service companies, CSWS and AEPSC. The execution
and performance by the respective parties of the amended service agreement is
subject to Section 13(b) of the 1935 Act and the rules thereunder. To the extent
not exempt under rules or otherwise under the 1935 Act, Applicants' subsidiaries
will provide services to each other at cost unless otherwise authorized by
Commission orders. See, e.g., Central and South West Corp., HCAR No. 26887 (June
19, 1998), AEP Energy Services, Inc., HCAR No. 26267 (April 5, 1995) and AEP
Resources, Inc., HCAR No. 26962 (Dec. 30, 1998) (authorizing certain
non-regulated subsidiaries of Applicants to provide services at fair market
value).
The amended service agreement to be entered into between AEPSC and the
utility and nonutility subsidiary companies of AEP and CSW, which, pending
Commission approval, will become effective upon the consummation of the Merger,
is similar to those service agreements currently in place. Under the terms of
the amended service agreement, AEPSC will render services to the subsidiary
companies of the Combined Company at cost. AEPSC will account for,
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allocate and charge its costs of the services provided on a full cost
reimbursement basis under a work order system consistent with the Uniform System
of Accounts for Mutual and Subsidiary Service Companies. Costs incurred in
connection with services performed for a specific subsidiary company will be
billed 100% to that subsidiary company. Costs incurred in connection with
services performed for two or more subsidiary companies will be allocated in
accordance with the attribution bases set forth in Exhibit B-3. Indirect costs
incurred by AEPSC which are not directly allocable to one or more subsidiary
companies will be allocated in proportion to how either direct salaries or total
costs are billed to the subsidiary companies depending on the nature of the
indirect costs themselves. The time AEPSC employees spend working for each
subsidiary will be billed to and paid by the applicable subsidiary on a monthly
basis, based upon time records. Each subsidiary company will maintain separate
financial records and detailed supporting records showing AEPSC charges.
Several state commissions have already approved the Merger and included
codes of conduct that will govern the relationship between AEPSC, the operating
companies, and other affiliated companies. For example, the orders of the
Indiana, Kentucky, Louisiana and Arkansas Commissions approving the Merger all
contain detailed guidelines relating to affiliate transactions. The order of the
Oklahoma Commission approving the Merger grants the Oklahoma Commission and the
State Attorney General access to the books and records of AEP and its affiliates
and subsidiaries (including their participation in joint ventures) with respect
to matters and activities that relate to Oklahoma retail rates. The settlement
with the staff of the Texas Commission requires compliance with a detailed code
of conduct governing activities among the Combined Company's subsidiaries. These
orders and agreements, consistent with state law, generally require certain
separations and safeguards between utility and nonutility affiliates to prevent
cross-subsidization and preferential treatment of nonutility affiliates.
Applicants hereby request that the Commission approve the amended service
agreement between AEPSC and the subsidiary companies of the Combined Company and
the related attribution bases listed in Exhibit B-3. The proposed attribution
bases are based on cost-drivers emphasizing factors that correlate to the volume
of activity that is inherent in performing certain services. The frequency at
which each attribution basis will be recalculated is noted in Exhibit B-3.1.
Exhibit B-3.2 compares the proposed attribution bases to the attribution
bases currently used by both AEPSC and CSWS. This exhibit also includes
explanations for the proposed differences. In all cases, the proposed
attribution bases are based on the attribution bases currently used by either
AEPSC or CSWS with some variations. Exhibit B-3.3 identifies the scope of each
of the attribution bases by class of companies. Exhibit B-3.4 describes the
services that will be performed by AEPSC after the Merger and lists the
attribution bases associated with each major service category.
AEP currently utilizes the following principles in coordinating its work
order and billing control, planning and budgeting and internal audit functions
and expects that these principles will continue to govern such functions
following the Merger. An AEPSC work order may be
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initiated by AEPSC or by a subsidiary company of AEP. Any AEPSC work order,
whether for a single company or multiple companies, including the proposed cost
allocation method, must be reviewed and approved by the AEPSC Corporate
Accounting Department and then by a person appointed by the subsidiary company.
As a result of the centralization in AEPSC of the responsibilities previously
assigned to the officers of the subsidiary companies, the Corporate Planning and
Budgeting Department of AEPSC has been appointed by the subsidiary companies to
approve work orders. Corporate Planning and Budgeting is independent of the
AEPSC work order billing process, which is maintained by the Corporate
Accounting Department of AEPSC.
Time records are completed by or for each employee in AEPSC and approved
by work group supervisors. Charges are accumulated by the Corporate Accounting
Department of AEPSC and billed to each AEP subsidiary company at the end of each
month. These bills are reviewed for reasonableness and approved on behalf of the
AEP subsidiary companies by Corporate Planning and Budgeting.
Management has developed strategic performance measures for AEP and its
subsidiary companies as a business enterprise. These measures include earnings
per share, total shareholder return, competitive cost comparison, market share,
customer satisfaction and loyalty, employee development, safety and
productivity, and environmental performance. Management has developed targets
against which to measure the performance of AEP and its subsidiaries on a
consolidated basis. In addition, based upon these strategic performance measures
and targets, management has developed performance measures and targets for each
business group. These measures and targets focus on the business group, not on
the corporate entity; however, the expected impact of proposed plans and budgets
on expenses of the subsidiary companies is determined.
Efficiency in business operations is important in order to achieve targets
in some of the strategic performance measures, such as earnings per share and
competitive cost comparison. A new planning and budgeting system, including
activity based management, has been developed and implemented. This system
focuses on the business process - a network of related and interdependent
activities performed to achieve a specific purpose. It provides cost information
quickly and allows managers to evaluate the efficiency and value of processes,
including trends and internal benchmarks.
Using this planning and budgeting system, an annual budget is prepared by
each business unit and support organization and submitted to the Office of the
Chairman for approval. The Office of the Chairman consists of the Chairman of
the Board, President and Chief Executive Officer of AEP and AEPSC and the
executive vice presidents of AEPSC that report to him. A majority of these
officers are also directors and executive officers of each of the subsidiary
companies. The Corporate Planning and Budgeting Group assists the business units
and support organizations in the planning and budgeting process and monitors
expenses. It also determines and reports the expected impact of proposed plans
and budgets on the expenses of the subsidiary companies.
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The planning and budgeting process for AEPSC is part of the overall
process for the business units and support organizations and subject to approval
by the Office of the Chairman.
The AEPSC Internal Audits Department continuously conducts audits of the
functions of AEP and its subsidiaries, including those of AEPSC, to ensure that
proper internal controls exist and to determine if they are functioning as
intended and are efficient and effective. As a part of the audit plan, the
Internal Audits Department performs audits of the AEPSC work order system and
related billings to AEP subsidiary companies. The purpose of the audits is to
render an opinion on the internal controls over the work order billing process
and compliance with Commission-approved cost allocation billing methodologies.
The Internal Audits Department completed the latest review in 1997 and expressed
an opinion that the internal controls are functioning properly and that the
costs are being allocated to AEP subsidiary companies in accordance with the
Commission-approved cost allocation billing methodologies. The Department will
perform its next audit of the work order system and related billings in 1999 and
then every two years.
The Vice President of Internal Audits (the "Vice President") reports to
the Chairman of the Audit Committee of the Board of Directors of AEP (the "Audit
Committee"). Administratively, the Vice President reports to the Executive Vice
President - Financial Services of AEPSC. The Vice President attends each meeting
of the Audit Committee. In accordance with New York Stock Exchange listing
requirements, the Audit Committee is comprised solely of outside directors.
In December of each year, the results of the year's audit activities are
reviewed with the Audit Committee and the following year's audit plan is
reviewed and approved by the Audit Committee. The Audit Committee annually
reviews and approves the Internal Audits Department Charter to ensure that it
sufficiently allows the Vice President to carry out his duties. The Vice
President meets privately with the Audit Committee several times during the year
and has the addresses and telephone numbers of the Audit Committee members and
is free to contact them at any time. The Vice President is reminded in these
private meeting sessions that he has such freedom.
F. ACQUISITION OF NON-UTILITY BUSINESSES
Section 10(c)(1) provides that the Commission shall not approve an
acquisition that is "detrimental to the carrying out of the provisions of
Section 11." Section 11(b)(1) limits the non-utility interests of a registered
holding company to those that are "reasonably incidental, or economically
necessary or appropriate to the operations of such integrated public-utility
system." The Commission may find that a non-utility business meets this standard
when it finds that the interest in the business is "necessary or appropriate in
the public interest or for the protection of investors or consumers and not
detrimental to the proper functioning of such [integrated] system." CSW has a
number of non-utility businesses that AEP will indirectly acquire as a result of
the Merger. CSW owns seven material non-utility subsidiaries: CSW Energy, CSW
International, C3 Communications, EnerShop, CSW Energy Services, CSW Credit, and
holds an
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80% interest in CSW Leasing. For a description of CSW's non-utility businesses,
see Item 1.B.1(b) supra. The Commission has found that CSW's non-utility
businesses meet the 11(b)(1) standard (to the extent that such a finding was
necessary).(48) Such businesses have an operating or functional relationship to
CSW's utility operations. See, e.g., Conectiv, supra (the Commission has
interpreted section 11(b)(1) "to require the existence of an operating or
functional relationship between the utility operations of the registered holding
company and its nonutility activities.")
Upon consummation of the Merger, the non-utility businesses of CSW will
become indirect subsidiaries of AEP. To the extent that Commission approval is
necessary for the acquisition of CSW's non-utility businesses, the acquisitions
should be approved because the indirect ownership of CSW's non-utility
businesses by AEP in no way affects the functional relationship of these
businesses to the Combined Company's core electric business following the
Merger. Moreover, acquisition of these businesses is in the public interest and
consistent with the applicable standards under the 1935 Act.
G. ORGANIZATION OF MERGER SUB; ACQUISITION OF MERGER SUB COMMON STOCK
Merger Sub was organized solely for the purpose of effecting the Merger
and has not conducted any activities other than in connection with the Merger.
Merger Sub has no subsidiaries. Each share of common stock of Merger Sub, par
value $0.01 per share, to be issued to AEP and outstanding immediately before
the consummation of the Merger will be converted into one share of CSW Common
Stock upon consummation of the Merger. Thus, the sole purpose for Merger Sub is
to serve as an acquisition subsidiary of AEP for purposes of effecting the
Merger. Approval of this Application-Declaration will constitute approval of the
acquisition by AEP of the common stock of Merger Sub.
ITEM 4. REGULATORY APPROVAL
Set forth below is a summary of the material regulatory requirements affecting
the Merger. Failure to obtain any necessary regulatory approval or any adverse
conditions that are imposed in connection with any necessary regulatory
approval, including the failure to obtain appropriate ratemaking treatment, may
affect the consummation of the Merger.
In addition to required Commission approvals, the state utility commissions of
Arkansas, Louisiana, Oklahoma, and Texas, and the FERC, the FCC, and the NRC
have jurisdiction over
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(48) A registered holding company may acquire and hold an interest in an
EWG, FUCO, and an exempt telecommunications company, without the need to apply
for or receive approval from the Commission (although the Commission retains
jurisdiction over certain related transactions with these entities). Sections
32, 33 and 34 of the 1935 Act. Moreover, a registered holding company may
acquire "energy-related" companies meeting the Rule 58 safe harbor conditions
(including an investment ceiling) without the need for Commission approval.
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various aspects of the transactions proposed herein.(49) Further, both AEP and
CSW are required to file notification and report forms under the HSR Act with
the DOJ with respect to the Merger. Additional consents from or notifications to
governmental agencies may be necessary or appropriate in connection with the
Merger.
Applicants already have obtained regulatory approvals of the Nuclear Regulatory
Commission, the Arkansas Commission, the Oklahoma Commission, the Louisiana
Commission, the Kentucky Commission, the Indiana Commission, and the Michigan
Commission. The Texas Commission issued an order finding the Merger to be
consistent with the public interest. An Initial Decision has been issued by a
FERC Administrative Law Judge approving the Merger. Applicants expect a final
decision from FERC by March 2000 approving the Merger. On January 21, 2000, the
FCC approved the transfer of certain microwave licenses held by CSW. On February
2, 2000, DOJ notified Applicants that it had completed its review of the Merger
and that no further action is warranted.
A. ANTITRUST CONSIDERATIONS
The 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 Antitrust Division and the specified HSR
Act waiting period has expired or been terminated. Applicants filed their
respective pre-merger notification pursuant to the HSR Act in July 26, 1999. On
August 26, 1999, AEP and CSW received a request for additional information from
the Antitrust Division. AEP and CSW filed the additional information with the
Antitrust Division in November, 1999. On February 2, 2000, the Antitrust
Division notified Applicants that it had completed its review of the Merger and
that no further action is warranted.
The expiration or earlier termination of the HSR Act waiting period would
not permanently preclude the Antitrust Division from challenging the Merger on
antitrust grounds, but it would represent a decision by such agencies that the
Merger may be consummated without challenge under Section 7 of the Clayton Act.
If the Merger is not consummated within 12 months after the expiration or
earlier termination of the initial HSR Act waiting period, AEP and CSW must
submit new information to the Antitrust Division, and a new HSR Act waiting
period must expire or be earlier terminated before the Merger may be
consummated.
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(49) AEP has U.S. electric utility subsidiaries operating in Ohio,
Indiana, Kentucky, Michigan, Tennessee, Virginia, and West Virginia. AEP
believes that the approval of the utility regulatory commissions in these states
is not required to consummate the Merger, and that these states therefore do not
have jurisdiction over this proposed transaction. Nevertheless, the Indiana
Commission, the Kentucky Commission and Michigan Commission have approved the
Merger, and AEP has been actively working with all of these state commissions
regarding both the FERC and state regulatory impacts of the transaction.
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B. ATOMIC ENERGY ACT
CSW, through its wholly-owned subsidiary CPL, owns a 25.2% interest in
the STP, a two-unit nuclear electric generating station. The STP is operated by
STP Operating, a Texas non-profit corporation, which is jointly-owned by CPL and
the other owners of the STP. CPL holds NRC licenses with respect to its
ownership interests in the STP and STP Operating. Section 184 of the Atomic
Energy Act provides that no license may be transferred, assigned or in any
manner disposed of, directly or indirectly, through transfer of control of any
license to any person, unless the NRC finds that the transfer is in accordance
with the provisions of the Atomic Energy Act and gives its consent in writing.
On June 19, 1998, CPL sought approval from the NRC for the transfer of
control of its NRC licenses as a result of the Merger. The Application for
Transfers of Control Regarding Operating License No. NPF-76 and NPF-80 for the
STP is filed as Exhibit D-6.1. On November 5, 1998, the NRC approved the
transfer of control of CPL's NRC licenses with a condition that the Merger must
be completed by December 31,1999. The NRC Order is filed as Exhibit D-6.2, and
incorporated by reference. On October 25, CPL requested an extension of the date
by which the Merger must be completed. On December 9, 1999, the NRC granted an
extension to June 30, 2000. After the Merger, CPL, as an operating utility
subsidiary of the Combined Company, will continue to own the identical
pre-Merger interests in the STP and STP Operating.
C. FEDERAL POWER ACT
Section 203 of the FPA provides that no public utility may sell or
otherwise dispose of its jurisdictional facilities, directly or indirectly merge
or consolidate its facilities with those of any other person, or acquire any
security of any other public utility, without first having obtained
authorization from the FERC. On April 30, 1998, AEP and CSW filed a joint
application with the FERC seeking approval of the Merger, as supplemented on
January 13, 1999. See Exhibits D-1.1 and D-1.2. A procedural schedule has been
adopted by FERC which directs the Administrative Law Judge to issue an Initial
Decision no later than November 24, 1999. This schedule will allow FERC to issue
a decision no later than March 2000. Under Section 203 of the FPA, the FERC will
approve a merger if it finds the merger to be 'consistent with the public
interest.'
On June 24, 1999, Applicants and the FERC trial staff filed the FERC
Stipulation resolving major issues related to the Merger, including all
significant competition and rate issues. In addition, FERC Trial Staff agreed to
support a finding that the Merger will have no adverse effect on competition.
The FERC Stipulation is filed as Exhibit D-1.3.
Under the terms of the FERC Stipulation, prior to the consummation of the
Merger, AEP will file with the FERC a proposal whereby it would transfer certain
control area functions relating principally to reliability and access to an
RTO.(50) As part of the transfer, AEP agreed to
- ----------
(50) As noted in Item I.B.2.d. above, on June 3, 1999, AEP and four other
utilities filed the Alliance RTO Application. CSW is participating in the ERCOT
independent regional transmission plan
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transfer functions relating to transmission service, transmission security and
control area responsibility to the RTO. In addition thereto, prior to December
31, 2000, AEP will file with the FERC an unconditional application to transfer
the corresponding control area functions relating principally to reliability and
access, controlled and/or operated by AEP and currently located in the SPP to a
FERC-approved RTO directly interconnected with the facilities located outside
the SPP. On December 20, 1999, FERC conditionally approved the application
forming the Alliance RTO, which would geographically include the transmission
systems of AEP, Consumers, Detroit Edison, FirstEnergy and Virginia Power.
The FERC Stipulation also addresses rates for transmission services and
ancillary services and confirms, subject to FERC guidance on the timing of
divestiture, that the previously announced generation divestiture program will
satisfy the market power concerns of the FERC trial staff. In its filing with
FERC, the Applicants proposed divesting ownership of 300 MW of generation
capacity at CSW's Northeastern Power Station Units 3 and 4 and 250 MW of
generation capacity located at the Frontera Power Plant, a merchant power plant
being constructed by a CSW subsidiary near Mission, Texas.
In addition to the waiver of transmission priorities that is explained in
the FERC testimony of Stephen B. Jones, Applicants agreed that they will not
assert the "AES/TVA" priority for any transfers of non-firm energy from AEP West
to AEP East for a period of four years from the date of the consummation of the
Merger.
On November 23, 1999, the Administrative Law Judge at FERC issued an
Initial Decision which approved the Merger, a copy of which is filed as Exhibit
D-1.7 and incorporated by reference. The Administrative Law Judge found that the
Merger is consistent with the public interest; the rates, terms and conditions
of service are just, reasonable and not otherwise unlawful; and the joint open
access transmission tariff providing for post-Merger transmission services is
just, reasonable and not otherwise unlawful. As noted above, a final decision
from FERC approving the Merger is expected in the first quarter, 2000.
D. COMMUNICATIONS ACT
CSW, itself or through one or more subsidiaries, holds various radio
licenses subject to the jurisdiction of the FCC under Title III of the
Communications Act. Under Section 310 of the Communications Act, no station
license may be assigned or transferred, directly or indirectly, except upon
application to and approval by the FCC. On July 26, 1999, Applicants filed with
the FCC for authority to transfer control of licenses held by several CSW
subsidiaries to AEP. See Exhibit D-9.1. On January 21, 2000, the FCC approved
the transfer of certain microwave licenses held by CSW. Applicants expect the
FCC to approve the transfer of the remaining licenses prior to the consummation
of the Merger.
- --------------------------------------------------------------------------------
for the portion of its system that is within ERCOT and is participating in
discussions with other interested parties about the formation of an RTO that
would include utility systems in the SPP.
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E. ARKANSAS COMMISSION
SWEPCO is subject to the jurisdiction of the Arkansas Commission. Pursuant
to Section 23-3-306(b) of the Arkansas Statutes, and Arkansas Commission
approval is required before any person may merge with or otherwise acquire
control of a domestic public utility. The Arkansas Commission must approve a
merger application unless it finds that one or more of five adverse
circumstances would result from the transaction. The circumstances include an
adverse effect on the public utility's existing obligations or quality of
service, a reduction in competition for the provision of utility services within
the state, and an adverse effect on the financial condition of the public
utility.
On June 12, 1998, AEP, CSW and SWEPCO filed an application with the
Arkansas Commission seeking Arkansas Commission approval of the Merger, a copy
of which is filed as Exhibit D-2.1 and incorporated by reference. On August 13,
1998, the Arkansas Commission issued an order conditionally approving the
Merger, a copy of which is filed as Exhibit D-2.2 and incorporated by reference.
F. LOUISIANA COMMISSION
SWEPCO is subject to the jurisdiction of the Louisiana Commission.
Pursuant to Louisiana Statutes Section 45:1164, the Louisiana Commission is
granted general supervisory authority over public utilities operating in the
state and, under this authority, the Louisiana Commission has held that its
approval or non-opposition is required prior to the sale, lease, merger,
consolidation, stock transfer, or any other change of control or ownership of a
public utility subject to its jurisdiction. The Louisiana Commission reviews
merger applications pursuant to an 18 factor test that generally relates to the
impact of the transaction on competition, the financial condition of the
utility, quality of service, public health and safety, employment, and other
similar "public interest" matters.
On May 15, 1998, AEP, CSW and SWEPCO filed an application seeking
Louisiana Commission approval of, or non-opposition to, the Merger, a copy of
which is filed as Exhibit D-3.1 and incorporated by reference. On July 29, 1999,
the Louisiana Commission voted to issue an order conditionally approving the
Merger, a copy of which is filed as Exhibit D-3.2 and incorporated by reference.
G. OKLAHOMA COMMISSION
PSO is subject to the jurisdiction of the Oklahoma Commission. The
Oklahoma Statutes concerning mergers and acquisitions of public utilities are
substantially identical to the sections of the Arkansas Statutes discussed
above. Oklahoma Commission approval is required before any person may merge with
or otherwise acquire control of an Oklahoma public utility.
On August 14, 1998, AEP, CSW and PSO filed an application with the
Oklahoma Commission seeking approval of the Merger, a copy of which is filed as
Exhibit D-4.1 and
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incorporated by reference. On May 4, 1999, an administrative law judge
recommended that the Oklahoma Commission approve the Merger subject to certain
conditions. Those conditions included the recommendation that Applicants
participate in an SPP study of the impacts of the effect of the Merger on the
transmission system of OG&E at its Fort Smith, Arkansas substation. On May 11,
1999, the Oklahoma Commission issued an order approving the Merger, a copy of
which is filed as Exhibit D-4.2 and incorporated by reference. The order of the
Oklahoma Commission was appealed to the Oklahoma State Supreme Court by
Municipal Electric Systems of Oklahoma and Oklahoma Association of Electric
Cooperatives. The appeal by Municipal Electric Systems of Oklahoma was dismissed
on September 8, 1999, and the appeal by Oklahoma Association of Electric
Cooperatives was dismissed on October 11, 1999.
On October 15, 1999, the Oklahoma Association of Electric Cooperatives
informed the Commission that it had have reached a settlement with Applicants
resolving all outstanding issues among them, and that the Oklahoma Association
of Electric Cooperatives no longer opposed the Merger. In addition thereto, the
Oklahoma Association of Electric Cooperatives withdrew all comments and requests
for hearing that they had previously filed in this proceeding.
H. TEXAS COMMISSION
CPL, SWEPCO, and WTU are subject to the jurisdiction of the Texas
Commission. Pursuant to Section 14.101 of the Texas Utilities Code, each
transaction involving the sale of at least 50 percent of the stock of a public
utility must be reported to the Texas Commission within a reasonable time. On
April 30, 1998, AEP, CSW, CPL, SWEPCO and WTU reported the Merger to the Texas
Commission for its review, as supplemented on January 15, 1999. See Exhibits
D-5.1 and D-5.2.
In reviewing a transaction involving the sale of at least 50 percent of
the stock of a Texas utility, the Texas Commission is required to determine
whether the action is consistent with the public interest, taking into
consideration factors such as the reasonable value of the property, facilities,
or securities to be acquired, disposed of, merged, transferred, or consolidated,
and whether the transaction will adversely affect the health or safety of
customers or employees, result in the transfer of jobs of Texas citizens to
workers domiciled outside of Texas, or result in the decline of service. On
November 18, 1999, the Texas Commission issued an order finding the Merger to be
consistent with the public interest. A copy of the order is filed as Exhibit
D-5.5 and incorporated by reference. An Administrative Law Judge had previously
recommended that the Texas Commission find the Merger to be consistent with the
public interest under Texas Law. A copy of the Administrative Law Judge's
Proposal for Decision is filed as Exhibit D-5.4 and incorporated by reference.
In the proceedings before the Texas Commission, Applicants entered into an
Integrated Stipulation and Agreement with the Public Utility Commission of Texas
General Counsel, the State of Texas (in its capacity as a consumer of
electricity), the Texas Industrial Energy Consumers, Low Income Intervenors, the
Office of Public Utility Counsel, and the Steering Committee of the Cities of
McAllen, Corpus Christi, Victoria, Abilene, Big Lake, Vernon and
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Paducah. The Texas Stipulation is filed as Exhibit D-5.3 and incorporated by
reference. In addition thereto, in a letter dated July 9, 1999 to the
administrative law judge in the Texas proceeding, Medina Electric Cooperative,
Inc. and the City of Robstown, Texas stated that they have no objection to the
Merger and would not file testimony in that proceeding. Furthermore, agreements
were reached with several wholesale customer groups including South Texas
Electric Cooperative (STEC) and its member distribution cooperatives, the City
of Brownsville Public Utility Board, the East Texas Cooperatives, which includes
East Texas Electric Cooperative Inc., Northeast Texas Electric Cooperative,
Inc., and Tex-La Electric Cooperative of Texas, Inc., and a group of
transmission dependent utilities (TDUs), which includes Magic Valley Electric
Cooperative, Inc. Mid-Tex Generation and Transmission Electric Cooperative, Inc.
and its members and Rayburn Country Electric Cooperative.
I. INDIANA COMMISSION
On April 26, 1999, the Indiana Commission issued an order approving a
stipulation and settlement agreement among AEP, CSW, and the staff of the
Indiana Commission, a copy of which is filed as Exhibit D-8.1 and incorporated
by reference.
J. KENTUCKY COMMISSION
On May 24, 1999, the Kentucky Commission issued an order approving the
stipulation among AEP, CSW, Kentucky Industrial Customers Inc., Kentucky
Industrial Steel, Inc., and the Kentucky Attorney General, a copy of which is
filed as Exhibit D-7.1 and incorporated by reference.
K. MISSOURI COMMISSION
No regulatory authorization is required from the Missouri Commission.
However, in an effort to address concerns raised by the Missouri Commission with
respect to competitive impacts that may occur as a result of Applicants' use of
the Contract Path, Applicants agreed that, as part of a settlement between
Applicants and the Missouri Commission, the Missouri Commission may initiate,
within four years of the consummation of the Merger, a review by the FERC of the
Merger's effects on retail competition, assuming retail competition has been
implemented in Missouri. The settlement also gives the FERC discretion to decide
if mitigation measures are necessary to the extent that the review results in a
finding that the Contract Path is harmful to competition. Any relief ordered by
FERC cannot extend beyond six years after the consummation of the Merger. On
January 27, 2000, the FERC approved the subject settlement.
L. MICHIGAN COMMISSION
On December 16, 1999, the Michigan Commission approved a Settlement
Agreement with AEP related to the Merger. In approving the Settlement Agreement,
the Michigan Commission agreed not to oppose the Merger at the federal level.
AEP agreed to share Merger savings with Michigan customers; establish
performance standards that will maintain or improve
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customer service and system reliability; join a RTO by December 31, 2000; and
establish affiliate rules to protect consumers and promote fair competition.
M. AFFILIATE CONTRACTS
AEP, CSW and their subsidiaries intend to enter into or amend agreements
related to the provision by affiliates of various services, including
management, supervisory, construction, engineering, accounting, legal, financial
or similar services. The approval or non-opposition of certain state regulatory
commissions and the Commission is required with respect to the creation or
amendment of certain inter-affiliate agreements. Applicants and their
subsidiaries intend to file such agreements with the appropriate state
regulatory commissions within the next few months.
ITEM 5. PROCEDURE
The Commission is respectfully requested to issue and publish not later
than November 20, 1998, the requisite notice under Rule 23 with respect to the
filing of this Application-Declaration, such notice to specify a date not later
than December 15, 1998, by which comments may be entered and a date not later
than December 16, 1998, as the date after which an order of the Commission
granting and permitting this Application-Declaration to become effective may be
entered by the Commission.
It is submitted that a recommended decision by a hearing or other
responsible officer of the Commission is not needed for approval of the Merger.
The Division of Investment Management may assist in the preparation of the
Commission's decision. There should be no waiting period between the issuance of
the Commission's order and the date on which it is to become effective.
ITEM 6. EXHIBITS AND FINANCIAL STATEMENTS
Exhibit
Number Description
*A-1 Copy of Restated Certificate of Incorporation of AEP, dated October 29,
1997 (filed as Exhibit 3(a) to the Quarterly Report on Form 10-Q for the
period ended September 30, 1997 (File No. 1-3525) and incorporated herein
by reference)
*A-2 Second Restated Certificate of Incorporation of CSW (filed as Exhibit 3(1)
to the Form 10-K for the fiscal year ended December 31, 1997 (File No.
1-1443) and incorporated herein by reference)
*A-3 Certificate of Incorporation of Merger Sub
*A-4 By-laws of Merger Sub
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<PAGE> 124
*B-1 Agreement and Plan of Merger among AEP, CSW and Merger Sub, dated at
December 21, 1997 (filed as Annex A to the Registration Statement on Form
S-4 on April 15, 1998 (Registration No. 333-50109) and incorporated herein
by reference), as amended (see Current Report of AEP on Form 8-K, dated
December 16, 1999 (File No. 1-3525) and incorporated herein by reference)
*B-2 Proposed Service Agreement between AEPSC and subsidiaries of the Combined
Company
*B-3 Proposed Attribution basis List
*B-3.1 Update Frequencies Applicable to the Proposed AEPSC Attribution Bases
*B-3.2 Comparison of AEPSC and CSWS Current Attribution Bases to Proposed
Post-Merger AEPSC Attribution Basis
*B-3.3 Scope of the Proposed Post-Merger AEPSC Attribution Bases by Class of
Companies
*B-3.4 Description of Services to be Provided by AEPSC Post-Merger and
Associated Attribution bases by Category of Services
*C-1 Registration Statement of AEP on Form S-4 (as amended) (filed as
Registration Statement No. 333-50109 and incorporated herein by reference)
*C-2 Joint Proxy Statement and Prospectus (included in Exhibit C-1)
*D-1.1 Joint Application of jurisdictional subsidiaries of AEP and CSW before
the FERC, together with exhibits, appendices and workpapers, dated April
30, 1998 (filed on Form SE) and consisting of:
VOLUME 1 - Exhibit D-1.1
Transmittal Letter dated April 30, 1998 for Section 203 of the FPA and
part 33 of the FERC's Regulations
Joint Application of AEP and CSW for Authorization and Approval of Merger
for Section 203 Filing
Appendix 1 -Designation of the Territories Served, by States and Counties
Appendix 2 -Morgan Stanley Letter to the Board of Directors concerning
Merger; Opinion Letter from Salomon Smith Barney to Board of Directors dated
December 21, 1997
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Appendix 3 - AEP and CSW Companies Community and Franchise Expiration Date
Exhibit A - Certified Copy of a Resolution of the Board of Directors of Central
and South West Corporation Adopted on December 21, 1997
Exhibit B - Statement of Measures of Control of Ownership over AEP and CSW
Exhibit C - Balance Sheets and Supporting Plant Schedules
Exhibit D - Consolidated Statement of Contingencies and Commitments as of
December 31, 1997
Exhibit E - Income Statements
Exhibit F - Analysis of Retained Earnings
Exhibit G - Copies of State and Federal Applications and Exhibits
Exhibit H - Agreement and Plan of Merger among AEP and CSW
Exhibit I - Territory Service Maps of AEP, CSW and the Ameren Interconnection
VOLUME 2 - Exhibit D-1.1
Testimonies and Exhibits for Section 203 Filing of the Following
Witnesses: Draper, Shockley, Munczinski, Baker, Hieronymus, Jones, Bethel and
Maliszewski
VOLUME 3 - Exhibit D-1.1
Workpapers of Witnesses Munczinski and Hieronymus for Section 203 Filing
VOLUME 4 - Exhibit D-1.1
Transmittal Letter dated April 30, 1998 for Section 205 of the FPA and
part 35 of the FERC's Regulations
System Integration Agreement among AEP companies and CSW companies
AEPSC Transmission Reassignment Tariff
Testimony and Exhibits of J. Craig Baker in Support of the System
Integration Tariff
System Transmission Integration Agreement among AEP companies and CSW
companies
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<PAGE> 126
Testimony and Exhibits of Dennis W. Bethel in Support of the System
Transmission Integration Agreement
VOLUME 5 - Exhibit D-1.1
Transmittal Letter dated April 30, 1998 for Section 205 of the FPA Open
Access
Transmission Service Tariff of the AEP System
VOLUME 6 - Exhibit D-1.1
AEP System Procedures for Implementation of the FERC Standards of Conduct
Testimony and Exhibits of Dennis W. Bethel
Testimony and Exhibits of Bruce M. Barber
VOLUME 7 - Exhibit D-1.1
Workpapers of Dennis W. Bethel
*D-1.2 Supplemental and Direct Testimony before the FERC, January 13, 1999 filed
herewith on Form SE) and consisting of:
VOLUME 1 - Exhibit D-1.2
Transmittal Letter dated January 13, 1999
Supplemental and Direct Testimonies and Exhibits for the Following
Witnesses: Baker, Jones, Smith, Maliszewski, Henderson
VOLUME 2 - Exhibit D-1.2
Supplemental and Direct Testimonies and Exhibits for the Following
Witnesses: Hieronymus, Zausner
VOLUMES 3-6 - Exhibit D-1.2
Workpapers of Witness Henderson
VOLUMES 7-71 - Exhibit D-1.2
Workpapers of Witness Hieronymus
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<PAGE> 127
*D-1.3 Stipulation of American Electric Power Company, Inc., Central and South
West Corporation, and Commission Trial Staff, FERC Docket No. EC 98-40
(filed June 24, 1999).
*D-1.4 Stipulation of American Electric Power Company, Inc., Central and South
West Corporation, and Commission Trial Staff, FERC Docket No. ER98-2770.
*D-1.5 Application for Approval of the Alliance Regional Transmission
Organization under Section 205 of the Federal Power Act, Docket No.
ER99-3144 (filed June 3, 1999).
*D-1.6 Application for Approval of Transaction under Section 203 of the Federal
Power Act, Docket No. EC 99-80 (filed June 3, 1999).
D-1.7 Initial Decision, Docket Nos. EC98-40, et al. (issued November 23, 1999)
(to be filed by amendment).
D-1.8 Order on Proposed Disposition, Alliance Companies, 89 FERC P. 61,298
(December 20, 1999) (to be filed by amendment).
*D-2.1 Joint Application of AEP, CSW and SWEPCO before the Arkansas Commission,
together with exhibits, appendices, and workpapers, dated June 12, 1998
(filed on Form SE) and consisting of:
VOLUME 1 - Exhibit D-2.1
Joint Application with Exhibits of AEP, SWEPCO, and CSW regarding Merger
Exhibit A - AEP's Corporate Structure and Listing of Affiliate Companies
and Business Engaged
Exhibit B - Restated Certificate of Incorporation of AEP
Exhibit C - Statement of Directors' and Officers' Qualifications
Exhibit D - AEP's 1997 Summary Report to Shareholders
Exhibit E - Annual Report of AEP on Form 10-K for the Year Ended December
31, 1997 (File No. 1-3525)
Exhibit F - Quarterly Report of AEP on Form 10-Q for the Quarter Ended
March 31, 1998 (File No. 1-3525)
Exhibit G - Registration Statement of AEP on Form S-4, Amendment No. 1
(Registration No. 333-50109)
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Exhibit H - Notice to Customers of SWEPCO
VOLUME 2 - Exhibit D-2.1
Direct Testimony and Exhibits of the Following Witnesses: Draper,
Shockley, Flaherty, Baker, Munczinski, Roberson, Davis, Hieronymus, Mitchell,
Pena, Martin and Bailey
VOLUME 3 - Exhibit D-2.1
Workpapers of Witness Roberson
Workpapers of Witness Davis
VOLUME 4 - Exhibit D-2.1
Continued Workpapers of Witness Davis
Workpapers of Witness Pena
Workpapers of Witness Martin
Workpapers of Witness Munczinski
VOLUME 5 - Exhibit D-2.1
Workpapers of Witness Flaherty
VOLUME 6 - Exhibit D-2.1
Continued Workpapers of Witness Flaherty
*D-2.2 Order of Arkansas Commission conditionally approving the Merger, dated
August 13, 1998
*D-3.1 Joint Application of AEP, CSW and SWEPCO before the Louisiana Commission,
together with exhibits, appendices and workpapers, dated May 15, 1998
(filed on Form SE) and consisting of:
VOLUME 1 - Exhibit D-3.1
Joint Application of SWEPCO, CSW, and AEP for Approval of Proposed
Business Combination
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<PAGE> 129
Testimony and Exhibits of the Following Witnesses: Draper, Shockley,
Flaherty, Baker, Munczinski, Roberson, Davis, Hieronymus, Mitchell, Pena, Martin
and Bailey
VOLUME 2 - Exhibit D-3.1
Workpapers of Witness Roberson
Workpapers of Witness Davis
VOLUME 3 - Exhibit D-3.1
Continued Workpapers of Witness Davis
Workpapers of Witness Pena
Workpapers of Witness Martin
Workpapers of Witness Munczinski
VOLUME 4 - Exhibit D-3.1
Workpapers of Witness Flaherty
VOLUME 5 - Exhibit D-3.1
Continued Workpapers of Witness Flaherty
*D-3.2 Order of the Louisiana Commission conditionally approving the Merger,
dated July 29, 1999 (to be filed by amendment)
*D-4.1 Joint Application of AEP, CSW and PSO before the Oklahoma Commission,
together with exhibits, appendices and workpapers, dated August 14, 1998
(filed on Form SE) and consisting of:
VOLUME 1 - Exhibit D-4.1
Joint Application of AEP, PSO and CSW regarding Proposed Merger
Appendix 1-Statement Required by 17 O.S. sec. 191.3
Appendix 2 -Notice of Hearing
Exhibit A - AEP's Corporate Structure and Listing of Affiliate Companies
and Business Engaged
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<PAGE> 130
Exhibit B - Restated Certificate of Incorporation of AEP
Exhibit C - Statement of Directors' and Officers' Qualifications Exhibit D
- 1997 Summary Report to Shareholders of AEP
Exhibit E - Annual Report of AEP on Form 10-K for the Year Ended December
31, 1997 (File No. 1-3525)
Exhibit F - Quarterly Report of AEP on Form 10-Q for the Quarter Ended
March 31, 1998 (File No. 1-3525)
Exhibit G - Registration Statement of AEP on Form S-4, Amendment No. 1
(Registration No. 333-50109)
VOLUME 2 - Exhibit D-4.1
Direct Testimony and Exhibits of the Following Witnesses: Draper,
Shockley, Flaherty, Baker, Munczinski, Roberson, Davis, Hieronymus, Mitchell,
Pena, Evans and Bailey
VOLUME 3 - Exhibit D-4.1
Workpapers of Witness Flaherty
VOLUME 4 - Exhibit D-4.1
Continued Workpapers of Witness Flaherty
Workpapers of Witness Munczinski
Workpapers of Witness Roberson
VOLUME 5 - Exhibit D-4.1
Workpapers of Witness Davis
VOLUME 6 - Exhibit D-4.1
Continued Workpapers of Witness Davis
Workpapers of Witness Pena
Workpapers of Witness Evans
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<PAGE> 131
*D-4.2 Order of Oklahoma Commission conditionally approving the Merger, dated
May 11, 1999
*D-5.1 Joint Application of AEP, CSW and PSO before the Texas Commission,
together with exhibits, appendices and workpapers, dated April 30, 1998
(filed on Form SE) and consisting of:
VOLUME 1 - Exhibit D-5.1
Petition of CSW and AEP Direct Testimony and Exhibits of the Following
Witnesses: Draper, Shockley, Flaherty, Baker, Munczinski, Roberson, Davis,
Hieronymus, Mitchell, Pena, Evans and Bailey
VOLUME 2 - Exhibit D-5.1
Workpapers of Witness Flaherty
VOLUME 3 - Exhibit D-5.1
Workpapers of Witness Roberson
Workpapers of Witness Davis
Workpapers of Witness Pena
Workpapers of Witness Evans
*D-5.2 Direct Testimony, Supplemental Direct Testimony and Second Supplemental
Direct Testimony before the Texas Commission, January 15, 1999 (filed
herewith on Form SE) and consisting of:
Transmittal Letter dated January 15, 1999
Supplemental and Direct Testimonies and Exhibits of the Following
Witnesses: Hieronymus, Jones, Mitchell, Roberson
*D-5.3 Stipulation and Agreement between the Public Utility Commission of Texas
General Counsel, the State of Texas (in its capacity as a consumer of
electricity), the Texas Industrial Energy Consumers, Low Income
Intervenors, the Office of Public Utility Counsel, and the Steering
Committee of the Cities of McAllen, Corpus Christi, Victoria, Abilene,
Big Lake, Vernon and Paducah.
D-5.4 Proposal for Decision issued September 30, 1999 (to be filed by
amendment).
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D-5.5 Order of Public Utility Commission of Texas dated November 18, 1999 (to
be filed by amendment).
*D-6.1 Application for Transfers of Control Regarding Operating License No.
NPF-76 and NPF-80 for the South Texas Project, dated June 19, 1998
*D-6.2 Order Approving Application for Transfers of Control Regarding Operating
License No. NPF-76 and NPF-80 for the South Texas Project, Docket Nos.
50-498, 499 (issued Nov. 5, 1998).
*D-7.1 Order of Kentucky Commission conditionally approving the Merger, dated
May 24, 1999
*D-8.1 Order of Indiana Commission conditionally approving the Merger, dated
April 26, 1999
*D-9.1 Application for Transfer of License, dated July 29, 1999
D-10.1 Order of Michigan Commission approving Settlement, dated December 16,
1999 (to be filed by amendment).
*E-1 Map of AEP service area, major transmission lines and interconnection
points (filed on Form SE)
*E-2 Map of CSW service area, major transmission lines and interconnection
points (filed on Form SE)
*E-3 Map of transmission lines showing the 250 MW Contract Path linking the
Combined System (filed on Form SE)
*E-4 AEP corporate chart (filed on Form SE)
*E-5 CSW corporate chart (filed on Form SE)
*E-6 Combined Company corporate chart after the Merger (filed on Form SE)
*F-1 Opinion of Counsel
*F-2 Opinion of Counsel
*F-1-1 Past-tense Opinion of Counsel
*F-2-1 Past-tense Opinion of Counsel
*G-1 Annual Report of AEP on Form 10-K for the year ended December 31, 1997, as
amended, (File No. 1-3525) and incorporated herein by reference
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*G-2 Quarterly Report of AEP on Form 10-Q for the quarter ended March 31, 1998
(File No. 1-3525) and incorporated herein by reference
*G-3 Quarterly Report of AEP on Form 10-Q for the quarter ended June 30, 1998
(File No. 1-3525) and incorporated herein by reference
*G-4 Annual Report of CSW on Form 10-K for the year ended December 31, 1997
(File No. 1-1443) and incorporated herein by reference
*G-5 Quarterly Report of CSW on Form 10-Q for the quarter ended March 31, 1998
(File No. 1-1443) and incorporated herein by reference
*G-6 Quarterly Report of CSW on Form 10-Q for the quarter ended June 30, 1998
(File No. 1-1443) and incorporated herein by reference
*G-7 AEP Consolidated Balance Sheet as of June 30, 1998 (incorporated by
reference to the Quarterly Report on Form 10-Q of AEP for the quarterly
period ended June 30, 1998 (File No. 1-3525)
*G-8 Combined Company Unaudited Pro Forma Combined Balance Sheet at June 30,
1998
*G-9 AEP Statement of Income for the period ended June 30, 1998 (incorporated
by reference to the Quarterly Report on Form 10-Q of AEP for the quarterly
period ended June 30, 1998 (File No. 1-3525)
*G-10 Combined Company Unaudited Pro Forma Combined Statement of Income for the
twelve-month period ended June 30, 1998
*G-11 Combined Company Unaudited Pro Forma Combined Statement of Retained
Earnings for the twelve-month period ended June 30, 1998
*G-12 CSW Consolidated Balance Sheet as of June 30, 1998 (incorporated by
reference to the Quarterly Report on Form 10-Q of CSW for the quarterly
period ended June 30, 1998 (File No. 1-1443)
*G-13 CSW Consolidated Statement of Income as of June 30, 1998 (incorporated by
reference to the Quarterly Report on Form 10-Q of CSW for the quarterly
period ended June 30, 1998) (File No. 1-1443)
*G-14 CSW Consolidated Statement of Income for the fiscal years ended December
31, 1997, 1996 and 1995 (incorporated herein by reference to the Annual
Report of CSW on Form 10-K for the year ended December 31, 1997 (File No.
1-1443)
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*G-15 Annual Report of AEP on Form 10-K for the year ended December 31, 1998
(File No. 1-3525) and incorporated herein by reference
*G-16 Quarterly Report of AEP on Form 10-Q for the quarter ended March 31, 1999
(File No. 1-3525) and incorporated herein by reference
*G-17 Annual Report of CSW on Form 10-K for the year ended December 31, 1998
(File No. 1-1443) and incorporated herein by reference
*G-18 Quarterly Report of CSW on Form 10-Q for the quarter ended March 31, 1999
(File No. 1-1443) and incorporated herein by reference
*G-19 Quarterly Report of AEP on Form 10-Q for the quarter ended June 30, 1999
(File No. 1-3525) and incorporated herein by reference
*G-20 Quarterly Report of CSW on Form 10-Q for the quarter ended June 30, 1999
(File No. 1-1443) and incorporated herein by reference
G-21 Quarterly Report of AEP on Form 10-Q for the quarter ended September 30,
1999 (File No. 1-3525) and incorporated herein by reference
G-22 Quarterly Report of CSW on Form 10-Q for the quarter ended September 30,
1999 (File No. 1-1443) and incorporated herein by reference
*H Proposed Form of Notice
*I-1 CSWS Authorizations
I-2 Short-Term Borrowing Program
*I-3 CSW Credit Authorizations
*I-4 CSW Guarantee Authorizations
*J Tax Basis Discussion
*K Agreement between Applicants and International Brotherhood of Electrical
Workers
* Previously filed.
ITEM 7. INFORMATION AS TO ENVIRONMENTAL EFFECTS
The Merger neither involves "major federal actions" nor "significantly
[affects] the quality of the human environment" as those terms are used in
Section (2)(C) of the National Environmental Policy Act, 42 U.S.C. Sec. 4332.
The only federal actions related to the Merger
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pertain to the Commission's declaration of the effectiveness of the Registration
Statement, the approvals and actions described under Item 4 and Commission
approval of this Application-Declaration. Consummation of the Merger will not
result in significant changes in the operations of public utilities of the AEP
or CSW Systems or have any significant impact on the environment. Apart from the
Application for Transfers of Control Regarding Operating License No. NPF-76 and
NPF-80 in connection with the STP, no federal agency is preparing an
environmental impact statement with respect to this matter.
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SIGNATURE
Pursuant to the requirements of the Public Utility Holding Company Act of
1935, the undersigned companies have duly caused this statement to be signed on
their behalf by the undersigned thereunto duly authorized.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: /s/ A. A. Pena
------------------------------------
Treasurer
CENTRAL AND SOUTH WEST CORPORATION
By: /s/ Wendy G. Hargus
-------------------------------------
Treasurer
Dated: March 1, 2000
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STATUS OF STATE RESTRUCTURING LEGISLATION
The following is a summary of restructuring legislation in the states in
which the Combined Company will operate:
1. Arkansas
On April 15, 1999, the Governor of Arkansas signed into law a
comprehensive restructuring bill that calls for retail competition to start as
early as January 1, 2002, but in no event later than June 30, 2003. Under the
measure, utilities may recover transition and net stranded costs and may use
securitization to mitigate stranded costs. Utilities that recover stranded costs
must freeze rates for residential and small commercial customers for three
years, and, for those utilities that do not recover stranded costs, rates must
be frozen for one year. Utilities must functionally unbundle into generation,
transmission, and distribution units by either creating separate divisions,
nonaffiliated companies, separate affiliated companies, or by selling assets to
a third party. The Arkansas Commission can force divestiture of generation
assets to alleviate market power, and it can decide if stockholders should share
stranded cost recovery with ratepayers.
2. Louisiana
In Louisiana, the staff of the Louisiana Commission, in May 1999,
presented a report on restructuring, recommending a slow approach to adoption of
restructuring legislation. The report states that Louisiana has lower than
national average electric rates, and competition could increase prices, not
lower them. The report recommends that no action be taken at this time, but
"reluctantly" submitted a draft restructuring plan in case the Louisiana
Commission decides to order retail competition. In Louisiana, the Louisiana
Commission can order retail competition without legislative action.
3. Ohio
On July 6, 1999, the governor of Ohio signed "The Ohio Electric
Restructuring Act of 1999" (the "Ohio Act") that will restructure the electric
utility industry in Ohio affecting OPCo and CSPCo. The Ohio Act provides for
customer choice of electricity supplier and a residential rate reduction of 5%
of the unbundled generation rate beginning on January 1, 2001. The Ohio Act also
provides for a five-year transition period to move from cost based rates to
market pricing for generation services. The law provides Ohio electric utilities
the opportunity to recover regulatory assets and other potential stranded costs.
Retail electric services that will be competitive are defined in the Ohio
Act as electric generation service, aggregation service, and power marketing and
brokering. The Ohio Commission has been granted broad oversight responsibility
under the Ohio Act. The Ohio Act requires the Ohio Commission to promulgate
rules for competitive retail electric generation service.
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The Ohio Act further provides Ohio electric utilities with an opportunity
to recover Ohio Commission approved allowable transition costs through unbundled
rates paid by customers who do not switch generation suppliers and through a
wires charge by customers who switch generation suppliers. Transition costs can
include regulatory assets, impairments of generating assets and other stranded
costs, employee severance and retraining costs and other costs. Recovery of
transition revenues can under certain circumstances extend beyond the five-year
transition period but cannot continue beyond December 31, 2010. AEP must file a
transition plan with the Ohio Commission by January 3, 2000, and the Ohio
Commission is required to issue a transition order no later than October 31,
2000. On December 30, 1999, AEP, on behalf of its subsidiaries CSPCo and OPCo,
filed its restructuring transition plan required by the Ohio Act. The filing
provides details on the companies' proposed rate unbundling, corporate
separation, operational support, employee assistance and consumer education
plans. The filing also includes a request to recover transition costs and a
proposal for independent operation of transmission facilities.
The Ohio Act also provides that the property tax assessment percentage on
electric generation equipment be lowered from 100% to 25% of value effective
January 1, 2001. Electric utilities will also become subject to the Ohio
Corporate Franchise Tax and municipal income taxes on January 1, 2002. The last
year for which electric utilities will pay the excise tax based on gross
receipts is the year ending April 30, 2002. As of May 1, 2001 electric
distribution companies will be subject to an excise tax based on kilowatt-hours
sold to Ohio customers. It is expected that these changes will put the company's
generation operations on an equal basis with other competitive businesses in
Ohio regarding state taxation.
4. Oklahoma
In April, 1997, the Oklahoma Legislature passed restructuring legislation
providing for retail access by July 1, 2002. That legislation called for a
number of studies to be completed on a variety of restructuring issues,
including independent system operator issues, technical issues, financial
issues, transition issues and consumer issues. The study on independent system
operator issues was completed in January, 1998. The Legislative Joint Electric
Utility Task Force completed its studies of the remaining issues and provided
its final report to the Oklahoma Legislature on October 1, 1999.
5. Texas
On June 18, 1999, the Texas Legislature passed restructuring legislation
that will restructure the electric utility industry within the state. The new
law gives Texas customers of investor-owned utilities the opportunity to choose
their electricity provider beginning January 1, 2002. The legislation also
provides a rate freeze until that date followed by a 6% rate reduction for
residential and small commercial customers, additional rate reductions for low
income customers and a number of customer protections. Rural electric
cooperatives and municipal electric systems can choose whether to participate in
retail competition. Some of the key provisions of the legislation include:
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- - Beginning January 1, 2002, retail customers of investor-owned electric
companies will be able to choose their electric provider. The affiliated
retail electric provider of the utility that serves the customer on
December 31, 2001 will continue to serve the customer unless the customer
chooses another retail electric provider. Delivery of the electricity will
continue to be the responsibility of the local electric utility company at
regulated prices. Each utility must unbundle its business activities into
a retail electric provider, a power generation company and a transmission
and distribution utility.
- - Retail electric cooperatives and municipal electric systems can choose
whether to participate in retail competition.
- - Investor-owned utilities must freeze their rates effective September 1,
1999, through the start of competition on January 1, 2002. Investor-owned
utilities at January 1, 2002 will lower rates for residential and small
commercial customers by 6%. This reduced rate is known as the "Price to
Beat," which will be available to those customers for five years.
- - The legislation establishes a system benefit fund for low-income customer
assistance, customer education and to offset reductions in school property
tax revenues. The fund will be funded through a charge on retail electric
providers that can be set by the Texas Commission at up to 65 cents per
MWH.
- - Electric utilities are allowed to recover all of their net, verifiable,
non-mitigable stranded costs that otherwise may not be recoverable in the
future competitive market. A majority of those regulatory assets and
stranded costs can be recovered through securitization, which is a
financing process to recover regulatory assets and stranded costs through
the use of debt that lowers the financing cost of assets compared to
conventional utility financing methods.
- - Each year during the 1999 through 2001 rate freeze period, utilities with
stranded costs are required to apply any earnings in excess of the most
recently approved cost of capital (if issued on or after January 1, 1992)
to reduce stranded costs. Utilities without stranded costs must either
flow such amounts back to customers or make capital expenditures to
improve transmission or distribution facilities or to improve air quality.
- - Investor-owned utilities will be required to auction entitlements to at
least 15% of their generating capacity for five years or until 40% of the
residential and small commercial consumption of electricity in the
utility's service area is provided by nonaffiliated retail electric
providers.
- - Grandfathered power plants, those built or started prior to implementation
of the Texas Clean Air Act of 1972, must reduce emissions of Nitrogen
Oxide by 50% and Sulfur Dioxide by 25% by May, 2003. The law also requires
an additional
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2,000 MW of renewable power generation in Texas by 2009 from retail
electric providers, municipally owned utilities and electric cooperatives.
- - A legislative oversight committee will be established to monitor the
implementation and effectiveness of electric utility restructuring and
make recommendations for any necessary further legislative action. The
Texas Commission has established numerous task forces to address various
issues associated with the restructuring legislation and to provide for
further guidance regarding implementation of the restructuring.
6. Virginia
In March, 1999, Virginia enacted a new law to restructure the electric
utility industry in that state. Under the restructuring law, a transition to
choice of supplier for retail customers will commence on January 1, 2002 and be
completed, subject to a finding by the Virginia Commission that an effective
competitive market exists, by January 1, 2004. Provisions allowing for an
acceleration or limited delay in this schedule are also contained in the law.
Except as provided in the law, the generation of electricity will not be subject
to rate regulation after January 1, 2002. APCo's retail pilot program would
allow approximately 2% of its retail customers to participate in June, 2000, and
an additional 8% of its retail customers would be allowed to participate by
March, 2001. Both phases of the program would be weighted heavily toward
industrial customers. APCo proposed that industrial customers will account for
35 MW of the 50 MW load opened to competition in June, 2000, and will account
for 140 MW of the 200 MW load opened to competition in March, 2001. The Virginia
Commission held hearings on APCo's proposal in November, 1999. Additionally,
each Virginia electric utility is required by 2001 to join or establish a
regional transmission entity which will manage and control transmission assets.
The Virginia restructuring law also provides an opportunity for recovery of just
and reasonable net stranded costs.
7. West Virginia
On February 7, 2000, the West Virginia Public Service Commission passed a
plan to restructure the state's electric industry. The restructuring plan would
begin January 1, 2001. Provisions in the plan include a four-year freeze on
electric rates and a nine-year transition period during which only incremental
increases could occur while competition begins. The plan would add a small
charge to all electric bills in order to collect approximately $84 million which
the PSC would then redistribute to residential customers near the end of the 13
year period for rate relief during the transition to competition.
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Exhibit I-2
Short-Term Borrowing Program
Pursuant to Central and South West Corp., et al., HCAR No. 26697 (Mar. 28,
1997), this Commission granted an extension of authority for CSW, CPL, PSO,
SWEPCO, WTU and CSWS (the "Money Pool Participants") to continue their
short-term borrowing program through March 31, 2002, including the sale of
commercial paper by CSW to commercial paper dealers and financial institutions,
and the sale of short-term notes to banks and their trust departments, by the
Money Pool Participants.
Pursuant to Central and South West Corp., et al., HCAR No. 26854 (Apr. 3,
1998), this Commission authorized increased short-term borrowing limits for CSW
and the Money Pool Participants as follows:
<TABLE>
<S> <C>
- --------------------------------------------------------------------------------
CSW $2,500,000,000
- --------------------------------------------------------------------------------
CPL $ 600,000,000
- --------------------------------------------------------------------------------
PSO $ 300,000,000
- --------------------------------------------------------------------------------
SWEPCO $ 250,000,000
- --------------------------------------------------------------------------------
WTU $ 165,000,000
- --------------------------------------------------------------------------------
CSWS $ 210,000,000
- --------------------------------------------------------------------------------
</TABLE>
Pursuant to American Elec. Power Co., et al., HCAR No. 27049 (July 14,
1999), this Commission authorized the following short-term borrowing limits for
AEP and certain of its subsidiaries identified below (the "AEP Utility
Subsidiaries"):
<TABLE>
<S> <C>
- --------------------------------------------------------------------------------
AEP $ 500,000,000
- --------------------------------------------------------------------------------
AEGCo $ 125,000,000
- --------------------------------------------------------------------------------
APCo $ 325,000,000
- --------------------------------------------------------------------------------
CSPCo $ 350,000,000
- --------------------------------------------------------------------------------
I&M $ 500,000,000
- --------------------------------------------------------------------------------
KPCo $ 150,000,000
- --------------------------------------------------------------------------------
KgPCo $ 30,000,000
- --------------------------------------------------------------------------------
OPCo $ 450,000,000
- --------------------------------------------------------------------------------
WPCo $ 30,000,000
- --------------------------------------------------------------------------------
TOTAL:$2,460,000,000
- --------------------------------------------------------------------------------
</TABLE>
Applicants hereby request authority, effective upon consummation of the
Merger, for the Combined Company to continue the Money Pool and to manage and
fund it consistent with all the terms and conditions of Central and South West
Corp., et al., HCAR No. 26697 (Mar. 28, 1997); Central and South West Corp., et
al., HCAR No. 26854 (Apr. 3, 1998) and all previous orders of this Commission
relating to the Money Pool subject to the following: (1) CSW's $2,500,000,000
short-term borrowing authorization shall transfer to the Combined Company and
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<PAGE> 2
Combined Company's short-term borrowing limit shall be increased from
$500,000,000 to $5,000,000,000 (such limit consisting of (a) $2,500,000,000
authorized for CSW, (b) $2,460,000,000 authorized for AEP and AEP Utility
Subsidiaries, and (c) $40,000,000 for AEPSC); (2) the Combined Company and the
AEP Utility Subsidiaries shall be added as participants to the Money Pool and
permitted to issue short term debt up to the amounts specified in American Elec.
Power Co., et al., HCAR No. 26867 (May 4, 1998); and (3) the Coal Subsidiaries
and AEPSC shall be added as participants to the Money Pool, although their
borrowings would be exempt under Rule 52(b).
140
