File No. 70-9381
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
* * *
AMENDMENT NO. 2
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
Susan Tomasky Jeffrey D. Cross
Senior 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
2445 M Street, N.W. 1 Chase Manhattan Plaza
Washington, DC 20037-1420 New York, NY 10005
(Names and addresses of agents for service)
TABLE OF CONTENTS
Page
ITEM 1. DESCRIPTION OF MERGER 1
A. INTRODUCTION 1
B. DESCRIPTION OF THE 3
PARTIES TO THE MERGER
1. General Description 3
2. Description of 12
Energy Sales and Facilities
3. Electric Coordination 22
C. DESCRIPTION OF MERGER AND
STATEMENT AS TO CONSIDERATION 25
1. Background of the Merger 25
2. Merger Agreement 26
3. Reasons for the Merger 27
4. AEP Management 28
Following the Merger
ITEM 2. FEES, COMMISSIONS AND EXPENSES 28
ITEM 3. APPLICABLE STATUTORY PROVISIONS 29
A. SECTION 10(b) 31
1. Section 10(b)(1) 31
2. Section 10(b)(2) 40
3. Section 10(b)(3) 47
B. SECTION 10(c) 50
1. Section 10(c)(1) 50
2. Section 10(c)(2) 71
C. SECTION 10(f) 73
D. INTRA-SYSTEM FINANCING
AND OTHER COMMISSION
AUTHORIZATIONS 73
E. SERVICE AGREEMENT;
APPROVAL OF METHODOLOGY
FOR ALLOCATING COSTS
UNDER THE SERVICE AGREEMENT 74
F. ACQUISITION OF
NON-UTILITY BUSINESSES 75
G. ORGANIZATION OF MERGER
SUB; ACQUISITION OF
MERGER SUB COMMON STOCK 76
ITEM 4. REGULATORY APPROVAL 76
A. ANTITRUST CONSIDERATIONS 77
B. ATOMIC ENERGY ACT 77
C. FEDERAL POWER ACT 78
D. COMMUNICATIONS ACT 78
E. ARKANSAS COMMISSION 78
F. LOUISIANA COMMISSION 78
G. OKLAHOMA COMMISSION 79
H. TEXAS COMMISSION 79
I. AFFILIATE CONTRACTS 80
ITEM 5. PROCEDURE 80
ITEM 6. EXHIBITS AND FINANCIAL STATEMENTS 80
ITEM 7. INFORMATION AS TO ENVIRONMENTAL 82
EFFECTS
GLOSSARY OF TERMS
The following abbreviations or acronyms used in this Application-Declaration are
defined below:
250 MW Contractual reservation of 250 MW
Contract Path 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
AEGCo AEP Generating Company
AEP American Electric Power Company,
Inc. before the Merger,
unless the context indicates
otherwise
AEPC AEP Communications, LLC
AEP Common AEP common stock, $6.50 par value
Stock
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
Ameren Ameren Corporation, a public
utility holding company
registered under the 1935 Act
Antitrust Antitrust Division of U.S.
Division Department of Justice
APCo Appalachian Power Company
Applicants AEP and CSW
Arkansas Arkansas Public Service Commission
Commission
Atomic Energy Atomic Energy Act of 1954, as
Act amended
C3 C3 Communications, Inc.
Communications
Commission Securities and Exchange Commission
Central Computer software program,
Dispatch developed by the Applicants
Planning 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 Computer software program,
Economic developed by the Applicants
Dispatch 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 AEP following the Merger
Company
Combined System resulting from combination
System of the AEP System and
CSW System following the Merger
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 CSW common stock, $3.50 par value
Stock
CSW Credit CSW Credit, Inc.
CSW Energy CSW Energy, Inc.
CSW Energy CSW Energy Services, Inc.
Services
CSW CSW International, Inc.
International
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
Division Commission's Division of
Investment Management
D.C. Circuit U.S. Court of Appeals for the
District of Columbia Circuit
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 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
Excluded Shares of CSW Common Stock owned
Shares 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
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
I&M Indiana Michigan Power Company
IPP Independent Power Producer
ISO Independent System Operator
KPCo Kentucky Power Company
KgPCo Kingsport Power Company
Kv Kilovolt
KwH Kilowatt hours
Louisiana Louisiana Public Service Commission
Commission
Merger Business combination of AEP and
CSW pursuant to the
Merger Agreement
Merger Agreement and Plan of Merger,
Agreement 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
Merger Sub Augusta Acquisition Corporation,
to become a wholly
owned subsidiary of AEP
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 Nanyang General Light Electric
Electric Co., Ltd.
NCE New Century Energies, Inc.
NEPOOL New England Power Pool
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
OASIS Open Access Same-Time Information
System
Ohio Public Utilities Commission of Ohio
Commission
OPCo Ohio Power Company
Oklahoma Corporation Commission of the
Commission State of Oklahoma
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 Joint Proxy Statement/Prospectus
Statement dated April 16, 1998 of
AEP and CSW
Salomon Salomon Smith Barney Inc., an
investment banking firm
and AEP's financial adviser with
respect to the Merger
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
in which CPL owns a 25.2% interest
STP Operating STP Nuclear Operating Company
SWEPCO Southwestern Electric Power Company
Texas Public Utility Commission of Texas
Commission
UE Union Electric Company, a public
utility and a wholly
owned subsidiary of Ameren
West Virginia West Virginia Public Service
Commission Commission
WPCo Wheeling Power Company
WR Western Resources, Inc.
WTU West Texas Utilities Company
Yorkshire Yorkshire Electricity Group plc,
Electricity 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 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 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 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 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.
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 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/FTC
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 except the
FCC and DOJ/FTC, with which they intend to file during the next several months.
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. 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 TO 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, 1997, the U.S. subsidiaries of AEP had a total of 17,844
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
877,000 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, 1997, APCo had 3,877 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 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 621,000
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, 1997, CSPCo had 1,802
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
549,000 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,
1997, I&M had 3,306 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 Utility Regulatory
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
168,000 customers in eastern Kentucky, and in supplying electric power at
wholesale to other utilities and municipalities in Kentucky. At December 31,
1997, KPCo had 731 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
Public Service Commission.
KgPCo (organized in Virginia in 1917) provides electric service to
approximately 43,000 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, 1997, KgPCo had 85 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 approximately 679,000 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, 1997, OPCo and its wholly owned subsidiaries had 4,376 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, 1997, WPCo had
94 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, qualifying cogeneration facilities 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 2.1 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 has commenced and will continue through completion
thereof, which is expected to occur sometime before the end of 1999.
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.
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 $1,645,000,000 at June 30, 1998) 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. 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 August 31, 1998, there were 190,915,648 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.
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, 1998,
there were 194,902 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, 1998, 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. As of June 30, 1998, there were
59,767 shares of its 4-1/8% Cumulative Preferred Stock outstanding; 14,912
shares of its 4.56% Cumulative Preferred Stock outstanding; 19,131 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, 1998, there were
15,393 shares of its 4.08% Cumulative Preferred Stock outstanding; 103,821
shares of its 4-1/2% Cumulative Preferred Stock outstanding; 23,100 shares of
its 4.20% Cumulative Preferred Stock outstanding; 32,474 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,
1998, after eliminating intercompany transactions, were $8,195,575,000.
Consolidated assets of AEP and its subsidiaries as of June 30, 1998, were
approximately $17.8 billion, consisting of $11.6 billion in net electric utility
property, plant and equipment and $6.2 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, 1997, as amended, and
the Quarterly Reports on Form 10-Q for the quarters ended March 31, 1998, as
amended, and June 30, 1998, each of which is attached and incorporated by
reference as Exhibits G-1, G-2 and G-3, 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, 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 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, 1997, the U.S. subsidiaries of CSW had 7,254 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
628,000 customers in portions of south Texas, and in supplying electric power
at wholesale to other electric utility companies and municipalities. At
December 31, 1997, CPL had 1,668 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
481,000 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, 1997, PSO had 1,273 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
416,000 customers in portions of northeastern Texas, northwestern Louisiana
and western Arkansas, and in supplying electric power at wholesale to other
electric utility companies and municipalities. At December 31, 1997, SWEPCO
had 1,529 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
187,000 customers in portions of central west Texas, and in supplying
electric power at wholesale to other electric utility companies and
municipalities. At December 31, 1997, WTU had 907 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 $1,781,000,000 at June 30, 1998) for investment in EWGs and
FUCOs 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 and serves as an energy service provider to wholesale and retail
customers. 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 August 31,
1998, there were 212,461,876 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 June 30, 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 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 June 30,
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 June 30, 1998, there were 44,640 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 June 30, 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 June 30, 1998, there were 37,739 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 June 30, 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 June 30, 1998, there were 23,675 shares of 4.40% Series Cumulative Preferred
Stock outstanding.
CSW's consolidated operating revenues for the twelve months ended June 30,
1998, after eliminating intercompany transactions, were approximately $5.4
billion. Consolidated assets of CSW and its subsidiaries as of June 30, 1998
were approximately $13.8 billion, consisting of $8.4 billion in net electric
utility property, plant and equipment and $5.4 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,
1997 and the Quarterly Reports on Form 10-Q for the quarters ended March 31,
1998 and June 30, 1998, each of which is attached and incorporated by reference
as Exhibits G-4, G-5 and G-6, 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.
2. Description of Energy Sales and Facilities
a. AEP
(i) Energy Sales
KwH of Electric Energy Sold (in millions)
Company Twelve Months Ended December 31, 1997
APCo 46,658
CSPCo 22,601
I&M 34,546
KPCo 12,408
KgPCo 1,774
OPCo 55,875
WPCo 1,795
AEP Total 145,423(a)
(a) Total after the elimination of intercompany transactions.
(ii) Electric Generating Facilities
At December 31, 1997, subsidiaries of AEP owned (or leased where indicated)
generating plants with the net power capabilities (winter rating) shown in the
following table:
Net
Megawatt
Owner, Plant Type and Name Location (Near) Capability
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
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
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
(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 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, 1995, 1996 and 1997.
1995 1996 1997 (a)
---------- ---------- ---------
(in thousands)
APCo.$(252,000) $(258,000) $(237,000)
CSPCo (143,000) (145,000) (138,000)
I&M.. 118,000 121,000 67,000
KPCo. 23,000 2,000 20,000
OPCo. 254,000 280,000 288,000
(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, 1997, 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:
TOTAL OVERHEAD
CIRCUIT MILES
OF TRANSMISSION
AND CIRCUIT MILES OF
DISTRIBUTION LINES 765 KV LINES
AEP 127,864(a)(b) 2,022
System.
APCo... 49,534 641
CSPCo.. 14,820(a) --
I&M.... 20,855 614
KPCo... 10,136 258
OPCo... 29,448 509
(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.
As of December 31, 1997, the AEP System was interconnected through 120
high-voltage transmission interconnections with 26 neighboring electric utility
systems. The all-time and 1997 one-hour peak system demands were 25,940,000 and
24,485,000 kilowatts, respectively (which included 7,314,000 and 4,400,000
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 January 17, 1997, respectively. The
net dependable capacity to serve the system load on such dates, including power
available under contractual obligations, was 23,457,000 and 23,669,000
kilowatts, respectively. The all-time and 1997 one-hour internal peak demands
were 19,557,000 and 19,381,000 kilowatts, respectively, and occurred on February
5, 1996 and January 17, 1997, respectively. The net dependable capacity to serve
the system load on such dates, including power dedicated under contractual
arrangements, was 23,765,000 and 23,669,000 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:
1995 1996 1997
Coal......... 88% 87% 92%
Nuclear...... 11% 12% 7%
Hydroelectric
and other.... 1% 1% 1%
Total........ 100% 100% 100%
AEP's average cost of fuel per million BTUs for the calendar years ended
December 31, 1995, 1996, and 1997 was 145 cents, 140 cents and 140 cents,
respectively.
b. CSW
(i) Energy Sales
KwH of Electric Energy Sold (in millions)
Company Twelve Months Ended December, 31, 1997
CPL 21,839
PSO 15,616
SWEPCO 22,533
WTU 7,335
CSW Total 63,157(a)
(a) Total after elimination of intercompany transactions.
(ii) Electric Generating Facilities
At December 31, 1997, 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:
Net
Megawatt
Owner, Plant Type and Name Location (Near) Capability
CPL:
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 195
Laredo Laredo, TX 176
Lon C. Hill Corpus Christi, TX 528
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 53(c)
Hydroelectric--Conventional:
Eagle Pass Eagle Pass, TX 6
CT--Gas:
La Palma #7 San Benito, TX 48
4,437
CT/Steam--Gas:
Comanche Lawton, OK 273(a)
Steam--Gas:
Northeastern 1 & 2 Oologah, OK 637
Riverside Jenks, OK 916
Southwest Washita, OK 475
Tulsa Tulsa, OK 415
Steam--Coal:
Northeastern 3 & 4 Oologah, OK 900
Oklaunion Vernon, TX 106(d)
CT--Gas:
Weleetka Weleetka, OK 163
Diesel--Diesel:
Diesels Oklahoma 25
3,910
SWEPCO:
Steam-Gas:
Arsenal Hill Shreveport, LA 110
Knox Lee Longview, TX 471
Lieberman Mooringsport, LA 273
Lone Star Lone Star (Avinger), TX 50
Wilkes Avinger, TX 880
Steam--Lignite:
Dolet Hills Naborton, LA 262(e)
Pirkey Hallsville, TX 580(f)
Steam--Coal:
Flint Creek Gentry, AR 264(g)
Welsh Pittsburg, TX 1,584
4,474
WTU:
Steam-Gas:
Abilene Abilene, TX 7
Fort Phantom Abilene, TX 362
Lake Pauline Quanah, TX 45
Oak Creek Blackwell, TX 85
Paint Creek Haskell, TX 237
CT-Gas:
Fort Stockton Ft. Stockton, TX 5
CT/Steam--Gas:
Rio Pecos Girvin, TX 137(a)
San Angelo San Angelo, TX 125(a)
Steam--Coal:
Oklaunion Vernon, TX 370(h)
Diesel--Diesel:
Presidio Presidio, TX 2
Vernon Vernon, TX 9
1,384
Total Generating Capability 14,205
SUMMARY:
Steam--Gas..................................................... 8,031
Steam--Nuclear................................................. 630
Steam--Coal.................................................... 3,909
Hydroelectric--Conventional.................................... 6
CT--Gas........................................................ 216
CT/Steam--Gas.................................................. 535
Diesel--Diesel................................................. 36
Steam--Lignite................................................. 842
14,205
(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)
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.
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
Capacity Capacity Ownership
Company Location Total Committed Interest Status
Brush II......... CSW Energy Colorado 68 68 47% QF
Ft. Lupton....... CSW Energy Colorado 272 272 50% QF
Mulberry......... CSW Energy Florida 120 110 50% QF
Orange Cogen..... CSW Energy Florida 103 97 50% QF
Newgulf.......... CSW Energy Texas 85 n/a 100% IPP
Sweeny........... CSW Energy Texas 330 90 50% QF
Total....... 978 637
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 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, 1997:
TOTAL CIRCUIT MILES TOTAL CIRCUIT MILES
OF TRANSMISSION OF DISTRIBUTION
LINES LINES
--------------- ---------------
CPL... 4,915 28,110
PSO... 3,563 17,916
SWEPCO 3,372 14,240
WTU... 4,490 8,606
----- -----
Total. 16,340 68,872
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, Texas Municipal Power Pool, 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 18 investor-owned utilities, 11 municipalities, 11 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 1997 was 13,105
MW on July 28, 1997. The 1997 net dependable capacity to serve the system load
was 14,290 MW. Power generation at the time of the peak was 12,817 MW and net
purchases at the time of the peak were 288 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 with ISOs and other
regional bodies interested in transmission planning and compliance with the
terms of the open access transmission tariff ("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 to
generate electricity:
1995 1996 1997
Natural Gas 47% 40% 38%
Coal 36% 42% 44%
Lignite 9% 10% 10%
Nuclear 8% 8% 8%
Total.. 100% 100% 100%
CSW's average cost of fuel per million BTUs for the calendar years ended
December 31, 1995, 1996, and 1997 was 158 cents, 181 cents and 183 cents,
respectively.
3. Electric Coordination
The Combined System will be physically interconnected and economically
operated as a single interconnected and coordinated system. 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 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. The Applicants' goal ultimately is to further enhance
the interconnection and coordination of the Combined System through
participation in a regional ISO.
Each aspect of the electric coordination and interconnection of the Combined
System is discussed below:
a. System Integration Agreement and System Transmission Integration
Agreement
The System Integration Agreement provides for the coordination of generation
within the Combined System. 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
agreements and their functions are summarized below.
As noted, the System Integration Agreement provides for the coordination of
generation within the Combined System. AEPSC will coordinate the planning,
operation and maintenance of generating capacity resources and the dispatch of
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 central 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.
The System Transmission Integration Agreement provides for the coordinated
planning, operation and maintenance of the Combined System's transmission
facilities and the assignment among the Combined System's operating companies of
third-party transmission costs incurred to coordinate post-Merger operations.
AEPSC will coordinate the planning, operation and maintenance of transmission
facilities and capacity of the Combined System. 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.
b. 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. 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's testimony filed as an
exhibit to Exhibit D-1.2 and incorporated herein by reference.
c. 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 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.
d. Future Participation in an ISO
The Applicants' goal ultimately is to further enhance the interconnection
and coordination of their companies through participation in a regional ISO.
Through an ISO, a utility relinquishes control over the operation of its
transmission system, effecting a structural separation of the control of access
to transmission service from the utility's merchant function. ISOs provide
strengthened assurances to the marketplace that transmission service will be
available to all eligible customers on a non-discriminatory basis. In addition,
ISOs can enhance regional reliability and, if properly structured and
configured, improve economic efficiencies and provide a broad range of buyers
and sellers access across a large geographic region. AEP and CSW each have been
actively engaged in discussions concerning participation in ISOs. The testimony
of Raymond M. Maliszewski and J. Craig Baker before the FERC, copies of which
are filed herewith as Exhibits D-1.1 and D-1.2, respectively, and incorporated
herein by reference, set forth Applicants' views and goals with respect to
participating in an ISO. The ultimate goal of the Applicants is to bring the
northern portion of the CSW System and the AEP System into the same ISO. The
ERCOT portions of CSW participate in the ERCOT ISO, and are expected to remain
members.
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 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.
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:
- 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.
ITEM 2. FEES, COMMISSIONS AND EXPENSES
Thousands
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 *
(*) 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
and rules existing financing authority to allow the Combined Company
thereunder to engage in 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
rules thereunder common 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.
13 and rules Merger of CSWS into AEPSC with AEPSC as the
thereunder surviving 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 (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
Giradeau 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
(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. SEC, 1994 WL
704047 (D.C. Cir. Nov. 16, 1994) (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 second to
the fifth largest public utility system in the United States depending on the
criterion of measurement. Giving effect to the Merger as of December 31, 1997,
on a pro forma basis, the Combined Company would have ranged from the largest to
the fourth largest public utility system in the United States, again depending
on the criterion of measurement.
(As of December 31, 1997)
U.S. U.S. U.S.
Operating Total Electric Sales Market Generating
Revenues Assets Customers in KwH Capitalization Capacity
System ($Millions)($Millions)(Millions)(Billions)($Millions)(b) (MW)
Duke 16,309 24,020 2.0 77.5 19,924 17,246
Southern 12,611 35,271 3.7 156.5 17,942 31,146
Entergy 9,562 27,001 2.5 106.8 7,361 21,727
PG&E 15,400 30,557 4.5 79.4 12,661 13,583
CSW 5,268 13,451 1.7 63.2 5,743 14,205
AEP 6,161 16,615 3.0 145.4 9,808 23,759
Combined
Company 11,352(a) 30,066 4.7 208.6 16,381(c) 37,964
(a)Gives effect to certain reclassifications expected to be adopted by the
Combined Company upon completion of the Merger.
(b)Based on number of shares outstanding multiplied by the closing stock price
at December 31, 1997.
(c)Gives effect to the conversion of CSW Common Stock to AEP Common Stock
following the Merger at the Exchange Ratio.
These data show that the Combined Company will be comparable in size to other
large public utility systems. Southern and PG&E would have been larger than the
Combined Company in total assets. Southern, PG&E and Duke would have been larger
than the Combined Company in terms of operating revenues. Duke and Southern
would have been larger than the Combined Company in total market capitalization.
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 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').(1) 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
10 percent to 16 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."
- ----------
(1) 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.
Net Utility
Electric Electric Number of Total Net
Plant Revenues Electric Generation
($Thousands) ($Thousands) Customers MwH Sales (MwH)
Inter-
connected
Utilities $169,463,307 $ 69,737,780 28,075,111(a)1,224,545,371 1,092,704,814
Combined
Company $ 18,512,582 $ 9,097,234 4,614,541 194,998,011 199,222,365
Total $187,975,889 $ 78,835,014 32,689,652 1,419,534,382 1,291,927,179
% of Total
represented
by Combined
Company 10% 12% 15% 14% 16%
(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.
Sources:Edison Electric Institute, Electrical Utility Data, EZStat Query System
(1996); EIA Publication-Financial Statistics of Major US Investor-Owned
Electric Utilities (1996); EIA Publication Financial Statistics of Major
US Publicly-Owned Electric Utilities (1996).
Specifically, as the table above indicates, at December 31, 1996, 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 (10%); electric revenues (12%); number of electric customers (15%); MwH
sales (14%); and net generation (16%). As such, the size of the Combined Company
relative to the relevant region is significantly below the 40% threshold
previously cited by the Commission.
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.(2) 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.
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(2) The "state of the art" is discussed in depth in Item 3.B.1.a below.
(ii) Antitrust Considerations
The Commission's analysis under Section 10(b)(1) also includes a
consideration of federal antitrust policies.(3) 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.
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(3) See, e.g., Conectiv, HCAR No. 26832 (Feb. 25, 1998) [hereinafter
"Conectiv"].
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. It
will make a finding as to whether the Merger is consistent with the public
interest based, in part, upon consideration of the anticompetitive consequences,
if any, 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:
Although the SEC may not rely upon the FERC's concurrent jurisdiction over
an acquisition as a reason to shirk its own statutory mandate to determine
the anticompetitive effect of that transaction, . . . it does not follow
that the SEC must pretend that it is the only agency addressing the issue
when it is not . . . . Rather, when 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."
City of Holyoke Gas & Elec. Dep't v. SEC, 972 F.2d 358 (D.C. Cir. 1992)
(citations omitted) [hereinafter "City of Holyoke"]. 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 this case,
the SEC can watchfully defer to other agencies (namely, the DOJ/FTC 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. If the Commission determines to approve the Merger
(subject to the FERC's approval of the Merger and/or the DOJ's or FTC's lack of
challenge to the transaction), it can defer to these agencies even if their
proceedings are not yet complete because the Commission retains ongoing
authority under Section 20(a) of the 1935 Act to rescind or further condition
its approval of a transaction. Id.
ii(a). The Role of the DOJ and the FTC
Pursuant to the HSR Act, AEP and CSW are required to file with the FTC
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 either [the DOJ or the
FTC] to challenge the legality of the transaction."(4) The HSR Act prohibits
consummation of the Merger until the statutory waiting period has expired or
been terminated.
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(4) Premerger Practice Notification Manual at xi (American Bar Association
1991).
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. 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.(5) 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's
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. Dr. Hieronymus's testimony is summarized below:
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(5) 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).
(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. 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 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 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 auction process for the SPP generation capacity
will begin after two conditions are satisfied. First, in order to preserve the
benefits to shareholders and ratepayers of the pooling of interests accounting
treatment used for the Merger, two years must have passed after the completion
of the Merger before the divestiture can begin. Second, because the generation
to be divested is used to serve PSO's native load, the auction of such
generation cannot begin until the progress of retail access and penetration by
alternate suppliers has caused a reduction in PSO's native load obligations to
the point that the 300 MW to be divested is no longer 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 not begin until two full years have passed
after the completion of the Merger, unless the Combined Company is fully
satisfied that an earlier sale will not cause the benefits of the pooling of
interests accounting treatment to be lost. Until such time, the Combined Company
will conduct a unit power sale of 250 MW hours of energy per hour from the
generation to be divested. 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 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.
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 open access transmission
tariffs. 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.
AEP and CSW each have committed to join an ISO, thus eliminating any
remaining concerns regarding the transmission facilities' impact on competition.
Through the ISO, the Combined Company will relinquish control over the operation
of its transmission facilities. The Combined Company will retain ownership of
the facilities, but the facilities will be operated by the ISO for the benefit
of the system users in a competitive and non-discriminatory manner.
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, including an 800 MW merchant plant in Grimes County and a
350 MW merchant plant under consideration for Uvalde County, each of which will
be capable of selling into both ERCOT and SPP.(6) By utilizing the Combined
Company's open access tariff, customers within the Combined Company's service
territory will be able to 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.
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(6) Power Generation Markets Quarterly, Fourth Quarter 1997.
In addition, Applicants submitted to the FERC testimony by J. Stephen
Henderson demonstrating that, irrespective of the existence of an ISO, 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. 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's testimony demonstrates that taking into account the
Combined Company's mitigation measures, the Merger presents no competitive
problems. Thus, the Merger can be expected to obtain required approval and
clearance from the FERC. 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
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.
(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 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 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.
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.
AEP CSW
- -----------------------------------------------------------------------------
High Low Dividends High Low Dividends
- -----------------------------------------------------------------------------
1996
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 26 20-3/4 0.435
2nd Qtr......... 42-1/2 39-1/8 0.60 22-1/4 18 0.435
3rd Qtr......... 46-5/8 41-1/2 0.60 22-9/16 19-1/2 0.435
4th Qtr......... 52 45-1/4 0.60 27-1/2 20 0.435
- -----------------------------------------------------------------------------
(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.
(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]."(7) 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(8) 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.
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(7) "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]."
(8) "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."
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 together expect to incur
total transaction and regulatory processing 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 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)).
As indicated in Item 2 above, the fees and expenses which are not yet
finalized will be filed by amendment when they become available.
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 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, 1997, the respective capital structures of AEP and CSW were as
follows:
AEP CSW
(in $ millions) (in $ millions)
Common Stock Equity....... $ 4,677 45.52% $ 3,556 44.27%
Preferred Stock........... 175 1.70% 203 2.53%
Long-Term Debt............ 5,424 52.78% 8,937 49.02%
Trust Preferred Securities -0- -0- 335 4.17%
Total................... $10,276 100.00% $ 8,031 100.00%
If the Merger had been consummated on December 31, 1997, 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:
Combined Company Pro Forma
(in $ millions)
Common Stock Equity....... $ 8,233 44.97%
Preferred Stock........... 378 2.06%
Long-Term Debt............ 9,361 51.13%
Total................... 335 1.83%
$18,307 100.00%
(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 44.8% 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
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 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;
(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)).(9) As
demonstrated below, the Merger meets each of these standards.
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(9) Although the integrated utility system requirement has been interpreted to
involve a four-part test, Applicants submit that the requirement can be fairly
interpreted to involve only a three-part test. The plain reading of the
integration requirement suggests the last two tests should be read as one test.
The requirement provides, in pertinent part, that the "system [be] 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." There is no "and" inserted between "single area or
region" and "not so large as to impair" leading to the conclusion that there are
two distinct tests which the "system" must meet. Rather, the sentence
construction leads to the conclusion that it is the "single area or region"
which must not be so large as to result in the specified impairments. In any
event, the proposed Merger meets either the three-part test, as set forth in the
statute, or the four-part test.
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 cited with favor U.S. Supreme Court and Circuit Court of
Appeals cases(10) that recognized the need of an agency to "adapt [its] rules
and policies to the demands of changing circumstances"(11) and to "treat
experience not as a jailer but as a teacher."(12)
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(10) 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).
(11) NIPSCO, supra, citing Rust v. Sullivan at 186-187. Accord, Sempra,
supra at n. 23.
(12) NIPSCO, supra, citing Shawmut Assn. v. SEC at 796-97. Accord, Sempra,
supra at n. 23.
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. FERC Order Nos. 888 and
889, issued in April 1996, taken together provide that public utilities must
file tariffs 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.
In response to deregulation in the wholesale market for electricity, many
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.
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 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 and ISOs, have
emerged as new market structures and participants. More than 100 marketers
have registered with the FERC to trade in electric power. See
"Restructuring Energy Industries: Lessons From Natural Gas," Energy
Information Administration, Natural Gas Monthly, May 1997.
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.
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." Rodney E.
Stevenson & David W. Penn, "Discretionary Evolution: Restructuring the
Electric Utility Industry," Land Economics, Vol. 71, No. 3 (August 1, 1995).
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 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 high-voltage direct current ("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 between the 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.
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 combining entities need not own the transmission line
connecting them in order to meet the physical interconnection requirement. The
physical interconnection requirement can be met on the basis of contractual
rights to use third party transmission lines. See, e.g., 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).
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. The eastern terminus
of the 250 MW Contract Path will be the Breed-Casey interconnection between AEP
and Ameren. The western terminus of the 250 MW Contract Path is the
interconnection between Ameren and PSO, a CSW subsidiary, at the MOKANOK Line
which is jointly owned by UE, an Ameren subsidiary, PSO and two other
unaffiliated entities.
The 250 MW Contract path satisfies the interconnection requirement of Section
2(a)(29)(A). 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 this limit.(13) See Dr. Hieronymus's testimony
filed as an exhibit to Exhibit D-1.2.
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(13) 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.
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 ISO (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 ISO, the ISO 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 ISOs,
provided the ISOs are not permitted to erect economic barriers between them. The
Commission has found that the transmission rights associated with being a member
of an ISO help to satisfy the interconnection requirement. Conectiv, supra.
(ii) Single Interconnected and Coordinated System
The Combined System will be capable of being economically operated as a
single interconnected and coordinated system, as required by Section
2(a)(29)(A). The Commission has "interpreted this language to refer to the
physical operation of utility assets as a system in which, among other things,
the generation and/or flow of current within the system may be centrally
controlled and allocated as need or economy directs." Conectiv, supra (citing
North American Co., 11 SEC 194, 242 (1942), aff'd, SEC v. North American Co.,
133 F.2d 148 (2d Cir. 1943), aff'd on constitutional issues, 327 U.S. 686
(1946)). 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)).
The Commission has considered advances in technology and the particular
operating circumstances in applying this integration standard. Unitil, supra
(citation omitted). 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.
The Combined System will operate as a single interconnected and coordinated
system through the centralized coordination of generation and transmission. The
centralized coordination within the Combined System will be accomplished under
the System Integration Agreement and the System Transmission Integration
Agreement, both of which will take effect upon consummation of the Merger, as
described above in Item 1.B.3. 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 Applicants' goal ultimately is to further enhance
the coordination of their companies through participation in a regional ISO.
Moreover, in applying this integration standard, the Commission looks beyond
simply the coordination of the generation and transmission within the system to
the coordination of other activities. See, e.g., General Public Utilities Corp.,
HCAR No. 13116 (Mar. 2, 1956) [hereinafter "GPU"] (integration is accomplished
through power dispatching by a central load dispatcher as well as through
coordination of maintenance and construction requirements); Middle South
Utilities, 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); The North American Co., 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).
The Combined System will be coordinated in a variety of ways beyond simply
the coordination of the generation and transmission within the system. AEPSC
will be the designated agent under the System Integration Agreement. AEPSC's
major functions will be to coordinate the planning and design or purchase of new
generation facilities, the operation and maintenance of generating capacity
resources, economic dispatch, centralized trading and marketing activities,
acquisition and provision of transmission services needed for inter-zone power
transfers and billing and administration. In addition, the accounting functions
of the Combined System will be prepared and consolidated through the use of a
single enterprise-wide financial system. This financial system will include a
general ledger module, accounts receivable and cash remittance processing
modules, an accounts payable module, a purchasing and materials management
module, owned and leased assets modules as well as a single integrated
timekeeping and payroll system. These systems will enable the Combined Company
to have a single accounting organization which will be managed by a single team
in one or more locations.
The coordination and integration of the Combined System is expected to be
further achieved through the coordination and integration of information system
networks; procurement organizations; organizational structures for Power
Generation, Nuclear Generation, Energy Delivery and Customer Relations; and
support services. Each is discussed below:
- Analysis completed to date has concluded that there are approximately 600
information systems software packages which support either AEP or CSW
operations. This initial analysis has concluded that these packages can be
organized under a single, integrated information system network with the
capability of being operated from a single location. The network will be
supported by a single data center and will have common software tools and a
single centralized IT development organization. The individual integration
teams are currently analyzing the various software systems being used by
each of the companies in order to identify the single best system to be
utilized to support the Combined Company in each area.
- AEP and CSW each have created centralized procurement organizations which
assist the business units in preparing bid solicitations, procuring
materials and supplies and managing the inventory required to support the
assets of each business unit. The Combined Company expects to utilize a
single organizational structure to accomplish these activities.
- AEP and CSW each have created four substantially equivalent business unit
management and organizational structures: Power Generation, Nuclear
Generation, and Energy Delivery and Customer Relations. Each of these
business units has created a combination of central management and
engineering groups with regional and field organizations designed to
provide the services of the business unit as efficiently as possible. The
integration teams are studying how best to integrate these activities. It
is anticipated that each of the business unit structures recommended for
the Combined Company will be similar to the existing single, integrated
organizational structure that is being used in AEP and CSW.
- AEP and CSW currently utilize a single service company model to provide
support services, including office, finance, treasury, legal, corporate
communications and other corporate services. Upon the merger of AEPSC and
CSWS, these services would be effectively provided by combined groups
handling office, finance, treasury, legal, corporate communications and
other corporate services.
As dictated by the language under Section 2(a)(29)(A) that the coordinated
system be "economically operated," the Commission further analyzes whether the
coordinated operation of the system results in economies and efficiencies. See,
e.g., City of New Orleans v. SEC, 969 F.2d 1163, 1168 (D.C. Cir. 1992) (Court
supported Commission's reading of the term "economically" to mean "that
facilities, in addition to their physical interconnection, be consolidated so as
to take advantage of efficiencies"); WPL Holdings, Inc., HCAR No. 26856 (Apr.
14, 1998) (discussing this integration standard as it relates to the requirement
under Section 10(c)(2) that the acquisition tend towards the economic and
efficient development of an integrated system and noting that the applicants
introduced substantial evidence concerning the efficiencies to be realized by
the combined operation of the merging companies' generation and transmission
systems). The Applicants expect to realize significant economies and
efficiencies as a result of the Merger. As described in Item 3.B.2 below,
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.
In short, pursuant to the System Integration Agreement, the Combined System
will be centrally and efficiently planned and dispatched. Pursuant to the System
Transmission Integration Agreement, the operation and management of transmission
within the Combined System will be centrally overseen. Thus, as with other
merger applications approved by the Commission, the Combined System will be
capable of being economically operated as a single interconnected and
coordinated system. The Combined System will be "economically operated" as a
coordinated system as further demonstrated by the variety of means through which
its operations will be coordinated and the efficiencies and economies expected
to be realized by the Merger as described below in Item 3.B.2.
(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." 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 Section specifically provides that a
region can encompass more than one state. As Ganson Purcell, Chairman of the
Securities and Exchange Commission, testified before the Subcommittee of the
House Committee on Interstate and Foreign Commerce in 1946:
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. . . .(14)
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(14) 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).
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. . . .(15)
- ----------
(15) Id. at 857 (referring to American Gas and Electric system).
No absolute size limitation is specified. 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. 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 sytem); accord, Sempra, supra. The 1935
Act itself 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"(16) in light of "the state of the art and the area
or region affected" as discussed in Item 3.B.1.a.(iv) below.(17)
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(16) 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.
(17) In fact, as discussed in note 9 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.
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) (New Century Energies,
HCAR No. 26748 (Aug. 1, 1997) [hereinafter "New Century"] (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.(18) 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).
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(18) 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.
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,
supra (integration test was met where entities planned to build a 300 mile
transmission line to interconnect the systems which operated in noncontiguous
territories); 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. 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.(19)
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(19) 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.
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 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.(20) 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.
Although it is "probably premature . . . to conclude that a true North American
market for natural gas has emerged," market integration is improving and
"regional clusters of markets across certain broad areas seem to be highly
competitive, even between U.S. and Canadian markets." Id. at xii.
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(20) 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.
Developments in the natural gas industry which are eroding traditional
boundaries are being applied to the electricity industry. Many gas marketers are
moving into the new 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. More than 100 energy marketing companies have registered with the
FERC to market electric power on a wholesale basis. Natural Gas Monthly. These
companies will be marketing retail power to retail power markets as well.
Moreover, the developments in electric and gas industries "may imply a close
relationship in the future for both industries." Natural Gas 1996 at xiii. Not
only are gas marketers entering the electricity markets, but "gas and electric
companies are forming mergers and strategic alliances to give customers menus
that allow buyers to bridge the differences between the industries." Id. And the
development of financial markets "may help to integrate the energy markets." Id.
In short, the concept of "area or region" should be interpreted flexibly to keep
pace with the current state of the industry.(21)
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(21) 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 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).
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 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, 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 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.
Although the Applicants have just recently launched transition teams that are
studying how the various components of the two organizations will be
combined, 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.
In short, the 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.
- Effective Regulation
The Merger will not impair the effectiveness of regulation at either the
state or federal level.
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.(22)
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(22) 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.
On the federal level, the Combined System will continue to be regulated by
the Commission. The electric utility subsidiaries of the Combined System 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.
Moreover, the Merger Agreement requires approvals from all regulatory
authorities having jurisdiction over the Merger as a condition to the
consummation of the Merger. Applicants are working closely with such
regulators (both state and federal) to obtain the required 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.
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 transitional 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 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 the requirements of Section 11(b)(2).(23) 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.
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(23) 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.
(i) The Existence of Two Tiers of Registered Holding Companies
in a Single Integrated Public-Utility System Is Not
Prohibited under the 1935 Act
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 no more than two tiers of holding companies through the
'great-grandfather clause' of Section 11(b)(2).(24) 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).
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(24) 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.').
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.' (emphasis added).
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.' (emphasis
added).(25) See also, 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).
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(25) 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 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.).
(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 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.(26) Vermont Yankee,
supra.
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(26) 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.
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, 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.
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).(27) 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.
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(27) 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.
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.
Economic efficiency is the driving force behind the Merger; its purpose is
to create an entity well situated to compete effectively in an increasingly
active market. Applicants will achieve $1,966 million of net non-fuel cost
savings over the ten-year period immediately following consummation of the
Merger. These savings will be passed on to shareholders and customers of the
Combined Company. Applicants also anticipate net fuel-related savings of
approximately $98 million over this same period that will be passed on to
customers. 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:
Savings Category Millions
Elimination of Duplicate Corporate and Operations Support Staffing $ 996
Elimination of Duplicate Corporate and Administrative Programs 1,044
Purchasing Economies (Not Fuel-related) 367
Total Savings 2,407
Less: Costs to Achieve (a) (248)
Premerger Initiatives (193)
Net Savings $1,966
(a) 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 pre-Merger CSW and
approximately $1,253 million will be allocated to pre-Merger AEP. 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.
As part of the filings with various state and federal regulators, Applicants
propose an equitable sharing of the net savings from the Merger between
shareholders and customers. Although specific determinations of the net savings
to each group cannot be finalized until all regulatory proceedings have been
completed, it is expected that each group will realize approximately half of the
net savings.
Applicants estimate that the Combined Company will also realize approximately
$98 million in net fuel-related savings over the same 10 year period. 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 central coordinated dispatch of energy by the Combined Company. These
savings will be realized by customers.
These expected savings exceed the anticipated savings in a number of other
acquisitions approved by the Commission. See, e.g., New Century, 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. 25325 (June 3, 1991) (expected
savings of $91 million over ten years); CINergy, supra (estimated savings of
approximately $895 million over ten years).
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). In this regard, the Merger
will result in additional benefits which, although not precisely quantifiable,
are nonetheless significant.
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)
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 requested from the Oklahoma Commission, the
Arkansas Commission, and the Louisiana Commission. Applicants have also
requested a determination from the Texas Commission that the Merger is in the
public interest. See Item 4, infra, for further discussion of regulatory
approvals and the standard of review applicable to such approval. 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.
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 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 AEPSC to participate in the Money Pool,
and (2) the 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 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 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
THE SERVICE AGREEMENT
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, 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.
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 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.
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 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).(28) 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.")
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(28) 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.
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 various aspects
of the transactions proposed herein.(29) Further, both AEP and CSW are required
to file notification and report forms under the HSR Act with the FTC and 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.
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(29) AEP has U.S. electric utility subsidiaries operating in Ohio, Indiana,
Kentucky, Michigan, Tennessee, Virginia, and West Virginia. Utility regulatory
commissions in certain of these states have asserted that they have or may have
approval authority over the Merger. 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. AEP has been actively working with all of these state
commissions regarding both the FERC and state regulatory impacts of the
transaction.
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 FTC and the
specified HSR Act waiting period has expired or been terminated. Applicants
intend to provide their respective pre-Merger notifications pursuant to the HSR
Act during the next several months. The expiration or earlier termination of the
HSR Act waiting period would not permanently preclude the Antitrust Division or
the FTC 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 the FTC, and a new HSR Act waiting period must expire or be earlier
terminated before the Merger may be consummated.
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 of its parent, CSW, with a subsidiary of
AEP. 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. 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. Under Section 203 of the FPA,
the FERC will approve a merger if it finds the merger to be 'consistent with the
public interest.'
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. AEP and CSW intend to file applications
with the FCC seeking approval for the transfer of control of these licenses as a
result of the Merger within the next few months.
E. ARKANSAS COMMISSION
SWEPCO is subject to the jurisdiction of the Arkansas Commission. Pursuant to
Section 23-3-306(b) of the Arkansas Statutes, Arkansas Commission approval is
required before any person may merge with or otherwise acquire control of a
domestic 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.
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 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. 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.
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.
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
incorporated by reference. On October 1, 1998, the administrative law judge
presiding over the application proceeding orally informed the parties of his
intention to recommend to the Oklahoma Commission that the application be
dismissed, without prejudice, for its lack of information regarding the
potential impact of the Merger on retail electric markets in Oklahoma.
Applicants are reviewing the appropriate actions to take in response to the
recommendation and do not anticipate it causing a delay in consummating the
Merger.
The Oklahoma Commission is required to approve such merger or acquisition of
control unless it finds that the transaction will result in one or more of a
list of adverse circumstances, which are substantially identical to the adverse
circumstances listed above with respect to Arkansas.
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. If the Texas Commission
determines that a transaction is not in the public interest, it may take the
effect of the transaction into consideration in ratemaking proceedings and
disallow the effect of such transaction if such transaction will unreasonably
affect rates or service.
I. 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
*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))
*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
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
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
*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)
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
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-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
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
*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-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
*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 (to be filed by amendment)
F-2 Opinion of Counsel (to be filed by amendment)
F-1-1 Past-tense Opinion of Counsel (to be filed by amendment)
F-2-1 Past-tense Opinion of Counsel (to be filed by amendment)
*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
*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)
*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
* 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 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.
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 8, 1999
Exhibit B-3
PROPOSED AEPSC ATTRIBUTION BASES
1. Number of Bank Accounts Number of Bank Accounts
Per Company
Total Number of Bank Accounts
2. Number of Call Center Number of Call Center Telephones
Telephones Per Company
Total Number of Call Center Telephones
3. Number of Cell Number of Cell Phones/Pagers Per Company
Phones/Pagers Total Number of Cell Phones/Pagers
4. Number of Checks Printed Number of Checks Printed Per Company Per Month
Total Number of Checks Printed Per Month
5. Number of CIS Customer Number of Customer Information System (CIS)
Mailings Customer Mailings Per Company
Total Number of CIS Customer Mailings
6. Number of Commercial Number of Commercial Customers Per Company
Customers Total Number of Commercial Customers
7. Number of Credit Cards Number of Credit Cards Per Company
Total Number of Credit Cards
8. Number of Electric Retail Number of Electric Retail Customers
Customers Per Company
Total Number of Electric Retail Customers
9. Number of Employees Number of Full-Time and Part-Time Employees
Per Company
Total Number of Full-Time and Part-Time
Employees
10. Number of Generating Number of Generating Plant Employees
Plant Employees Per Company
Total Number of Generating Plant Employees
11. Number of GL Transactions Number of General Ledger (GL) Transactions
Per Company
Total Number of GL Transactions
12. Number of Help Desk Calls Number of Help Desk Calls Per Company
Total Number of Help Desk Calls
13. Number of Industrial Number of Industrial Customers Per Company
Customers Total Number of Industrial Customers
14. Number of JCA Number of Lines of Accounting Distribution
Transactions on Job Cost Accounting (JCA) Sub-System
Per Company
Total Number of Lines of Accounting
Distribution on JCA Sub-System
15. Number of Non-UMWA Number of Non-UMWA or All Non-Union Employees
Employees Per Company
Total Number of Non-UMWA or All Non-Union
Employees
16. Number of Phone Center Number of Phone Calls Per Phone Center
Calls Per Company
Total Number of Phone Center Phone Calls
17. Number of Purchase Orders Number of Purchase Orders Written Per Company
Written Total Number of Purchase Orders Written
18. Number of Radios Number of Radios (Base/Mobile/Handheld)
(Base/Mobile/Handheld) Per Company
Total Number of Radios (Base/Mobile/Handheld)
19. Number of Railcars Number of Railcars Per Company
Total Number of Railcars
20. Number of Remittance Number of Electric Bill Payments Processed
Items Per Company Per Month (non-lockbox)
Total Number of Electric Bill Payments
Processed Per Month (non-lock)
21. Number of Remote Terminal Number of Remote Terminal Units Per Company
Units Total Number of Remote Terminal Units
22. Number of Rented Water Number of Rented Water Heaters Per Company
Heaters Total Number of Rented Water Heaters
23. Number of Residential Number of Residential Customers Per Company
Customers Total Number of Residential Customers
24. Number of Routers Number of Routers Per Company
Total Number of Routers
25. Number of Servers Number of Servers Per Company
Total Number of Servers
26. Number of Stores Number of Stores Transactions Per Company
Transactions Total Number of Stores Transactions
27. Number of Telephones Number of Telephones Per
Company (includes all phone lines) Total
Number of Telephones (includes all phone
lines)
28. Number of Transmission Number of Transmission Pole Miles
Pole Miles Per Company
Total Number of Transmission Pole Miles
29. Number of Transtext Number of Expected Transtext Customers
Customers Per Company
Total Number of Expected Transtext Customers
30. Number of Travel Number of Travel Transactions Per Company Per
Transactions Month
Total Number of Travel Transactions Per Month
31. Number of Vehicles Number of Vehicles Per
Company (includes fleet and pool cars) Total
Number of Vehicles Per Company (includes fleet
and pool cars)
32. Number of Vendor Invoice Number of Vendor Invoice Payments
Payments Per Company Per Month
Total Number of Vendor Invoice Payments Per
Month
33. Number of Workstations Number of Workstations (PCs) Per Company
Total Number of Workstations (PCs)
34. Active Owned or Leased Number of Active Owned/
Communication Channels Leased Communication Channels Per Company
Total Number of Active Owned/
Leased Communication Channels
35. Avg Peak Load for Past 3 Average Peak Load for Past 3 Years
Years Per Company
Total of Average Peak Load for Past 3 Years
36. Coal Company Combination The Sum of Each Coal
Company's Gross Payroll, Original Cost of
Fixed Assets, Original Cost of Leased Assets
and Gross Revenues for Last 12 Months The Sum
of the Same Factors for All Coal Companies
37. AEPSC Past 3 Months Total AEPSC Past 3 Months Total Bill Dollars
Bill Dollars Per Company
Total AEPSC Past 3 Months Bill Dollars
38. AEPSC Prior Month Total AEPSC Prior Month Total Bill Dollars
Bill Dollars Per Company
AEPSC Total Prior Month Bill Dollars
39. Direct 100% to One Company
40. Equal Share Ratio One (1)
Total Number of Companies
41. Fossil Plant Combination The Sum of (a) the Percentage Derived by
Dividing the Total Megawatt Capability of
All Fossil Generating Plants Per Company
by the Total Megawatt Capability of
All Fossil Generating Plants and (b)
the Percentage Derived by Dividing the
Total Scheduled Maintenance Outages of
All Fossil Generating Plants Per Company
for the Last 3 Years by the Total Scheduled
Maintenance of All Fossil Generating Plants
During the Same 3 Years
Two (2)
42. Functional Department's Functional Department's Past 3 Months
Past 3 Months Total Bill Dollars Per Company
Total Bill Dollars Total Functional Department's Past 3 Months
Total Bill Dollars
43. KWH Sales KWH Sales Per Company
Total KWH Sales
44. Level of Construction - Construction Expenditures for All
Distribution Distribution Plant Accounts Except Land
and Land Rights, Services, Meters and Leased
Property on Customers Premises and Exclusive
of Construction Expenditures Accumulated on
Direct Work Orders for Which Charges by AEPSC
Are Being Made Separately, Per Company During
the Last 12 Months Total of the Same for All
Companies
45. Level of Construction - Construction Expenditures for All
Production Production Plant Accounts Except Land
and Land Rights, Nuclear Accounts and
Exclusive of Construction Expenditures
Accumulated on Direct Work Orders for Which
Charges by AEPSC are Being Made Separately,
Per Company During the Last 12 Months Total of
the Same for All Companies
46. Level of Construction - Construction Expenditures for All
Transmission Transmission Plant Accounts Except Land
and Land Rights and Exclusive of
Construction Expenditures Accumulated on
Direct Work Orders for Which Charges
by AEPSC are Being Made Separately,
Per Company During the Last 12 Months
Total of the Same for All Companies
47. Level of Construction - Construction Expenditures for Plant Accounts
Total Except Land and Land Rights, Line Transformers
Services, Meters and Leased Property on
Customers' Premises; and the Following General
Plant Accounts: Structures and Improvements,
Shop Equipment, Laboratory Equipment and
Communication Equipment; and Exclusive of
Construction Expenditures Accumulated on
Direct Work Orders for Which Charges by AEPSC
are Being Made Separately, Per Company During
the Last 12 Months Total of the Same for All
Companies
48. MW Generating Capability MW Generating Capability Per Company
Total MW Generating Capability
49. MWH's Generated Number of MWH's Generated Per Company
Total Number of MWH's Generated
50. Current Year Budgeted Current Year Budgeted AEPSC Payroll Dollars
Salary Dollars Billed Per Company
Total Current Year Budgeted AEPSC Payroll
Dollars Billed
51. Past 3 Mo. MMBTU's Burned Past 3 Months MMBTU's Burned
(All Fuel Types) Per Company (All Fuel Types)
Total Past 3 Months MMBTU's Burned
(All Fuel Types)
52. Past 3 Mo. MMBTU's Burned Past 3 Months MMBTU's Burned
(Coal Only) Per Company (Coal Only)
Total Past 3 Months MMBTU's Burned
(Coal Only)
53. Past 3 Mo. MMBTU's Burned Past 3 Months MMBTU's Burned
(Gas Type Only) Per Company (Gas Type Only)
Total Past 3 Months MMBTU's Burned
(Gas Type Only)
54. Past 3 Mo. MMBTU's Burned Past 3 Months MMBTU's Burned
(Oil Type (Only) Per Company (Oil Type Only)
Total Past 3 Months MMBTU's Burned
(Oil Type Only)
55. Past 3 Mo. MMBTU's Burned Past 3 Months MMBTU's Burned
(Solid Fuels Only) Per Company (Solid Fuels Only)
Total Past 3 Months MMBTU's Burned
(Solid Fuels Only)
56. Peak Load/Avg # Cust/ Average of Peak Load, # of Retail Customers
KWH Sales Combination and KWH Sales to Retail Customers
Per Company
Total of Average of Peak Load,
# of Retail Customers and KWH Sales
to Retail Customers
57. Tons of Fuel Acquired Number of Tons of Fuel Acquired
Per Company
Total Number of Tons of Fuel Acquired
58. Total Assets Total Assets Amount Per Company
Total Assets Amount
59. Total Assets Total Assets Amount Less Nuclear Assets
Less Nuclear Plant Per Company
Total Assets Amount Less Nuclear Assets
60. Total AEPSC Bill Dollars Total AEPSC Bill Dollars Less Interest and/or
Less Interest and/or Income Taxes and/or Other Indirect Costs
Income Taxes and/or Other Per Company
Indirect Costs Total AEPSC Bill Dollars Less Interest and/or
Income Taxes and/or Other Indirect Costs
61. Total Fixed Assets Total Fixed Assets Amount
Per Company
Total Fixed Assets Amount
62. Total Gross Revenue Total Gross Revenue Last 12 Months
Per Company
Total Gross Revenue Last 12 Months
63. Total Gross Utility Plant Total Gross Utility Plant Amount
(including CWIP) Per Company (including CWIP)
Total Gross Utility Plant Amount
(including CWIP)
64. Total Peak Load (Prior Total Peak Load for Prior Year
Year) Per Company
Total Peak Load for Prior Year
NOTE: See Exhibit B-3.1 for the update frequency applicable to each
attribution basis and related notes.
Exhibit B-3.1
Update Frequencies Applicable to the Proposed AEPSC Attribution Bases
Each service provided by AEPSC will be represented by a work order. Every work
order, in turn, will have an attribution basis assigned to it based on the
nature and scope of the service. The attribution basis identifies the allocation
factor or combination of allocation factors that are used to bill the costs
associated with each work order. Only companies benefiting from a particular
service or transaction will be billed. The volume of each benefiting company
relative to the total volume of all benefiting companies will be used to
determine the billing allocation percentages as applicable to each attribution
basis. The billing percentages are recalculated either monthly, quarterly,
semi-annually, or annually as designated herein:
Attribution Basis Update Frequency
1 NUMBER OF BANK ACCOUNTS Semi-Annually
2 NUMBER OF CALL CENTER TELEPHONES Semi-Annually
3 NUMBER OF CELL PHONES / PAGERS Quarterly
4 NUMBER OF CHECKS PRINTED Monthly
5 NUMBER OF CIS CUSTOMER MAILINGS Monthly
6 NUMBER OF COMMERCIAL CUSTOMERS Annually
7 NUMBER OF CREDIT CARDS Semi-Annually
8 NUMBER OF ELECTRIC RETAIL CUSTOMERS Annually
9 NUMBER OF EMPLOYEES Quarterly
10 NUMBER OF GENERATING PLANT EMPLOYEES Quarterly
11 NUMBER OF GL TRANSACTIONS Monthly
12 NUMBER OF HELP DESK CALLS Monthly
13 NUMBER OF INDUSTRIAL CUSTOMERS Annually
14 NUMBER OF JCA TRANSACTIONS Monthly
15 NUMBER OF NON-UMWA EMPLOYEES Quarterly
16 NUMBER OF PHONE CENTER CALLS Monthly
17 NUMBER OF PURCHASE ORDERS WRITTEN Monthly
18 NUMBER OF RADIOS (BASE/MOBILE/HANDHELD) Semi-Annually
19 NUMBER OF RAILCARS Annually
20 NUMBER OF REMITTANCE ITEMS Monthly
21 NUMBER OF REMOTE TERMINAL UNITS Annually
22 NUMBER OF RENTED WATER HEATERS Annually
23 NUMBER OF RESIDENTIAL CUSTOMERS Annually
24 NUMBER OF ROUTERS Semi-Annually
25 NUMBER OF SERVERS Semi-Annually
26 NUMBER OF STORES TRANSACTIONS Monthly
27 NUMBER OF TELEPHONES Semi-Annually
28 NUMBER OF TRANSMISSION POLE MILES Annually
29 NUMBER OF TRANSTEXT CUSTOMERS Annually
30 NUMBER OF TRAVEL TRANSACTIONS Monthly
31 NUMBER OF VEHICLES Annually
32 NUMBER OF VENDOR INVOICE PAYMENTS Monthly
33 NUMBER OF WORKSTATIONS Quarterly
34 ACTIVE OWNED OR LEASED COMMUNICATION CHANNELS Annually
35 AVG PEAK LOAD FOR PAST THREE YEARS Annually
36 COAL COMPANY COMBINATION Semi-Annually
37 AEPSC PAST 3 MONTHS TOTAL BILL DOLLARS Monthly
38 AEPSC PRIOR MONTH TOTAL BILL DOLLARS Monthly
39 DIRECT Not Required
40 EQUAL SHARE RATIO Not Applicable
41 FOSSIL PLANT COMBINATION Annually
42 FUNCTIONAL DEPARTMENT'S PAST 3 MONTHS TOTAL BILL DOLLARS Monthly
43 KWH SALES Annually
44 LEVEL OF CONSTRUCTION - DISTRIBUTION Semi-Annually
45 LEVEL OF CONSTRUCTION - PRODUCTION Semi-Annually
46 LEVEL OF CONSTRUCTION - TRANSMISSION Semi-Annually
47 LEVEL OF CONSTRUCTION - TOTAL Semi-Annually
48 MW GENERATING CAPABILITY Annually
49 MWH 'S GENERATED Semi-Annually
50 CURRENT YEAR BUDGETED SALARY DOLLARS Annually
51 PAST 3 MO. MMBTU'S BURNED (ALL FUEL TYPES) Quarterly
52 PAST 3 MO. MMBTU'S BURNED (COAL ONLY) Quarterly
53 PAST 3 MO. MMBTU'S BURNED (GAS TYPE ONLY) Quarterly
54 PAST 3 MO. MMBTU'S BURNED (OIL TYPE ONLY) Quarterly
55 PAST 3 MO. MMBTU'S BURNED (SOLID FUELS ONLY) Quarterly
56 PEAK LOAD/AVG # CUST/KWH SALES Annually
COMBINATION
57 TONS OF FUEL ACQUIRED Semi-Annually
58 TOTAL ASSETS Quarterly
59 TOTAL ASSETS LESS NUCLEAR PLANT Quarterly
60 TOTAL AEPSC BILL DOLLARS LESS INTEREST AND/OR INCOME Annually
TAXES AND/OR OTHER INDIRECT EXPENSES
61 TOTAL FIXED ASSETS Quarterly
62 TOTAL GROSS REVENUE Quarterly
63 TOTAL GROSS UTILITY PLANT (INCLUDING CWIP) Quarterly
64 TOTAL PEAK LOAD (PRIOR YEAR) Annually
NOTE: (1) The measurement date for an attribution basis with an update
frequency of monthly is the last day of the month. The period covered,
if applicable, is one month unless otherwise stated in the calculation
description which appears in Exhibit B-3.
(2) The measurement dates for an attribution basis with an update
frequency of quarterly are March 31, June 30, September 30 and December 31. The
period covered, if applicable, is three months unless otherwise stated in the
calculation description which appears in Exhibit B-3.
(3) The measurement dates for an attribution basis with an update
frequency of semi-anually are June 30 and December 31. The period covered, if
applicable, is three months unless otherwise stated in the calculation
description which appears in Exhibit B-3.
(4) The measurement date for an attribution basis with an update
frequency of annually is December 31. The period covered, if applicable, is
twelve months unless otherwise stated in the calculation description which
appears in Exhibit B-3.
(5) Nothing shall preclude calculation of the attribution bases more
frequently than stated herein as circumstances may warrant.
Exhibit B-3.2
COMPARISON OF AEPSC AND CSWS CURRENT ATTRIBUTION BASES
TO
PROPOSED POST-MERGER AEPSC ATTRIBUTION BASES (See notes on last
page regarding current attribution bases.)
AEPSC
AEPSC CSWS Post
Current Current Merger Description Explanation of Differences
X X 1. Number of Bank Accounts To collect, track and
allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 2. Number of Call Center To collect, track and
Telephones allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 3. Number of Cell Phones/Pagers To collect, track and
allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 4. Number of Checks Printed To collect, track and
allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 5. Number of CIS Customer To collect, track and
Mailings allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 6. Number of Commercial To collect, track and
Customers allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
This factor is a subset
of an existing AEPSC
allocation factor, namely
Number of Electric
Customers.
X X 7. Number of Credit Cards To collect, track and
allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 8. Number of Electric Retail To collect, track and
Customers allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
This factor is a subset
of an existing AEPSC
allocation factor, namely
Number of Electric
Customers.
X X X 9. Number of Employees
X X 10. Number of Generating To collect, track and
Plant Employees allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
This factor is a subset
of an existing AEPSC
allocation factor, namely
Total Number of
Employees.
X X 11. Number of GL Transactions To collect, track and
allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 12. Number of Help Desk Calls To collect, track and
allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 13. Number of Industrial To collect, track and
Customers allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
This factor is a subset
of an existing AEPSC
allocation factor, namely
Number of Electric
Customers.
X X 14. Number of JCA To collect, track and
Transactions allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 15. Number of Non-UMWA To collect, track and
Employees allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
This factor is a subset
of an existing AEPSC
allocation factor, namely
Total Number of
Employees.
AEP employs union mine
workers and other union
workers who may not
participate in certain
AEP system benefit
programs.
X X X 16. Number of Phone Center
Calls (Note 2)
X X 17. Number of Purchase This is a cost causative
Orders Written driver of
providing procurement
services. This is
equivalent to CSWS' JCA
transactions.
X X 18. Number of Radios To collect, track and
(Base/Mobile/Handheld) allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 19. Number of Railcars CSW's railcar costs are
billed direct. AEPSC
manages a large fleet of
railcars.
X X 20. Number of Remittance To collect, track and
Items allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 21. Number of Remote To collect, track and
Terminal Units allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 22. Number of Rented Water CSW companies do not
Heaters currently rent water
heaters to their
customers. Only companies
with water heater rental
programs would be billed
using this attribution
basis.
X X 23. Number of Residential To collect, track and
Customers allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
This factor is a subset
of an existing AEPSC
allocation factor, namely
Number of Electric
Customers.
X X 24. Number of Routers To collect, track and
allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 25. Number of Servers To collect, track and
allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 26. Number of Stores This is equivalent to
Transactions CSWS' JCA transactions.
X X 27. Number of Telephones To collect, track and
allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X X 28. Number of Transmission
Pole Miles
X X 29. Number of Transtext CSW companies do not have
Customers Transtext customers.
Only companies with
Transtext customers would
be billed using this
attribution basis.
X X 30. Number of Travel To collect, track and
Transactions allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 31. Number of Vehicles To collect, track and
allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X X 32. Number of Vendor Invoice
Payments
X X 33. Number of Workstations To collect, track and
allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 34. Active Owned or Leased To collect, track and
Communication Channels allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 35. Average Peak Load for To collect, track and
Past 3 Years allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
This factor is a subset
of an existing AEPSC
allocation factor, namely
Total Peak Load (also
known as Client Load
Ratio).
X X 36. Coal Company Combination AEPSC uses this factor
for allocating
supervisory and
administrative costs to
active coal mining
facilities. CSWS
currently does not
provide this service.
X X 37. AEPSC Past 3 Months To collect, track and
Total Bill Dollars allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
This factor is a subset
of an existing AEPSC
allocation factor, namely
AEPSC Annual Costs
Billed.
X X 38. AEPSC Prior Month Total To collect, track and
Bill Dollars allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
This factor is a subset
of an existing AEPSC
allocation factor, namely
AEPSC Annual Costs
Billed.
X X X 39. Direct
X X X 40. Equal Share Ratio
X X 41. Fossil Plant Combination AEPSC uses this factor
for allocating
supervisory and
administrative costs
applicable to its fossil
generating plants.
X X 42. Functional Department's To collect, track and
Past 3 Months allocate costs based on a
Total Bill Dollars cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
This factor is a subset
of an existing AEPSC
allocation factor, namely
AEPSC Annual Costs
Billed.
X X X 43. KWH Sales
X X 44. Level of Construction - Level of Construction is
Distribution an allocation factor
AEPSC uses for allocating
supervisory,
administrative, technical
and engineering costs
related to minor
construction projects.
X X 45. Level of Construction - Level of Construction is
Production an allocation factor
AEPSC uses for allocating
supervisory,
administrative, technical
and engineering costs
related to minor
construction projects.
X X 46. Level of Construction - Level of Construction is
Transmission an allocation factor
AEPSC uses for allocating
supervisory,
administrative, technical
and engineering costs
related to minor
construction projects.
X X 47. Level of Construction - Level of Construction is
Total an allocation factor
AEPSC uses for allocating
supervisory,
administrative, technical
and engineering costs
related to minor
construction projects.
X X X 48. MW Generating Capability
X X X 49. MWH's Generated
X X 50. Current Year Budgeted To collect, track and
Salary Dollars allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 51. Past 3 Months MMBTU's To collect, track and
Burned (All Fuel Types) allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 52. Past 3 Months MMBTU's To collect, track and
Burned (Coal Only) allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 53. Past 3 Months MMBTU's To collect, track and
Burned (Gas Type Only) allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 54. Past 3 Months MMBTU's To collect, track and
Burned (Oil Type Only) allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 55. Past 3 Months MMBTU's To collect, track and
Burned (Solid Fuels Only) allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 56. Peak Load/Avg # Cust/KWH To collect, track and
Sales Combination allocate costs based on
cost-causative factors
which, in combination
with each other, are
highly likely to vary in
proportion to the
benefits received by each
participating company.
X X 57. Tons of Fuel Acquired This is a cost-causative
driver of fuel purchased
by the ton.
X X 58. Total Assets To collect, track and
allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 59. Total Assets Less To collect, track and
Nuclear Plant allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X X 60. Total AEPSC Bill Dollars
Less Interest and/or
Income Taxes and/or
Other Indirect Costs
X X 61. Total Fixed Assets To collect, track and
allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X 62. Total Gross Revenue To collect, track and
allocate costs based on a
cost-causative factor
which is highly likely to
vary in proportion to the
benefits received by each
participating company.
X X X 63. Total Gross Utility
Plant (Including CWIP)
X X 64. Total Peak Load (Prior
X Computer Resource Intermediate cost
Unit allocation; not used for
billing purposes.
X Data Processing Not required; will use
Staff Job Hours Number of Electric
Customers.
X Useable Square Intermediate cost
Footage by Group allocation; not used for
billing purposes.
X Number of Energy Not currently used for Trading
Transactions billing purposes.
X Specific Incorporated in the list of
Identification proposed post-merger
allocations
(e.g., Number of Railcars).
NOTE: 1. Per Schedule A of AEPSC's Service Agreement (File No. 70-8777,
Amendment No. 4, Exhibit B-1). Also, see Note 2.
2. Number of Phone Center Calls: Per 60-Day Letter filed by AEPSC, dated
10/15/98 (effective 01/01/99).
3. Per 60-Day Letters filed by CSWS, dated 03/07/97, 07/11/97, 11/03/97
and 01/23/98.
Exhibit B-3.3
SCOPE OF THE PROPOSED POST-MERGER AEPSC ATTRIBUTION BASES
BY CLASS OF COMPANIES
The following list describes which class of companies applies to each
attribution basis. The four classes of companies are:
"Operating companies" - System electric utility companies; "Generating
companies" - System companies which operate facilities for the production
of electricity, other than exempt wholesale generators, foreign utility
companies and qualifying facilities; "Coal companies" - System companies
engaged in the mining, preparation and sale of coal to the System
generating companies; and "All companies" - All System companies.
Only companies under a particular company class which have the factors on which
the attribution basis is based will have costs allocated to them. In the event
that a particular work order only benefits certain companies within a company
class, only those companies which receive a benefit from the work order will
have costs allocated to them by including only the benefiting companies or the
applicable segments of those companies in the calculation of the attribution
basis based on the scope of the work order. As a result, each of the listed
attribution bases could have one or more permutations. Segments of a company may
be applicable based on the scope of a work order in terms of regions, divisions
or other organizational boundaries which involve two or more companies.
Description Company Class
1. Number of Bank Accounts All Companies
2. Number of Call Center Telephones Operating Companies
3. Number of Cell Phones/Pagers All Companies
4. Number of Checks Printed All Companies
5. Number of CIS Customer Mailings Operating Companies
6. Number of Commercial Customers Operating Companies
7. Number of Credit Cards All Companies
8. Number of Electric Retail Customers Operating Companies
9. Number of Employees All Companies
10. Number of Generating Plant Employees Generating Companies
11. Number of GL Transactions All Companies
12. Number of Help Desk Calls All Companies
13. Number of Industrial Customers Operating Companies
14. Number of JCA Transactions Operating Companies
15. Number of Non-UMWA Employees All Companies
16. Number of Phone Center Calls Operating Companies
17. Number of Purchase Orders Written All Companies
18. Number of Radios (Base/Mobile/Handheld) All Companies
19. Number of Railcars Operating Companies
20. Number of Remittance Items All Companies
21. Number of Remote Terminal Units All Companies
22. Number of Rented Water Heaters Operating Companies
23. Number of Residential Customers Operating Companies
24. Number of Routers All Companies
25. Number of Servers All Companies
26. Number of Stores Transactions All Companies
27. Number of Telephones All Companies
28. Number of Transmission Pole Miles Operating Companies
29. Number of Transtext Customers Operating Companies
30. Number of Travel Transactions All Companies
31. Number of Vehicles All Companies
32. Number of Vendor Invoice Payments All Companies
33. Number of Workstations All Companies
34. Active Owned or Leased Communication All Companies
Channels
35. Average Peak Load for Past 3 Years Operating Companies
36. Coal Company Combination Coal Companies
37. AEPSC Past 3 Months Total Bill Dollars All Companies
38. AEPSC Prior Month Total Bill Dollars All Companies
39. Direct All Companies
40. Equal Share Ratio All Companies
41. Fossil Plant Combination Generating Companies
42. Functional Department's Past 3 Months All Companies
Total Bill Dollars
43. KWH Sales Operating Companies
44. Level of Construction - Distribution Operating Companies
45. Level of Construction - Production Operating Companies
46. Level of Construction - Transmission Operating Companies
47. Level of Construction - Total Operating Companies
48. MW Generating Capability Generating Companies
49. MWH's Generated Generating Companies
50. Current Year Budgeted Salary Dollars All Companies
51. Past 3 Months MMBTU's Burned (All Fuel Generating Companies
Types)
52. Past 3 Months MMBTU's Burned (Coal Only) Generating Companies
53. Past 3 Months MMBTU's Burned (Gas Type Generating Companies
Only)
54. Past 3 Months MMBTU's Burned (Oil Type Generating Companies
Only)
55. Past 3 Months MMBTU's Burned (Solid Fuels Generating Companies
Only)
56. Peak Load/Avg # Cust/KWH Sales Combination Operating Companies
57. Tons of Fuel Acquired Generating Companies
58. Total Assets All Companies
59. Total Assets Less Nuclear Plant All Companies
60. Total AEPSC Bill Dollars Less Interest All Companies
and/or Income Taxes and/or Other
Indirect Costs
61. Total Fixed Assets All Companies
62. Total Gross Revenue All Companies
63. Total Gross Utility Plant (Including CWIP) Operating Companies
64. Total Peak Load (Prior Year) Operating Companies
Exhibit B-3.4
Description of Services to Be Performed by AEPSC Post-Merger
and Associated Attribution Bases by Category of Services
Production Services: Production services coordinates the planning and operation,
including centralized dispatching, of the integrated bulk-power supply system.
In addition, production services provides management, drafting and engineering
services for all integrated system power plants, unit commitment and maintenance
scheduling and centralized maintenance crews that serve regional power plants,
as well as new technology evaluation. Fuel procurement and fuel supply
administration, environmental services, production mining services, and
regulatory compliance and reporting are also provided.
Depending on the exact nature and the scope of the services performed, the
attribution bases most utilized by this category of services are: direct, number
of generating plant employees, average peak load for the past three years, peak
load/average number of customers/kwh sales combination, MW generating
capability, past 3 months MMBTUs burned (all fuel types, coal only, gas type
only, oil type only, or solid fuels only), coal company combination, fossil
plant combination, number of railcars, level of construction - production, level
of construction - total, total peak load (prior year), number of electric
customers (retail, residential, commercial, or industrial), kwh sales, MWH's
generated, tons of fuel acquired, and functional department's past three months
total bill dollars.
Transmission Services: Transmission services provides project management, design
and development of construction projects, drafting and engineering services,
contract administration, development of standards associated with the evaluation
of materials related to electric transmission systems, forestry services, and
impact studies.
Depending on the exact nature and the scope of the services performed, the
attribution bases most utilized by this category of services are: direct, number
of transmission pole miles, level of construction - transmission, level of
construction - total, total peak load (prior year), number of electric customers
(retail, residential, commercial or industrial), average peak load for past
three years, and functional department's past three months total bill dollars.
Distribution Services: Distribution services provides mapping services, project
management, design and development of construction projects, drafting and
engineering services, contract administration, forestry services and
administrative and planning services.
Depending on the exact nature and the scope of the services performed, the
attribution bases most utilized by this category of services are: direct, number
of electric customers (retail, residential, commercial, or industrial), level of
construction - distribution, level of construction total, kwh sales, number of
transtext customers, and functional department's past three months total bill
dollars.
Customer Services: Customer services prints, inserts and mails customer bills
and other required mailings for electric service customers. Customer services
also provides support services for the customer information system, remittance
processing, power billing, credit and collections, customer accounting, and
customer call centers.
Depending on the exact nature and the scope of the services performed, the
attribution bases most utilized by this category of services are: direct, number
of electric customers (retail, residential, commercial, or industrial), number
of CIS customer mailings, number of phone center calls, number of call center
telephones, number of remittance items, kwh sales, number of rented water
heaters, and functional department's past three months total bill dollars.
Financial Services: Financial services includes coordination in the areas of
accounting policy and research and in the development and maintenance of all
financial information systems. In addition, financial services compiles and
maintains financial, statistical and regulatory records and reports; and it
provides accounting services that include centralized processing for accounts
payable and payroll. The accounting and reporting for employee benefit plans is
also performed. In addition, financial services provides tax research and
consultation services in both state and Federal tax areas. Internal audit
services are provided, as well as the coordination of financings for all
companies, investor relations services, and corporate planning and budgeting
(including services related to strategic planning and operational forecasting).
Depending on the exact nature and the scope of the services performed, the
attribution bases most utilized by this category of services are: direct, number
of employees, number of general ledger transactions, number of checks printed,
number of credit cards, AEPSC past 3 months total bill dollars, AEPSC prior
month total bill dollars, equal share ratio, current year budgeted salary
dollars, total assets less nuclear plant, total gross revenue, level of
construction - total, number of vehicles, total assets, number of vendor invoice
payments, number of bank accounts, total fixed assets, total AEPSC bill dollars
(less interest and/or income taxes and/or other indirect costs), total gross
utility plant, number of stores transactions, number of job cost accounting
(JCA) transactions, and functional department's past three months total bill
dollars.
Human Resource Services: Human resource services provides administration and
coordination of the employee benefit plans, labor relations, certain employee
and management training, centralized processing of medical benefit claims, and
human resource management for all companies.
Employee based allocation factors are the most utilized by this category,
including number of employees, number of non-UMWA employees, and current year
budgeted salary dollars.
Information Technology Services: Information technology services provides
information processing, electric customer billing, application development,
client computing, technical software support, and telecommunications support
services such as telephone system support, leased lines, and maintenance of
telecommunications equipment. Research and administration support of
company-wide information technology standards and specification requirements for
mainframe and PC based hardware and software systems is also provided. In
addition to providing and maintaining system infrastructure, user and
application support services are provided. These services include feasibility
studies for new applications, development of new applications and providing
enhancements to existing applications, along with other related activities.
Depending on the exact nature and the scope of the services performed, the
attribution bases most utilized by this category of services are: direct, number
of employees, number of general ledger transactions, number of help desk calls,
equal share ratio, current year budgeted salary dollars, number of transtext
customers, number of servers, number of routers, number of work stations, number
of electric customers (retail, residential, commercial, or industrial), number
of vendor invoice payments, number of cell phones/pagers, number of radios
(base, mobile, handheld), number of telephones, number of remote terminal units,
active owned or leased communication channels, number of CIS customer mailings,
and functional department's past three months total bill dollars.
Operational Services: Strategic and business planning is coordinated on a
system-wide basis to track the key issues facing the utility industry in both
the short- and long-term and to facilitate the business planning efforts of the
individual subsidiaries. In addition, operational services provides central
management of rate reviews and other regulatory matters for the electric
operating companies.
Depending on the exact nature and the scope of the services performed, the
attribution bases most utilized by this category of services are: direct, total
assets, number of employees, total peak load (prior year), equal share ratio,
and functional department's past three months total bill dollars.
Other Support Services: Other support services provided include executive group,
procurement and supply chain management, research and development, internal and
external communications, legal services, governmental affairs, travel services,
building and lease services, fleet and equipment services, corporate
development, power marketing and energy trading, and special projects.
Depending on the exact nature and the scope of the services performed, the
attribution bases most utilized by this category of services are: direct, total
assets, number of employees, number of travel transactions, number of vehicles,
total peak load (prior year), number of purchase orders written, number of
stores transactions, equal share ratio, current year budgeted salary dollars,
total assets less nuclear plant, level of construction total, kwh sales, total
AEPSC bill dollars (less interest and/or income taxes and/or other indirect
costs) and functional department's past three months total bill dollars.
Exhibit J
Pursuant to the Merger Agreement, an acquisition company, wholly owned by
AEP and formed solely for the purpose of accomplishing the Merger, will merge
with and into CSW. CSW will survive the Merger and become a wholly owned
subsidiary of AEP. The former CSW shareholders will exchange their shares of CSW
Common Stock for shares of AEP Common Stock. This type of merger, in which CSW
survives, will satisfy the definition of a tax free "stock for stock"
reorganization as set forth in IRC Sec. 368(a)(1)(B) assuming several other
important criteria are met (a "B Reorganization"). On the other hand, if CSW
immediately merged directly with and into AEP, then for tax purposes the
acquisition would be governed by IRC Sec. 368(a)(1)(A)(an "A Reorganization")
instead of IRC Sec. 368(a)(1)(B).
The tax significance of not immediately merging CSW with and into AEP,
relates to the determination of the appropriate tax basis for that which AEP has
acquired. Under an A Reorganization (in which CSW did not survive but instead
merged directly with AEP), AEP has acquired the assets of CSW from a tax
perspective. In that instance, AEP's tax basis would not equal the aggregate tax
basis of the former CSW shareholders. Rather, it would equal CSW's tax basis in
the former assets of CSW, the common stock of the CSW subsidiaries. This would
be referred to as CSW's "inside" tax basis.
In a B Reorganization, AEP has acquired all the CSW Common Stock from the
former shareholders of CSW; accordingly AEP's tax basis in CSW would equal the
aggregate tax basis of the former CSW shareholders in the CSW Common Stock they
used to hold. This would be referred to as CSW's "outside" tax basis. The actual
size of CSW's outside basis cannot be fixed until the Merger closes and the then
current shareholders of CSW are identified and the amounts each paid for their
shares of CSW Common Stock are determined. A type B Reorganization is not
possible unless CSW survives.1
In general terms, an asset's tax basis is subtracted from the amount
realized on its disposition to determine the amount of taxable gain for which
the transferor is liable. It follows that a larger tax basis equates to lower
tax liability upon disposition of the asset. Subject to certain important
assumptions as well as quantifications that cannot precede the closing of the
Merger, it has been estimated that CSW's outside tax basis is substantially
greater than CSW's inside tax basis. It is difficult to envision any
circumstances in which AEP would divest itself of CSW as a whole. However, while
AEP has no such present plan or intention, the Combined Company may be required
or strongly encouraged either through regulatory or other initiatives or
constraints to dispose of a portion of CSW's assets at some time in the future.
For example, several states have already instituted utility restructuring
efforts that compel the sale or transfer of generation assets. A proportionate
share of CSW's outside tax basis would accompany the disposition of such assets
only if certain holding periods and other criteria of IRC Sec. 355 have been
satisfied. IRC Sec. 355 and related regulations may require that such assets be
held for up to seven years. It follows that in all likelihood, the benefits of
CSW's greater outside tax basis will not be available to AEP until seven years
following the Merger and then only if AEP, either voluntarily or otherwise,
divests a portion of CSW's assets in compliance with IRC Sec. 355 and related
regulations.
Subject to certain important assumptions as well as quantifications and
other analysis some of which cannot be performed until after the Merger, it has
been estimated that CSW's inside tax basis is approximately $1.1 billion. As
noted earlier, CSW's outside tax basis cannot be fixed until the Merger closes.
Given that CSW currently has approximately 212 million shares of common stock
outstanding and that the publicly available market price for that stock has
ranged between $15 and $30 per share over the past five years and assuming that
all of CSW's current shareholders have purchased their shares within the past
five years, it is possible to project the range of CSW's outside tax basis: $3.2
billion ($15 x 212 million) to $6.4 billion ($30 x 212 million).
Further, because tax basis reduces taxable gain, a determination of the
amount of ultimate reduction of tax liability in the event of a disposition,
would be made by multiplying the amount of tax basis by the prevailing corporate
income tax rate. For example, assuming the prevailing corporate income tax rate
of 35% and applying that rate to the projected inside and outside tax bases
estimated above, the resulting reduction in tax liability in the event of a
disposition of all of CSW's present assets would be as follows:
Potential Tax Reduction due to Change in Basis
Low end: $0.735 billion ($3.2 billion - $1.1 billion) x 35% =
$0.735 billion
High end: $1.855 billion ($6.4 billion - $1.1 billion) x 35%
= $1.855 billion
While the possibility of a total divestiture seems extremely remote,
proportional tax savings would still accrue from a B Reorganization in the event
of a partial divestiture. For example, a B Reorganization would result in the
following additional savings in partial divestitures:
a divestiture of 5% of CSW's assets = $36,750,000 to
$92,750,000
a divestiture of 10% of CSW's assets = $73,500,000 to
$185,500,000
a divestiture of 15% of CSW's assets = $110,250,000 to
$278,250,000
In summary, the foregoing tax benefits are not possible unless CSW
survives the Merger. Preserving CSW's outside tax basis can yield substantial
tax savings in the event of a subsequent disposition of a portion of CSW's
assets if the requirements of IRC Sec. 355 can be met. Except with respect to
the specific mitigation commitments disclosed in Item 3.A.1.b.(ii).ii(b).(x),
AEP has no present plan or intention, either after completing the Merger or
after any applicable holding period, to dispose of any portion of CSW's assets.
However, in order to limit AEP's tax liability in the event of a future
disposition, whether voluntary or otherwise, prudent tax planning argues for
compliance with the rules for a B Reorganization and the requisite survival of
CSW.
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1 While a B Reorganization necessitates CSW's survival, the same may not be true
of its subsidiaries which, at least in theory, might merge with and into CSW
without sacrificing B Reorganization tax treatment. Such consolidation, however,
creates more difficulties than it resolves and would be impractical at best and
impossible at worst from business, operational and regulatory perspectives.
