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File No. 70-9381
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
* * *
AMENDMENT NO. 5
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
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and
CENTRAL AND SOUTH WEST CORPORATION 1616 Woodall Rodgers
Freeway, Dallas, Texas 75202
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(Name of companies and top registered holding company
parents filing this statement and address
of principal executive offices)
* * *
Armando A. Pena Wendy G. Hargus
Treasurer Treasurer
American Electric Power Company, Inc. Central and South West Corporation
1 Riverside Plaza 1616 Woodall Rodgers Freeway
Columbus, OH 43215 Dallas, TX 75202
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Susan Tomasky Jeffrey D. Cross
Executive Vice President and General Vice President and General Counsel
Counsel AEP Resources, Inc.
American Electric Power Company, Inc. 1 Riverside Plaza
1 Riverside Plaza Columbus, OH 43215
Columbus, OH 43215
Marianne K. Smythe Joris M. Hogan
Wilmer, Cutler & Pickering Milbank, Tweed, Hadley & McCloy L.L.P.
2445 M Street, N.W. 1 Chase Manhattan Plaza
Washington, DC 20037-1420 New York, NY 10005
(Names and addresses of agents for service)
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TABLE OF CONTENTS
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Page
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GLOSSARY OF TERMS.......................................................... 1
ITEM 1. DESCRIPTION OF MERGER............................................. 9
A. INTRODUCTION......................................................... 9
B. DESCRIPTION OF THE PARTIES TO THE MERGER............................. 12
1. General Description................................................. 12
2. Description of Energy Sales and Facilities.......................... 20
3. Electric Coordination............................................... 30
C. DESCRIPTION OF MERGER AND STATEMENT AS TO CONSIDERATION.............. 37
1. Background of the Merger............................................ 37
2. Merger Agreement.................................................... 37
3. Reasons for the Merger.............................................. 38
4. AEP Management Following the Merger................................. 39
ITEM 2. FEES, COMMISSIONS AND EXPENSES.................................... 39
ITEM 3. APPLICABLE STATUTORY PROVISIONS................................... 39
A. SECTION 10(b)........................................................ 42
1. Section 10(b)(1).................................................... 42
2. Section 10(b)(2).................................................... 48
3. Section 10(b)(3).................................................... 54
B. SECTION 10(c)........................................................ 56
1. Section 10(c)(1).................................................... 56
2. Section 10(c)(2).................................................... 99
C. SECTION 10(f)........................................................ 106
D. INTRA-SYSTEM FINANCING AND OTHER COMMISSION AUTHORIZATIONS........... 107
E. SERVICE AGREEMENT; APPROVAL OF METHODOLOGY FOR ALLOCATING
COSTS UNDER.......................................................... 110
F. ACQUISITION OF NON-UTILITY BUSINESSES................................ 114
G. ORGANIZATION OF MERGER SUB; ACQUISITION OF MERGER SUB COMMON STOCK... 115
ITEM 4. REGULATORY APPROVAL............................................... 115
A. ANTITRUST CONSIDERATIONS............................................. 116
B. ATOMIC ENERGY ACT.................................................... 116
C. FEDERAL POWER ACT.................................................... 117
D. COMMUNICATIONS ACT................................................... 118
E. ARKANSAS COMMISSION.................................................. 118
F. LOUISIANA COMMISSION................................................. 118
G. OKLAHOMA COMMISSION.................................................. 119
H. TEXAS COMMISSION..................................................... 119
I. INDIANA COMMISSION................................................... 120
J KENTUCKY COMMISSION.................................................. 120
K. MISSOURI COMMISSION.................................................. 120
L. MICHIGAN COMMISSION.................................................. 121
M. AFFILIATE CONTRACTS.................................................. 121
ITEM 5. PROCEDURE......................................................... 121
ITEM 6. EXHIBITS AND FINANCIAL STATEMENTS................................. 122
ITEM 7. INFORMATION AS TO ENVIRONMENTAL EFFECTS........................... 133
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STATUS OF STATE RESTRUCTURING LEGISLATION Appendix A
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GLOSSARY OF TERMS
The following abbreviations or acronyms used in this Application-Declaration are
defined below:
AEGCo AEP Generating Company
AEP American Electric Power Company, Inc.
before the Merger, unless the context
indicates otherwise
AEPC AEP Communications, LLC
AEP Common Stock AEP common stock, $6.50 par value
AEPES AEP Energy Services, Inc. (formerly, AEP
Energy Solutions, Inc.)
AEPRESCO AEP Resources Service Company (formerly,
AEP Energy Services, Inc.)
AEP Resources AEP Resources, Inc.
AEPSC American Electric Power Service
Corporation
AEP System American Electric Power System, an
integrated electric utility system owned
and operated by AEP's U.S. electric
utility subsidiaries
Alliance RTO Application Application of Alliance RTO for Approval of
Transaction under Section 203 of the Federal
Power Act, FERC Docket No. EC99-80 (filed
June 3, 1999)
Ameren Ameren Corporation, a public utility
holding company registered under the
1935 Act
Antitrust Division Antitrust Division of U.S. Department of
Justice
APCo Appalachian Power Company
Applicants AEP and CSW
Arkansas Commission Arkansas Public Service Commission
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Atomic Energy Act Atomic Energy Act of 1954, as amended
C3 Communications C3 Communications, Inc.
Central Dispatch Planning Computer software program,
developed by the Applicants using proprietary
technology and technology licensed from third
parties, which forecasts the generation needs of
the Combined System and schedules each generating
unit accordingly
Central Economic Dispatch Computer software program,
developed by the Applicants using proprietary
technology and technology licensed from third
parties, which adjusts, every four seconds, the
dispatch of each generating unit within the
Combined System
Combined Company AEP following the Merger
Combined System System resulting from combination of the
AEP System and CSW System following the
Merger
Commission Securities and Exchange Commission
Consumers Consumers Energy Company
Contract Path Contractual reservation of 250 MW over
the Ameren system providing firm
point-to-point transmission service from
AEP's Breed-Casey interconnection with
Ameren to CSW's MOKANOK line
interconnection with Ameren
CPL Central Power and Light Company
CSPCo Columbus Southern Power Company
CSW Central and South West Corporation
before the Merger, unless the context
indicates otherwise
CSW Common Stock CSW common stock, $3.50 par value
CSW Credit CSW Credit, Inc.
CSW Energy CSW Energy, Inc.
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CSW Energy Services CSW Energy Services, Inc.
CSW International CSW International, Inc.
CSW Leasing CSW Leasing, Inc.
CSWS Central and South West Services, Inc.
CSW System CSW Electric Power System, an integrated
electric utility system, owned and
operated by CSW's U.S. electric utility
subsidiaries
D.C. Circuit U.S. Court of Appeals for the District
of Columbia Circuit
Detroit Edison Detroit Edison Company
Division Commission's Division of Investment
Management
DOJ U.S. Department of Justice
Duke Duke Energy Corporation, an integrated
energy and energy services provider
including an electric public utility
ECAR East Central Area Reliability Council
Economic Base Points An EMS for the dispatch of generation
which calls for the operation of the
generating units of a system at the most
economic operating point for that time
period. The EMS identifies those
generating units that are to be
dispatched based upon a consideration of
relevant operating conditions,
including, but not limited to, the
amount of load to be served, the cost of
fuel, the current loading of the
generators, unit operating efficiency
curves, the reserve obligations, the
fuel constraints and the transmission
capabilities, as adjusted for frequency
control requirements of the respective
control areas.
EMS Energy Management System
Energy Act Energy Policy Act of 1992
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EnerShop EnerShop Inc.
Entergy Entergy Corporation, a public utility
holding company registered under the
1935 Act
ERCOT Electric Reliability Council of Texas
EWG Exempt Wholesale Generator
Exchange Ratio specified in the Merger Agreement of
converting CSW Common Stock for AEP Common Stock,
i.e., each share of CSW Common Stock converts
into 0.60 shares of AEP Common Stock
Excluded Shares Shares of CSW Common Stock owned by AEP,
Merger Sub or any other direct or
indirect subsidiary of AEP and shares of
CSW Common Stock that are owned by CSW
or any direct or indirect subsidiary of
CSW, in each case not held on behalf of
third parties
FCC Federal Communications Commission
FERC Federal Energy Regulatory Commission
FERC Stipulation Stipulation of American Electric Power
Company, Inc., Central and South West
Corporation, and Commission Trial Staff,
FERC Docket No. EC 98-40 (filed June 24,
1999)
FirstEnergy FirstEnergy Corporation
FPA Federal Power Act
FTC Federal Trade Commission
FUCO Foreign Utility Company
HHI Herfindahl-Hirschman Index
HSR Act Hart-Scott-Rodino Antitrust Improvements
Act of 1976
HVDC High Voltage Direct Current
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I&M Indiana Michigan Power Company
Indiana Commission Indiana Utility Regulatory Commission
IPP Independent Power Producer
ISO Independent System Operator, ISO. An
ISO is a type of RTO which functions as
an independent entity set up to control
and operate one or more transmission
systems owned by other entities. Under
the ISO structure, transmission owners
retain title to their assets, and the
ISO runs the systems as a joint
operation. An ISO generally files a
single transmission tariff for the
region in which it controls transmission
facilities, plans and schedules
transmission outages, takes a lead role
in transmission system planning,
collects transmission charges, and makes
payments to the actual providers.
Kentucky Commission Kentucky Public Service Commission
KPCo Kentucky Power Company
KgPCo Kingsport Power Company
Kv Kilovolt
KwH Kilowatt hours
Louisiana Commission Louisiana Public Service Commission
Merger Business combination of AEP and CSW
pursuant to the Merger Agreement
Merger Agreement Agreement and Plan of Merger, dated as
of December 21, 1997 among CSW, AEP and Merger
Sub in which Merger Sub will be merged with and
into CSW and CSW will become a wholly-owned
subsidiary of AEP
Michigan Commission The Michigan Public Service Commission
Merger Sub Augusta Acquisition Corporation, to
become a wholly owned subsidiary of AEP
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MISO Midwest Independent Transmission System
Operator, Inc.
Missouri Commission Missouri Public Service Commission
MOKANOK Line 345 Kv transmission line jointly owned by
PSO, UE, Associated Electric Cooperative and
Kansas Gas and Electric
Company.
Morgan Stanley Morgan Stanley & Co. Incorporated, an
investment banking firm and CSW's
financial adviser with respect to the
Merger
MW Megawatts
Nanyang Electric Nanyang General Light Electric Co., Ltd.
NCE New Century Energies, Inc.
NEPOOL New England Power Pool
NERC North American Electric Reliability
Council
1935 Act Public Utility Holding Company Act of
1935, as amended
1995 Report The Regulation of Public Utility Holding
Companies (report to Congress by the
Division, June 1995)
NRC Nuclear Regulatory Commission
NSP Northern States Power Company
OASIS Open Access Same-Time Information
System, OASIS. An OASIS is a system
that gives a third-party potential
transmission user information about a
system's transmission capability and
prices, and that allows transmission
users to effect transmission
transactions.
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OATT Open Access Transmission Tariff, OATT.
OATTs are open access nondiscriminatory
transmission tariffs under which, as
required by FERC Order No. 888, an
electric utility must provide wholesale
transmission services on a
non-discriminatory basis and set forth,
at a minimum, terms and conditions of
service.
OG&E Oklahoma Gas & Electric Company
Ohio Commission Public Utilities Commission of Ohio
Oklahoma Commission Corporation Commission of the State of
Oklahoma
OPCo Ohio Power Company
PG&E PG&E Corporation, a public utility
holding company
PSNH Public Service Company of New Hampshire
PSO Public Service Company of Oklahoma
QF Qualifying Facility as defined in the
Public Utility Regulatory Policies Act
of 1978
Registration Statement Joint Proxy Statement/Prospectus dated
April 16, 1998 of AEP and CSW
RTO Regional Transmission Organizations,
RTOs. RTOs are regional transmission
organizations which satisfy the minimum
characteristics required by FERC Order
No. 2000, including independence from
market participants, a transmission
system of sufficient scope and regional
configuration, operational authority
over the transmission grid in a
particular region, and responsibility
for maintaining short-term reliability
of the transmission grid.
Salomon Salomon Smith Barney Inc., an investment
banking firm and AEP's financial adviser
with respect to the Merger
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SEEBOARD SEEBOARD plc, one of the 12 regional electricity
companies formed due to the restructuring and
subsequent privatization of the United Kingdom
electricity industry in 1990
Southern The Southern Company, a public utility
holding company registered under the
1935 Act
SPP Southwest Power Pool
STP South Texas Project, a two-unit nuclear
electricity generating station in which
CPL owns a 25.2% interest
STP Operating STP Nuclear Operating Company
SWEPCO Southwestern Electric Power Company
Tennessee Commission Tennessee Regulatory Authority
Texas Commission Public Utility Commission of Texas
Texas Utilities Texas Utilities Company
UE Union Electric Company, a public utility
and a wholly owned subsidiary of Ameren
Virginia Commission The Virginia State Corporations
Commission
Virginia Power Virginia Electric and Power Company
West Virginia Commission West Virginia Public Service Commission
WPCo Wheeling Power Company
WR Western Resources, Inc.
WTU West Texas Utilities Company
Yorkshire Electricity Yorkshire Electricity Group plc, one
of the 12 regional electricity companies formed
due to the restructuring and subsequent
privatization of the United Kingdom electricity
industry in 1990
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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
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.
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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 possibly CSW Credit, which may 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 possibly CSW Credit). The final
ownership structure has not yet been determined.
Upon consummation of the Merger, each share of issued and outstanding CSW
Common Stock (other than Excluded Shares) will be exchangeable for 0.60 shares
of AEP Common Stock. The former holders of CSW Common Stock will own
approximately 40% of the outstanding shares of AEP Common Stock after the
Merger. The only voting securities of AEP that will be publicly held will be AEP
Common Stock; the Merger is expected to have no effect on the issued and
outstanding public debt securities, preferred stock and/or preferred trust
securities of CSW and the respective subsidiaries of AEP and CSW.
With respect to the cost of capital of AEP and CSW, the nationally
recognized rating agencies of Moody's Investors Service, Standard & Poor's, Duff
& Phelps and Fitch reaffirmed their rating of the outstanding first mortgage
bonds, commercial paper and other rated securities of AEP and CSW and/or their
subsidiaries shortly after the Merger announcement. Since that time, there has
been no merger-related change in any of the ratings by the rating agencies.(1) A
summary of ratings on securities of AEP and CSW is presented in Exhibit M which
is incorporated by reference.
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;
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(1) On January 6, 1998, Standard & Poor's revised its ratings outlook on
CSW's regulated U.S. units to negative from stable and affirmed its ratings on
these utilities. Moody's lowered its rating from Aa3 to A1 on PSO's First
Mortgage Bonds based upon a rate review by the Oklahoma Commission that was
unrelated to the Merger.
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(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 according
to procedures set forth in the HSR Act and a determination by the Texas
Commission that the Merger is consistent with the public interest. Applicants
have made filings with each of these regulatory agencies.
On November 23, 1999, an Initial Decision was issued by the Administrative
Law Judge at FERC approving the Merger, a copy of which is filed as Exhibit
D-1.7 and incorporated by reference. On March 15, 2000, FERC issued an order
conditionally approving the Merger, a copy of which is filed as Exhibit D-1.9
and incorporated by reference. The NRC approved the transfer of control of CPL's
NRC licenses, a copy of which is filed as Exhibit D-6.2 and incorporated by
reference, and on December 9, 1999, granted an extension of such approval to
June 30, 2000. On July 26, 1999, Applicants filed with the DOJ under the HSR
Act. On February 2, 2000, DOJ notified Applicants that it had completed its
review of the Merger and that no further action is warranted. On July 29, 1999,
Applicants filed an application with the FCC to transfer control of certain
licenses held by CSW subsidiaries to AEP, a copy of which is filed as Exhibit
D-9.1. On January 21, 2000, the FCC approved the transfer of certain microwave
licenses held by CSW. Orders approving the Merger have been received from the
Arkansas Commission, the Louisiana Commission, the Oklahoma Commission, the
Kentucky Commission, the Indiana Commission, and the Michigan Commission, copies
of which are filed as Exhibit D-2.2, Exhibit D-3.2, Exhibit D-4.2, Exhibit
D-7.1, Exhibit D-8.1, and Exhibit
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D-10.1, respectively, and incorporated by reference. On November 18, 1999, the
Texas Commission issued an order finding the Merger to be consistent with the
public interest, a copy of which is filed as Exhibit D-5.4 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, 1999, the U.S. subsidiaries of AEP had a total of 16,873
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 896,000 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, 1999, APCo had 3,290 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
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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
655,000 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, 1999, CSPCo
had 1,466 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 559,000 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, 1999, I&M had 3,130 employees. Among the
principal industries served by I&M are primary metals, transportation
equipment, electrical and electronic machinery, fabricated metal products,
rubber and miscellaneous plastic products and chemicals and allied
products. I&M's retail rates and certain other matters are subject to
regulation by the Indiana Commission and the Michigan Public Service
Commission. I&M also is subject to regulation by the NRC under the Atomic
Energy Act with respect to the operation of its nuclear generation plant.
KPCo (organized in Kentucky in 1919) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 171,000 customers in eastern Kentucky, and in supplying
electric power at wholesale to other utilities and municipalities in
Kentucky. At December 31, 1999, KPCo had 501 employees. The principal
industries served by KPCo include coal mining, petroleum refining, primary
metals and chemicals. KPCo's retail rates and certain other matters are
subject to regulation by the Kentucky Commission.
KgPCo (organized in Virginia in 1917) provides electric service to
approximately 45,000 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, 1999, KgPCo had 62 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 691,000 customers in the northwestern,
east central, eastern and southern sections of Ohio, and in supplying
electric power at wholesale to other electric utility
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companies and municipalities. At December 31, 1999, OPCo and its wholly
owned subsidiaries had 3,941 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,
1999, WPCo had 74 employees. The principal industries served by WPCo
include chemicals, coal mining and primary metal products. WPCo's retail
rates and certain other matters are subject to regulation by the West
Virginia Commission.
AEGCo was organized in Ohio in 1982 as an electric generating company.
AEGCo sells power at wholesale to I&M, KPCo and Virginia Electric and Power
Company, an unaffiliated public utility. AEGCo has no employees.
AEPSC provides, at cost, accounting, administrative, information systems,
engineering, financial, legal, maintenance and other services to the AEP
companies. The executive officers of AEP and its public utility subsidiaries are
all employees of AEPSC.
AEP, primarily through AEP Resources, AEPRESCO, AEPC, and AEPES, pursues
new non-utility business opportunities, particularly those which allow use of
its expertise. These subsidiaries are described below:
AEP Resources' primary business is development of, and investment
in, EWGs, FUCOs, QFs and other energy-related domestic and international
investment opportunities and projects.
AEP Resources indirectly owns 50% of the outstanding share capital
of Yorkshire Electricity. Yorkshire Electricity is principally engaged in
the distribution of electricity to approximately 2.2 million customers in
its authorized service territory which is comprised of 3,860 square miles
and located centrally on the east coast of England.
AEP Resources' indirect subsidiary, AEP Pushan Power, LDC, has a 70%
interest in Nanyang Electric, a joint venture organized to develop and
build two 125 MW coal-fired generating units near Nanyang City in the
Henan Province of The Peoples' Republic of China. Funding for the
construction of the generating units was completed in June 1999.
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.
-14-
<PAGE> 18
In December 1998, AEP Resources, through wholly-owned subsidiaries,
acquired CitiPower Pty., an electric distribution and retail sales company
in Victoria, Australia. CitiPower Pty. serves approximately 250,000
customers in a service area that covers approximately 100 square miles in
the city of Melbourne.
In December 1998, AEP Resources acquired from Equitable Resources,
Inc. midstream gas operations consisting of: (i) a 2,000-mile intrastate
pipeline system in Louisiana, (ii) four natural gas processing plants that
straddle the pipeline, and (iii) a storage facility, including an existing
salt dome storage cavern and a second cavern under construction, both
connected to the most active gas trading area in North America. The
pipeline and storage facility are interconnected to 15 interstate and 23
intrastate pipelines. The gas trading and marketing group included in this
purchase was acquired by AEPES.
AEP received approval from the Commission under the 1935 Act to
issue and sell securities in an amount up to 100% of its consolidated
retained earnings (approximately $1,740,000,000 at December 31, 1999) for
investment in EWGs and FUCOs through AEP Resources. American Elec.
Power Co., HCAR No. 26864 (Apr. 27, 1998).
AEPRESCO offers engineering, construction, project management and
other consulting services for projects involving transmission,
distribution or generation of electric power both domestically and
internationally.
AEPC, an "exempt telecommunications company" under the 1935 Act, was
formed in 1997 to pursue opportunities in the telecommunications field.
AEPC operates a fiber optic line that runs through Kentucky, Ohio,
Virginia and West Virginia. This fiber optic line is capable of providing
high speed telecommunications capacity to other telecommunications
companies. In addition to establishing and providing fiber optic services,
AEPC also made investments in two companies engaged in providing digital
personal communications services, the West Virginia PCS Alliance, LLC and
the Virginia PCS Alliance, LLC.
AEPES is authorized to engage in energy-related activities,
including marketing electricity, gas and other energy commodities. As
noted above, AEPES acquired the gas trading and marketing group of
Equitable Resources, Inc. AEPES is an energy-related company under Rule
58.
AEP Common Stock is listed on the New York Stock Exchange, Inc. under the
trading symbol, "AEP." As of October 31, 1999, there were 194,103,349 shares of
AEP Common Stock outstanding. All shares of the common stock of APCo, CSPCo,
I&M, KPCo, KgPCo, OPCo and WPCo are held by AEP.
APCo has four series of cumulative preferred stock issued and outstanding,
one of which is listed on a public securities exchange. As of December 31, 1999,
there were 184,916 shares of its 4-1/2% Cumulative Preferred Stock outstanding
(listed on the Philadelphia Stock Exchange); 57,100 shares of its 5.90% Series
Cumulative Preferred Stock outstanding; 61,500 shares of its
-15-
<PAGE> 19
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 December 31, 1999, there were
250,000 shares of its 7% Cumulative Preferred Stock outstanding.
I&M has seven series of cumulative preferred stock outstanding, none of
which is listed on any public securities exchange. As of December 31, 1999,
there were 59,139 shares of its 4-1/8% Cumulative Preferred Stock outstanding;
14,412 shares of its 4.56% Cumulative Preferred Stock outstanding; 18,931 shares
of its 4.12% Cumulative Preferred Stock outstanding; 152,000 shares of its 5.90%
Cumulative Preferred Stock outstanding; 192,500 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 December 31, 1999, there
were 14,595 shares of its 4.08% Cumulative Preferred Stock outstanding; 99,727
shares of its 4-1/2% Cumulative Preferred Stock outstanding; 23,100 shares of
its 4.20% Cumulative Preferred Stock outstanding; 31,944 shares of its 4.40%
Cumulative Preferred Stock outstanding; 72,500 shares of its 5.90% Cumulative
Preferred Stock outstanding; 11,000 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 December
31, 1999, after eliminating intercompany transactions, were $6,916,000,000.
Consolidated assets of AEP and its subsidiaries as of December 31, 1999, were
approximately $21.5 billion, consisting of $13.1 billion in net electric utility
property, plant and equipment and $8.4 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, 1999, and the
Quarterly Report on Form 10-Q for the quarter ended September 30, 1999, each of
which is attached and incorporated by reference as Exhibits G-23 and G-21,
respectively.
b. CSW
CSW, incorporated under the laws of Delaware in 1925, has its principal
executive offices at 1616 Woodall Rodgers Freeway, Dallas, Texas. CSW is a
public utility holding company registered under the 1935 Act that owns all of
the common stock of four U.S. electric utility operating subsidiaries: CPL, PSO,
SWEPCO, and WTU. CSW also owns all of the common stock of CSWS, CSW Energy, CSW
International, C3 Communications, EnerShop, 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
-16-
<PAGE> 20
operating subsidiaries serve an average of approximately 1.8 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, 1999, the U.S. electric utility operating subsidiaries of
CSW had 4,969 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
661,100 customers in portions of south Texas, and in supplying electric
power at wholesale to other electric utility companies and municipalities.
At December 31, 1999, CPL had 1,558 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 490,900 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, 1999, PSO had 1,127
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 421,900 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, 1999, SWEPCO had 1,377 employees. The principal industries
served by SWEPCO include natural gas and oil production, petroleum
refining, manufacturing of pulp and paper, chemicals, food processing, and
metal refining. 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.
-17-
<PAGE> 21
WTU (organized in Texas in 1927) is engaged in the generation, sale,
purchase, transmission and distribution of electric power to approximately
189,100 customers in portions of central west Texas, and in supplying
electric power at wholesale to other electric utility companies and
municipalities. At December 31, 1999, 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 nine projects, seven in operation and two 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 $1,906,000,000 at December 31, 1999) 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. 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.
-18-
<PAGE> 22
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 December
31, 1999, there were 212,648,293 shares of CSW Common Stock issued and
outstanding. All shares of the common stock of CPL, PSO, SWEPCO and WTU are held
by CSW.
CPL has two series of cumulative preferred stock issued and outstanding.
As of December 31, 1999, there were 42,048 shares of 4.00% Series Cumulative
Preferred Stock outstanding; 17,476 shares of 4.20% Series Cumulative Preferred
Stock outstanding. CPL has one series of 8.00% Cumulative Quarterly Income
Preferred Securities issued and outstanding, which are listed on the NYSE. As of
December 31, 1999, the principal amount of $150,000,000 of such trust preferred
securities was outstanding.
PSO has two series of cumulative preferred stock issued and outstanding.
As of December 31, 1999, there were 44,631 shares of 4.00% Series Cumulative
Preferred Stock outstanding and 8,069 shares of 4.24% Series Cumulative
Preferred Stock outstanding. PSO has one series of 8.00% Trust Originated
Preferred Securities issued and outstanding, which are listed on the NYSE. As of
December 31, 1999, the principal amount of $75,000,000 of such trust preferred
securities was outstanding.
-19-
<PAGE> 23
SWEPCO has three series of cumulative preferred stock issued and
outstanding. As of December 31, 1999, there were 37,727 shares of 5.00% Series
Cumulative Preferred Stock outstanding; 1,907 shares of 4.65% Series Cumulative
Preferred Stock outstanding; and 7,386 shares of 4.28% Series Cumulative
Preferred Stock outstanding. SWEPCO has one series of 7.875% Trust Preferred
Securities issued and outstanding, which are listed on the NYSE. As of December
31, 1999, the principal amount of $110,000,000 of such trust preferred stock was
outstanding.
WTU has one series of cumulative preferred stock issued and outstanding.
As of December 31, 1999, there were 23,673 shares of 4.40% Series Cumulative
Preferred Stock outstanding.
CSW's consolidated operating revenues for the twelve months ended December
31, 1999, after eliminating intercompany transactions, were approximately $5.5
billion. Consolidated assets of CSW and its subsidiaries as of December 31, 1999
were approximately $14.2 billion, consisting of $8.7 billion in net electric
utility property, plant and equipment and $5.5 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,
1999 and the Quarterly Report on Form 10-Q for the quarter ended September 30,
1999, each of which is incorporated by reference as Exhibits G-24 and G-22,
respectively.
c. Merger Sub
Merger Sub, a transitory subsidiary of AEP, was incorporated under the
laws of the State of Delaware, solely for the purpose of effecting the Merger.
Merger Sub has no operations other than those contemplated by the Merger
Agreement. AEP will own all the outstanding common stock, $0.01 par value per
share, of Merger Sub. A copy of the Certificate of Incorporation and By-laws of
Merger Sub are incorporated by reference and attached as Exhibits A-3 and A-4,
respectively. The principal executive office of Merger Sub will be located at 1
Riverside Plaza, Columbus, Ohio.
2. Description of Energy Sales and Facilities
a. AEP
(i) Energy Sales
<TABLE>
<CAPTION>
KwH of Electric Energy Sold (in millions)
Company Twelve Months Ended December 31, 1999
------- -------------------------------------
<S> <C>
APCo 37,738
CSPCo 20,540
I&M 25,920
KPCo 11,336
KgPCo 1,804
OPCo 50,610
WPCo 1,799
AEP Total 128,868(a)
</TABLE>
-20-
<PAGE> 24
(a) Total after the elimination of intercompany transactions.
(ii) Electric Generating Facilities
At December 31, 1999, subsidiaries of AEP owned (or leased where
indicated) generating plants with the net power capabilities (winter rating)
shown in the following table:
<TABLE>
<CAPTION>
Net
Megawatt
Owner, Plant Type and Name Location (Near) Capability
- -------------------------- --------------- ----------
<S> <C> <C>
AEGCo:
Steam--Coal Fired:
Rockport Plant (AEGCo share) Rockport, Indiana 1,300(a)
APCo:
Steam--Coal-Fired:
John E. Amos, Units 1 & 2 St. Albans, West Virginia 1,600
John E. Amos, Unit 3 (APCo share) St. Albans, West Virginia 433(b)
Clinch River Carbo, Virginia 705
Glen Lyn Glen Lyn, Virginia 335
Kanawha River Glasgow, West Virginia 400
Mountaineer New Haven, West Virginia 1,300
Philip Sporn, Units 1 & 3 New Haven, West Virginia 308
Hydroelectric--Conventional:
Buck Ivanhoe, Virginia 10
Byllesby Byllesby, Virginia 20
Claytor Radford, Virginia 76
Leesville Leesville, Virginia 40
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
</TABLE>
-21-
<PAGE> 25
<TABLE>
<S> <C> <C>
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
</TABLE>
SUMMARY:
<TABLE>
<CAPTION>
Total Steam--
<S> <C>
Coal-Fired................................................................................. 20,795
Nuclear.................................................................................... 2,110
Total Hydroelectric--
Conventional............................................................................... 271
Pumped Storage............................................................................. 565
Other...................................................................................... 18
Total Generating Capability 23,759
</TABLE>
-22-
<PAGE> 26
(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, 1998 and 1999.
<TABLE>
<CAPTION>
1998 1999
---- ----
<S> <C> <C>
APCo $(142,500) $ (89,100)
CSPCo (146,800) (184,500)
I&M (86,100) (61,700)
KPCo
34,000 23,700
OPCo
341,400 311,600
</TABLE>
(a) Includes credits and charges from allowance transfers related to the
transactions.
(iii) Electric Transmission and Other Facilities
The following table sets forth, as of December 31, 1999, 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:
-23-
<PAGE> 27
<TABLE>
<CAPTION>
TOTAL OVERHEAD CIRCUIT
MILES OF TRANSMISSION CIRCUIT MILES OF 765
AND DISTRIBUTION LINES KV LINES
---------------------- --------
<S> <C> <C>
AEP System.... 129,106(a)(b) 2,022
APCo.......... 50,008 642
CSPCo......... 14,947(a) --
I&M........... 20,938 614
KPCo.......... 10,352 258
OPCo.......... 29,756 509
</TABLE>
(a) Includes 766 miles of 345 Kv lines jointly owned with non-affiliates.
(b) Includes lines of other AEP System companies not shown.
AEP is a member of ECAR. ECAR's membership includes 29 major electricity
suppliers located in nine states serving more than 36 million people. Membership
is voluntary, and the current full members are those utilities whose generation
and transmission have an impact on the reliability of the interconnected
electric systems in the region. ECAR members interchange power and energy with
one another on a firm, economy and emergency basis.
As of December 31, 1999, the AEP System was interconnected through 121
high-voltage transmission interconnections with 25 neighboring electric utility
systems. The all-time and 1998 one-hour peak system demands were 25,940,000 and
23,192,000 kilowatts, respectively (which included 7,314,000 and 3,732,000
kilowatts, respectively, of scheduled deliveries to unaffiliated systems which
the AEP System might, on appropriate notice, have elected not to schedule for
delivery) and occurred on June 17, 1994 and June 22, 1998, respectively. The net
dependable capacity to serve the system load on such dates, including power
available under contractual obligations, was 23,457,000 and 23,761,000
kilowatts, respectively. The all-time and 1998 one-hour internal peak demands
were 19,557,000 and 19,414,000 kilowatts, respectively, and occurred on February
5, 1996 and July 21, 1998, respectively. The net dependable capacity to serve
the system load on such dates, including power dedicated under contractual
arrangements, was 23,765,000 and 23,749,000 kilowatts, respectively.
APCo, CSPCo, I&M, KPCo and OPCo are parties to the Transmission
Equalization Agreement, dated April 1, 1984 (the "Transmission Agreement"),
which defines the method pursuant to which the parties share the costs
associated with their relative ownership of the extra-high-voltage transmission
system (which includes facilities rated 345 Kv and above) and certain facilities
operated at lower voltages (which includes facilities rated 138 Kv and above).
Like the Interconnection Agreement, sharing is based upon each company's
"member-load-ratio."
Other assets owned by AEP include electric distribution systems located
throughout its service area, and property, plant and equipment owned or leased
supporting its electric utility functions.
AEP also owns or leases other physical properties, including real
property, and other facilities necessary to conduct its operations.
-24-
<PAGE> 28
(iv) Fuel Supply
The following table shows the sources of power used by the AEP System to
generate electricity:
<TABLE>
<CAPTION>
1998 1999
---- ----
<S> <C> <C>
Coal..................................... 99% 99%
Nuclear.................................. 0% 0%
Hydroelectric and other........... 1% 1%
Total.................................... 100% 100%
</TABLE>
AEP's average cost of fuel per million BTUs for the calendar years ended
December 31, 1998 and 1999 was 144 cents and 143 cents, respectively.
b. CSW
(i) Energy Sales
<TABLE>
<CAPTION>
KwH of Electric Energy Sold (in millions)
Company Twelve Months Ended December, 31, 1999
------- --------------------------------------
<S> <C>
CPL 23,116
PSO 16,621
SWEPCO 23,571
WTU 7,622
CSW Total 66,800(a)
</TABLE>
(a) Total after elimination of intercompany transactions.
(ii) Electric Generating Facilities
At December 31, 1999, the U.S. electric utility subsidiaries of CSW owned
(or leased where indicated) generating plants with the net power capabilities
(based on summer ambient and water conditions) shown in the following table:
<TABLE>
<CAPTION>
Net
Megawatt
Owner, Plant Type and Name Location (Near) Capability
- -------------------------- --------------- ----------
<S> <C> <C>
CPL:
Steam--Gas:
B.M. Davis Corpus Christi, TX 697
E.S. Joslin Point Comfort, TX 254
J.L. Bates Palm View (Mission), TX 182
La Palma San Benito, TX 209
Laredo Laredo, TX 179
Lon C. Hill Corpus Christi, TX 557
Neuces Bay Corpus Christi, TX 567
</TABLE>
-25-
<PAGE> 29
<TABLE>
<S> <C> <C>
Victoria Victoria, TX 491
Steam--Nuclear:
STP Bay City, TX 630(b)
Steam--Coal:
Coleto Creek Fannin (Goliad), TX 632
Oklaunion Vernon, TX 54(c)
Hydroelectric--Conventional:
Eagle Pass Eagle Pass, TX 6
CT--Gas:
La Palma #7 San Benito, TX 48
------
4,510
PSO:
CT/Steam--Gas:
Comanche Lawton, OK 273(a)
Steam--Gas:
Northeastern 1 & 2 Oologah, OK 627
Riverside Jenks, OK 917
Southwest Washita, OK 472
Tulsa Tulsa, OK 415
Steam--Coal:
Northeastern 3 & 4 Oologah, OK 900
Oklaunion Vernon, TX 108(d)
CT--Gas:
Weleetka Weleetka, OK 163
Diesel--Diesel:
Diesels Oklahoma 25
------
3,900
SWEPCO:
Steam-Gas:
Arsenal Hill Shreveport, LA 110
Knox Lee Cherokee Lake, TX 484
Lieberman Mooringsport, LA 269
Lone Star Dangerfield, TX 50
Wilkes Jefferson, TX 882
Steam--Lignite:
Dolet Hills Mansfield, LA 262(e)
Pirkey Hallsville, TX 580(f)
Steam--Coal:
Flint Creek Gentry, AR 264(g)
Welsh Cason, TX 1,584
------
4,485
WTU:
Steam-Gas:
Abilene Abilene, TX 18
Fort Phantom Abilene, TX 362
Lake Pauline Quanah, TX 35
</TABLE>
-26-
<PAGE> 30
<TABLE>
<S> <C> <C>
Oak Creek Bronte, TX 85
Paint Creek Stamford, TX 238
CT-Gas:
Fort Stockton Ft. Stockton, TX 5
CT/Steam--Gas:
Rio Pecos Girvin, TX 140(a)
San Angelo San Angelo, TX 123(a)
Steam--Coal:
Oklaunion Vernon, TX 377(h)
Diesel--Diesel:
Presidio Presidio, TX 2
Vernon Vernon, TX 9
------
1,393
Total Generating Capability 14,288
</TABLE>
<TABLE>
<CAPTION>
SUMMARY:
<S> <C>
Steam -- Gas................................................... 8,099
Steam -- Nuclear............................................... 630
Steam -- Coal.................................................. 3,919
Hydroelectric -- Conventional.................................. 6
CT -- Gas...................................................... 220
CT/Steam -- Gas................................................ 536
Diesel -- Diesel............................................... 36
Steam -- Lignite............................................... 842
-------
14,288
</TABLE>
(a) Normally operated as combined cycle.
(b) CPL owns 25.2% of STP
(c) CPL owns 7.81% of Oklaunion.
(d) PSO owns 15.6% of Oklaunion.
(e) SWEPCO owns 40.234% of Dolet Hills. Central Louisiana Electric Company,
Northeast Texas Electric Cooperative and Oklahoma Municipal Power Authority own
the rest of the interests in Dolet Hills.
(f) SWEPCO owns 85.936% of Pirkey. Northeast Texas Electric Cooperative and
Oklahoma Municipal Power Authority own the rest of the interests in Pirkey.
(g) SWEPCO owns half of Flint Creek and Arkansas Electric Cooperative
Corporation owns the other half.
(h) WTU owns 54.7% of Oklaunion. (Non-affiliates own 12.29% of Oklaunion).
-27-
<PAGE> 31
All of the generating facilities described above are located on land
owned by CSW's U.S. electric utility subsidiaries or, in the case of jointly
owned facilities, jointly with other participants. The principal plants and
properties of CSW's electric utility subsidiaries are subject to liens of first
mortgage indentures under which CSW's electric utility subsidiaries' first
mortgage bonds are issued.
As part of the FERC order conditionally approving the Merger,
Applicants were required to divest 250 MW of capacity in ERCOT and 300 MW of
generation capacity in SPP. In the proceedings before the Texas Commission,
Applicants entered into a settlement approved by the Texas Commission under
which they agreed to divest 1604 MW of generation capacity in ERCOT (including
the 250 MW of generating capacity required to be divested by the FERC). The
timing of divestiture of the generation capacity located in ERCOT and SPP is
conditioned upon there being no violation of the criteria for
pooling-of-interests accounting treatment of the Merger. If it is determined
that the FERC-ordered-portion of the ERCOT divestiture can proceed immediately
after the Merger closes without jeopardizing pooling-of-interests accounting
treatment for the Merger, sale of the plants would begin no later than 60 days
after the Merger closes.(2) The divestiture of generation capacity located in
SPP is also conditioned upon the plant no longer being required to meet PSO's
native load demand requirements following electric industry restructuring in
Oklahoma, but must occur no later than July 1, 2002.
In addition to the generating facilities described above, CSW has
ownership interests in nonutility electrical generating facilities. Information
concerning U.S. facilities is listed below.
Operating Facilities - United States
<TABLE>
<CAPTION>
Total Ownership
Facility Company Location Capacity Interest
<S> <C> <C> <C> <C>
Brush II CSW Energy Colorado 68 47%
Ft. Lupton CSW Energy Colorado 272 50%
Mulberry CSW Energy Florida 120 50%
Orange Cogen CSW Energy Florida 103 50%
Newgulf CSW Energy Texas 85 100%
Sweeny (1) CSW Energy Texas 330 50%
Frontera (2) CSW Energy Texas 330 100%
-----
Total 1,308
</TABLE>
(1) During 2000, additional development at the Sweeny facility is
expected to add approximately 150 MW to current capacity.
(2) Frontera commenced operations during the summer of 1999 with a
capacity of 330 MW. During the fourth quarter of 1999, construction
continued to bring the plant to
- --------
(2) In a separate filing, the Applicants will seek such further
authority as may be required for the divestiture of generation assets.
- 28 -
<PAGE> 32
combined cycle operation in the first quarter of 2000 at which time
the facility is expected to have a capacity of 500 MW.
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, 1999:
<TABLE>
<CAPTION>
TOTAL CIRCUIT MILES OF TOTAL CIRCUIT MILES OF
TRANSMISSION LINES DISTRIBUTION LINES
<S> <C> <C>
CPL 5,024 28,846
PSO 3,596 14,380
SWEPCO 3,398 14,267
WTU 4,570 9,318
Total 16,588 66,811
</TABLE>
CSW's U.S. electric utility subsidiaries' electric transmission and
distribution facilities are mostly located over or under highways, streets and
other public places or property owned by others, for which permits, grants,
easements or licenses have been obtained.
CPL and WTU are members of ERCOT, which operates in Texas. Other ERCOT
members include Texas Utilities Electric Company, Houston Lighting & Power
Company, Texas Municipal Power Agency, Lower Colorado River Authority, the
municipal systems of San Antonio, Austin and Brownsville, the South Texas and
Medina Electric Cooperatives, and several other interconnected systems and
cooperatives. PSO and SWEPCO are members of the SPP, which includes 12
investor-owned utilities, 7 municipalities, 7 cooperatives, 3 state and 1
federal agency as well as IPPs and power marketers operating in the states of
Arkansas, Kansas, Louisiana, Oklahoma and parts of Mississippi, Missouri, New
Mexico and Texas. ERCOT members interchange power and energy with one another on
a firm, economy and emergency basis, as do the members of the SPP.
The highest all-time maximum coincident system demand through 1999 was
14,006 MW on August 12, 1999. The 1999 net dependable capacity to serve the
system load was 15,525
- 29 -
<PAGE> 33
MW. Power generation at the time of the peak was 13,220 MW and net purchases at
the time of the peak were 846 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 OATT filed with the FERC and the
rules of the FERC relating to such tariff. Under the TCA, CSW's U.S. electric
utility subsidiaries have delegated to CSWS the responsibility of monitoring the
reliability of their transmission systems and administering the OATT on their
behalf. The TCA also provides for the allocation among CSW's U.S. electric
utility operating subsidiaries of revenues collected for transmission and
ancillary services provided under the OATT. The TCA has been accepted for filing
by the FERC effective as of January 1, 1997, and is the subject of proceedings
commenced to consider the reasonableness of its terms and conditions.
(iv) Fuel Supply
The following table shows the sources of power used by the CSW System:
<TABLE>
<CAPTION>
1999 1998
---- ----
<S> <C> <C>
Natural Gas 39% 38%
Coal 38% 39%
Lignite 7% 8%
Nuclear 6% 7%
Other 0 0
Purchased Power 9% 8%
-- --
Total 100% 100%
</TABLE>
CSW's average cost of fuel per million BTUs for the calendar years
ended December 31, 1998 and 1999 was 167 cents and 178 cents, respectively.
3. Electric Coordination
The Combined System will be physically interconnected by means of the
Contract Path, and economically operated as a single interconnected and
coordinated system pursuant to a series of contractual arrangements. Upon
implementation of the System Integration Agreement and the System Transmission
Integration Agreement and through the use of Central Dispatch Planning and
Central Economic Dispatch, the Combined System will have a central dispatch
system capable of scheduling and jointly dispatching the generating resources of
the Combined System on an economical, real-time basis. The Combined System will
be physically interconnected through the 250 MW Contract Path. Each aspect of
the electric coordination and interconnection of the Combined System is
discussed below:
a. System Integration Agreement, System Transmission Integration
Agreement, AEP Interconnection Agreement, CSW Operating
Agreement.
- 30 -
<PAGE> 34
The System Integration Agreement provides for the coordination and
joint dispatch of generation within the Combined System. Applicants define the
term "joint economic dispatch" or "central economic dispatch" to mean the
ability of the merging companies to dispatch their generation units on a least
cost basis, taking into account various operating conditions, in order to
achieve certain efficiencies in the operation of the Combined System which could
not be realized on a stand-alone basis. The System Transmission Integration
Agreement provides for the coordination of transmission within the Combined
System. The agreements, each of which will take effect upon consummation of the
Merger, are described in the Testimony of J. Craig Baker and Dennis W. Bethel
before the FERC which are filed with Exhibit D-1.1 and incorporated by
reference. The existing AEP Interconnection Agreement and the existing CSW
Operating Agreement will remain in effect after the Merger and continue to
control the distribution of costs and benefits within each zone. Briefly stated,
the existing agreements will continue to govern the allocation of costs and
benefits as between the operating companies of the east zone, on the one hand,
and those of the west zone, on the other. The agreements, which match intra- and
inter-zonal power transfers with the appropriate operating company, are
necessary to assure the affected state regulators that there will be no cost or
benefit transfers within the AEP system or the CSW system as a result of the
Merger.(3) The agreements and their functions are summarized below.
The System Integration Agreement provides for the integration and
coordination of the AEP operating companies and the CSW operating companies and
the distribution of costs and benefits between the two operating zones. The
purpose of the System Integration Agreement, given the settlements with various
State commissions, is to ensure that the benefits achieved through the joint
dispatch of the two zones on a going-forward basis are shared, in the first
instance, between the two zones and then within the zones, based on the
historical cost and benefit sharing arrangements under the existing AEP and CSW
intrasystem agreements. It is
- ----------
(3) See, e.g., page 34 of the FERC order conditionally approving
the Merger, a copy of which is filed as Exhibit D-1.9 (agreeing with Applicants
that the FERC's formula for split-savings rates are not dispositive where the
reasonableness of the inter-affiliate cost allocation method is at issue in
energy transactions resulting from joint dispatch); page 5 of Oklahoma
Commission Order No. U-23327 conditionally approving the Merger, a copy of which
is filed as Exhibit D-3.2 (stating Commission's concern "that the proposed
system agreements not result in cost shifting from AEP to SWEPCO or be otherwise
unjust or unreasonable"); page 21 of Texas Commission Order finding the Merger
to be consistent with the public interest, a copy of which is filed as Exhibit
D-5.4 (stating Commission's conclusion that "Applicants have provided sufficient
guarantees that will prevent unjustified cost shifting . . ."); Page 5 of
Michigan Commission Order Approving Settlement Agreement, a copy of which is
filed as Exhibit D-10.1 (citing AEP's commitment to file any allocation of the
cost of new, modified or upgraded generation or transmission facilities whose
costs will be subject to the System Integration Agreement or System Transmission
Integration System with the FERC and to notify the Michigan Commission of the
filing); page 9 of Indiana Commission Order approving the Merger under the terms
of a Stipulation and Settlement Agreement, a copy of which is filed as Exhibit
D-8.1 (citing AEP's commitment as set forth hereinabove with respect to the
Michigan Order). See also AEP state settlement agreements filed with or referred
to in state orders conditionally approving the Merger, which contain hold
harmless provisions for native load customers in circumstances when one or more
AEP operating companies in one AEP zone are supplying power to the other AEP
zone, and, as a result, the supplying zone needs to purchase replacement power
to serve its native load.
- 31 -
<PAGE> 35
designed to function as an umbrella agreement in addition to the existing AEP
Interconnection Agreement and the existing CSW Operating Agreement, which will
continue to control the distribution of costs and benefits within each zone.
Under the System Integration Agreement, the east zone and the west zone
are each required to have enough generating capacity to meet their respective
firm load obligations. When one zone has surplus capacity available for sale and
the other zone has insufficient capacity, the surplus zone will make its surplus
capacity available. If neither zone has surplus capacity after meeting its firm
load obligations or if third party capacity is cheaper than that from the
surplus zone, then capacity will be purchased from third parties for the zone(s)
with insufficient capacity. Economic energy will be transferred from one zone to
another in order to minimize the total production cost of the Combined System.
The AEP and CSW areas will be centrally dispatched on a least-cost basis for the
Combined System. The designated agent, AEPSC, will perform these functions.
The System Integration Agreement contains four service schedules
governing: (1) the allocation of capacity costs and purchased power costs; (2)
pricing for system capacity exchanges; (3) pricing for system energy exchanges;
and (4) the allocation of "Trading and Marketing Realizations," which are the
net gains or losses from the Combined System's off-system transactions. The
System Integration Agreement applies to the generating resources and loads
served by the Combined System, but not to the transmission facilities owned or
operated by the Combined System.
The System Transmission Integration Agreement contains two service
schedules governing: (1) the allocation of transmission costs and revenues
between the two areas; and (2) the allocation of system control and dispatch
costs associated with the integration of the two areas, the cost of the
transmission capacity reserved on other systems to link the two areas, and any
revenues from the resale of those capacity rights. AEPSC will coordinate the
planning, operation and maintenance of transmission facilities and capacity of
the Combined System. The System Transmission Integration Agreement will also
provide a mechanism for coordinating the existing AEP Transmission Agreement and
CSW Coordination Agreement. Specifically, the AEP and CSW transmission
agreements will remain in place in their current form to avoid cost shifts among
the operating companies and between the zones and to reflect the existing
ownership of transmission. The existing agreements will continue to govern the
allocation of costs and benefits associated with transmission assets, as between
the operating companies of the east zone, on the one hand, and those of the west
zone, on the other.
The Combined System will be subject to regulation by the FERC with
respect to transmission and the Combined System intends to operate in full
compliance with all applicable FERC rules and orders regarding, among other
things, tariffs, billing and revenue allocation, immediately upon the
consummation of the Merger. In this regard, on March 15, 2000, the FERC issued
an Opinion that affirmed a FERC ALJ's finding that the rates, terms, and
conditions of service contained in the above agreements, as modified by the
Stipulation between Applicants and FERC Staff, are just, reasonable and not
otherwise unlawful. The FERC Opinion is filed as Exhibit D-1.9 and incorporated
by reference.
- 32 -
<PAGE> 36
The existing AEP Interconnection Agreement and existing CSW Operating
Agreement will provide for the joint dispatch of the respective zones. As noted
above, these agreements will remain in place in their current form to avoid cost
shifts among the operating companies and zones and to reflect the existing
ownership of generation assets.
With respect to AEP, the operating utilities of the AEP system have
historically planned, constructed, and operated their generation and
transmission facilities on a combined system "pool" basis. Pool costs are shared
pursuant to the AEP Interconnection Agreement, which has been amended from time
to time by the AEP operating companies. The AEP Interconnection Agreement
expressly provides, among other things, for the sharing of the costs of
generation facilities used in the integrated operation of the AEP system.
The AEP Interconnection Agreement does not, however, contain any
express provision for the sharing of the costs of transmission facilities used
in the integrated operation of the AEP system. That is the function of the
Transmission Equalization Agreement ("TEA"). The TEA provides for the sharing of
the costs of the system's Extra High Voltage transmission facilities among the
AEP operating companies.
With respect to CSW, the CSW Operating Agreement provides for the
coordination of construction and operation of jointly-owned facilities; unit
sales to assist companies to meet capacity reserve levels; emergency energy;
economy energy; off-system sales and purchases; and central load dispatching.
Schedule A of the CSW Operating Agreement provides for planning and construction
of joint units to be owned by the CSW operating companies in percentages
allocated by the CEO "to achieve a Prorated Reserve Level" for all participating
companies. Schedule B lists the ownership by individual CSW operating companies
of particular generating units. Basically, the agreement preserves the planning
and investment in generation by the four operating companies when they were
independently operated and, at the same time, integrates and coordinates the
planning and investment of the CSW integrated system.
b. Central Dispatch Planning and Central Economic Dispatch.
AEPSC will coordinate the planning, operation and maintenance of
generating capacity resources and jointly dispatch electricity throughout the
Combined System. The coordination of generation is accomplished through two
computer software programs: Central Dispatch Planning and Central Economic
Dispatch. Central Dispatch Planning forecasts (usually on a day-ahead basis,
although sometimes several days ahead) the generation needs of the Combined
System and determines the least-cost allocation of generation resources
available within the Combined System necessary to meet the forecasted
obligations. The joint dispatch is based on anticipated fuel costs, load levels,
wholesale power market conditions, planned unit maintenance (which units are out
of service or operating below normal operating limits), and prevailing
transmission capabilities (including capacity reserved by third parties). During
the morning of normal working days (Monday through Friday), Central Dispatch
Planning will estimate 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.
- 33 -
<PAGE> 37
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 capabilities, issues new dispatch control signals to each
generating unit within the Combined System.
Following the Merger, there will be two data relay centers; one in
Dallas and the other in Columbus. Central Economic Dispatch will run on an EMS.
The EMS will determine Economic Base Points for every unit in the Combined
System and provide the Economic Base Points to the data relay centers in Dallas
and Columbus. The data relay centers will then use these Economic Base Points
for frequency control requirements of the respective control areas to send the
proper control signals to the generating units of the Combined System. The data
relay centers will be staffed with personnel 24 hours a day, 365 days a year.
Merger transition teams have designed the organizational structure and job
responsibilities for the data relay centers. See Exhibit B-3.4 for a copy of
AEPSC (Post-Merger) Organization Chart.
Central Dispatch Planning and Central Economic Dispatch will be ready
to serve the Combined System immediately after consummation of the Merger. Each
will utilize the existing electronic communication infrastructures currently in
place in each of the AEP System and the CSW System. The existing electronic
communication infrastructures will feed data to, and receive instructions from,
Central Dispatch Planning and Central Economic Dispatch via a high speed data
link. In this way, the Combined Company will jointly dispatch the Combined
System upon consummation of the Merger.
c. 250 MW Contract Path
The Combined Company will transmit power from east to west over the 250
MW Contract Path. The 250 MW Contract Path's term is from June 1, 1999 to May
31, 2003, which may be renewed through the Ameren OATT. In the event AEP
determines for any reason not to renew the 250 MW Contract Path, AEP will file a
post-effective amendment no later than May 31, 2003 concerning the measures it
will take to ensure that the interconnection requirements of Section 2(a)(29) of
the Act are satisfied. 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(4). 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
- ------------------------------
(4) PSO owns the Neosho, Kansas to Oneta, Oklahoma segment of the
MOKANOK line but has the right to use the capacity in the entire line, including
capacity in the segments owned by the other three owners of the line. One-half
of PSO's capacity allocation is unrestricted and may be used for any purpose.
PSO currently uses one-half of its capacity allocation as emergency transfer
capacity. PSO has used its unrestricted capacity in the past to import power
into the PSO service area, to buy and sell capacity and/or energy on an economic
basis, and to purchase capacity and/or energy from other parties when supplies
are available at a cost that is lower than PSO's cost of self-generation or
purchases from affiliates. After consummation of the Merger, PSO will use its
unrestricted capacity allocation to engage in capacity and/or energy
transactions with the AEP system.
- 34 -
<PAGE> 38
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 rights to use
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 exceed this limit. See Dr. William Hieronymus' testimony filed as an
exhibit to Exhibit D-1.2 and incorporated herein by reference.
d. Additional Power Transfers
The Applicants expect that from time to time there will be opportunity
to transfer energy economically in the Combined Company from west to east. In
these circumstances, Applicants will make use of their rights to nominate
secondary points of receipt and delivery under their transmission service
agreements with WR and Ameren. PSO also 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.
As part of the FERC Stipulation, Applicants agreed to waive the
Combined Company's priority with respect to its use of the HVDC ties for
unplanned (i.e., non-firm) transactions in ERCOT and non-firm transactions in
the SPP. See Exhibit D-1.2, Supplemental Testimony of Stephen Jones at 15-17.
This waiver of priority would not apply to planned (i.e., firm) transactions
that are submitted to ERCOT or other transfers of firm capacity between the
Applicants' SPP and ERCOT control areas, including the use of the North HVDC tie
to export the output of the Oklaunion generation station to PSO and to Oklahoma
Municipal Power Authority, both located in the SPP.(5) Thus, the Applicants
would continue to use the HVDC ties
- ------------------------------
(5) CSW's firm transmission capacity has always been adequate to
integrate its operations, and there has never been a need to assert a priority
for unplanned transactions over the HVDC ties. As a result, Applicants do not
expect their waiver of priority for non-firm use of the HVDC ties to affect the
integration of their system in any manner.
- 35 -
<PAGE> 39
to integrate CSW's Texas assets with its non-Texas assets in the same manner
that previously has been approved by the Commission.
e. Future Participation in an RTO
On June 3, 1999, AEP and four other utilities filed the Alliance RTO
Application, which was conditionally approved by FERC on December 20, 1999, a
copy of which is filed as Exhibit D-1.8 and incorporated by reference. CSW is
participating in the ERCOT independent regional transmission plan for the
portion of its system that is within ERCOT and is participating in discussions
with other interested parties about the formation of an RTO that would include
its utility systems located in the SPP.(6) Participation in these RTOs will
enhance system reliability after the Merger as described below.
The Applicants' goal ultimately is to further enhance the reliability
of the Combined System through participation in a regional RTO. RTOs provide
strengthened assurances to the marketplace that transmission service will be
available to all eligible customers on a non-discriminatory basis. In addition,
RTOs can enhance regional reliability and, if properly structured and
configured, improve economic efficiencies and provide access to a broad range of
buyers and sellers across a large geographic region.
Until such time as the Combined Company transfers certain control area
functions related principally to reliability and access to one or more RTOs, all
facets of the centralized coordination of the transmission facilities of the
Combined Company's system will be accomplished through the System Transmission
Integration Agreement. At such time as AEP transfers to the RTO certain control
area operations relating principally to system reliability and access, the
remaining functions of the Combined Company's transmission system will continue
to be coordinated through the System Integration Transmission Agreement.
Participation in RTOs can enhance the reliability of the Combined
Company's system in several ways. In the Notice of Proposed Rulemaking regarding
RTOs,(7) FERC found that an RTO would improve efficiencies in the management of
the transmission grid (RTO NOPR at page 33,716); would improve grid reliability
(Id.); would improve market performance (RTO NOPR at page 33,717); and would
facilitate lighter governmental regulation (Id.). It is FERC's view that all
utilities should participate in a FERC-approved RTO.
- ---------
(6) In the order of the Oklahoma Commission approving the Merger,
AEP is required to file with the FERC, not later than six months before retail
competition commences in the State, or December 31, 2001, an application to,
transfer the operational control of bulk transmission facilities owned,
controlled and/or operated by AEP that are currently located in the SPP to a
FERC-approved RTO that is directly interconnected with the AEP system. See
Exhibit 4.2, at 17.
(7) Notice of Proposed Rulemaking, Regional Transmission
Organizations, Docket No. RM99-2-000, 87 FERC P. 61,173 (May 13, 1999) ("RTO
NOPR").
- 36 -
<PAGE> 40
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.
- 37 -
<PAGE> 41
The Merger Agreement provides for a business combination of AEP and CSW
in which Merger Sub will be merged with and into CSW. CSW will be the surviving
corporation and will become a wholly-owned subsidiary of AEP. Upon the
consummation of the Merger, each issued and outstanding share of CSW Common
Stock (other than the Excluded Shares) will be exchangeable for 0.60 shares of
AEP Common Stock. Based on the price of AEP Common Stock on December 19, 1997,
the transaction would be valued at $6.6 billion. Each issued and outstanding
share of AEP Common Stock will be unchanged as a result of the Merger.
The former holders of CSW Common Stock will own approximately 40% of
the issued and outstanding AEP Common Stock after the Merger. The Merger is
subject to customary closing conditions, including the receipt of all necessary
governmental approvals, including the approval of the Commission. The Merger is
designed to qualify as a tax-free reorganization under Section 368(a) of the
Internal Revenue Code of 1986, as amended, and will be treated as a
"pooling-of-interests" for accounting purposes.
On December 31, 1999, Applicants executed Amendment No. 1 to the Merger
Agreement which provides that either AEP or CSW may terminate the Merger
Agreement after June 30, 2000 if the Merger has not been consummated by that
date.
3. Reasons for the Merger
The Merger offers significant opportunities to create additional value
for shareholders, customers and employees of the Combined Company. The benefits
of the Merger include the following:
- - 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
- 38 -
<PAGE> 42
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
<TABLE>
<CAPTION>
Thousands
<S> <C>
Filing fee for Form S-4 $ 1,759
Accountants' fees 1,983
Legal fees and expenses 21,641
Shareholder communication and
proxy solicitation expenses 3,168
NYSE listing fee 420
Exchanging, printing and
engraving stock certificates
expenses 450
Investment bankers' fees and
expenses 30,800
Consulting fees 7,778
Miscellaneous 4,714
Total $72,713
</TABLE>
The total fees, commissions and expenses expected to be incurred for
transaction and regulatory processing costs are estimated to be approximately
$72.7 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
- 39 -
<PAGE> 43
UNDER THE 1935 ACT
<TABLE>
<S> <C>
6, 7, 12, 32 and 33 Issuance of AEP Common Stock; amendment to
and rules existing AEP's financing authority to allow the
thereunder Combined Company 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
rules thereunder Merger 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 On or before December 31, 2000, the merger of
thereunder CSWS into AEPSC with AEPSC as the surviving
service company; approval of service
agreement and method for allocating costs
under the service agreement.
</TABLE>
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;
- 40 -
<PAGE> 44
- - 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 Girardeau v. SEC, 521 F.2d
324 (D.C. Cir. 1975) (citation omitted) [hereinafter "Union Electric"]. The
Commission is not disposed to "apply concepts such as res judicata or stare
decisis to the essentially regulatory and policy determinations called for in a
Holding Company Act case . . . ." AEP, supra. In considering whether to approve
an acquisition, the Commission "must make that determination in light of
contemporary circumstances . . . and [its] present view of the Act's
requirements." Southern, supra (citations omitted).
The Merger complies with the 1935 Act. In light of contemporary
circumstances, the Merger does not result in any of the concerns the 1935 Act
was intended to address. In this regard, the Merger will benefit the public
interest and the interests of investors and consumers. Adequate safeguards,
through both state and federal regulation, ensure that the public interest and
the interests of investors and consumers continue to be protected. Approval of
the Merger is consistent with previous merger transactions approved by the
Commission under the 1935 Act. Each subsection of Section 10 of the 1935 Act is
addressed below, as well as the public policies underlying the 1935 Act, as they
relate to the Merger.
- 41 -
<PAGE> 45
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
- 42 -
<PAGE> 46
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) on remand, Entergy Corp., HCAR No. 26410 (Nov. 17,
1995) (citations omitted) [hereinafter "Entergy"]. These factors are discussed
below.
(i) Size
As the terms of Section 10(b)(1) dictate and as the Commission has
recognized, Section 10(b)(1) does not "impose any precise limits on holding
company growth." AEP, supra. Congress condemned the "growth and extension of
holding companies [that] bears no relation to economy of management and
operation or the integration and coordination of related operating properties."
Section 1(b)(4) of the 1935 Act. The Commission has rejected a mechanical size
analysis under Section 10(b)(1) in favor of assessing the size of the resulting
system as it relates to the efficiencies and economies that can be achieved
through the integration and coordination of the new system's utility operations.
Entergy, supra (rejecting "conclusory assertions that the combined systems would
be too large to satisfy [Section 10(b)(1)]" and finding that merger created a
"large system, but not one that exceeds the economies of scale of current
electrical generation and transmission technology.") Section 10(b)(1) allows the
Commission to "exercise its best judgment as to the maximum size of a holding
company in a particular area, considering the state of the art and the area or
region affected." AEP, supra. Other recent transactions confirm that the
Commission evaluates the resulting size of a merging entity in terms of the
overall effects of the merger. For example, in Centerior Energy Corp., HCAR No.
24073 (Apr. 29, 1986) [hereinafter "Centerior"], the Commission stated that a
"determination of whether to prohibit enlargement of a system by acquisition is
to be made on the basis of all the circumstances, not on the basis of size
alone." See also, Northeast I, supra (applying standard articulated in
Centerior, supra, to find acquisition satisfied Section 10(b)(1)). Likewise, the
Division recommended in its 1995 Report that the Commission approach its
analysis of merger and acquisition transactions in a flexible manner with an
emphasis on whether the transaction creates an entity subject to effective
regulation and results in economies and efficiencies as opposed to focusing on
rigid, mechanical tests. 1995 Report at 66-70.
In short, size alone is not suspect. Rather, as the 1935 Act provides,
the concern is an enlargement of the system that is "of a kind or to an extent
detrimental to the public interest or the interest of investors or consumers"
caused "by the growth and extension of holding companies [that] bears no
relation to economy of management and operation or the integration and
coordination of related operating properties." Sections 10(b)(1) and 1(b)(4) of
the 1935 Act.
- 43 -
<PAGE> 47
For purposes of comparison, the table below provides certain operating
information for a selected group of public utility systems, which was derived
from a study prepared by Navigant Consulting, Inc. Navigant obtained its
information for the study from Form 10-K filings and FERC Form 1 filings. Each
public utility system referenced in the chart below, with the exception of CSW,
ranks at or near the top of at least one of the categories presented. In
addition, several pending mergers of utility systems are also referenced in the
chart below. Among the utilities presented, AEP currently ranges from the fifth
to the eighth largest public utility system in the United States depending on
the criterion of measurement. Giving effect to the Merger as of December 31,
1998, on a pro forma basis, the Combined Company would have ranged from the
largest (two categories) to the fourth largest public utility system in the
United States, again depending on the criterion of measurement.
(As of December 31, 1998)
<TABLE>
<CAPTION>
Electric Operating U.S. Electric
Revenues Total Assets Customers
System ($Millions) ($Millions) (Millions)
- ------ ----------- ----------- ----------
<S> <C> <C> <C>
Texas Utilities 6,556 39,514 2.5
Duke 4,586 26,806 2.0
Southern 9,763 36,192 3.8
Entergy 6,136 22,848 2.5
PG&E 8,924 33,234 4.5
AEP 7,133 19,483 3.0
CSW 3,488 13,744 1.7
Combined
Company 10,044 33,227 4.7
Proposed
PECO/Unicom
Combined (a) 11,962 37,755 4.9
Con Ed/Northeast Combined (b) 9,932 24,769 5.0
NSP/NCE 5,339 15,068 3.1
Combined (c)
</TABLE>
(a) Recently announced merger between Unicom Corp. and PECO Energy Corp.
which would form a new registered holding company (the merged company
hereinafter referred to as "PECO/Unicom").
(b) Recently announced merger between Consolidated Edison Company and
Northeast Utilities Company (the merged company hereinafter referred to as
"ConEd/Northeast").
(c) Recently announced merger between Northern States Power Company and New
Century Energies Company (the merged company hereinafter referred to as
"NSP/NCE").
Sources: Navigant Consulting, Inc. (See Exhibits L-1 through L-3).
- 44 -
<PAGE> 48
The data show that, as of December 31, 1998, PECO/Unicom would have
been larger than the Combined Company in terms of electric operating revenues;
Southern, PECO/Unicom, PG&E and Texas Utilities would have been larger than the
Combined Company in terms of total assets; and PECO/Unicom and ConEd/Northeast
would have been larger than the Combined Company as measured by total U.S.
electric customers. In addition, the Combined Company's percentage in all three
categories in relation to the investor owned utility group as a whole is
approximately 5%, and the Combined Company is just slightly ahead of PG&E in
terms of the number of U.S. electric customers and just slightly ahead of the
Southern Company in terms of electric operating revenues. Thus, the data show
that the Combined Company will be comparable in size to other large public
utility systems and soon will be surpassed by the proposed PECO/Unicom and
ConEd/Northeast combinations in certain categories.
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").(8) See Entergy, supra (Commission adopted the applicants'
definition of the relevant region for purposes of measuring size to include
applicants and those electric utilities directly interconnected with either or
both). As the table below indicates, the size of the Combined Company compared
to the size of the Interconnected Utilities and the Combined Company varies from
11 percent to 15 percent depending on the criterion of measurement. Further, if
data from the Applicants' historical wholesale customers are added to these
Interconnected Utilities data (the sum equaling the
- -----------------------------
(8) 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.
- 45 -
<PAGE> 49
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), then the size of the Combined Company as a percentage
of the destination markets identified by Dr. Hieronymus is even smaller.
<TABLE>
<CAPTION>
Net Electric Utility Electric Number of Total Net
Plant Revenues Electric Customers Total Sales Generation
($Thousands) ($Thousands) 12 Mo. Avg. (MwH) (MwH)
<S> <C> <C> <C> <C> <C>
Combined Company 18,589,138 9,833,518 4,733,734 197,345,794 192,992,107
Region (b) 172,487,197 84,261,562 33,525,779(a) 1,558,199,149 1,332,170,731
% of total
represented by
Combined Company 11% 12% 14% 13% 15%
</TABLE>
(a) The customers of the Tennessee Valley Authority and Southwestern Power
Administration are not included in this figure, since these federal
power marketing agencies typically do not have retail customers. The
Tennessee Valley Authority has 160 distributor customers and
Southwestern Power Administration has 92 customers comprised of
municipalities, federal agencies and cooperatives.
(b) The Region includes the Interconnected Utilities and the Combined
Company
Sources: POWERdat database (Resource Data International, Inc.); Form
10-K and Form 10-Q Filings; 10 Year Statistical Reports; and
Annual Reports.
Specifically, as the table above indicates, at December 31, 1998, the
Combined Company would have represented no more than the following percentages
of the utility industry in the region, in terms of the above criteria: net
electric plant (11%); electric revenues (12%); number of electric customers
(14%); MwH sales (13%); and total net generation (15%). As such, the size of the
Combined Company relative to the relevant region is significantly below the 40%
threshold previously cited by the Commission. In fact, two of these percentages
would be even less if the data reflected Applicants' agreement to divest 1604 MW
of generation capacity in ERCOT and, as required by FERC, to divest 300 MW of
generation capacity in SPP.
By definition, any merger creates an entity larger than each of the
constituent parts. However, the size of the Combined Company will not exceed the
economies of scale of current electrical generation and transmission technology
and, therefore, does not exceed the maximum size of a holding company
considering the "state of the art." Technological changes have resulted in power
being transmitted over greater distances with less line loss, single integrated
computer networks that more efficiently dispatch generation sources and control
constricted transmission areas, and generation technologies that have reduced
the cost of power and increased the flexibility of power plant siting. Moreover,
changes in the regulatory and legal framework have resulted in an increase in
non-utility generators, non-utility marketers and
- 46 -
<PAGE> 50
brokers. Together, these technological, legal and regulatory changes have
resulted in increased competition within the industry.(9) 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.
(ii) Antitrust Considerations
The Commission's analysis under Section 10(b)(1) also includes a
consideration of federal antitrust policies. In this regard, the Commission has
found, and the courts have agreed, that it is appropriate for the SEC to look to
the FERC's expertise in operating issues, in determining that the standards of
Section 10(b)(1) are met. In this regard, the Court of Appeals for the D.C.
Circuit has found:
[W]hen the SEC and another regulatory agency both have jurisdiction
over a particular transaction, the SEC may "watchfully defer[]" to the
proceedings held before - and the result reached by - that other
agency.
Madison Gas & Elec. Co. v. SEC, 168 F.3d 1337, 1341-42 (D.C. 1999), citing City
of Holyoke Gas & Elec. Dep't v. SEC, 972 F.2d 358 (D.C. Cir. 1992).
In this matter, potential competitive concerns have been addressed by
both the DOJ and the FERC. Pursuant to the HSR Act, AEP and CSW are required to
file with the Antitrust Division Premerger Notification and Report Forms. See 16
C.F.R. Parts 801 through 803. The purpose of the HSR Act reporting requirements
is to "facilitate evaluation of the antitrust implications of the proposed
transaction and, where the competitive consequences appear substantial, to
permit the Antitrust Division to challenge the legality of the transaction."(10)
The HSR Act prohibits consummation of the Merger until the statutory waiting
period has expired or been terminated. On July 26, 1999, Applicants filed with
the Antitrust Division under the HSR Act. On August 26, 1999, AEP and CSW
received a request for additional information from the Antitrust Division. AEP
and CSW filed the additional information with the Antitrust Division in November
1999. On February 2, 2000, the Antitrust Division notified Applicants that it
had completed its review of the Merger and that no further action is warranted.
This completes the review process by the Antitrust Division.
On March 15, 2000, the FERC issued an order conditionally approving the
Merger. In order to find that the Merger would not adversely affect competition
as a result of combining the generation and transmission of AEP and CSW, the
FERC imposed certain conditions. The FERC presented the companies with an
alternative: either (i) accept the condition that they transfer operational
control of their transmission facilities to a fully-functioning, FERC-approved
RTO by December 15, 2001 and adopt certain mitigation measures in the interim,
or (ii) join a
- -----------------
(9) The "state of the art" is discussed in depth in Item 3.B.1.a
below.
(10) Premerger Practice Notification Manual at xi (American Bar
Association 1991).
- 47 -
<PAGE> 51
fully-functioning, FERC-approved RTO before closing their transaction. On March
27, AEP and CSW notified the FERC that they elected the first option.
Thereafter, on March 31, 2000, AEP and CSW made compliance filings at
the FERC describing: (i) their plans to implement the interim transmission
mitigation measures (independent calculation and posting of available
transmission capacity ("ATC") and independent market monitoring) and (ii) the
terms and conditions of the interim energy sales. AEPSC has engaged the
Southwest Power Pool ("SPP") to perform the independent ATC calculation and
postings. In addition, the SPP will perform the OASIS function of disposing of
transmission service requests for customers (including marketers affiliated with
AEP) seeking service over the AEP East zone. For the market monitoring
requirement, AEPSC has engaged Dr. Douglas R. Bohi (Charles River Associates),
who will be responsible for reviewing transmission constraint data, the
effectiveness of redispatch to alleviate such constraints, and the impacts of
redispatch on the volume and price of energy before and after redispatch. AEP
and CSW have also submitted, in a separate FERC filing, the terms and conditions
under which they would conduct the interim energy sales.(11) Accordingly, the
Merger will not tend toward an impermissible concentration of control of public
utility companies.
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
- -----------------
(11) The FERC Order required the Applicants to make the compliance
filing described above at least 60 days before consummating the Merger. The
Applicants have asked the FERC to reduce this period to 44 days to permit them
to close the transaction on May 15, 2000.
- 48 -
<PAGE> 52
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;
- 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.
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<PAGE> 53
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
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<PAGE> 54
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
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<PAGE> 55
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) Shareholder Approval
In addition, the holders of AEP Common Stock and the holders of CSW
Common Stock overwhelmingly approved the shareholder actions necessary to effect
the Merger. At the Annual Meeting of Shareholders of AEP held on May 27, 1998,
holders of approximately (i) 71% of all outstanding AEP Common Stock approved an
amendment to the Restated Certificate of Incorporation of AEP increasing the
number of authorized shares of AEP Common Stock, and (ii) 72% of all outstanding
AEP Common Stock approved the issuance of the AEP Common Stock, each necessary
to effect the Merger. Holders of approximately 82% of all outstanding CSW Common
Stock approved the Merger at the Annual Meeting of Stockholders of CSW held on
May 28, 1998.
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<PAGE> 56
(iv) Merger Agreement
Finally, the Merger Agreement contains a number of closing conditions
that help ensure the continued reasonableness of the consideration. Under
Section 8.1(g), it is a condition precedent to closing, applicable to both AEP
and CSW, that "there shall not have occurred and remain in effect a Divestiture
Event with respect to [either company]."(12) Pursuant to Sections 8.2 and 8.3,
AEP and CSW are each required to affirm that all representations made with
respect to the Merger Agreement are true and correct as of the date of closing,
including the representation that no Material Adverse Effect(13) shall have
occurred and that there shall exist no fact or circumstance which may reasonably
be expected to give rise to a Material Adverse Effect. Other closing conditions
ensure that the Merger will not be consummated in the event of onerous or
burdensome regulatory orders or conditions.
b. Reasonableness of Fees
The various categories of fees, commissions and expenses in connection
with the transaction and regulatory processing costs for the Merger are set
forth in Item 2 to this Application-Declaration. Applicants expect to incur
total transaction and regulatory related costs of approximately $72.7 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 $72.7 million to be incurred by Applicants represent approximately 1.1%
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
- -----------------
(12) "Divestiture Event" means "any Law, Regulation or Order adopted or
issued by a Governmental Authority that requires the divestiture of a
substantial portion of the generating assets of . . ." CSW or AEP.
(13) "Material Adverse Effect" means "any change or effect that is
material and adverse to the business, condition (financial or otherwise) or
results of operations or prospects of a specified Person and its subsidiaries,
if any, taken as a whole; provided, however, that, as used in this definition
the word material shall have the meaning accorded thereto in Section 11 of the
Securities Act."
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<PAGE> 57
(Northeast I; Northeast II); $47.12 million in connection with the
reorganization of Cincinnati Gas and Electric and PSI Resources as subsidiaries
of CINergy (CINergy Corp., HCAR No. 26146 (Oct. 21, 1994) [hereinafter
"CINergy"]) and $38 million in fees, commissions and expenses in connection with
Entergy's acquisition of Gulf States Utilities Company, representing
approximately 1.7% of the value of the consideration paid to Gulf States'
shareholders (Entergy, supra).
The investment banking fees of approximately $31 million to be incurred
by Applicants represent approximately 0.47% of the value of consideration to be
paid by AEP, based on the price of AEP Common Stock on December 19, 1997. These
fees incurred by Applicants resulted from a marketplace in which investment
banking firms actively compete with each other to act as financial advisers to
merger participants. The Commission has previously approved financial advisory
fees of approximately $10.6 million, representing approximately 0.46% of the
value of the assets to be acquired (Northeast I, supra and Northeast II, supra),
financial advisory fees representing approximately 0.96% of the aggregate value
of the acquisition, (Southern Co., HCAR No. 24579 (Feb. 12, 1988), modified on
other grounds, HCAR No. 24579A (February 26, 1988), and Amendment No. 9 to
Southern Form U-1 (April 13, 1988)), and financial advisory fees of $8.3
million, representing approximately 0.36% of the value of the consideration paid
to Gulf States' shareholders (Entergy, supra and Amendment No. 24 to Entergy
Form U-1 (Nov. 18, 1993)).
For all of the above reasons, the consideration and fees to be paid are
fair and reasonable in compliance with Section 10(b)(2).
3. Section 10(b)(3)
Section 10(b)(3) of the 1935 Act requires the Commission to approve a
proposed acquisition unless the acquisition would unduly complicate the capital
structure of the holding company system, or would be detrimental to the public
interest, the interest of investors or consumers or the proper functioning of
such holding company system.
a. Capital Structure
The Commission has found that an acquisition does not unduly complicate
the capital structure of the holding company system where the effect of a
proposed acquisition on the acquirer's capital structure is negligible and the
debt to equity ratio due to the acquisition is well within "the 65/30%
debt/common equity ratio generally prescribed by the Commission." Entergy, supra
(citing Northeast I). The Commission has approved common equity to total
capitalization ratios as low as 27.6%. See Northeast I, supra.
In this regard, the proposed combination of AEP and CSW will not unduly
complicate the capital structure of the Combined System. The only changes to the
capital structure of AEP will be the acquisition by AEP 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,
1999, the respective capital structures of AEP and CSW were as follows:
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<PAGE> 58
<TABLE>
<CAPTION>
AEP CSW
--- ---
(in $ millions) (in $ millions)
<S> <C> <C> <C> <C>
Common Stock Equity $5,006 37.1% $3,683 36.0%
Preferred Stock 164 1.2% 18 0.2%
Long-Term Debt 7,447 55.1% 4,077 39.8%
Trust Preferred Securities -0- -0- 335 3.3%
Short - Term Debt 888 6.6% 2,124 20.7%
Total $13,505 100.0% $10,237 100.0%
</TABLE>
If the Merger had been consummated on December 31, 1999, the pro forma
consolidated capital structure of the Combined Company as of such date
(according to generally accepted accounting principles, assuming that the Merger
is treated as a "pooling-of-interests" under Accounting Principles Board Opinion
No. 16) would have been as follows:
<TABLE>
<CAPTION>
Combined Company Pro Forma
(in $ millions)
<S> <C> <C>
Common Stock Equity $8,689 36.6%
Preferred Stock 182 0.8%
Long-Term Debt 11,524 48.5%
Trust Preferred Securities 335 1.4%
Short - Term Debt 3,012 12.7%
Total $23,742 100.00%
</TABLE>
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 36.6% is
substantially higher than Northeast Utilities' recently approved 27.6% common
equity position and 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
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<PAGE> 59
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
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<PAGE> 60
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.
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<PAGE> 61
See, e.g., Environmental Action, Inc. v. SEC, 895 F.2d 1255, 1263 (9th Cir.
1990) (citing In re Electric Energy Inc., 38 SEC 658, 668 (1958)). As
demonstrated below, the Merger meets each of these standards.
The Commission must interpret the statutory integration standards "to
meet the problems and eliminate the evils enumerated in [the 1935 Act.]" Section
1(c). In so interpreting the integration standards, the Commission must balance
the 1935 Act's various objectives. See, e.g., Union Electric, supra (the
Commission noted that in the past it had "exercise[d] [its] discretion so as to
allow the expeditious consummation of plans that would make for financial
simplification even though they fell far short of full compliance with the Act's
integration standards" because "with respect to the enforcement of this complex
multifaceted and far-reaching statute" it had "found it necessary or appropriate
to subordinate some statutory objectives to others."). The various aspects of
the integration standard cannot be considered independently of one another and
the other objectives of the 1935 Act. See, e.g., Middle West Corp., HCAR No.
4846 (Jan. 24, 1944) (the Commission noted that while it was difficult to reach
the conclusion that the systems constituted a single system given the geographic
spread of the properties, the integration test was met due to the "contemplated
savings resulting from closely coordinated operation and joint planning with
respect to the routing of power and the installation of facilities."); Middle
West Corp., HCAR No. 5606 (Feb. 16, 1945) (the Commission found that the
combined system was not too large "in light of demonstrated disadvantages of
lack of coordination."); Sempra Energy, HCAR No. 26971 (Feb. 1, 1999)
[hereinafter "Sempra"], citing North American Co., 18 SEC 459, 463 (1945)(in
connection with evaluating the integration standard for gas utility systems, the
Commission has "read each standard of section 2(a)(29)(B) in connection with the
other provisions of the section"). Where the acquisition will result in
significant economies and efficiencies to the benefit of the public, investors
and consumers, Commission precedent supports a flexible interpretation of the
integration standards to further the very interests that the 1935 Act was meant
to protect.
The Commission has recognized that the 1935 Act "creates a system of
pervasive and continuing economic regulation that must in some measure at least
be refashioned from time to time to keep pace with changing economic and
regulatory climates." Southern, supra (quoting Union Electric, supra). The
Commission interprets the 1935 Act and its integration standards "in light of []
changed and changing circumstances." Sempra, supra (interpreting the integration
standards of the 1935 Act in light of developments in the gas industry). Accord,
NIPSCO Industries, Inc., HCAR No. 26975 (Feb. 10, 1999) [hereinafter "NIPSCO"].
The Commission has cited with favor U.S. Supreme Court and Circuit Court of
Appeals cases(14) that recognized the need of an agency to "adapt [its] rules
and policies to the demands of changing circumstances"(15) and to "treat
experience not as a jailer but as a teacher."(16)
(14) Rust v. Sullivan, 500 U.S. 173 (1991); American Trucking Assns.,
Inc. v. Atchison, T.&S.F.R. Co., 387 U.S. 397 (1967); Shawmut Assn. v. SEC, 146
F.2d 791 (1st Cir. 1945).
(15) NIPSCO, supra, citing Rust v. Sullivan at 186-187. Accord, Sempra,
supra at n. 23.
(16) NIPSCO, supra, citing Shawmut Assn. v. SEC at 796-97. Accord,
Sempra, supra at n. 23.
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As the definition of an integrated public utility system suggests, and
as the Commission has previously observed, Section 11 is not intended to impose
"rigid concepts" but rather creates a "flexible" standard designed "to
accommodate changes in the electric utility industry." UNITIL Corp., HCAR No.
25524 (April 24, 1992) [hereinafter "Unitil"]; see also Yankee Atomic Elec. Co.,
HCAR No. 13048 (Nov. 25, 1955) [hereinafter "Yankee Atomic"] ("We think it is
clear from the language of Section 2(a)(29)(A), which defines an integrated
public utility system, that Congress did not intend to imposed [sic] rigid
concepts with respect thereto." (citations omitted)). Section 2(a)(29)(A)
expressly directs the Commission to consider the "state of the art" in analyzing
size and to apply "normal conditions" as the standard for determining whether a
system may be economically operated as a single coordinated system. The
Commission is not constrained by its past decisions interpreting the integration
standards based on a different "state of the art." See AEP, supra (noting that
the state of the art -- technological advances in generation and transmission,
unavailable thirty years prior -- served to distinguish a prior case and
justified "large systems spanning several states.")
The concept of what constitutes an integrated public utility system has
evolved in light of the dramatic changes in the law, technology and structure of
the industry since the passage of the 1935 Act over 60 years ago. In recent
years, the "state of the art" has changed enormously. As the Energy Information
Administration of the Department of Energy aptly noted, "The era of competition
in the electric industry is upon us." Energy Information Administration,
Department of Energy, The Changing Structure of the Electric Power Industry: An
Update (last modified May 30, 1997) <http://www.eia.doe.gov/cneaf/electricity/
chg_str/intro.html>.
The initial groundwork for competition was laid by the passage of PURPA
in 1978, which opened wholesale markets to certain non-utility producers. PURPA
created a new class of non-utility generators, QFs, from which utilities were
required to buy power. The passage of the Energy Act in 1992 marked another
significant step towards the deregulation of the electric power industry. The
Energy Act was designed, among other things, to foster competition in the
wholesale market through (a) amendments to the 1935 Act that facilitated and
encouraged the ownership and operation of generating facilities by EWGs (which
may include IPPs as well as affiliates of electric utilities) and (b) amendments
to the FPA, authorizing the FERC under certain conditions to order utilities
that own transmission facilities to provide wholesale transmission services for
other utilities and entities generating electric power. In order to facilitate
the development of non-utility generation, many states, including Texas,
Louisiana and Ohio, developed integrated resource planning requirements that
require utilities to focus on both supply-side and demand-side resources and to
competitively bid their resource procurement requirements to obtain the lowest
cost available. As a result of these initiatives at both the federal and state
levels, the share of nationwide generating capacity from non-utility generators
has more than tripled from 3.6 percent in 1987 to 11.5 percent in 1999. In fact,
since 1990, non-utility generators have contributed half of all new investment
in generating facilities. See Edison Electric Institute, Directory of Electric
Power Producers, 106th ed. (1999).
FERC Order Nos. 888 and 889, issued in April 1996, taken together
provide that public utilities must file OATTs permitting open access to
transmission and must functionally or actually unbundle their transmission
services, by requiring them to use their own transmission
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tariffs in making off-system and third-party sales. Order No. 888 was intended
to facilitate third-party utilization of the transmission grid in order to
develop a more competitive market for wholesale power transactions. Under Order
No. 888, a utility must transmit power for third parties upon their request, on
either a firm or non-firm basis. If the transmitting utility does not have
sufficient capacity to transmit the power on a firm basis, it must either offer
to expand its transmission system to accommodate the request or, if appropriate,
to redispatch generation to relieve constraints and thereby make capacity
available. In the interim, a utility must offer transmission on a non-firm basis
to the requesting entity.
As a result of federal restructuring, the Applicants have experienced
significant changes in their relationships with wholesale customers. The
majority of contracts for supply are no longer based on a bundled requirements
cost of service approach. Instead, they are unbundled, partial supply, and
market-based. The Applicants have experienced significant growth in the usage of
their transmission system for purposes other than servicing its native load. For
example, during the previous two summers the AEP transmission grid provided
service at a level equal to 150% of their native load. As a result of the
federal restructuring, the Applicants now provide delivery service under various
tariffs based on the FERC Pro Forma Tariffs, and have either joined or filed to
join RTOs. The ERCOT ISO controls the SPP/ERCOT facilities and provides service
under CSW specific tariffs. The SPP, which has filed for RTO status, has a
region-wide tariff for all facilities including the non-ERCOT CSW facilities.
The AEP transmission system will be part of the conditionally approved Alliance
RTO and currently provides service under its OATT.
In response to deregulation in the wholesale market for electricity,
most state legislatures and regulatory commissions either have adopted or
currently are considering the adoption of "retail customer choice" provisions.
In general terms, these initiatives require the electric utility to transmit
electric power over its transmission and distribution system to a retail
customer in its service territory. A requirement to transmit directly to retail
customers permits retail electric customers to purchase electric power, at the
election of such customers, either from the electric utility in whose service
area they reside or from another electric service provider or directly from an
electric generator source.
As of the date of this filing, state electric restructuring plans have
been adopted by the state public utility commissions or legislatures in
approximately twenty-four states, and all but a few states currently are
studying or taking action aimed at restructuring their electric markets. Of the
states in which the Combined Company will operate, restructuring legislation has
been adopted in Oklahoma, Virginia, Arkansas, Texas, and Ohio. Investigations
have been commenced which are expected to lead to restructuring plans in the
remaining states in which the Combined Company will operate.(17) Attached as
Appendix A is a summary of the status of state electric restructuring activities
in the states in which the Combined Company will operate.
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(17) Again, the state restructuring initiatives are not the subject of
this Application. The Combined Company will seek such additional approvals, as
may be required, in connection with state-mandated restructuring.
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On December 30, 1999 CSPCo and OPCo filed the restructuring transition
plan required by the Ohio Electric Restructuring Act of 1999 ("Ohio
Restructuring Act"). The filing provides details on the companies' proposed rate
unbundling, corporate separation, operational support, employee assistance and
consumer education plans. The filing also includes a request to recover
transition costs and a proposal for independent operation of transmission
facilities.
The Ohio Commission is expected to issue its final decision on the plan
by October 31, 2000. Ohio customers are eligible to choose their electric
service provider effective January 1, 2001. Rates are frozen through the market
development period, which begins 2001 and can extend until 2005.
CSPCo and OPCo will implement and operate under a Corporate Separation
Plan to be implemented by January 1, 2001. Additionally, the Code of Conduct
adopted by the Ohio Commission governs relationships between the corporate
entities established pursuant to the Corporate Separation Plan.
As part of the Corporate Separation Plan, each company plans to
establish a new transmission subsidiary and a new distribution subsidiary. These
new distribution subsidiaries will own and operate all of the distribution
assets currently owned by CSPCo and OPCo, respectively. The new transmission
subsidiaries will own the transmission assets currently owned by CSPCo and OPCo,
respectively, and those assets will be operated in a manner consistent with the
companies' plan for the independent operation of their transmission facilities.
The generation assets will remain with CSPCo and OPCo. The Corporate Separation
Plan will be implemented with the appropriate recognition of the substantial
overlapping financial arrangements that currently exist. The goal is to separate
each operating company in an orderly and economically efficient manner, and to
minimize additional transition costs that result from prematurely unwinding the
existing financial arrangements such as the companies' mortgages. Subject to
approval by the Ohio Commission, CSPCo and OPCo may in the interim choose a
functional unbundling.
CSPCo and OPCo have also proposed a plan for the independent operation
of their transmission facilities by a qualifying transmission entity. This
component of the transition plans will be consistent with the Ohio Restructuring
Act, to the extent that such sections and rule are not preempted by federal law,
do not improperly interfere with interstate commerce, or are otherwise not
beyond the Ohio Commission's statutory authority. CSPCo and OPCo intend to
participate in the Alliance RTO, pending FERC approval. The companies anticipate
that the Alliance RTO will be operational during 2001. AEP believes
participation in the Alliance RTO will satisfy the statutory requirements
relating to ownership and operation of transmission assets. AEP intends to
comply with the Ohio Restructuring Act in all respects, and Applicants will file
an application with the Commission seeking necessary authority to comply with
the unbundling requirements in a timely manner.
As set forth in Appendix A, on June 18, 1999, the Texas Legislature
passed restructuring legislation ("Texas Restructuring Legislation") that, among
other things, requires each utility to unbundle its business activities into a
retail electric provider, a power generation company and a transmission and
distribution utility. The unbundling process is required to be completed by
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January 1, 2002. Under the Texas Restructuring Legislation, each utility with
more than 400 MW of generating capacity is required to sell at auction at least
15% of the utility's installed generating capacity until the earlier of (i) five
years after competition begins or (ii) the date the Texas Commission determines
that 40% of residential and small commercial customer demand is provided by
nonaffiliated retail electric providers.
Under provisions of the Texas Legislation, CSW's subsidiary, Central
Power and Light Company ("CPL"), filed an application with the Texas Commission
to securitize generation related regulatory assets. To date, the Texas
Commission has approved for securitization CPL regulatory assets in the amount
of $763.7 million. CSW intends to comply with the Texas Restructuring
Legislation in all respects, and Applicants will file an application with the
Commission seeking necessary authority to comply with the unbundling
requirements in a timely manner.
In conjunction with the implementation of retail restructuring, many
states are requiring that utilities divest themselves of utility generating
assets. For example, in Texas, no power generation company may own and/or
control more than 20% of the installed generation capacity in ERCOT. In
Arkansas, the Arkansas Commission can force divestiture of generation assets to
alleviate market power. As a result of these actions, since August 1997, more
than 50,000 MW of generating capacity has been sold (or is currently under
contract to be sold) by utilities, and an additional 30,000 MW is currently for
sale. In total this represents more than 10 percent of U.S. generating
capacity.(18)
Taken together, these fundamental changes in the legal and regulatory
framework governing the electric utility industry are producing the following
structural changes:
- - FERC Order No. 888 and the concomitant development of ISOs and FERC's
recent Notice of Proposed Rulemaking regarding the development of RTOs
are moving the electric power industry to a disaggregation of control
over generation and transmission. Utilities that retain control of
their generation capacity are ceding significant control over their
transmission capacity, and vice-versa. Consequently, the "1935 model"
of an integrated public utility holding company as one that combines
generation and transmission is being supplanted by a different model in
which the two functions are separated.
- - One goal of the above-described disaggregation is to eliminate
ownership of transmission facilities as a barrier to entry into power
markets for those who are ready to compete for customers traditionally
served by electric utilities. If nondiscriminatory access to
transmission facilities is guaranteed, distance will be significantly
reduced as a barrier to competition.
- - An electricity futures market and electricity spot markets, as well as
newly formed entities, such as power marketers, brokers, ISOs and RTOs,
have emerged as new market structures and participants. More than 570
marketers have
(18) RTO NOPR at page 33,690.
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registered with the FERC to trade in electric power. See Edison
Electric Institute, Directory of Power Producers, 106th ed. (1999).
One way in which investor-owned utilities are seeking to improve their
position in today's increasingly competitive market is through mergers and
acquisitions. Between 1986 and 1996, thirty-nine electric investor-owned
utilities merged with other utilities in the industry. Energy Information
Administration, Department of Energy, The Restructuring of the Electric Power
Industry: A Capsule of Issues and Events (Feb. 10, 1998). Between 1992 and the
first half of 1998, 48 investor-owned electric utilities have been involved in
the domestic merger and acquisition process. Edison Electric Institute, "Merger
& Acquisitions," EEI Financial Information (August 28, 1998). AEP and CSW are
seeking to merge to further their mutual strategy of adapting to these historic
changes in the electric utility industry.
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, facilitating centralized inventory and warehousing of materials. 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). Today, these small plants
have been replaced with larger, more efficient units and "improved transmission
and monitoring technologies have increased the feasible geographic bounds for
supply choice; a geographic radius of 1,000 miles or more is currently
considered reasonable for choosing among supply options."(19)
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(19) Rodney E. Stevenson & David W. Penn, "Discretionary Evolution:
Restructuring the Electric Utility Industry," Land Economics, Vol. 71, No. 3
(Aug. 1, 1995). See also Paul L. Joskow, "Electricity Sectors in Transition,"
The Energy Journal, Vol. 19, No. 2 (Apr. 1, 1998) (noting the changes occurring
to the "traditional industrial structures" due to "technological advances that
have expanded the geographic expanse over which integrated AC networks can be
controlled reliably . . ."); Jason Makansi & Robert Swanekamp, eds., "Powerplant
IT Benchmarks Power to Process Industries," Power Magazine, Vol. 140, No. 5 (May
1, 1996) (reporting that in order to "adapt[] organizational structures to the
IT systems" utilities are organizing "tactical group[s] . . . around [a central
information "hub"], not around individual plants, geography, etc"); "Automation
Developments," Transmission & Distribution World (Apr. 30, 1998) (identifying
Allegheny Power's recent purchase of "a computerized maintenance management
system (CMMS) program to help it with utility-wide substation maintenance of a
grid that spans 29,000 sq. miles (75,000 sq. km), seven regional offices and 41
service centers [and serves] customers in portions of Maryland, Ohio,
Pennsylvania, Virginia and West Virginia").
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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 have 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 the mid-1950s. 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 designed and built by
AEP and were energized in 1969. 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.
The development of high-voltage technology, together with FERC's Order
888, made possible the acquisition of a transmission path between the
southwestern part of the AEP transmission system and the northeastern part of
the CSW transmission system. This path will be used to accomplish the integrated
dispatch of the Combined System.
Technological advances have also occurred with respect to the "type" of
transmission lines. The application of HVDC technology provides the ability to
transmit bulk power over longer distances with less energy loss and normally
with a smaller investment than with alternating current ("AC") transmission
lines. This technology provides an economical way to interconnect separated AC
power grids and enables power transfers to occur between these systems such that
it not only provides for improved economies, but also provides improvements in
reliability.
HVDC technology was not commercially applied in the United States for
bulk power transfers until 1970, with the operation of the Pacific Intertie,
Stage 1 USA. Transmission Line at 17. From 1968 to 1981, there were 11,326 MWs
of HVDC capacity added in North America. Id. HVDC capacity has continued to be
added in different areas of the United States since 1981. In fact, the CSW
System constructed and placed in service a 220 MW HVDC interconnection 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.
With respect to new developments in transmission line technologies, AEP
has focussed on the development and application of AC bulk transmission systems,
while CSW has developed and applied HVDC technologies. The Combined Company
will, therefore, have the full complement of transmission line technologies at
its disposal.
The application of phase shifting transformers, series compensation,
and flexible alternating current transmission system ("FACTS") technology also
has provided the ability to
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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 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.
AEP has benefited from series compensation projects since the series
capacitor installation on the 345 Kv Kanawha River-Matt Funk line in 1991. CSW
is in the initial stages of a 138 Kv series capacitor project. AEP's Unified
Power Flow Controller (which is the most advanced FACTS system in operation
today and was jointly developed by AEP, Seimens, and EPRI) is based on voltage
source converter (VSC) electronics. It has the flexibility to maintain bus
voltage while independently controlling the line power flow. CSW will commission
its first "back-to-back" VSC installation at Eagle Pass in 2000. Soon to follow
are other static compensator (STATCOM) FACTS devices at CSW's Military Highway
and Laredo locations. In addition, AEP is now placing in service a unique phase
shifting auto transformer at its Cloverdale Station which will allow deferral of
multi-million dollar capital expenditures for three to four years. A patented
AEP innovation, the bridge capacitor bank also offers cost and performance
benefits. One installation provides voltage support at two bus voltage levels,
at less cost than the equivalent conventional capacitor banks. These
technologies are permitting utilities to more optimally direct power flow on
their transmission grids, provide voltage and reactive power support, and
realize economic savings.
Advances in telecommunications 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,
microwave and fiber-optic network expansion 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 T1 (1.544 Mbit).
AEP has engineered and installed an extensive fiber-optic-based
internal communications system, which has effectively enabled almost unlimited
communications bandwidth at competitive costs. AEP's and CSW's fiber systems are
a mix of OPGW (Optical Ground Wire) and ADSS (All Dielectric Self Supporting)
technologies. Both AEP and CSW have existing Cisco data networks, which will
result in a seamless integration of the networks. A contract is
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being finalized for leased capacity, equivalent to multiple T3 (45 Mbit) lines,
to interconnect the AEP and CSW territories. The major points on the
interconnected system will be Columbus and Canton, Ohio; Roanoke, Virginia;
Tulsa, Oklahoma and Dallas, Texas. ATM (Asynchronous Transport Mode) protocol
will be used with integrated data and voice. Recent technological advancements
in both the fiber medium and the associated electronics, as well as continually
decreasing costs for these systems, have made the integration of the AEP and CSW
telecommunications systems practical. The resulting large data capacity will
lead to further long-term savings by the consolidation of the Combined Company's
mainframe computer facilities at one location.
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 10 years. The improvements
provided by fast and reliable telecommunication networks 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.
The NERC requirement to electronically tag all interchange transactions
would be very difficult without state-of-the-art computer tools and software.
Implementing an e-tag system for the Combined Company has been relatively easy,
because all U.S. control areas must conform to the common NERC specification.
This transaction scheduling process has allowed for more efficient and timely
scheduling coordination.
Developing the Combined Company's economic dispatch system has also
been much easier than it would have been 20 years ago, thanks to common computer
architectures and inter-operable software standards in place today. Relational
databases have facilitated the mass transfer and retrieval of data, and Windows
operating systems permit one to run and view multiple applications. Site
selection and location of computer systems become less of an issue, because the
principal offices are connected to the high-capacity data transmission system.
The joint dispatch will provide economies for customers of the Combined Company
and is achievable via fiber communications from Dallas to Columbus and the
Contract Path via the OATT.
FERC Order 889 mandated the implementation of an OASIS. OASIS has been
made possible because of the growth and breadth of the Internet. It provides the
market with available transfer capability for moving power from supplier to
consumer. The Merger provides the market with a greater opportunity to take
advantage of AEP's large transmission system through its integration with CSW.
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Regarding the market, two recent developments have a bearing on the
integration of the Combined System: (i) the maturation of power trading has led
to increased trading speed, and more efficient information technology will allow
the Combined Company and the industry as a whole to respond quickly to the needs
of the Combined System and the marketplace (i.e. "integration" is through the
surrounding markets, not just the specific interconnection between Applicants);
and (ii) natural gas capacity, specifically combustion turbines and to some
extent combined cycle units, is growing rapidly as a factor in the market which
will allow for greater flexibility in meeting the demands of the Combined System
through the market (i.e. through generation capacity owned and operated by
others).
Transmission and resource planning have also seen significant changes.
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.
Advances in computer and communications technologies will also
facilitate the integration of the Combined System and the effective operation of
the Combined System in other ways. For example, internet-based electronic
communications across the 11-state area will be used to provide immediate data
transfer from simple text messages to complex engineering files, drawings and
technical standards documents.
Value-added computer-based technologies now are also appearing
routinely in the substation environment. AEP has standardized an integrated
distribution station design that provides 30% savings in the Protection and
Control-related capital costs of a new station, while providing remote access to
more operational data than in the past. Since the data communications are based
on an industry UCA standard, future implementation across the Combined System
will be possible. Modern RTUs (remote terminal units) for substation data
acquisition and control are based on standard hardened PC hardware and software,
which provides flexibility and ease in configuration.
Reliable operation and maintenance of the Combined Company's
transmission and distribution facilities are possible through the use of common
state-of-the-art monitoring and diagnostics systems. Digital devices report "by
exception," with increasing dependence on low-cost wireless communications.
Applications such as EPRI's PT LOAD, which accurately determines transformer
load ability and loss of life, and near real-time sag monitors of transmission
line conductors, allows the Combined Company to optimize the use of these
assets.
Digital technologies have improved the ability to control, monitor and
analyze generating plant thermal, electrical and auxiliary system operations.
State of the art heat rate monitoring and optimization systems installed in AEP
generating plants are used to identify and prioritize areas of needed
improvement, which help focus resources for the greatest pay back.
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Reduced costs and improved thermal cycle efficiencies result. Standardized
computer software and wide band communication systems will facilitate the
organization of operational data and the sharing of the benefits of improved
operations with other generating plants across the Combined System.
The greater diversity of fuel mix that the Combined Company will have
is a benefit of the Merger. Specifically, AEP traditionally has realized nearly
90 percent of its generation from coal, while CSW historically has had a greater
utilization of natural gas-fired generation. In the area of renewable
technologies, AEP has made use of its limited availability of hydro resources,
while CSW has potential in the areas of wind and solar, having already launched
some small-scale projects. From the perspective of environmental stewardship, in
meeting environmental requirements of the future the Combined Company will be
aggressively developing, in concert with others, new technologies and
strategies, and employing the combined expertise of Applicants.
Recognizing the demands of a competitive industry, the Combined Company
will form a Corporate Technology Development group to focus on enhancing
existing businesses, providing a basis for new businesses, and enhancing
technological skills. This group will also provide the focal point for
interactions with EPRI (and other collaborative research projects) and will
constantly seek out research projects that leverage the experience of the
Combined Company. The resources of the technology group of the Combined Company,
including the Dolan Electrical Laboratory in Columbus, will focus on
investigating, evaluating, testing and qualifying promising new technologies for
the Combined System's generation, transmission and distribution, and retail
businesses. Testing and pilot demonstrations will be performed in both the
laboratory environment and in the field. As a result of the Merger, the benefits
and savings due to technology synergies in a wide variety of areas such as power
quality, distributed resources, and renewables will be realized across the
Combined System. In addition, AEP has developed over many years a comprehensive
in-house engineering/technical training program (Power Systems Concepts Course)
which will now be available throughout the Combined System. AEP and CSW have
both pioneered electric utility technologies in the past. The Combined Company
will continue this tradition in an effort to develop new technologies that will
enhance the integration of the Combined System.
The fundamental changes in technology outlined above dramatically alter
the "state of the art" which Congress, more than 60 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
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The Combined System will be physically interconnected or capable of
interconnection. The required method of interconnection is not defined in the
1935 Act. The Commission has recognized that the interconnection requirement
should be applied flexibly to allow for methods of interconnection beyond simply
a transmission line owned by the merging utilities. In this regard, the
Commission has found (which finding was upheld on appeal) sufficient a
"three-year 'firm contract' to use a transmission line owned by two unrelated
parties." WPL Holdings at 2262-63, aff'd, Madison Gas & Electric; Conectiv Inc.,
66 S.E.C. Docket 1260 (1998) [hereinafter "WPL Holdings"] ("Delmarva and
[Atlantic City Electric] are interconnected through their undivided interests
in, and/or rights to use, the same regional generation facilities and extra-high
voltage transmission facilities, as well as through their contractual rights to
use the transmission facilities of other members of the PJM regional power
pool") [hereinafter "Conectiv"]; Northeast I, supra (interconnection standard
met where combining entities reached an agreement to obtain service by utilities
with a transmission line interconnecting the two systems); Centerior, supra
(interconnection standard met where merging systems could be interconnected
through a power transmission line, owned by an unaffiliated company, that each
had the right to use).
The Commission has long noted that electric utility systems could be
integrated without direct interconnections. E.g., Unitil (interconnection by
contractual right to use third-party's transmission even though no particular
lines would transfer power). In Unitil, the Commission found that three
noncontiguous electric distribution territories were sufficiently capable of
interconnection due to contractual rights to use a third-party's transmission
service, even though no particular lines would transfer power among the
companies. Unitil at 564-66. The description of the transmission arrangements in
Unitil -- "power will be delivered through a non-affiliate system and a
transmission charge will be paid" id. at 566) -- is analogous to the
transmission service requested across Ameren.
The Division has recommended that the Commission "respond realistically
to the changes in the utility industry and interpret more flexibly each piece of
the integration equation," including the physical integration requirement. 1995
Report at 67. The means through which two utilities are physically capable of
sharing power has expanded with changes in the industry. Utility companies can
now share power through power pool arrangements, reliability councils, RTOs, and
ISOs.
As noted in Item 1.B.3 above, AEP and CSW will interconnect their
systems through the 250 MW Contract Path across the Ameren system. Under
Commission precedent, this satisfies the interconnection requirement of Section
2(a)(29)(A). Moreover, the Applicants have the ability through the Ameren OATT
to renew the Contract Path. Thus, the Contract Path provides the Applicants with
the means to meet the interconnection standard under the Act and, at the same
time, preserves flexibility to enter into more favorable arrangements should
they become available during the four-year term of the Ameren contract. As noted
above, the electric industry is in the process of dynamic change; there is
growing pressure on public utilities to restructure and increasing competition
in the marketplace. Applicants believe that within the next four years there may
be transmission interconnection alternatives available as a result of these
changes and that the Commission therefore should find the Contract Path to be
sufficient. Although the
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precise method of interconnection has not yet been determined four years into
the future, the Applicants commit to continue to meet the interconnection
requirement at that time.(20)
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.(21) See Dr. Hieronymus' testimony
filed as an exhibit to Exhibit D-1.2. This is sufficient to allow the Combined
System to be physically interconnected or capable of physical interconnection,
which is the standard applied under the Act. 15 U.S.C. Section 79b(a)(29)(A).
Accord WPL Holdings, supra, wherein the Commission held that interconnection
through a 200 MW firm transmission contract met the standards of the Act.
Capacity exchanges will be made between the east zone and the west zone
for periods of one year or less when one zone has capacity available for sale
and the other zone needs capacity to meet its reserve requirements, and when the
selling region's capacity market price is lower than the buying region's cost of
installing capacity or purchasing such capacity in the market. In this regard,
the production cost modeling studies conducted by the Applicants indicate that,
during the first ten years of post-Merger operations, the Combined Company will
be able to economically transfer 250 MW from the east zone to the west zone 87.5
% of the time and from the west zone to the east zone 4.3% of the time.(22) See
Testimony of J. Craig Baker at page 24.
As discussed above in Item 1.B.3, Applicants' goal ultimately is to
further enhance the interconnection of the Combined System through participation
in a regional RTO (subject to the need of the CSW-ERCOT companies to continue
participation in the ERCOT ISO). Assuming that the Combined Company belongs to a
single RTO, the RTO will have the capability to use the other members'
transmission lines to transmit power within the Combined System. The effect is
the same even if the Combined Company belongs to separate but contiguous RTOs,
provided the RTOs are not permitted to erect economic barriers between them.(23)
In this regard,
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(20) As noted in Item 1.B.3, in the event AEP determines for any reason
not to renew the 250 MW Contract Path, AEP will file a post-effective amendment
no later than May~31, 2003 concerning the measures it will take to ensure that
the interconnection requirements of Section 2(a)(29) of the Act are satisfied.
(21) 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.
(22) The underlying study, the results of which are set forth in
Exhibit D-2.1, focused on production costs and the cost of transmission over the
Contract Path, and did not factor in the potential for the wholesale market to
address production cost differences between the east and west zones. Applicants
have not conducted a study solely for the purpose of determining the effect of
various wholesale market conditions upon Contract Path utilization.
(23) In this regard, the Commission has previously approved a merger
where the merging utilities were in more than one reliability council. See New
Century Energies, supra (approving a merger in which one of the merging utility
systems was located in the southwest corner of the eastern United States
electricity grid and was a member of the Southwest Power Pool, a regional
reliability coordinating organization in the eastern grid, and the other merging
utility system was located in the western United States electrical grid and was
a member of the Western Systems Coordinating Council, a reliability council for
members in the western United States electrical grid).
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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
Under normal conditions, the Combined System will be "economically
operated as a single interconnected and coordinated system" as required by the
second clause of Section 2(a)(29)(A). The Commission has noted that, through
this standard, Congress "intended that the utility properties be so connected
and operated that there is coordination among all parts, and that those parts
bear an integral operating relationship to one another." Conectiv, supra, citing
The North American Co., HCAR No. 3466 (April 14, 1942), aff'd, 133 F.2d 148 (2d
Cir. 1943), aff'd on constitutional issues, 327 U.S. 686 (1946). Cf. Section
1(b)(4) of the Act which cites, as one of the problems the Act was intended to
address, the harm to the public interest and the interest of investors and
consumers "[w]hen the growth and extension of holding companies bear[] no
relation to economy of management and operation or the integration and
coordination of related operating properties."
The Commission and the courts have emphasized this aspect of the
coordination requirement in recent decisions. In 1992, in a matter involving
Entergy, intervenors argued that the system would no longer be "economically
operated", as required by the second clause of Section 2(a)(29)(A), as the
result of the transfer of spun-off certain generating facilities from system
utilities to an unregulated affiliate. The problem, identified by intervenors,
was that power from these facilities would no longer be offered first for
in-system use. The Court of Appeals for the District of Columbia Circuit noted
that:
Although that reading might be consistent with the words of
section 11 [and, by implication, Section 2(a)(29)(A)], it is
by no means the required one. The Commission reads
"economically" to impose a less stringent requirement, i.e.,
that facilities, in addition to their physical
interconnection, be consolidated so as to take advantage of
efficiencies. We are satisfied that the Commission's
interpretation neither contravenes Congress's intent nor is
"unreasonable."
City of New Orleans v. SEC, 969 F.2d 1163 (July 17, 1992), citing Chevron U.S.A.
Inc. v. Natural Resources Defense Council, Inc., 467 U.S. 837 (1984) (emphasis
added). In this regard, the Court of Appeals anticipated the situation that is
faced by system operators today, in which there is a "tool kit" of resources
that can be used to obtain the maximum benefits for the Combined System.
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The emphasis on economical operation of the system as a whole was
reinforced by the 1999 Madison Gas decision, in which the D.C. Circuit expressly
found that "section 2(a)(29)(A) requires that a system's combined 'assets' (and
not the interconnection in particular) be economically operated." Madison Gas,
supra.
The coordination requirement was recently addressed in Unitil, supra.
In that case, the Commission concluded that the merged system was sufficiently
coordinated by means of factors which will also be present in the Combined
System, specifically, "centralized dispatch and . . . [the] coordinated
planning, construction, operation and maintenance of generation and transmission
facilities." Unitil, at 565 (footnotes omitted).(24) In its analysis of the
coordination requirement, the Unitil decision places particular emphasis on the
importance of centralized dispatch:
Section 2(a)(29) further requires that the utility . . . be
"economically operated as a single interconnected and coordinated
system." The Commission has interpreted this language to refer to the
physical operation of utility assets as a system in which . . . the
generation and/or flow of current within the system may be centrally
controlled and allocated as need or economy directs.
Unitil, at 566 (footnote omitted).(25) Through this standard, Congress "intended
that the utility properties be so connected and operated that there is
coordination among all parts, and that those parts bear an integral operating
relationship to one another." Id. (citing Cities Services Co., 14 SEC 28, 55
(1943)).
As explained more fully herein, there will be "joint dispatch" of the
generating units of the Combined System within the meaning of Commission
precedent. It is important to note, however, that federal deregulation and state
restructuring initiatives have dramatically altered the way in which the
electric utility industry coordinates and integrates electric utility
operations. As a result, joint dispatch is but one aspect of the economic
operation of a single interconnected
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(24) See also Electric Energy, Inc., 38 SEC 658, 670-71 (1958)
(acquired company satisfies "coordinated system" standard if its "generation,
transmission and distribution" functions can be efficiently coordinated with the
existing system through communications equipment, joint dispatch and joint
planning).
(25) This passage from Unitil also stresses the need for "flexible
considerations" in applying the Act' integration requirements. Unitil, at 566.
For example, in Unitil, the Commission found that participation in a power pool
was sufficient to meet the economic integration standards even though the
"definition [of economic integration] reflects an assumption that the holding
company would coordinate the operations of the integrated system." Similarly, in
approving the acquisition of PSNH by Northeast, the Commission noted that "the
operation of the generating and transmission facilities of PSNH and the
Northeast operating companies is coordinated and centrally dispatched under the
NEPOOL Agreement [a regional power pool agreement]." Northeast I, supra at n.
85. In Conectiv, supra, the Commission noted that in addition to coordinated
operation through an ISO, Conectiv would also have a central operating
transmission and generation control center for the essentially local functions
of the Conectiv system, thereby meeting the standard.
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and coordinated system. Accordingly, this filing addresses means, in addition to
simple joint dispatch, of coordinating the operations of the Combined System.
(a) Joint Dispatch
AEP and CSW will have joint dispatch which will be implemented by means
of a System Integration Agreement and the System Transmission Integration
Agreement, along with the use of Central Dispatch Planning and Central Economic
Dispatch software programs. It should be noted that the term "joint dispatch" is
nowhere defined in the Act or the rules thereunder. Consistent with the
precedent discussed above, the term "joint dispatch" in this application refers
to the ability of an integrated system to dispatch its generation on a
least-cost basis, taking into account various operating conditions, to achieve
the maximum efficiencies in the operation of the subject assets.
In the instant case, a single control center will schedule the
generating resources of the Combined System on a day-ahead and an hour-ahead
basis. The joint dispatch of all of the power supply resources of the Combined
System will be controlled by this center. The generating resources of the
Combined System will be jointly dispatched on a least-cost basis. Subject to
currently prevailing constraints, unit commitment will be performed to meet the
Combined System's obligations, taking into account the specific obligations
within each control area.(26) The control areas will be jointly dispatched in
real time to minimize total system production costs for the Combined System,
subject to currently prevailing transmission capabilities. The Combined System
will have firm transmission rights over the Contract Path.
The joint dispatch of the Combined System will be performed in two
steps.
- The first step is unit commitment. In this step, the system
operator projects the system peak load requirements for a
period and, to meet that requirement, schedules available
generating units to be on-line in economic order subject to
any operational or other constraints. The system operator will
not load the less economic units unless the load requires
them. The system operator will also examine the energy market
to determine if reliable energy can be purchased at lower cost
in order to avoid loading higher cost generating sources.
- The second step is the incremental loading of the on-line
generation sources and purchases. This step is performed
continuously as each unit's available generation is dispatched
above its minimum load in order to match the generation to the
load. Generation of the Combined System's various units will
be dispatched from lowest to highest cost. The joint dispatch
will be consistent with available firm transmission, including
the HVDC ties
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(26) For example, in determining the Combined System's generation
dispatch priorities, each zone's most economic generation will be used to serve
its native load customers and previously committed firm load contracts.
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connecting the ERCOT and non-ERCOT components of the west zone and the
Contract Path between the east zone and the west zone.
See Testimony of J. Craig Baker, filed as Exhibit D-1.2. Following the Merger,
there will be two data relay centers, one in Dallas and the other in Columbus.
These centers will be staffed with personnel 24 hours a day, 365 days a year.
Merger transition teams have designed the organization structure and job
responsibilities. See Exhibit B-3.4 for the AEPSC (Post-Merger) Organization
Chart.
AEPSC will engage in the joint dispatch of the Combined System through
Central Dispatch Planning and Central Economic Dispatch of the generation units
of the Combined System. Through Central Dispatch Planning, the coordination of
each generation unit in the Combined System will be scheduled on a day-ahead
basis. Central Economic Dispatch will use an EMS to compute at regular intervals
(currently every four seconds) the Economic Base Points based upon certain
current operating conditions and will automatically 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 current CSW dispatch program will be the Central Economic Dispatch
program for the Combined System, modified to take into account the internal
transmission capabilities of the Combined System.(27) Using an EMS, it will
jointly dispatch all of the generators of the Combined System by calculating at
regular intervals (currently every four seconds) the Economic Base Points based
upon certain current operating conditions. After the Economic Base Points have
been identified, the EMS will transmit that information to the data relay
centers in Dallas and Columbus. The respective data relay centers will use this
information to adjust the Combined System's generating units, thereby assuring
economic dispatch of the Combined System. The Economic Base Points for the
generators located in the eastern zone will be transmitted to the data relay
center in Columbus via a high-speed data link.
The Central Economic Dispatch program is designed to achieve the most
economic dispatch of the total generation of the Combined System. This program
must honor certain physical conditions of the system. The program will honor
transmission capabilities at all points in time. The program will also honor
limitations on generating units, as they appear from time to time.
Capacity exchanges will be made between the east zone and the west zone
for periods of one year or less when one zone has capacity available for sale
and the other zone needs capacity to meet its reserve requirements, and when the
selling region's capacity market price is lower than the buying region's cost of
installing capacity or purchasing such capacity in the market. In this regard,
the production cost modeling studies conducted by Applicants indicate that,
during the first ten years of post-Merger operations, the Combined Company will
be able to economically transfer 250 MW from the east zone to the west zone over
the Contract Path 87.5%
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(27) This dispatch system is currently used by CSW to coordinate its
SPP and ERCOT operations.
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of the time. When economic energy is expected to flow that would exceed the 250
MW Contract Path, then non-firm transmission service would be requested from
third parties to accomplish the joint dispatch. As explained in the Application,
the Combined System will make use of its rights to nominate secondary points of
receipt and delivery under its transmission service agreements with WR and
Ameren for transfers of capacity from the west zone to the east zone. For
transfers of economic energy in excess of the Contract Path, Applicants will use
the OATT of neighboring utilities to effect delivery. The transfer limits of the
Central Economic Dispatch program would be adjusted to reflect the transmission
conditions occurring in real-time. The System Integration Agreement gives legal
effect to the foregoing technical description.
(b) Other Aspects of Coordination
Applicants will also coordinate the operation of the Combined System in
other ways. As noted above, industry restructuring and deregulation have
expanded the ways by which a company can coordinate and integrate its merged
operations. Applicants intend, subject to applicable regulatory constraints, to
implement additional coordinated activities by which the Combined System will be
operated in a coordinated and integrated manner.
(1) Coordinated Wholesale Generation and Trading Operations
The Combined Company's Wholesale - Energy Services Business Unit, a
division of AEPSC, will be responsible for coordinating the following: marketing
and trading efforts; design and purchase of new generating facilities; operation
and maintenance of generating capacity resources; centralization of trading and
marketing activities; acquisition and maintenance of transmission services
needed for inter-zonal power transfers; provision of billing and administration;
and other administrative services.
The purpose of the Wholesale - Energy Services Business Unit will be to
coordinate the Combined Company's joint marketing and trading efforts, both as a
buyer and as a seller. Today, a utility creates value by selling as much
electricity as it profitably can, after meeting the requirements of its native
load. Whether electricity can be sold profitably is a function of several
factors including: the prevailing price of electricity, the location of the
potential customer, the price of fuel, and other factors. As these factors tend
to be volatile, many utilities have created trading groups composed of
individuals with specialized, sophisticated skill sets necessary to predict
market behavior and devise appropriate trading strategies. These trading
strategies necessarily have an impact on that particular utility's generation
plans. In other words, if the price of electricity is such that a utility can
sell electricity profitably, the trading group will direct that utility's
generating units to generate electricity to full capacity. If, on the other
hand, the price of electricity is so low that it is cheaper to purchase
electricity to meet native load instead of incurring production costs, then the
trading group will direct its generating units to curtail operations.
Currently, as part of its regulated operations, AEP has integrated its
trading operations with the operation of its generating assets. This has further
enabled AEP to integrate the operation of its generation assets with the broader
power market. Upon consummation of the Merger, the Combined Company will
integrate its trading operations with the operation of its generating assets to
achieve similar benefits. The Wholesale - Energy Services Business Unit
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will take advantage of the Combined System's generation capacity, wholesale
customer base, diversity of weather, time and fuel supply to allocate resources
more efficiently and thereby decrease the overall production costs of the
Combined System. This ability to diversify supply over a broader region with
diverse weather and time zones is another way that companies like the Combined
Company can achieve the benefits of economic integration in a market-based
commodity like electricity.
Power trading and the generation business have a synergistic
relationship as trading activities complement the generation function in terms
of price discovery and "finding" the customer. Trading provides an opportunity
to create value when, for example, there is a difference between gas and
electric prices. Trading will also enable the Wholesale - Energy Business Unit
to manage risk relating to sudden changes in market prices. Ownership of
generation provides, among other things, industry expertise and knowledge that
enable the traders to make more-informed decisions, for the benefit of both
shareholders and customers. Thus, the coordination of these complementary
activities in the Combined Company is expected to benefit ratepayers and
shareholders alike.
As noted previously, in the past, electric utility companies operated
as self-contained, regulated monopolies that sold their product almost
exclusively to their captive retail customers. By and large, a traditional
utility's customers were limited to those end-users situated in that utility's
service territory. A traditional utility created the most value for its
shareholders by incurring the least possible costs to generate just enough
electricity to serve its native load. Achieving a constant uniform cost of
production across a system necessarily resulted in the greatest return for
investors. Federal deregulation and state restructuring have materially altered
this paradigm. Today there is a vibrant market for electricity. A utility sells
electricity not only to the customers located in its service area, but also to
wholesale customers.
The importance of coordinated trading operations was magnified by
passage of the Energy Act and the issuance of FERC Order Nos. 888 and 889. One
commentator has recently described the resulting markets as follows:
What resulted is a highly competitive and sophisticated 24-hour power
market. . . . Next we examine what happens in "real-time." . . .
Economic power schedulers, working in the front office, monitor the
utility's entire real-time system, making sure that the planners have
accurately matched the power supply assets with the hourly demand or
native load. Economic power schedulers also make sure that the planners
have utilized the least expensive power supply assets. Schedulers may
also make adjustments to the power plan in order to maximize the goals
of reducing costs providing customers with the lowest possible
wholesale prices. To make these adjustments economic power schedulers
rely on available power supply assets and the hourly or "spot" market.
Unexpected changes in the weather, mechanical problems at the
generating station and congestion on the transmission grid are only a
few of the factors that can result in deviations from the planner's
schedule. Let's assume the scheduler needs an additional 10 MW of power
for two hours, one hour from now. He or she . . . may consult a data
screen that displays the real-time spot-market price and the
incremental cost of generation or the cost of producing the additional
or next 10 MW of electricity.
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If the incremental cost of generation is less than the market price,
the power scheduler may ask the generating plant to increase production
or start a peaking unit. If the price of power from pre-existing
contracts is less than the spot market price or generation, the
scheduler may draw upon the amount of electricity stipulated in the
contract. But if the spot market price is less than the incremental
cost of generation or contract power, the scheduler may notify the
traders in the "front office." They immediately go to the spot market
and begin the buying process.
The economic power scheduler may also find that the utility is "long"
on power or has excess capacity for several hours. The traders may now
begin the selling process. Trading in the spot market has the same
requirements as day-ahead, weekly and monthly trading except that it
happens at a much faster pace. Spot market trading averages less than
20 minutes for securing a buyer or seller scheduling transmission or
obtaining a NERC tag, applying competitive intelligence and price and
credit risk management, confirming the trade and notifying billing,
finance and accounting in the "back office."
Nelson, Kenneth C., "The New World of Power Marketing," Management Quarterly, v.
40, pp. 13-32 (Spring 1999).
Thus, the Wholesale business unit will coordinate all of the power
trading and generation business activities of the Combined Company, thereby
integrating these activities across both the east zone and the west zone.
(2) North American Energy Delivery
The North American Energy Delivery unit will use an asset management
approach to centrally coordinate the assets of the Combined Company.
Specifically, this unit will centralize asset-management policy decisions,
provide an integrated approach to financial decisions, develop an appropriate
allocation of resources between new capital investment and routine O&M expenses
and implement the use of best practices throughout the Combined System. The
North American Energy Delivery unit will consist of a Transmission organization,
a Distribution organization, a Customer Interface and Services organization, a
Regulatory, Planning and Budgeting Services organization, and a Customer and
Community Services organization. The functions of these organizations are
described below:
(a) Transmission - the Combined Company's Transmission organization will
respond in a flexible manner to future regulatory requirements. Under
the new organization design, the Transmission organization will be
further sub-divided into the following four subgroups:
- Transmission Asset Management, which will integrate the
Combined Company's capital planning, system engineering and
maintenance management processes into a performance-driven,
strategic approach to managing assets.
- Transmission Operations, which will have responsibility for
dispatching and controlling the Combined System, and
developing plans for participation in RTOs.
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- Transmission Capital Improvements, which will provide
engineering, right-of-way, construction management and project
management services for expansion or refurbishment of
transmission line and T&D station facilities.
- Transmission Services, which will provide transmission system
maintenance, operation, service restoration and construction
labor services.
(b) Distribution - the Distribution organization will adopt an asset
management philosophy, integrating a number of critical perspectives
(including regulatory, capital planning, O&M planning, engineering,
etc.) into a strategic approach for managing distribution assets across
the eight distribution operating regions (six in the AEP East Zone and
two in the AEP West Zone).
In addition, several key process improvements will be implemented,
including: expanded use of mobile data computers to enhance
productivity; implementation of a single new work management system as
part of the corporate Enterprise Application Solution (EAS) for
information management and process improvements in dispatching.
The Combined Company's Distribution organization will be sub-divided
into the following five subgroups:
- Asset Management, which will develop business scenarios, set
strategic direction, plan system enhancements, develop
standardization and monitor performance.
- Distribution Support, which will provide distribution support
services to the operating companies.
- Distribution Regions Management, which will maintain and
operate assets, restore service, deliver new service, develop
tactical plans and improve efficiencies to meet customer and
regulatory requirements.
- Meter Services, which will perform meter engineering, field
operations, meter inventory management and equipment testing.
- Telecommunications, which will provide voice and data
communication services.
(c) Customer Interface and Services - Customer Operations, Field Revenue
Services and Billing and Collection Services will be provided by the
Customer Interface and Services organization. The Customer Interface
and Services organization will be responsible for maintaining:
- Customer service centers, or call centers, which respond to
customer inquiries and handle requests for service, billing
inquiries and outage restoration. Customer call centers are
expected to handle 15 million calls per year. An organization
design that
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maximizes the use of call center resources by creating a
virtual call center environment will be implemented by the
Combined Company.
- Customer Operations Support, which will provide training to
call center employees and set standards regarding the content
of calls and the consistency and quality of calls.
- Network Operations, which will forecast call volume and
develop work schedules to handle call volume. It will also
route calls based on current and planned conditions, managing
the virtual call center environment.
- Customer Relations, which will handle billing analysis, rate
analysis, power quality issues, contract negotiations,
business expansions and other account maintenance issues for
residential, small commercial and small industrial customers.
- Major Accounts, which will handle billing analysis, rate
analysis, power quality issues, contract negotiations,
business expansions and other account maintenance issues for
large industrial and commercial customers.
- Field Revenue Services and Billing and Collection Services,
which will combine resources for meter reading and
connections/disconnections and handle billing and collections.
(d) Regulatory, Planning and Budgeting Services - The Regulatory,
Planning and Budgeting Services organization will be responsible
for coordinating all state regulatory activities, through the use
of state regulatory offices that have centralized and regional
support. This organization will be responsible for all regulatory
filings, including restructuring filings that are mandated from
time-to-time in the various states. This unit will also administer
budgeting for the North American Energy Delivery unit.
(e) Customer and Community Services - The Combined Company will
coordinate a targeted customer and community relations strategy,
which will include economic development, new service coordination
and other community relations activities.
(3) Corporate Development
The functions of the Corporate Development unit will be centrally
coordinated and will include:
- Providing direction in such areas as integration,
best practices and business re-engineering across the
Combined Company.
- Coordinating mergers and acquisitions and integrating
new operations.
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- Providing communications and energy information services that
complement the Combined Company's affiliated businesses;
- Investing in new ventures, including selected new technology
companies, that will support the strategic plan of the
Combined Company.
(4) Coordinated Administrative and General Services
The coordination and integration of the Combined System will be further
achieved through the coordination and integration of information system networks
and other support services. Many administrative and general services will be
performed for the Combined System by AEPSC, including:
(a) Finance and Analysis - The Finance and Analysis unit will
provide various services, including accounting, tax,
budgeting, internal audits, treasury, risk management and
strategic analysis. Many of these operations will be
consolidated in the new organization, including a single AEPSC
billing system. The Combined Company has targeted the complete
integration of financial systems by 2002.
(b) Legal, Policy and Corporate Communications - This unit will
provide a number of services, including:
- Legal - The legal department will be responsible for
the Combined Company's legal business, with certain
attorneys located within business units and with
others who have responsibilities for portions of the
Combined Company's service territory.
- Public Policy - A centralized Public Policy unit will
be established to coordinate and develop
communications on public policy issues for the entire
Combined Company. The purpose of this unit will be to
provide the Combined Company with a more unified,
effective voice on industry matters.
- Governmental Affairs - The State Offices and
Governmental Affairs units will provide a greater
presence in the state capitals of the Combined
Company's service territory. The State Offices will
be coordinated by a State President in each State and
will better utilize existing resources to support
customer service and restructuring activities at the
State level.
- Corporate Communications - The Corporate
Communications unit will implement a
performance-based approach for internal
communications, geared toward helping business units
and shared services groups meet their performance
objectives.
- Environmental Policy - A centralized Environmental
Policy unit will coordinate all environmental affairs
activities for the Combined Company.
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(c) Shared Services - A combined Shared Services unit
will provide various support services to the business
units, including human resources, information
technology, procurement and other administrative
services.
- Human Resources - The Human Resources unit will
coordinate delivery of HR services with field-located
HR employees. Business unit HR needs will be
supported by co-located client directors. A combined
Human Resources organization will provide a single,
comprehensive service center that will be responsible
for all administrative transactions, including
coordination of all vendors in the areas of benefits,
compensation, training, health, safety and other HR
areas.
- Information Technology - The Information Technologies
(IT) unit will be centrally coordinated to align
Information Technology activities with individual
business unit strategy, ensuring that the right IT
solutions are delivered to the Combined Company.
Six groups will report directly to the Combined Company's chief
information officer, including:
- Architecture and Business Services unit, which will
develop IT strategy to optimize IT's contribution to
the Combined Company. This group will also develop
standard application frameworks and infrastructure to
reduce costs.
- Career Management unit, which will provide IT
employee career planning, skills assessment and staff
development.
- Infrastructure Delivery unit, which will be
responsible for the engineering, design and delivery
of all IT infrastructure required to support business
unit initiatives.
- Infrastructure Operations unit, which will be
responsible for the day-to-day processing of
applications and infrastructure. This group includes
The Combined Company's IT Help Desk. This group will
be focused on integrating the network operations and
data centers of the two companies into a single
backbone system.
- Relationship Management unit, which will be
responsible for maintaining partnerships between IT
and the business units and shared services groups. A
Service Management group within Relationship
Management unit will develop products and services to
meet business unit needs.
- Solutions Delivery unit, which will be responsible
for developing the methods and processes used by the
IT organization to deliver solutions to the business
units and for tracking the progress of these
activities. This group includes the IT Project
Office, which will monitor projects, identify any
project conflicts and assess their impact on
financial and human resources. This centralized
project management focus is designed to improve
delivery and reduce costs.
This group will implement the integration of all
software system consolidations, with the significant
efforts being customer information, human resources,
supply chain, work management, finance and accounting
systems, in conjunction with the
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appropriate business/shared services organization.
- Procurement/Supply Chain - The Procurement/Supply
Chain unit will combine existing organizations to
achieve improvements in inventory management,
resource optimization and supply management. The
Combined Company will achieve savings through joint
purchases of materials, combined procurement of labor
and services and improved management of delivery of
goods to various locations with the Combined System.
A business unit-focused organizational model will be
implemented that includes a Corporate Supply Chain
Services group, a Wholesale Supply Chain Services
group and a Wires Supply Chain Services group.
- General Services - Certain General Services will be
consolidated within the Combined Company, including
vehicle acquisition, use of system-wide travel
contracts and system-wide contracts for office
supplies. Additionally, the Combined System will
implement best practices in the areas of land
management, facilities management and fleet
management, and create a General Services Call Center
as the single point of contact for internal
customers.
(iii) Single Area or Region
As required by Section 2(a)(29)(A), the Combined System's operations
will be confined to a "single area or region in one or more States." As Mr.
Ganson Purcell, Chairman of the Securities and Exchange Commission, testified
before the Subcommittee of the House Committee on Interstate and Foreign
Commerce in 1946 concerning this standard of the Act:
I wish to make it clear that the Act does not require that an
integrated utility system be broken up, whether or not it crosses State
lines, or that a holding company necessary to integrate the properties
of several operating companies be abolished. . . .(28)
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. . . .(29)
No absolute size limitation is specified. While the terms "area" and
"region" are not defined in the 1935 Act, it is clear that the "single area or
region" requirement does not mandate
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(28) 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).
(29) Id. at 857 (referring to American Gas and Electric system).
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that a system's operations be confined to a small geographic area. The terms
"area" or "region," by their nature, are capable of flexible interpretation,
which permits the Commission to respond to the current state of the industry and
allows the Commission to give the terms practical meaning and effect.(30)
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
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(30)Another way to analyze what should constitute an "area" or "region"
is to examine how potential competitors of the Combined Company operate in the
marketplace. In its 1998 Annual Report, Enron Corporation described itself as
the "premier integrated energy merchant in the rapidly growing competitive North
American wholesale energy market." Enron 1998 Annual Report, p. 13. In the same
section of the report, Enron states that it has generation under construction in
Mississippi and Tennessee, has acquired generation within ten miles of New York
City, and has gas storage available in Houston, with the ability to move
electricity and gas from Houston to the East Coast or Midwest "on a moment's
notice" (id., p. 14). The Report also contains a multi-colored map of "Wholesale
Energy Operations and Services, North America" showing a nationwide network of
gas pipelines and electric grid, with generation assets stretching from
California to New York. Enron is operating on a hemispheric basis, with
operations in Canada and the United States, and with offices in Mexico. From
Enron's perspective, the appropriate "area or region" is at least as large as
the entire United States.
Other companies similarly view the appropriate marketplace on a
nationwide basis. For example, the Southern Company has electricity generation
and/or distribution operations in nine states, including Alabama, Georgia,
Florida, Mississippi, Virginia, Indiana, Massachusetts, Texas and California,
and is constructing new gas distribution projects in North Carolina and Maine.
Entergy Corporation provides services in several states, including supplying
electricity in Arkansas, Louisiana, Mississippi and Texas, as well as in
Massachusetts via its nuclear power subsidiary. Duke Energy Corporation,
headquartered in Charlotte, North Carolina, furnishes energy-related services in
North and South Carolina, is currently developing electric generation plants in
Connecticut, Missouri, Florida, California, Texas and Virginia, and offers
energy trading and marketing services in New York, Rhode Island, Pennsylvania,
Indiana, Georgia, South Carolina, Texas, Oklahoma, New Mexico, Nevada and Utah.
Edison International, in addition to its utility operating company subsidiary
located in California, has twenty-three energy generation facilities located in
Northern California, New Jersey, New York, Illinois, Pennsylvania, Florida,
Washington, West Virginia and Nevada. PP&L, Inc., headquartered in Pennsylvania,
provides energy related services in Pennsylvania, New Jersey, Maryland, Ohio,
Delaware, West Virginia, Virginia and various New England states, recently
acquired generation facilities in Maine, Oregon and Montana, and is developing
power plants in Arizona and Connecticut. NRG Energy has generation facilities in
California, Colorado, Connecticut, Florida, Illinois, Maine, Massachusetts,
Michigan, Minnesota, New Hampshire, New Jersey, New York, North Carolina,
Oklahoma, Pennsylvania, South Carolina, Utah, Virginia and Washington, and is
developing generation facilities in Louisiana. Sempra owns a gas and electric
utility company in California, has generation facilities in Connecticut, and has
a gas pipeline in North Carolina.
Other utilities view the marketplace on a global basis without regard
to national borders. The FERC recently approved the acquisition of PacifiCorp by
ScottishPower p.l.c. and the acquisition of New England Electric System (and the
potentially indirect acquisition of Energy Utilities) by National Grid Group
p.l.c., utilities located outside the United States. British Energy, through its
interest in Amergen Energy, has indirectly acquired the Pilgrim Nuclear Plant
from Boston Energy, the Three Mile Island Unit 1 from General Public Utility
Systems, and the Clinton Nuclear Plant from Illinois Power Company.
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operation and effective state regulation." NIPSCO, supra (applying single area
or region requirement with respect to gas utility system); accord, Sempra,
supra. The 1935 Act provides, and the Commission recognizes, that the question
of size must be informed by practical considerations, including its effect, if
any, on the "advantages of localized management, efficient operation, and the
effectiveness of regulation"(31) in light of "the state of the art and the area
or region affected" as discussed in Item 3.B.1.a.(iv) below.(32)
In considering size, the Commission has consistently found that utility
systems spanning multiple states satisfy the single area or region requirement
of the 1935 Act. For example, the Entergy system covers portions of four states
(Entergy, supra), the Southern system provides electric service to customers in
portions of four states (Southern Co., HCAR No. 24579 (Feb. 12, 1988)), and the
principal integrated system of NCE covers portions of five states (with all of
its electric operations serving customers in six states) and operates in two
reliability councils (New Century Energies, supra (citation omitted)). Other
registered holding companies also operate in multiple states. For example, the
Allegheny Energy, Inc. system provides electricity to customers in parts of five
states (Filings under the Public Utility Holding Company Act of 1935, HCAR No.
26846 (March 20, 1998)). As early as 1945, the Commission found that AEP's
operations in seven states were confined to a single region or area. American
Gas and Electric Co., HCAR No. 6333 (Dec. 26, 1945). In addition, in light of
the present state of the industry, other utility systems, although they are not
registered utility holding companies, span multiple states.(33) For example, the
PacifiCorp system covers portions of seven states (Annual Report of PacifiCorp
on Form 10-K for the year ended December 31, 1997), and the UtiliCorp system
covers portions of nine states (Form U-1 filed as of July 2, 1998).
In addition to not specifying an absolute size for an "area" or
"region," the 1935 Act likewise does not provide any specific parameters with
respect to the term "single" in the "single area or region" test. In considering
distance, the Commission has found that the combining systems need not be
contiguous in order for the requirement to be met. See, e.g., Conectiv, supra;
cf. New Century Energies, supra (finding that electric utilities located in two
different power pools, in two different reliability councils, in both the
Eastern and Western Interconnects, and with a physical separation of 300 miles
were in same area or region); Electric Energy, Inc., HCAR No. 13781 (Nov. 28,
1958) (utility assets were within the same area or region as the acquirer's
service area despite a distance of 100 miles crossing two states); Mississippi
Valley Generating Co., HCAR No. 12794 (Feb. 9, 1955) (single area or region test
met where generating station was located 150 air miles from the territory served
by the acquiring company).
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(31)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.
(32)In fact, as discussed in note 12 above, Applicants submit that the
integrated utility system requirement could be interpreted to involve only a
three-part test, with the last two tests read as one.
(33)In this regard, Applicants believe that the continued economic
viability of large utility holding company systems suggests their efficient
operation and, accordingly, these systems should be evaluated on the same basis
as comparably large utility systems not regulated as registered utility holding
companies under the 1935 Act.
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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.(34)
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
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(34) The concept of a geographic region, which includes the states in
which AEP and CSW are based (Ohio and Texas), exists within the electric
industry. In 1956, state regulators from 14 states, including Ohio and Texas,
formed the Mid-America Regulatory Conference. See Mid-America Regulatory
Conference, A History, 1956-1995.
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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.(35) 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.
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(35) 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.
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Developments in the natural gas industry that have eroded traditional
boundaries are being duplicated today in the electricity industry.(36) 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. Electric utilities are in the process of divesting or
separating their transmission and distribution assets from their generation
assets. As a result of federal and state electric industry restructuring
legislation, more than 570 energy marketing companies have registered with the
FERC and are currently competing with electric utilities to market electricity
on a wholesale and retail basis to customers who were previously an electric
utilities' captive customers. Edison Electric Institute, Directory of Electric
Power Producers, 106th ed. (1999). In short, as it has for the natural gas
industry, the Commission can easily interpret the concept of "area or region" to
include an area or region in which the merging companies both buy or sell
electricity.
Given the proximity of the AEP System to the CSW System and the present
technological ability to economically transmit power over longer distances, and
given that the Combined System will be economically operated as a single
integrated and coordinated system as described in Item 1.B.3, the Combined
Company satisfies the 1935 Act's requirement with respect to operating in a
"single area or region." The demonstrated economic advantages of the Merger
resulting in nearly $2 billion in net non-production savings and $98 million in
net fuel-related savings (as described below) also support the finding that the
single area or region test is met, consistent with the Commission's tradition of
balancing the various objectives of the 1935 Act. As discussed immediately
below, the size of the area or region in which the Combined Company will operate
will not result in the evils which the 1935 Act was meant to eliminate; namely,
it does not impair the advantages of localized management, efficient operation
or effective regulation.
(iv) Localized Management, Efficient Operation and Effective Regulation
Section 2(a)(29)(A), like Section 10(b)(1) discussed above, requires
the Commission to consider the size of the combined system. Section 2(a)(29)(A)
has been interpreted to require that the combined system must not be so large as
to impair (considering the state of the art and
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(36) 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).
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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, and Energy Delivery and
Customer Relations business units. CSW completed a similar
reorganization process in 1994.
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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.
The Applicants expect that the impact of the Merger will be
predominantly confined to the merging of CSWS into AEPSC and the
establishment of a business unit and management structure which
looks very much like the existing structures of AEP and CSW. The
electric utility subsidiaries will continue to operate through the
regional offices with local service personnel and line crews
available to respond to customers needs. The Combined Company will
preserve the well established delegations of authority -- currently
in place at AEP and CSW -- which permit the local, district and
regional management teams to budget for, operate and maintain the
electric distribution system, to procure materials and supplies and
to schedule work forces in order to continue to provide the high
quality of service which the customers of AEP and CSW have enjoyed
in the past.
The orders of the Oklahoma Commission, the Arkansas Commission, the
Indiana Commission, the Kentucky Commission, the Louisiana
Commission, and the Michigan Commission approving the Merger, as
well as the order of the Texas Commission finding the Merger
consistent with the public interest, impose an extensive list of
service quality standards on the utility operating companies
operating within their states. In Oklahoma and Michigan, the
Oklahoma Commission and the Michigan Commission established
standards with respect to (i) customer service center calls, (ii)
responses to requests for service, (iii) billing adjustments, (iv)
customer satisfaction, and (v) reliability performance. The
Louisiana Commission, in a service quality inquiry proceeding, has
recently established customer service, staffing, and tree standards
for SWEPCO. In Arkansas, Louisiana, Indiana, Kentucky, and Michigan,
the state commissions required that the Combined Company maintain or
improve historical reliability performance levels. Moreover, the
Texas Commission and the Louisiana Commission have recently been
active in promoting utilities' responsiveness to customers and are
expected to closely monitor the Combined Company's performance in
this regard. See, e.g., Public
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Utility Commission of Texas Substantive Rule 25.21 et seq.;
Louisiana Public Service Commission General Order of April 30, 1998.
Likewise, the order of the Texas Commission approved service quality
standards and provisions to ensure the continuity of CSW's local
management and organizational structure following the Merger. For
example, in Texas Applicants have agreed to (i) freeze CSW operating
company field positions and customer service jobs until October of
2000, (ii) maintain a bargaining and decision-making presence in the
CSW region with authority to enter binding agreements with wholesale
customers up to at least $3 million, (iii) designate an employee who
will act as a contact to the Texas Commission and consumer advocates
seeking information regarding affiliate transactions and personnel
transfers, and (iv) designate an employee or agent in Texas who will
act as a contact for retail consumers regarding service and
reliability concerns. In short, the customer service and field
operations management structures of AEP and CSW, which are
responsive to local needs, will be left essentially intact after the
Merger. Accordingly, the advantages of localized management will not
be impaired.
- Efficient Operation
As discussed above in the analysis of Section 10(b)(1), the size of
the Combined Company will not impede efficient operation; rather,
the Merger will result in significant economies and efficiencies as
described in Item 3.B.2 below. Economic dispatch (as described in
Item 1.B.3) is more efficiently performed on a centralized basis
because of economies of scale, standardized operating and
maintenance practices and closer coordination of system-wide
matters.
Both AEP and CSW have efficient generating facilities that were
recently noted by Public Utilities Fortnightly as being the fourth
and sixth most efficient in the utility industry (September 1, 1998
report). In addition, AEP and CSW have consistently been rated in
the top five utilities in the American Society for Quality and The
University of Michigan Business Schools American Customer
Satisfaction Index (ACSI). In the 1997 ACSI survey results which
were published in the February 16, 1998 issue of Fortune Magazine,
CSW tied for second place and AEP tied for third place, out of more
than 20 utilities surveyed. Because the Merger is expected to have
little impact on field personnel in either power generation or
transmission and distribution, AEP and CSW expect that the Combined
Company will to continue to perform at these high efficiency levels.
The divestiture of the Texas and Oklahoma generating assets will not
adversely affect the Combined Company's ability to operate on an
efficient basis. The Combined Company will jointly dispatch
generating units under its control, make economic purchases of
power, and supply power to its customers. The fact that certain
generating capacity will
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no longer be controlled by the Combined Company will not change the
centrally coordinated, least-cost approach to operating the combined
system.(37)
- Effective Regulation
The Merger will not impair the effectiveness of regulation at either
the federal or state level.
On the federal level, the Combined Company will continue to be
regulated by the Commission. The electric utility subsidiaries of
the Combined Company will continue to be regulated by the FERC with
respect to interstate electric sales for resale and transmission
services, by the NRC with respect to the operation of nuclear
facilities, and by the FCC with respect to certain communications
licenses. The jurisdiction of other federal regulators is also not
affected.
FERC declined to set the issue of effectiveness of regulation for
hearing. Indeed, the FERC concluded that Applicants had adequately
addressed the FERC's concerns about its own jurisdiction and that
state commissions could "impose in their own proceedings appropriate
conditions to ensure that there is no impairment of effective
regulation at the state level." 85 FERC at 61,821-822. Thus, FERC
has already concluded that the Merger will not impair the
effectiveness of regulation and that the issue does not merit
further investigation.
On the state level, the Commission has found that the effectiveness
of regulation is not impaired where the same state regulators have
jurisdiction both before and after a merger. See, e.g., Conectiv,
supra; GPU, supra. In finding that regulation is not impaired, the
Commission has also emphasized that the various state regulators
have approved the combination. Entergy, supra. The electric utility
subsidiaries of CSW will continue to be regulated by the state
commissions of Arkansas, Louisiana, Oklahoma and Texas with respect
to retail rates, service and related matters. The electric utility
subsidiaries of AEP will continue to be regulated by the state
commissions of Indiana, Kentucky, Michigan, Ohio, Tennessee,
Virginia, and West Virginia with respect to retail rates, service
and related matters.(38)
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(37) In fact, under the recent order of the Texas Commission, most
of the generating capacity being divested will be subject to recall by the
Combined Company during peak months to ensure that adequate capacity is
available to serve native load. See Texas Order, page 15.
(38) The AEP and CSW management structures are designed to
facilitate communications and relationships with state regulators. Each company
has established State offices which have responsibility for regulatory,
environmental, and corporate communications and have other external relations
purposes. These state offices provide a single point of contact with each of the
state regulatory and environmental offices and have the responsibility for
handling all regulatory contacts, including making regulatory filings and
answering customer inquiries to the regulatory commissions. It is expected that
these offices will be left essentially intact after the Merger.
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The FERC's conclusion that the states will take appropriate action
to protect their jurisdiction was correct.(39) The best evidence of
this is that none of the state commissions which regulate the AEP
and CSW utility subsidiaries has raised as an objection impairment
of its ability to regulate the Combined Company after the Merger, or
any other objection, in submissions to the Commission. In fact, the
order of the Texas Commission approved several provisions designed
to ensure the effectiveness of its regulatory authority over the
Combined Company's operations in Texas. Among other things, these
provisions include (i) a requirement that the Combined Company
continue to comply with the Texas Commission's transmission pricing
rules in ERCOT, (ii) a commitment by the Combined Company not to
withdraw from either ERCOT or the SPP without the Texas Commission's
prior approval, and (iii) a commitment that the Combined Company
will not contend in any forum that the jurisdiction of the Texas
Commission over any of CSW's operating companies located in Texas
changed as a result of the Merger. Thus, rather than impairing the
Texas Commission's regulatory authority, the order specifically
safeguards that authority.
Moreover, the Merger Agreement requires approvals from all
regulatory authorities having jurisdiction over the Merger as a
condition to the consummation of the Merger. The Merger has been
approved by the state commissions in Oklahoma, Arkansas, Louisiana,
Indiana, Kentucky, and Michigan, and the order of the Texas
Commission finds that the Merger is consistent with the public
interest. Applicants are working closely with other regulators to
obtain the remaining approvals (as described below in Item 4).
b. Section 11(b)(1) (Acquisition of Non-Utility Interests)
Section 11(b)(1) of the 1935 Act also requires that a registered
holding company limit its operations to a single integrated public utility
system and "such other businesses as are reasonably incidental, or economically
necessary or appropriate to the operations of such integrated public-utility
system." Each of CSW's non-utility business interests conforms to the "other
business" standards of the 1935 Act as previously determined by the Commission.
The indirect acquisition by AEP of CSW's non-utility businesses in no way
affects the functional relationship of these businesses to the Combined
Company's core electric business following the Merger. See Item 3.F below for a
detailed discussion on the acquisition by AEP of CSW's non-utility businesses.
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(39) The Oklahoma, Kentucky, Arkansas, and Indiana Commissions
conditioned the approval of the Merger on Applicants' agreement not to assert in
proceedings before that state commission, or in court proceedings involving
orders of that state commission, that the authority of the Commission as
interpreted in Ohio Power v. F.E.R.C., 554 F.2d 779 (D.C. Cir. 1992) cert.
denied, 498 U.S. 73 (1992) impairs that state commission's ability to examine
the reasonableness of non-power affiliate costs to be passed through to that
state's retail consumers. The order of the Texas Commission contains a similar
provision.
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c. Section 11(b)(2)
Section 11(b)(2) of the 1935 Act directs the Commission "to ensure
that the corporate structure or continued existence of any company in the
holding-company system does not unduly or unnecessarily complicate the
structure, or unfairly or inequitably distribute voting power among security
holders, of such holding-company system." The Merger is consistent with Section
11(b)(2). The resulting capital structure is not unduly complicated as discussed
in Item 3.A.3 above. See, e.g., Sierra Pacific Resources, HCAR No. 24566 (Jan.
28, 1988), aff'd Environmental Action, Inc., 895 F.2d 1255 (D.C. Cir. 1990)
(Commission incorporates its Section 10(b)(3) capital structure analysis into
its Section 11(b)(2) corporate structure analysis). Voting power is equitably
and fairly distributed among the security holders of each of AEP and CSW and
their current subsidiaries, all of which have been approved by the Commission in
previous proceedings. The shareholders of AEP and CSW, respectively, have
overwhelmingly approved the shareholder actions necessary to effect the Merger
or the Merger itself.
Immediately following the Merger, AEP will be a registered holding
company with respect to CSW, which, in turn, will be a registered holding
company with respect to the electric utility subsidiaries and other subsidiaries
it currently owns (with the exception of CSWS, which will be merged into AEPSC,
and possibly CSW Credit, which may be directly held by the Combined Company).
See Exhibit E-6. Although it is intended that these interests will be
restructured, the final ownership structure has not yet been determined.
Accordingly, Applicants request that CSW survive as a holding company interposed
between AEP and the electric utility subsidiaries and a portion of the other
subsidiaries it currently owns for a period of up to eight years following the
closing of the Merger.
Applicants have determined that the proposed corporate structure of
the Combined Company following the Merger will be in the best interests of the
Combined Company's shareholders and ratepayers. The continued existence of CSW
as an intermediate holding company will result in AEP having a tax basis in CSW
equal to the aggregate tax basis of the CSW shareholders in CSW prior to the
Merger. This tax basis would be lost if CSW were not retained as an intermediate
holding company. See Exhibit J for an explanation of certain relevant tax basis
issues.(40) 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
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(40) Section 355 of the Internal Revenue Code contains certain
statutory provisions with respect to a "tax-free" distribution of the stock of a
subsidiary corporation by a controlling corporation. Of particular note are two
statutory requirements addressing certain elements of ownership periods which
must be complied with in order for a distribution of the stock of a controlled
corporation to be eligible for the favorable tax benefits of section 355.
Section 355(d) places limitations on the application of section 355 for certain
distributions of stock acquired by purchase (within the meaning of section
355(d)), within five years of the date of such acquisition. In addition, section
355(e) places a two year restriction on changes of control of a distributed
corporation. The limitation for changes of control are for changes occurring
within two years before or two years after the date of a distribution.
Therefore, to avoid triggering section 355(d), such distribution must occur more
than five years from the date of purchase, and there can be no change of control
of the distributed corporation within two years before or after such
distribution.
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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).(41)
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
- ------------
(41) Applicants note that SWEPCO, a wholly owned electric
public-utility operating subsidiary of CSW, is technically a registered holding
company under the 1935 Act by virtue of its 47.6% ownership interest in a
company (which technically is an `electric utility company' under the 1935 Act)
whose assets at the end of 1997 accounted for approximately .02% of SWEPCO's
total assets (based on SWEPCO's and its subsidiary's total assets at year-end
December 31, 1997, and November 30, 1997, respectively). Applicants acknowledge
that questions could be raised under Section 11(b)(2) if SWEPCO were to remain a
holding company within the Combined Company following the Merger. Accordingly,
Applicants hereby commit to take appropriate action to eliminate SWEPCO's
holding company status following the Merger.
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continued existence of CSW are necessary and appropriate in serving the
interests of the Combined Company, its shareholders and ratepayers.
(i) The Existence of Two Tiers of Registered Holding Companies in
a Single Integrated Public-Utility System Is Not Prohibited
under the 1935 Act
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).(42) The legislative history
of the 1935 Act confirms that Congress's express authorization of two tiers of
holding companies in a registered holding company system was consistent with its
intent in passing the 1935 Act. While the version of the 1935 Act originally
passed by the Senate contained a provision, Section 11(b)(3), that required that
within five years all holding companies should cease to be holding companies
unless the equivalent of a certificate of convenience and necessity were
obtained from the Federal Power Commission, see American Power & Light Co. v.
SEC, 329 U.S. 90, 146, 147 (1946) (citing to S. 2796, 74th Cong., 1st Sess.),
the bill that became law replaced this section with the "great-grandfather
clause" of Section 11(b)(2). See 79 Cong. Rec. 14620 (August 24, 1935).
The 1935 Act is silent regarding whether a registered holding
company system with two tiers of holding companies is limited to one registered
holding company. However, the Commission's Rules promulgated under the 1935 Act
expressly envision a holding company system with more than one registered
holding company. Rule 1(c) provides that "where any holding company system
includes more than one registered holding company, the annual report shall be
filed by the top registered holding company in such system." Similarly, the
instructions to Form U5S (relating to holding company annual reports) track the
requirements of Rule 1(c), defining "holding company system" to mean "the parent
registered holding company together with all its subsidiary companies, including
all subsidiary registered holding companies."(43) See
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(42) The `great-grandfather clause' of Section 11(b)(2) provides
that `the Commission shall require each registered holding company (and any
company in the same holding-company system with such holding company) to take
such action as the Commission shall find necessary in order that such holding
company shall cease to be a holding company with respect to each of its
subsidiary companies which itself has a subsidiary company which is a holding
company.' See also, Entergy, supra, (`Section 11(b)(2) allows three tiers of
companies in a registered holding company system.').
(43) Rule 1, adopted in 1941, was amended in 1951 to include the
current formulation of subsection (c). HCAR No. 10432 (Mar. 12, 1951). Prior to
1951, each registered holding company in a holding company system was required
to file its own separate annual report on Form U5S. Id. The current formulation
of Rule 1(c) was adopted one year before the Commission `largely completed' its
task of `simplifying and reorganizing the complex financial and corporate
structures of holding company systems as required by section 11.' See 1995
Report at viii. Since 1951, the Commission has amended Rule 1 twice, without
altering the language of Rule 1(c). See HCAR No. 17435 (Jan. 25, 1972) (imposing
a 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.).
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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).
(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).
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<PAGE> 100
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.(44) Vermont Yankee,
supra.
In sum, the 1935 Act itself and the Rules thereunder, the policies
behind the Act, and the basic Commission interpretations of Section 11(b)(2),
all point to an obvious conclusion: the transitional survival of CSW is
consistent with the standards of Section 11(b)(2). Nevertheless, additional
discussion of the role of tax considerations under the Commission's
interpretation of the 1935 Act is helpful in light of several cases decided by
the Commission in the early-1950s and before. Not only are these cases
distinguishable from the case at hand, but other cases serve to support the
conclusion that the Applicants meet the standards of Section 11(b)(2).
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(44) The Commission has in recent years recognized that registered
holding companies may organize subsidiaries, including intermediate
subsidiaries, for various business and legal purposes. See, e.g., Exemption of
Acquisition by Registered Public-Utility Holding Companies, HCAR No. 26667 (Feb.
14, 1997) (modifying proposed Rule 58 to allow a registered holding company
system to use an intermediate subsidiary to invest in energy-related companies,
noting that use of such an intermediate subsidiary "could further insulate the
holding company and its other subsidiaries . . . from any direct losses that
could occur with respect to Rule 58 investments"); 1995 Report at 94 (noting
that in the 1980s and 1990s, registered holding companies expanded their use of
separate subsidiaries to engage in other activities, including the formation of
EWGs and FUCOs); Cinergy, HCAR No. 26376 (Sept. 21, 1995) (authorizing the
acquisition of subsidiaries organized, in part, for tax planning purposes).
Similarly, Applicants' proposal to retain CSW as an intermediate holding company
is for a legitimate business purpose, to preserve appropriate tax treatment of
certain corporate transactions that may occur in the future.
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(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
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<PAGE> 102
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).(45) These decisions are not
apposite here, however, where the Commission has not identified any unnecessary
or undue complication that would result from the post-Merger transition
structure the potential tax savings would inure to the Combined Company itself
for the benefit of all shareholders alike.
The temporary survival of CSW as a registered holding company to
further the interests of the Combined Company, its shareholders and ratepayers,
will meet all of the standards of the 1935 Act. The transitional corporate
structure will not create unnecessary or undue complications under Section
11(b)(2), and the significant, potential tax savings outweigh any negligible
complications and costs associated with CSW's survival.
2. Section 10(c)(2)
Section 10(c)(2) requires that the Commission approve a proposed
transaction if it will serve the public interest by tending towards the
economical and efficient development of an integrated public utility system. For
the reasons discussed above, the Combined System will be integrated. The Merger
will also tend towards the economic and efficient development of the Combined
System. This Section 10(c)(2) standard is met where the likely benefits of the
acquisition exceed its likely costs. City of Holyoke, supra.
The projected savings have not changed since the initial filing of
this Application. Applicants continue to project $1,966 million of net non-fuel
cost savings over the ten-year period immediately following consummation of the
Merger. The State settlements have not affected these estimates because the
States that have approved the Merger have accepted the Applicants' proposal to
guarantee ratepayers certain Merger-related savings, regardless of whether these
savings are actually achieved. The Applicants have also committed not to pass
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(45) In Portland Electric Power Company, HCAR No. 6365 (Jan. 14,
1946), supplemented on other grounds, 24 SEC 423 (1946), approved by, United
States District Court for District of Oregon (Order, June 29, 1946), aff'd, 162
F.2d 618 (9th Cir. 1947), the Commission, reviewing proposed plans of
reorganization under Section 11(f), found that the continued existence of a
shell holding company solely for the purpose of seeking tax advantages not then
available under applicable law was inimical to the standards of Section
11(b)(2). Here, by contrast, the economic and tax benefits sought by the
retention of CSW as a sub-holding company will accrue under the presently
existing tax laws.
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merger costs in excess of merger savings on to ratepayers. Based upon the
resolution of issues related to the allocation of Merger-related savings between
customers and shareholders of the Combined Company in the states which have
approved the Merger, Applicants have guaranteed that approximately 55% of the
projected savings from the Merger will be passed through to the respective
customers of each of the Combined Company's utility operating companies. In
addition, FERC-jurisdictional customers will receive the benefits of Merger
savings in future rate proceedings or through their current formula rates.
Applicants also anticipate net fuel-related savings of approximately
$98 million over this same period that will be passed on to customers. J. Craig
Baker's testimony before the FERC (a copy of which is included in Exhibit D-1.1
and is incorporated by reference) explains that these savings will result from
the joint dispatch of energy by the Combined Company. In this regard,
fuel-related savings will result from the economic transfer of energy between
the east zone and the west zone companies in order to displace relatively higher
cost generation in one zone with relatively lower cost generation from the other
zone. At the present time, the east zone operating companies and the west zone
operating companies, respectively, interchange power within their zones under
the terms of their respective operating agreements for the purpose of minimizing
generation costs. Through the Merger, the Combined System will create additional
opportunities for cost-effective energy transfers. In addition, based on the
projected resource needs of both companies over the 1999-2002 time period, it
appears that capacity transfers of up to 250 MW from the east zone to the west
zone could be made.(46) Thus, the Merger will allow the Combined Company to
realize the "opportunities for economies of scale, the elimination of duplicate
facilities and activities, the sharing of production capacity and reserves and
generally more efficient operations" described by the Commission in AEP, supra.
The nonproduction cost savings resulting from the Merger are set
forth in the testimony of Thomas J. Flaherty before the Texas Commission, a copy
of which is included in Exhibit D-5.1 and incorporated by reference. As
explained by Mr. Flaherty, the Combined Company is expected to achieve the
following nonproduction costs savings:
<TABLE>
<CAPTION>
Savings Category Millions
---------------- --------
<S> <C>
Elimination of Duplicate Corporate and Operations Support Staffing (a) $ 996
Elimination of Duplicate Corporate and Administrative Programs
Administrative and General Overhead (b) 74
Advertising 20
Association Dues 4
Benefits 85
Credit Facilities 1
Directors' Fees 6
Facilities 81
Information Services (c) 440
Insurance 71
</TABLE>
- ------------------------
(46) Because of the volatility in the marketplace for firm
capacity, Applicants have not attempted to quantify the capacity savings or
reflect them in the fuel-related savings at this time.
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<PAGE> 104
<TABLE>
<S> <C>
Professional Services (d) 213
Research and Development 11
Shareholder Services 9
Telecommunications 29
Purchasing Economies (Not Fuel-related) (e) 367
-----
Total Savings 2,407
Less: Costs to Achieve (f) (248)
Pre-merger Initiatives (193)
-----
Net Savings $1,966
=====
</TABLE>
(a) The position reductions are attributable to the Merger. The reduction
opportunities arise from overlap and duplication in functional performance,
rather than from stand-alone initiatives unrelated to the Merger. The total
corporate and operations support position reductions were estimated to be
1,061 positions.
(b) These costs are variable with the total number of positions and change as
the number of positions increase or decrease. As position reductions are
achieved through the Merger, miscellaneous overhead expenses are also
reduced.
(c) When the Merger is consummated, the Combined Company plans to consolidate
the respective IS departments which will eliminate duplicative system
development hardware, software and consolidate data center costs.
(d) The savings calculated were generated from the reduction of the combined
audit fees, legal fees, and general consulting services.
(e) Savings represent an estimated 7-8% reduction in total material costs due
to larger purchasing volumes and the availability of greater purchasing
power. This amount was determined based on the experience of other
companies, review of certain component per unit costs, management's
knowledge of vendors and potential approaches to material standardization
and vendor concentration.
(f) Does not include contingent change in control payments.
Assuming a March 31, 2000 closing, AEP and CSW estimate available
synergies and cost savings resulting from the Merger, net of costs necessary to
achieve these reductions, for each of the first ten years following the Merger
of approximately $17 million (9 months), $102 million, $135 million, $162
million, $181 million, $243 million, $255 million, $259 million, $267 million,
$275 million and $70 million (3 months), respectively, for a total of $1,966
million. The savings in the first five years are expected to be lower than in
the later years due to the costs incurred to achieve the savings. Of the $1,966
million in total anticipated net savings, Applicants estimate that approximately
$713 million of the total savings will be allocated to the west zone and
approximately $1,253 million will be allocated to the east zone. Moreover, even
though the savings are shown over 10 years only, it is expected that some of
these savings will continue to be realized over a much longer period. See
Testimony of Thomas J. Flaherty included in Exhibit D-5.1.
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The allocation of savings among the operating companies was made
using a Synergies Analysis prepared by Applicants and explained in more detail
in the testimony of Thomas Flaherty filed with the Texas Commission. First,
savings were categorized as either labor or non-labor. Labor savings were then
further categorized into a functional area and a sub-functional area. For
example, in his testimony filed with the Texas Commission, Mr. Russell Davis
first identified savings for the finance area. Within that area, savings were
then sub-categorized by payroll, accounts payable, general accounting, and other
activities. Each of these subcategories was given a work order and assigned an
allocation factor. General accounting, for example, received an allocation
factor based on the number of general ledger transactions. In this way, the
savings identified by work order and allocation factor were allocated to the
appropriate subsidiaries.
With respect to non-labor savings, the Synergies Analysis allocated
savings in the same manner as labor savings by categorizing savings into
functional and sub-functional areas. For example, the savings for professional
services are split into the sub-categories of legal, auditing, accounting and
finance, engineering and other. A synergy savings work order was assigned to
each functional and sub-functional area based on an analysis of the companies
benefiting from each area of savings. An allocation factor was assigned to each
work order based on an analysis of the savings. For example, professional
service savings for production engineering used the allocation factor "megawatts
of generating capacity." The Synergies Analysis then allocated the identified
savings to either the electric operating companies, the non-regulated
subsidiaries, or the service company.
In addition, Applicants allocated the costs to be incurred by
Applicants in order to achieve savings to their subsidiary companies on a
pro-rata basis. If for example, CPL received 12% of the savings, then CPL would
pay 12% of the costs to achieve the savings and other related costs. The
following table provides the amount of estimated Merger savings which has been
allocated to each of AEP's and CSW's subsidiaries:
<TABLE>
<CAPTION>
Total Savings less Pre-
Merger Initiatives and Cost
Company Name to Achieve ('000)
- ------------ -----------------
<S> <C>
AEP Regulated Savings
KgPCo 9,090
APCo 324,532
KPCo 76,134
I&M 241,254
WPCo 9,298
OPCo 305,628
CSPCo 184,372
AEG 24
Cardinal Operating Company 1,872
Central Operating Company 12
Indiana-Kentucky Power Company 334
Ohio Valley Electric Cooperative 440
Buckeye Power Company 3,266
</TABLE>
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<TABLE>
<S> <C>
Central Appalachian Coal Co. -
Central Coal Co. 2
Central Ohio Coal Company 5,732
Windsor Coal Co. 6,776
Southern Ohio Coal Co. 22,384
Southern Appalachian Coal Co. -
Cedar Coal Co. 6
Water Transportation Division 5,218
Cook Coal Terminal 1,320
Price River Coal Co. -
Blackhawk Coal Co. 6
Simco, Inc. 2
Conesville Coal Prep Co. 1,202
Sporn Plant Joint Books 2,920
Amos Plant Joint Books 2,910
Rockport Plant Joint Books 1,318
Gavin FGD 364
Tidd Plant PFBC Project -
Sporn Plant - OPCo Share -
Amos Plant - OPCo Share -
Rockport - I&M Share -
Rockport - AEG Share -
Carolina Power & Light 7,628
Non-affiliated 36
AEP Non-Regulated Savings 38,492
Total AEP Savings 1,252,572
CSW Regulated Savings
CPL 237,026
Energy Consulting SVCS 273
Joint Fuels Project 274
External Lab Services 24
PSO 159,773
SWEPCO 175,534
WTU 84,222
CSW Non-Regulated Savings 55,668
Total CSW Savings 712,794
Total Savings Less Cost to Achieve and Pre-Merger Initiatives 1,965,339
</TABLE>
The Applicants' estimates of Merger savings have been provided to
the staffs of all eleven state commissions which will have retail rate
jurisdiction over the Combined Company (Arkansas, Indiana, Kentucky, Ohio, West
Virginia, Michigan, Tennessee, Virginia, Louisiana, Oklahoma and Texas). In each
of those states, the Applicants have responded to discovery requests from
participants, and have defended the proposed level of savings as being
achievable. In each of those states, the Applicants have either received state
commission orders or entered into stipulations with the commission's staff (and
other parties) which establish the level of
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savings that will be shared with ratepayers and which guarantee to consumers the
savings regardless of whether they are achieved. The amount of the savings as
well as Applicants' plans for allocating the savings have been approved by the
state commissions of Arkansas, Louisiana, Indiana, Kentucky, Oklahoma, Texas,
and Michigan.
Based upon the resolution of issues related to the allocation of Merger
related savings between customers and shareholders of the Combined Company in
the states which have approved the Merger, Applicants have guaranteed that
approximately 55% of the projected savings from the Merger will be passed
through to the respective customers of each of the Combined Company's utility
operating companies. For example, the Texas Commission approved rate reductions
totaling $221 million over six years for CSW's three utility subsidiaries
operating in the state. Similarly, the Oklahoma Commission issued an order
approving the Merger as being in the "public interest," freezing base rates
through 2003 and requiring 55% of Oklahoma's share of Merger-related savings to
be recovered by ratepayers in Oklahoma. In addition, Applicants have agreed to
make a $5,000,000 reduction to the revenue requirement otherwise determined by
the Oklahoma Commission to be reasonable in the event they seek a rate review
any time after January 1, 2003 through the end of the fifth year after the
effective date of the Merger.
The Arkansas Commission issued an order approving the Merger as being
in the "public interest" and providing a total rate cut of $6 million over the
five-year period following the Merger.
In Louisiana, Applicants agreed to a base rate freeze for 5 years and a
nonfuel savings sharing mechanism ("SSM") for eight years, which is a
formula-based methodology to be used to quantify merger savings. During the
first 14 months following the consummation of the Merger, the Combined Company
will retain 100% of the Merger savings and may use savings to reduce deferrals
of the Merger costs. Beginning in the 15th month, 50% of the Merger savings as
computed pursuant to the SSM will be passed through to consumers in Louisiana.
The SSM will be updated annually and continue for the remainder of the
eight-year period following the Merger's consummation. Applicants have estimated
that the customer rate credits in Louisiana will total more than $18 million
over the eight-year period.
Likewise, Merger-related savings plans have been approved by the state
commissions of Indiana, Michigan, and Kentucky. The order of the Indiana
Commission provides for a credit to ratepayers of approximately 55% of the
$121.2 million, or $66.6 million, of Merger savings expected to be achieved over
the first eight years following the Merger. The order of the Indiana Commission
further provides for an extension of an existing rate freeze to January 1, 2005.
The order of the Kentucky Commission establishes merger savings of approximately
$51.6 million over the first eight years following the Merger, with consumers
receiving the benefit of approximately $28.4 million, or 55% of the total
savings. In addition, the order of the Kentucky Commission provides that
Kentucky Power, AEP's utility subsidiary, will not request an increase in its
existing base rates until the later of January 1, 2003, or three years from the
effective date of the Merger. The order of the Michigan Commission provides for
a credit to ratepayers of 55% of the $25.4 million, or approximately $14
million, of the total savings. Once the Merger is consummated, Michigan
customers will receive their share of the savings through credits of
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approximately 1 percent to 1.5 percent every year for at least eight years. In
addition, the order of the Michigan Commission provides that I&M, AEP's utility
subsidiary, will not request an increase in its existing base rates until
January 1, 2005. Although specific determinations of the net savings to each
group in the remaining states cannot be finalized until all regulatory
proceedings have been completed, it is expected that each group will realize
approximately 55% of the net savings.
In the states that have approved the Merger, Applicants have agreed
to mechanisms for sharing the savings which utilize the Applicants' estimate and
provide guaranteed net rate reduction riders for periods ranging from five to
eight years. In other words, if the Applicants do not achieve the estimated
level of savings, the consumers will nonetheless obtain the benefits of the
estimated Merger savings. This provides the requisite incentive for Applicants
to achieve the estimated Merger savings.
The Oklahoma Commission and the Texas Commission approved
Applicants' divestiture of generation assets based upon the mitigation measures
that Applicants proposed to protect ratepayers. The order of the Texas
Commission approved several significant provisions designed to protect consumers
from the economic effects of the divestiture, including (i) a requirement that
proceeds from the CPL divestiture be used to reduce stranded costs of the
Combined Company, (ii) a provision that limits any adverse impact on consumers
related to the divestiture of the units, and, most significantly, (iii) a
provision that guarantees rate reductions totaling $221 million to the Combined
Company's ratepayers in Texas over the six years following the Merger.
In Oklahoma, as part of the stipulation approved by the Oklahoma
Commission, the Applicants committed to hold Oklahoma retail consumers harmless
from adverse effects related to CSW's divestiture of 300 MW of generation
capacity in Oklahoma. Applicants agreed to make an "after the fact" calculation
of margins both before and after the divestiture. If negative margins result,
Oklahoma consumers will be held harmless from the additional costs associated
with the divestiture.
These expected savings exceed the anticipated savings in a number of
other acquisitions approved by the Commission. See, e.g., New Century Energies,
supra (expected savings of $770 million over 10 years); Entergy, supra (expected
savings of $1.67 billion over ten years); Northeast I, supra (estimated savings
of $837 million over 11 years); IE Industries, HCAR No. 25325 (June 3, 1991)
(expected savings of $91 million over ten years); CINergy, supra (estimated
savings of approximately $895 million over ten years).
The Commission has long recognized that, in reviewing an application
under Section 10(c)(2), it is appropriate to consider "not only benefits
resulting from the combination of utility assets, but also financial and
organizational economies and efficiencies." WPL Holdings, supra; see also
Chevron Holdings, Inc., HCAR No. 27122 (Dec. 27, 1999); Roanoke Gas Co., HCAR
No. 26966 (April 1, 1999); BEC Energy, HCAR No. 26874 (May 15, 1999); Western
Resources, Inc., HCAR No. 26783 (Nov. 24, 1997); KU Energy Corp., HCAR No. 25409
(Nov. 13, 1991). As the Commission has observed, with reference to the
requirement of Section 10(c)(2) that a proposed combination yield economies and
efficiencies, "specific dollar forecasts of future savings are not necessarily
required; a demonstrated potential for economies will suffice even
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when these are not precisely quantifiable." Centerior, supra (citation omitted).
If economies and efficiencies are anticipated from the transaction as a whole,
the Commission is justified in approving it. See Madison Gas, at page 9 ("The
Act, however, requires that the "acquisition" as a whole, not merely the
construction of an interconnection, tend toward efficiency and economy."); cf.
Union Electric Company, 45 SEC 489, 495-96 (1974) (approving acquisition of
assets not physically connected to the rest of the system since the acquisition
would "contribute in the main to the development of an integrated system."); New
Century Energies, supra, at pp. 9-10 (approving the acquisition of utility
assets not physically interconnected where "their combination will result in a
larger, financially stronger company, that, through the pooling of resources and
expertise, will be able to achieve increased financial stability and strength,
greater opportunities for earnings and dividend growth, reduction of operating
costs, deferral of certain capital expenditures, efficiencies of operations,
better use of facilities for the benefit of customers, seasonal diversity of
demand, improved ability to use new technologies, greater retail and industrial
sales diversity and improved capability to make wholesale power purchases and
sales.")
Two of these principal additional benefits relate to the Combined
Company's generation mix and system reliability. The Merger will result in a
more balanced generation mix that is less susceptible to fuel price volatility
and supply interruptions. In addition, the Combined System will be better
situated to provide more reliable electric service than is possible for AEP and
CSW on a stand-alone basis. For example, the Combined System will share in a
larger generating base after the Merger. As a result, the Combined System will
have more generating resources to call on when units are down for maintenance or
due to an unscheduled outage. In addition, each of AEP and CSW has a higher risk
of unserved load than would be the case for the Combined System, since each of
AEP and CSW on a stand-alone basis has access to fewer interconnections to
neighboring systems for emergency support.
C. SECTION 10(f)
Section 10(f) provides that:
The Commission shall not approve any acquisition as to which an
application is made under this section unless it appears to the satisfaction of
the Commission that such State laws as may apply in respect of such acquisition
have been complied with, except where the Commission finds that compliance with
such State laws would be detrimental to the carrying out of the provisions of
section 11.
Each of AEP's and CSW's obligation to consummate the Merger is
conditioned, among other things, on the receipt of all requisite state
regulatory approvals. State regulatory approvals have been obtained from the
Oklahoma Commission, the Arkansas Commission, the Indiana Commission, the
Louisiana Commission, the Kentucky Commission, and the Michigan Commission. An
order has been issued by the Texas Commission which found the Merger to be
consistent with the public interest. See Item 4, infra, for further discussion
of regulatory approvals and the standard of review applicable to such approval.
When the other approvals have been obtained, the Merger will comply with Section
10(f).
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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, on or before December 31, 2000, 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; provided, that any newly
formed non-utility subsidiaries will engage only in activities for which no
additional authority is needed under the 1935 Act) 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
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to 100% of its consolidated retained earnings for investment in EWGs and FUCOs
as provided by Central and South West Corp., et al., HCAR No. 26653 (Jan. 24,
1997) shall cease. To the extent that AEP and CSW were authorized, pursuant to
Sections 32 and 33 of the 1935 Act and the rules thereunder, to invest up to
100% of their consolidated retained earnings in EWG and FUCO interests, the
Combined Company should also be authorized to invest up to 100% of its combined
consolidated retained earnings in EWG and FUCO interests. Applicants therefore
propose that, upon consummation of the Merger, the authority of the Combined
Company to issue and sell securities in an amount up to 100% of its consolidated
retained earnings for investment in EWGs and FUCOs shall be the same as that
provided by American Elec. Power Co., HCAR No. 26864 (Apr. 27, 1998) and
American Elec. Power Co., HCAR No. 26516 (May 10, 1996), except that for
purposes of determining the amount of consolidated retained earnings as
contemplated by American Elec. Power Co., HCAR No. 26864 (Apr. 27, 1998) and
American Elec. Power Co., HCAR No. 26516 (May 10, 1996), "consolidated retained
earnings" shall consist of the consolidated retained earnings of the Combined
Company.
Currently, the CSW System uses short-term debt, primarily commercial
paper, to meet working capital requirements and other interim capital needs. In
addition, to improve efficiency, CSW has established a system money pool (the
"Money Pool") to coordinate short-term borrowings for CSW, its U.S. electric
utility subsidiary companies and CSWS, as set forth in various Commission orders
(which orders are summarized in Exhibit I-2 attached hereto). AEP has no
equivalent to the Money Pool. Applicants hereby request authorization, upon
consummation of the Merger and on the same terms and conditions as set forth in
the orders summarized in Exhibit I-2, to permit: (1) the Combined Company, AEP's
U.S. electric subsidiary companies and other subsidiaries(47) and AEPSC to
participate in the Money Pool, and (2) the 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
- --------
(47) The other subsidiaries include Cedar Coal Co., Central Appalachian
Coal Co., Central Coal Co., Central Ohio Coal Co., Colomet, Inc., Simco Inc.,
Southern Appalachian Coal Co., Southern Ohio Coal Co., Windsor Coal Co.,
Blackhawk Coal Co., Conesville Coal Preparation Company, Franklin Real Estate
Company, Indiana Franklin Realty Company and West Virginia Power Co., and are
referred to herein as the "Coal Subsidiaries." Each of the Coal Subsidiaries is
a wholly owned subsidiary of one or more AEP U.S. electric subsidiary companies,
except Franklin Real Estate Company, which is a direct subsidiary of AEP, and
Indiana Franklin Realty Company, which is a subsidiary of Franklin Real Estate
Company.
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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 Credit files quarterly reports with the Commission under Rule 24 of
the 1935 Act, which reporting obligation will be assumed by New Credit following
consummation of the Merger.
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).
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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
As described in Item 1.B.1 above, AEPSC is a service company that,
pursuant to service agreements with AEP and each of the subsidiary companies of
AEP, provides various technical, engineering, accounting, administrative,
financial, purchasing, computing, managerial, operational and legal services to
AEP and 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. 27006 (April 14, 1999) (order
authorizing amendment to service agreement between service company and operating
subsidiaries).
Similarly, CSWS is a service company which, pursuant to service
agreements signed with CSW and each of the subsidiary companies of CSW, provides
various technical, engineering, accounting, administrative, financial,
purchasing, computing, managerial, operational and legal services to CSW and to
each of the CSW subsidiary companies. Pursuant to the service
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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).
On or before December 31, 2000, 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 and the
subsidiary companies of the Combined Company. 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 among AEPSC, AEP and
the subsidiary companies of the Combined Company, 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 AEP and 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.(48) Costs incurred in connection with
services performed for AEP or a specific subsidiary company will be billed 100%
to that company. Costs incurred in connection with services performed for two or
more 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 companies will be allocated in proportion to how either
direct salaries or total costs are billed to the companies depending on the
nature of the indirect costs themselves. The time AEPSC employees spend working
for each company will be billed to and paid by the applicable company on a
monthly basis, based upon time records. Each company will maintain separate
financial records and detailed supporting records showing AEPSC charges.
Moreover, AEPSC is required to obtain the approval of the Commission "in the
event of a contemplated change in the organization of AEPSC, the type and
character of the companies to be serviced, the methods of allocating costs to
associate companies, or an increase in the scope or character of the services to
be rendered subject to Section 13 of the 1935 Act, or
- --------
(48) AEPSC records and bills its cost to associated companies in
accordance with the Uniform System of Accounts, as amended, prescribed by the
Commission for mutual and subsidiary service companies under the Public Utility
Holding Company Act 1935 using the accounts therein and accounts contained in
the FERC's Uniform System of Accounts for Public Utilities and Licensees
(18C.F.R. 101).
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any rule, regulation, or order thereunder."(49) In order to comply with this
requirement, AEPSC undertakes to provide the Commission with written notice of
any such proposed change not less than 60 days prior to the proposed
effectiveness of any such proposed change. If, upon the receipt of any such
notice, the Commission notifies AEPSC within the 60-day period that a question
exists as to whether the proposed change is consistent with the provisions of
Section 13 of the 1935 Act, or of any rule, regulation, or order thereunder,
then the proposed change shall not become effective unless and until AEPSC shall
have filed with the Commission an appropriate declaration regarding such
proposed change and the Commission shall have permitted such declaration to
become effective.
Several state commissions have already approved the Merger and included
codes of conduct that will govern the relationship between AEPSC, the operating
companies, and other affiliated companies. For example, the orders of the
Indiana, Kentucky, Louisiana, Michigan and Arkansas Commissions approving the
Merger all contain detailed guidelines relating to affiliate transactions. The
order of the Oklahoma Commission approving the Merger grants the Oklahoma
Commission and the State Attorney General access to the books and records of AEP
and its affiliates and subsidiaries (including their participation in joint
ventures) with respect to matters and activities that relate to Oklahoma retail
rates. The settlement with the staff of the Texas Commission requires compliance
with a detailed code of conduct governing activities among the Combined
Company's subsidiaries. These orders and agreements, consistent with state law,
generally require certain separations and safeguards between utility and
nonutility affiliates to prevent cross-subsidization and preferential treatment
of nonutility affiliates.
Applicants hereby request that the Commission approve the amended
service agreement among AEPSC, AEP 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 contains the AEPSC
(Post-Merger) Organization Chart. Exhibit B-3.5 describes the services that will
be performed by AEPSC after the Merger and lists the attribution bases
associated with each major service category. Exhibit B-3.6 contains the Proposed
Cost Allocation Policies and Procedures Manual of AEPSC which establishes
policies and procedures for the performance of services by AEPSC after the
Merger and includes Exhibits B-3 and B-3.5 as exhibits.
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
- --------
(49) See American Gas and Electric Service Corp., HCAR No. 1528 (May
15, 1939).
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initiated by AEPSC, by AEP, 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 company.
As a result of the centralization in AEPSC of the responsibilities previously
assigned to the officers of the 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 AEP and to each AEP subsidiary
company at the end of each month. These bills are reviewed for reasonableness
and approved on behalf of AEP and the AEP subsidiary companies by Corporate
Planning and Budgeting.
Management has developed strategic performance measures for 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 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 its subsidiaries, including those of AEPSC, to ensure that
proper internal controls exist and to
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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).(50)Such businesses have an operating
- --------
(50) A registered holding company may acquire and hold an interest in
an EWG, FUCO, and an exempt telecommunications company, without the need to
apply for or receive approval from the Commission (although the Commission
retains jurisdiction over certain related transactions with these entities).
Sections 32, 33 and 34 of the 1935 Act. Moreover, a registered holding company
may acquire "energy-related" companies meeting the Rule 58 safe harbor
conditions (including an investment ceiling) without the need for Commission
approval.
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or functional relationship to CSW's utility operations. See, e.g., Conectiv,
supra (the Commission has interpreted section 11(b)(1) "to require the existence
of an operating or functional relationship between the utility operations of the
registered holding company and its nonutility activities.")
Upon consummation of the Merger, the non-utility businesses of CSW will
become indirect subsidiaries of AEP. To the extent that Commission approval is
necessary for the acquisition of CSW's non-utility businesses, the acquisitions
should be approved because the indirect ownership of CSW's non-utility
businesses by AEP in no way affects the functional relationship of these
businesses to the Combined Company's core electric business following the
Merger. Moreover, acquisition of these businesses is in the public interest and
consistent with the applicable standards under the 1935 Act.
G. ORGANIZATION OF MERGER SUB; ACQUISITION OF MERGER SUB COMMON
STOCK
Merger Sub was organized solely for the purpose of effecting the Merger
and has not conducted any activities other than in connection with the Merger.
Merger Sub has no subsidiaries. Each share of common stock of Merger Sub, par
value $0.01 per share, to be issued to AEP and outstanding immediately before
the consummation of the Merger will be converted into one share of CSW Common
Stock upon consummation of the Merger. Thus, the sole purpose for Merger Sub is
to serve as an acquisition subsidiary of AEP for purposes of effecting the
Merger. Approval of this Application-Declaration will constitute approval of the
acquisition by AEP of the common stock of Merger Sub.
ITEM 4. REGULATORY APPROVAL
Set forth below is a summary of the material regulatory requirements
affecting the Merger. Failure to obtain any necessary regulatory approval or any
adverse conditions that are imposed in connection with any necessary regulatory
approval, including the failure to obtain appropriate ratemaking treatment, may
affect the consummation of the Merger.
In addition to required Commission approvals, the state utility
commissions of Arkansas, Louisiana, Oklahoma, and Texas, and the FERC, the FCC,
and the NRC have jurisdiction over various aspects of the transactions proposed
herein.(51)Further, both AEP and CSW are required to file notification and
report forms under the HSR Act with the DOJ with respect to the Merger.
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(51) AEP has U.S. electric utility subsidiaries operating in Ohio,
Indiana, Kentucky, Michigan, Tennessee, Virginia, and West Virginia. AEP
believes that the approval of the utility regulatory commissions in these states
is not required to consummate the Merger, and that these states therefore do not
have jurisdiction over this proposed transaction. Nevertheless, the Indiana
Commission, the Kentucky Commission and Michigan Commission have approved the
Merger, and AEP has been actively working with all of these state commissions
regarding both the FERC and state regulatory impacts of the transaction.
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Additional consents from or notifications to governmental agencies may be
necessary or appropriate in connection with the Merger.
Applicants already have obtained regulatory approvals of the Nuclear
Regulatory Commission, the Arkansas Commission, the Oklahoma Commission, the
Louisiana Commission, the Kentucky Commission, the Indiana Commission, and the
Michigan Commission. The Texas Commission issued an order finding the Merger to
be consistent with the public interest. An Initial Decision has been issued by a
FERC Administrative Law Judge approving the Merger. FERC issued an order
conditionally approving the Merger on March 15, 2000. On January 21, 2000, the
FCC approved the transfer of certain microwave licenses held by CSW. On February
2, 2000, DOJ notified Applicants that it had completed its review of the Merger
and that no further action is warranted.
A. ANTITRUST CONSIDERATIONS
The HSR Act and the rules and regulations thereunder provide that
certain transactions (including the Merger) may not be consummated until certain
information has been submitted to the Antitrust Division and the specified HSR
Act waiting period has expired or been terminated. Applicants filed their
respective pre-merger notification pursuant to the HSR Act in July 26, 1999. On
August 26, 1999, AEP and CSW received a request for additional information from
the Antitrust Division. AEP and CSW filed the additional information with the
Antitrust Division in November, 1999. On February 2, 2000, the Antitrust
Division notified Applicants that it had completed its review of the Merger and
that no further action is warranted.
The expiration or earlier termination of the HSR Act waiting period
would not permanently preclude the Antitrust Division from challenging the
Merger on antitrust grounds, but it would represent a decision by such agencies
that the Merger may be consummated without challenge under Section 7 of the
Clayton Act. If the Merger is not consummated within 12 months after the
expiration or earlier termination of the initial HSR Act waiting period, AEP and
CSW must submit new information to the Antitrust Division, and a new HSR Act
waiting period must expire or be earlier terminated before the Merger may be
consummated.
B. ATOMIC ENERGY ACT
CSW, through its wholly-owned subsidiary CPL, owns a 25.2% interest in
the STP, a two-unit nuclear electric generating station. The STP is operated by
STP Operating, a Texas non-profit corporation, which is jointly-owned by CPL and
the other owners of the STP. CPL holds NRC licenses with respect to its
ownership interests in the STP and STP Operating. Section 184 of the Atomic
Energy Act provides that no license may be transferred, assigned or in any
manner disposed of, directly or indirectly, through transfer of control of any
license to any person, unless the NRC finds that the transfer is in accordance
with the provisions of the Atomic Energy Act and gives its consent in writing.
On June 19, 1998, CPL sought approval from the NRC for the transfer of
control of its NRC licenses as a result of the Merger. The Application for
Transfers of Control Regarding Operating License No. NPF-76 and NPF-80 for the
STP is filed as Exhibit D-6.1. On November 5, 1998, the NRC approved the
transfer of control of CPL's NRC licenses with a condition that
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the Merger must be completed by December 31,1999. The NRC Order is filed as
Exhibit D-6.2, and incorporated by reference. On October 25, CPL requested an
extension of the date by which the Merger must be completed. On December 9,
1999, the NRC granted an extension to June 30, 2000. After the Merger, CPL, as
an operating utility subsidiary of the Combined Company, will continue to own
the identical pre-Merger interests in the STP and STP Operating.
C. FEDERAL POWER ACT
Section 203 of the FPA provides that no public utility may sell or
otherwise dispose of its jurisdictional facilities, directly or indirectly merge
or consolidate its facilities with those of any other person, or acquire any
security of any other public utility, without first having obtained
authorization from the FERC. On April 30, 1998, AEP and CSW filed a joint
application with the FERC seeking approval of the Merger, as supplemented on
January 13, 1999. See Exhibits D-1.1 and D-1.2. Under Section 203 of the FPA,
the FERC will approve a merger if it finds the merger to be "consistent with the
public interest."
On June 24, 1999, Applicants and the FERC trial staff filed the FERC
Stipulation resolving major issues related to the Merger, including all
significant competition and rate issues. In addition, FERC Trial Staff agreed to
support a finding that the Merger will have no adverse effect on competition.
The FERC Stipulation is filed as Exhibit D-1.3.
On November 23, 1999, the Administrative Law Judge at FERC issued an
Initial Decision which approved the Merger, a copy of which is filed as Exhibit
D-1.7 and incorporated by reference. On March 15, 2000, the FERC issued an
opinion and order (the "Merger Order") conditionally approving the Merger, a
copy of which is filed as Exhibit D-1.9 and incorporated by reference. The
Merger Order conditions FERC approval on the Combined Company's commitment to
certain interim and long-term conditions, many of which Applicants themselves
had proposed. FERC directed the Applicants to notify FERC within fifteen days of
the Merger Order whether they accepted the merger approval conditions. On March
27, 2000, Applicants filed a Notice with the FERC committing to comply with
those conditions.
On March 31, 2000, Applicants made a filing in compliance with FERC's
March 15, 2000 Merger Order, a copy of which is filed as Exhibit D-1.10 and
incorporated by reference. In their compliance filing, Applicants described
their plans to (i) implement interim transmission mitigation measures (from the
date the Merger is consummated to the date that the transmission facilities
located in the eastern zone are transferred to a FERC-approved RTO) and (ii) the
terms and conditions under which they would make interim sales of energy
(pending divestiture of specified generation capacity). Pursuant to the Merger
Order, Applicants may consummate the Merger sixty days after the March 31, 2000
filings and are not required to await a FERC ruling on those filings or on any
protests to the filings.
Only three parties have submitted protests to the March 31, 2000
filings, one of which subsequently withdrew its protest. The remaining two
protesting parties have filed a joint request for rehearing of the Merger Order.
Applicants also filed a request for rehearing of certain parts of the Merger
Order. Like the compliance filings, such requests for rehearing do not stay the
effect of the Merger Order. FERC issued an order on these requests on May 15,
2000, a copy of which is filed as Exhibit D-1.11 and incorporated by reference.
In that order,
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FERC denied the request jointly filed by the two protesting parties. With
respect to that portion of Applicants' request that sought to modify the
findings upon which certain interim transmission measures were predicated, FERC
noted that the Applicants did not seek to have the conditions themselves
modified or removed; accordingly, it found that Applicants were not aggrieved
and dismissed that portion of the request as moot. With respect to the other
portion of the Applicants' rehearing request, which dealt with a modification to
the pricing methodology for system energy exchanges between the AEP and CSW
zones after the Merger, FERC acknowledged the merit of Applicants' position,
granted rehearing, and reversed its modification.
D. COMMUNICATIONS ACT
CSW, itself or through one or more subsidiaries, holds various radio
licenses subject to the jurisdiction of the FCC under Title III of the
Communications Act. Under Section 310 of the Communications Act, no station
license may be assigned or transferred, directly or indirectly, except upon
application to and approval by the FCC. On July 26, 1999, Applicants filed with
the FCC for authority to transfer control of licenses held by several CSW
subsidiaries to AEP. See Exhibit D-9.1. On January 21, 2000, the FCC approved
the transfer of certain microwave licenses held by CSW. Applicants expect the
FCC to approve the transfer of the remaining licenses prior to the consummation
of the Merger.
E. ARKANSAS COMMISSION
SWEPCO is subject to the jurisdiction of the Arkansas Commission.
Pursuant to Section 23-3-306(b) of the Arkansas Statutes, and Arkansas
Commission approval is required before any person may merge with or otherwise
acquire control of a domestic public utility. The Arkansas Commission must
approve a merger application unless it finds that one or more of five adverse
circumstances would result from the transaction. The circumstances include an
adverse effect on the public utility's existing obligations or quality of
service, a reduction in competition for the provision of utility services within
the state, and an adverse effect on the financial condition of the public
utility.
On June 12, 1998, AEP, CSW and SWEPCO filed an application with the
Arkansas Commission seeking Arkansas Commission approval of the Merger, a copy
of which is filed as Exhibit D-2.1 and incorporated by reference. On August 13,
1998, the Arkansas Commission issued an order conditionally approving the
Merger, a copy of which is filed as Exhibit D-2.2 and incorporated by reference.
F. LOUISIANA COMMISSION
SWEPCO is subject to the jurisdiction of the Louisiana Commission.
Pursuant to Louisiana Statutes Section 45:1164, the Louisiana Commission is
granted general supervisory authority over public utilities operating in the
state and, under this authority, the Louisiana Commission has held that its
approval or non-opposition is required prior to the sale, lease, merger,
consolidation, stock transfer, or any other change of control or ownership of a
public utility subject to its jurisdiction. The Louisiana Commission reviews
merger applications pursuant to an 18 factor test that generally relates to the
impact of the transaction on competition,
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the financial condition of the utility, quality of service, public health and
safety, employment, and other similar "public interest" matters.
On May 15, 1998, AEP, CSW and SWEPCO filed an application seeking
Louisiana Commission approval of, or non-opposition to, the Merger, a copy of
which is filed as Exhibit D-3.1 and incorporated by reference. On July 29, 1999,
the Louisiana Commission voted to issue an order conditionally approving the
Merger, a copy of which is filed as Exhibit D-3.2 and incorporated by reference.
G. OKLAHOMA COMMISSION
PSO is subject to the jurisdiction of the Oklahoma Commission. The
Oklahoma Statutes concerning mergers and acquisitions of public utilities are
substantially identical to the sections of the Arkansas Statutes discussed
above. Oklahoma Commission approval is required before any person may merge with
or otherwise acquire control of an Oklahoma public utility.
On August 14, 1998, AEP, CSW and PSO filed an application with the
Oklahoma Commission seeking approval of the Merger, a copy of which is filed as
Exhibit D-4.1 and incorporated by reference. On May 4, 1999, an administrative
law judge recommended that the Oklahoma Commission approve the Merger subject to
certain conditions. Those conditions included the recommendation that Applicants
participate in an SPP study of the impacts of the effect of the Merger on the
transmission system of OG&E at its Fort Smith, Arkansas substation. On May 11,
1999, the Oklahoma Commission issued an order approving the Merger, a copy of
which is filed as Exhibit D-4.2 and incorporated by reference. The order of the
Oklahoma Commission was appealed to the Oklahoma State Supreme Court by
Municipal Electric Systems of Oklahoma and Oklahoma Association of Electric
Cooperatives. The appeal by Municipal Electric Systems of Oklahoma was dismissed
on September 8, 1999, and the appeal by Oklahoma Association of Electric
Cooperatives was dismissed on October 11, 1999.
On October 15, 1999, the Oklahoma Association of Electric Cooperatives
informed the Commission that it had have reached a settlement with Applicants
resolving all outstanding issues among them, and that the Oklahoma Association
of Electric Cooperatives no longer opposed the Merger. In addition thereto, the
Oklahoma Association of Electric Cooperatives withdrew all comments and requests
for hearing that they had previously filed in this proceeding.
H. TEXAS COMMISSION
CPL, SWEPCO, and WTU are subject to the jurisdiction of the Texas
Commission. Pursuant to Section 14.101 of the Texas Utilities Code, each
transaction involving the sale of at least 50 percent of the stock of a public
utility must be reported to the Texas Commission within a reasonable time. On
April 30, 1998, AEP, CSW, CPL, SWEPCO and WTU reported the Merger to the Texas
Commission for its review, as supplemented on January 15, 1999. See Exhibits
D-5.1 and D-5.2.
In reviewing a transaction involving the sale of at least 50 percent of
the stock of a Texas utility, the Texas Commission is required to determine
whether the action is consistent with the
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public interest, taking into consideration factors such as the reasonable value
of the property, facilities, or securities to be acquired, disposed of, merged,
transferred, or consolidated, and whether the transaction will adversely affect
the health or safety of customers or employees, result in the transfer of jobs
of Texas citizens to workers domiciled outside of Texas, or result in the
decline of service. On November 18, 1999, the Texas Commission issued an order
finding the Merger to be consistent with the public interest. A copy of the
order is filed as Exhibit D-5.4 and incorporated by reference. An Administrative
Law Judge had previously recommended that the Texas Commission find the Merger
to be consistent with the public interest under Texas Law.
In the proceedings before the Texas Commission, Applicants entered into
an Integrated Stipulation and Agreement with the Public Utility Commission of
Texas General Counsel, the State of Texas (in its capacity as a consumer of
electricity), the Texas Industrial Energy Consumers, Low Income Intervenors, the
Office of Public Utility Counsel, and the Steering Committee of the Cities of
McAllen, Corpus Christi, Victoria, Abilene, Big Lake, Vernon and Paducah. The
Texas Stipulation is filed as Exhibit D-5.3 and incorporated by reference. In
addition thereto, in a letter dated July 9, 1999 to the administrative law judge
in the Texas proceeding, Medina Electric Cooperative, Inc. and the City of
Robstown, Texas stated that they have no objection to the Merger and would not
file testimony in that proceeding. Furthermore, agreements were reached with
several wholesale customer groups including South Texas Electric Cooperative
(STEC) and its member distribution cooperatives, the City of Brownsville Public
Utility Board, the East Texas Cooperatives, which includes East Texas Electric
Cooperative Inc., Northeast Texas Electric Cooperative, Inc., and Tex-La
Electric Cooperative of Texas, Inc., and a group of transmission dependent
utilities (TDUs), which includes Magic Valley Electric Cooperative, Inc.,
Mid-Tex Generation and Transmission Electric Cooperative, Inc. and its members
and Rayburn Country Electric Cooperative.
I. INDIANA COMMISSION
On April 26, 1999, the Indiana Commission issued an order approving a
stipulation and settlement agreement among AEP, CSW, and the staff of the
Indiana Commission, a copy of which is filed as Exhibit D-8.1 and incorporated
by reference.
J. KENTUCKY COMMISSION
On May 24, 1999, the Kentucky Commission issued an order approving the
stipulation among AEP, CSW, Kentucky Industrial Customers Inc., Kentucky
Industrial Steel, Inc., and the Kentucky Attorney General, a copy of which is
filed as Exhibit D-7.1 and incorporated by reference.
K. MISSOURI COMMISSION
No regulatory authorization is required from the Missouri Commission.
However, in an effort to address concerns raised by the Missouri Commission with
respect to competitive impacts that may occur as a result of Applicants' use of
the Contract Path, Applicants agreed that, as part of a settlement between
Applicants and the Missouri Commission, the Missouri Commission may initiate,
within four years of the consummation of the Merger, a review by the
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FERC of the Merger's effects on retail competition, assuming retail competition
has been implemented in Missouri. The settlement also gives the FERC discretion
to decide if mitigation measures are necessary to the extent that the review
results in a finding that the Contract Path is harmful to competition. Any
relief ordered by FERC cannot extend beyond six years after the consummation of
the Merger. On January 27, 2000, the FERC approved the subject settlement.
L. MICHIGAN COMMISSION
On December 16, 1999, the Michigan Commission approved a Settlement
Agreement with AEP related to the Merger. In approving the Settlement Agreement,
the Michigan Commission agreed not to oppose the Merger at the federal level.
AEP agreed to share Merger savings with Michigan customers; establish
performance standards that will maintain or improve customer service and system
reliability; join a RTO by December 31, 2000; and establish affiliate rules to
protect consumers and promote fair competition.
M. OHIO, VIRGINIA, W. VIRGINIA, AND TENNESSEE COMMISSIONS
The Ohio Commission opened a docket to undertake a review of issues
associated with proposed Merger-related activities and filed an intervention at
FERC in the Merger case. The Ohio Commission terminated the Merger docket on
October 21, 1999, finding that, in light of the enactment of restructuring
legislation in Ohio, AEP's transition plans are the appropriate dockets in which
to consider issues related to the Merger. The Ohio Commission also withdrew its
intervention at FERC on that date. A copy of the Ohio Commission order and
notice of withdrawal at the FERC are attached as Exhibit N and incorporated by
reference. No action was taken by the Virginia, W. Virginia or Tennessee
Commissions relating to the Merger.
N. 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
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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
<TABLE>
<CAPTION>
Exhibit
Number Description
- ------ -----------
<S> <C>
*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), as amended (see Current Report of
AEP on Form 8-K, dated December 16, 1999 (File No. 1-3525) and
incorporated herein by reference)
*B-2 Proposed Service Agreement between AEPSC and subsidiaries of the
Combined Company
*B-3 Proposed Attribution Bases 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 Bases
B-3.3 Scope of the Proposed Post-Merger AEPSC Attribution Bases by Class of
Companies
B-3.4 AEPSC (Post-Merger) Organization Chart
B-3.5 Description of Services to be Provided by AEPSC Post-Merger and
Associated Attribution bases by Category of Services
B-3.6 Proposed Cost Allocation Policies and Procedures Manual of AEPSC
*C-1 Registration Statement of AEP on Form S-4 (as amended) (filed as
Registration Statement No. 333-50109 and incorporated herein by
reference)
</TABLE>
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<TABLE>
<S> <C>
*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
</TABLE>
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<PAGE> 127
<TABLE>
<S> <C>
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
</TABLE>
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<PAGE> 128
<TABLE>
<S> <C>
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-1.3 Stipulation of American Electric Power Company, Inc., Central and
South West Corporation, and Commission Trial Staff, FERC Docket No. EC
98-40 (filed June 24, 1999)
*D-1.4 Stipulation of American Electric Power Company, Inc., Central and
South West Corporation, and Commission Trial Staff, FERC Docket No.
ER98-2770
*D-1.5 Application for Approval of the Alliance Regional Transmission
Organization under Section 205 of the Federal Power Act, Docket No.
ER99-3144 (filed June 3, 1999) (filed on Form SE)
*D-1.6 Application for Approval of Transaction under Section 203 of the
Federal Power Act, Docket No. EC 99-80 (filed June 3, 1999)
D-1.7 Initial Decision, Docket Nos. EC98-40, et al. (issued November 23,
1999)
D-1.8 Order on Proposed Disposition, Alliance Companies, 89 FERC P. 61,298
(December 20, 1999)
D-1.9 Opinion No. 442, Docket Nos. EC98-40, et al. (issued March 15, 2000)
D-1.10 Applicants' compliance filing re: Opinion No. 442
D-1.11 Opinion No. 442-A, Docket Nos. EC98-40, et. al. (issued May 15, 2000)
*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:
</TABLE>
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<PAGE> 129
<TABLE>
<S> <C>
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
</TABLE>
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<PAGE> 130
<TABLE>
<S> <C>
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 December 17, 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
</TABLE>
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<PAGE> 131
<TABLE>
<S> <C>
D-3.2 Order of the Louisiana Commission conditionally approving the Merger,
dated September 16, 1999
*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 17O.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
</TABLE>
-128-
<PAGE> 132
<TABLE>
<S> <C>
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-4.2 Order of Oklahoma Commission conditionally approving the Merger,
dated May 11, 1999
*D-5.1 Joint Application of AEP, CSW and PSO before the Texas Commission,
together with exhibits, appendices and workpapers, dated April 30,
1998 (filed on Form SE) and consisting of:
VOLUME 1 - Exhibit D-5.1
Petition of CSW and AEP Direct Testimony and Exhibits of the
Following Witnesses: Draper, Shockley, Flaherty, Baker,
Munczinski, Roberson, Davis, Hieronymus, Mitchell, Pena, Evans
and Bailey
VOLUME 2 - Exhibit D-5.1
Workpapers of Witness Flaherty
VOLUME 3 - Exhibit D-5.1
Workpapers of Witness Roberson
Workpapers of Witness Davis
Workpapers of Witness Pena
Workpapers of Witness Evans
</TABLE>
-129-
<PAGE> 133
<TABLE>
<S> <C>
*D-5.2 Direct Testimony, Supplemental Direct Testimony and Second
Supplemental Direct Testimony before the Texas Commission, January 15,
1999 (filed herewith on Form SE) and consisting of:
Transmittal Letter dated January 15, 1999
Supplemental and Direct Testimonies and Exhibits of the Following
Witnesses: Hieronymus, Jones, Mitchell, Roberson
*D-5.3 Stipulation and Agreement between the Public Utility Commission of
Texas General Counsel, the State of Texas (in its capacity as a
consumer of electricity), the Texas Industrial Energy Consumers, Low
Income Intervenors, the Office of Public Utility Counsel, and the
Steering Committee of the Cities of McAllen, Corpus Christi, Victoria,
Abilene, Big Lake, Vernon and Paducah
D-5.4 Order of Public Utility Commission of Texas dated November 18, 1999.
*D-6.1 Application for Transfers of Control Regarding Operating License No.
NPF-76 and NPF-80 for the South Texas Project, dated June 19, 1998
*D-6.2 Order Approving Application for Transfers of Control Regarding
Operating License No. NPF-76 and NPF-80 for the South Texas Project,
Docket Nos. 50-498, 499 (issued Nov. 5, 1998)
*D-7.1 Order of Kentucky Commission conditionally approving the Merger, dated
May 24, 1999
*D-8.1 Order of Indiana Commission conditionally approving the Merger, dated
April 26, 1999
*D-9.1 Application for Transfer of License, dated July 29, 1999
D-10.1 Order of Michigan Commission approving Settlement, dated December 16,
1999
*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)
</TABLE>
-130-
<PAGE> 134
<TABLE>
<S> <C>
E-7 New AEP System (filed on Form SE)
E-8 Service Territories of U.S. Investor Owned Utilities (filed on Form
SE)
F-1 Opinion of AEP Counsel
F-2 Opinion of CSW Counsel
F-1-1 Past-tense Opinion of AEP Counsel (to be filed by amendment)
F-2-1 Past-tense Opinion of CSW 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
</TABLE>
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<PAGE> 135
<TABLE>
<S> <C>
*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)
*G-15 Annual Report of AEP on Form 10-K for the year ended December 31, 1998
(File No. 1-3525) and incorporated herein by reference
*G-16 Quarterly Report of AEP on Form 10-Q for the quarter ended March 31,
1999 (File No. 1-3525) and incorporated herein by reference
*G-17 Annual Report of CSW on Form 10-K for the year ended December 31, 1998
(File No. 1-1443) and incorporated herein by reference
*G-18 Quarterly Report of CSW on Form 10-Q for the quarter ended March 31,
1999 (File No. 1-1443) and incorporated herein by reference
*G-19 Quarterly Report of AEP on Form 10-Q for the quarter ended June 30,
1999 (File No. 1-3525) and incorporated herein by reference
*G-20 Quarterly Report of CSW on Form 10-Q for the quarter ended June 30,
1999 (File No. 1-1443) and incorporated herein by reference
G-21 Quarterly Report of AEP on Form 10-Q for the quarter ended September
30, 1999 (File No. 1-3525) and incorporated herein by reference
G-22 Quarterly Report of CSW on Form 10-Q for the quarter ended September
30, 1999 (File No. 1-1443) and incorporated herein by reference
G-23 Annual Report of AEP on Form 10-K for the year ended December 31, 1999
(File No. 1-3525) and incorporated herein by reference
G-24 Annual Report of CSW on Form 10-K for the year ended December 31, 1999
(File No. 1-1443) and incorporated herein by reference
*H Proposed Form of Notice
*I-1 CSWS Authorizations
</TABLE>
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<PAGE> 136
<TABLE>
<S> <C>
I-2 Short-Term Borrowing Program
*I-3 CSW Credit Authorizations
I-4 CSW Guarantee Authorizations
*J Tax Basis Discussion
*K Agreement between Applicants and International Brotherhood of
Electrical Workers
L-1 Navigant Consulting Market Share Study Sorted by Electric Revenues
L-2 Navigant Consulting Market Share Study Sorted by Assets
L-3 Navigant Consulting Market Share Study Sorted by Electric Customers
M Summary of Ratings on Securities of AEP and CSW
N. Ohio Commission Order and Notice of Withdrawal
</TABLE>
* 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, 42U.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.
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<PAGE> 137
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: May 24, 2000
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<PAGE> 138
APPENDIX A
STATUS OF STATE RESTRUCTURING LEGISLATION
The following is a summary of restructuring legislation in the states
in which the Combined Company will operate:
1. Arkansas
On April 15, 1999, the Governor of Arkansas signed into law a
comprehensive restructuring bill that calls for retail competition to start as
early as January 1, 2002, but in no event later than June 30, 2003. Under the
measure, utilities may recover transition and net stranded costs and may use
securitization to mitigate stranded costs. Utilities that recover stranded costs
must freeze rates for residential and small commercial customers for three
years, and, for those utilities that do not recover stranded costs, rates must
be frozen for one year. Utilities must functionally unbundle into generation,
transmission, and distribution units by either creating separate divisions,
nonaffiliated companies, separate affiliated companies, or by selling assets to
a third party. The Arkansas Commission can force divestiture of generation
assets to alleviate market power, and it can decide if stockholders should share
stranded cost recovery with ratepayers.
2. Louisiana
In Louisiana, the staff of the Louisiana Commission, in May 1999,
presented a report on restructuring, recommending a slow approach to adoption of
restructuring legislation. The report states that Louisiana has lower than
national average electric rates, and competition could increase prices, not
lower them. The report recommends that no action be taken at this time, but
"reluctantly" submitted a draft restructuring plan in case the Louisiana
Commission decides to order retail competition. In Louisiana, the Louisiana
Commission can order retail competition without legislative action.
3. Ohio
On July 6, 1999, the governor of Ohio signed "The Ohio Electric
Restructuring Act of 1999" (the "Ohio Act") that will restructure the electric
utility industry in Ohio affecting OPCo and CSPCo. The Ohio Act provides for
customer choice of electricity supplier and a residential rate reduction of 5%
of the unbundled generation rate beginning on January 1, 2001. The Ohio Act also
provides for a five-year transition period to move from cost based rates to
market pricing for generation services. The law provides Ohio electric utilities
the opportunity to recover regulatory assets and other potential stranded costs.
Retail electric services that will be competitive are defined in the
Ohio Act as electric generation service, aggregation service, and power
marketing and brokering. The Ohio Commission has been granted broad oversight
responsibility under the Ohio Act. The Ohio Act requires the Ohio Commission to
promulgate rules for competitive retail electric generation service.
<PAGE> 139
The Ohio Act further provides Ohio electric utilities with an
opportunity to recover Ohio Commission approved allowable transition costs
through unbundled rates paid by customers who do not switch generation suppliers
and through a wires charge by customers who switch generation suppliers.
Transition costs can include regulatory assets, impairments of generating assets
and other stranded costs, employee severance and retraining costs and other
costs. Recovery of transition revenues can under certain circumstances extend
beyond the five-year transition period but cannot continue beyond December 31,
2010. AEP must file a transition plan with the Ohio Commission by January 3,
2000, and the Ohio Commission is required to issue a transition order no later
than October 31, 2000. On December 30, 1999, AEP, on behalf of its subsidiaries
CSPCo and OPCo, filed its restructuring transition plan required by the Ohio
Act. The filing provides details on the companies' proposed rate unbundling,
corporate separation, operational support, employee assistance and consumer
education plans. The filing also includes a request to recover transition costs
and a proposal for independent operation of transmission facilities.
The Ohio Act also provides that the property tax assessment percentage
on electric generation equipment be lowered from 100% to 25% of value effective
January 1, 2001. Electric utilities will also become subject to the Ohio
Corporate Franchise Tax and municipal income taxes on January 1, 2002. The last
year for which electric utilities will pay the excise tax based on gross
receipts is the year ending April 30, 2002. As of May 1, 2001 electric
distribution companies will be subject to an excise tax based on kilowatt-hours
sold to Ohio customers. It is expected that these changes will put the company's
generation operations on an equal basis with other competitive businesses in
Ohio regarding state taxation.
4. Oklahoma
In April, 1997, the Oklahoma Legislature passed restructuring
legislation providing for retail access by July 1, 2002. That legislation called
for a number of studies to be completed on a variety of restructuring issues,
including independent system operator issues, technical issues, financial
issues, transition issues and consumer issues. The study on independent system
operator issues was completed in January, 1998. The Legislative Joint Electric
Utility Task Force completed its studies of the remaining issues and provided
its final report to the Oklahoma Legislature on October 1, 1999.
5. Texas
On June 18, 1999, the Texas Legislature passed restructuring
legislation that will restructure the electric utility industry within the
state. The new law gives Texas customers of investor-owned utilities the
opportunity to choose their electricity provider beginning January 1, 2002. The
legislation also provides a rate freeze until that date followed by a 6% rate
reduction for residential and small commercial customers, additional rate
reductions for low income customers and a number of customer protections. Rural
electric cooperatives and municipal electric systems can choose whether to
participate in retail competition. Some of the key provisions of the legislation
include:
<PAGE> 140
- Beginning January 1, 2002, retail customers of investor-owned
electric companies will be able to choose their electric
provider. The affiliated retail electric provider of the
utility that serves the customer on December 31, 2001 will
continue to serve the customer unless the customer chooses
another retail electric provider. Delivery of the electricity
will continue to be the responsibility of the local electric
utility company at regulated prices. Each utility must
unbundle its business activities into a retail electric
provider, a power generation company and a transmission and
distribution utility.
- Retail electric cooperatives and municipal electric systems
can choose whether to participate in retail competition.
- Investor-owned utilities must freeze their rates effective
September 1, 1999, through the start of competition on January
1, 2002. Investor-owned utilities at January 1, 2002 will
lower rates for residential and small commercial customers by
6%. This reduced rate is known as the "Price to Beat," which
will be available to those customers for five years.
- The legislation establishes a system benefit fund for
low-income customer assistance, customer education and to
offset reductions in school property tax revenues. The fund
will be funded through a charge on retail electric providers
that can be set by the Texas Commission at up to 65 cents per
MWH.
- Electric utilities are allowed to recover all of their net,
verifiable, non-mitigable stranded costs that otherwise may
not be recoverable in the future competitive market. A
majority of those regulatory assets and stranded costs can be
recovered through securitization, which is a financing process
to recover regulatory assets and stranded costs through the
use of debt that lowers the financing cost of assets compared
to conventional utility financing methods.
- Each year during the 1999 through 2001 rate freeze period,
utilities with stranded costs are required to apply any
earnings in excess of the most recently approved cost of
capital (if issued on or after January 1, 1992) to reduce
stranded costs. Utilities without stranded costs must either
flow such amounts back to customers or make capital
expenditures to improve transmission or distribution
facilities or to improve air quality.
- Investor-owned utilities will be required to auction
entitlements to at least 15% of their generating capacity for
five years or until 40% of the residential and small
commercial consumption of electricity in the utility's service
area is provided by nonaffiliated retail electric providers.
- Grandfathered power plants, those built or started prior to
implementation of the Texas Clean Air Act of 1972, must reduce
emissions of Nitrogen Oxide by 50% and Sulfur Dioxide by 25%
by May, 2003. The law also requires an additional 2,000 MW of
renewable power generation in Texas by 2009 from retail
electric providers, municipally owned utilities and electric
cooperatives.
<PAGE> 141
- A legislative oversight committee will be established to
monitor the implementation and effectiveness of electric
utility restructuring and make recommendations for any
necessary further legislative action. The Texas Commission has
established numerous task forces to address various issues
associated with the restructuring legislation and to provide
for further guidance regarding implementation of the
restructuring.
6. Virginia
In March, 1999, Virginia enacted a new law to restructure the electric
utility industry in that state. Under the restructuring law, a transition to
choice of supplier for retail customers will commence on January 1, 2002 and be
completed, subject to a finding by the Virginia Commission that an effective
competitive market exists, by January 1, 2004. Provisions allowing for an
acceleration or limited delay in this schedule are also contained in the law.
Except as provided in the law, the generation of electricity will not be subject
to rate regulation after January 1, 2002. APCo's retail pilot program would
allow approximately 2% of its retail customers to participate in June, 2000, and
an additional 8% of its retail customers would be allowed to participate by
March, 2001. Both phases of the program would be weighted heavily toward
industrial customers. APCo proposed that industrial customers will account for
35 MW of the 50 MW load opened to competition in June, 2000, and will account
for 140 MW of the 200 MW load opened to competition in March, 2001. The Virginia
Commission held hearings on APCo's proposal in November, 1999. Additionally,
each Virginia electric utility is required by 2001 to join or establish a
regional transmission entity which will manage and control transmission assets.
The Virginia restructuring law also provides an opportunity for recovery of just
and reasonable net stranded costs.
7. West Virginia
On February 7, 2000, the West Virginia Public Service Commission passed
a plan to restructure the state's electric industry. The restructuring plan
would begin January 1, 2001. Provisions in the plan include a four-year freeze
on electric rates and a nine-year transition period during which only
incremental increases could occur while competition begins. The plan would add a
small charge to all electric bills in order to collect approximately $84 million
which the PSC would then redistribute to residential customers near the end of
the 13 year period for rate relief during the transition to competition.
<PAGE> 1
EXHIBIT B-3.3
AMERICAN ELECTRIC POWER SERVICE CORPORATION
ATTRIBUTION BASES - CLASS OF CLIENT COMPANIES BILLED
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Attribution Basis Client Companies
- -----------------------------------------------------------------------------------------------------------------------------------
No. Description AEP Company, AEP Operating Nonregulated
Inc. Companies(*) Affiliates
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1 Number of Bank Accounts X X X
- -----------------------------------------------------------------------------------------------------------------------------------
2 Number of Call Center Telephones X
- -----------------------------------------------------------------------------------------------------------------------------------
3 Number of Cell Phones/pagers X X
- -----------------------------------------------------------------------------------------------------------------------------------
4 Number of Checks Printed X X X
- -----------------------------------------------------------------------------------------------------------------------------------
5 Number of Customer Information System Customer Mailings X
- -----------------------------------------------------------------------------------------------------------------------------------
6 Number of Commercial Customers (Ultimate) X
- -----------------------------------------------------------------------------------------------------------------------------------
7 Number of Credit Cards X X
- -----------------------------------------------------------------------------------------------------------------------------------
8 Number of Electric Retail Customers (Ultimate) X
- -----------------------------------------------------------------------------------------------------------------------------------
9 Number of Employees X X
- -----------------------------------------------------------------------------------------------------------------------------------
10 Number of Generating Plant Employees X
- -----------------------------------------------------------------------------------------------------------------------------------
11 Number of General Ledger Transactions X X X
- -----------------------------------------------------------------------------------------------------------------------------------
12 Number of Help Desk Calls X X
- -----------------------------------------------------------------------------------------------------------------------------------
13 Number of Industrial Customers (Ultimate) X
- -----------------------------------------------------------------------------------------------------------------------------------
14 Number of Job Cost Accounting Transactions X X
- -----------------------------------------------------------------------------------------------------------------------------------
15 Number of Non-UMWA Employees X X
- -----------------------------------------------------------------------------------------------------------------------------------
16 Number of Phone Center Calls X
- -----------------------------------------------------------------------------------------------------------------------------------
17 Number of Purchase Orders Written X X X
- -----------------------------------------------------------------------------------------------------------------------------------
18 Number of Radios (Base/Mobile/Handheld) X
- -----------------------------------------------------------------------------------------------------------------------------------
19 Number of Railcars X
- -----------------------------------------------------------------------------------------------------------------------------------
20 Number of Remittance Items X
- -----------------------------------------------------------------------------------------------------------------------------------
21 Number of Remote Terminal Units X
- -----------------------------------------------------------------------------------------------------------------------------------
22 Number of Rented Water Heaters X
- -----------------------------------------------------------------------------------------------------------------------------------
23 Number of Residential Customers (Ultimate) X
- -----------------------------------------------------------------------------------------------------------------------------------
24 Number of Routers X X
- -----------------------------------------------------------------------------------------------------------------------------------
25 Number of Servers X X
- -----------------------------------------------------------------------------------------------------------------------------------
26 Number of Stores Transactions X
- -----------------------------------------------------------------------------------------------------------------------------------
27 Number of Telephones X X
- -----------------------------------------------------------------------------------------------------------------------------------
28 Number of Transmission Pole Miles X
- -----------------------------------------------------------------------------------------------------------------------------------
29 Number of Transtext Customers X
- -----------------------------------------------------------------------------------------------------------------------------------
30 Number of Travel Transactions X X
- -----------------------------------------------------------------------------------------------------------------------------------
31 Number of Vehicles X X
- -----------------------------------------------------------------------------------------------------------------------------------
32 Number of Vendor Invoice Payments X X X
- -----------------------------------------------------------------------------------------------------------------------------------
33 Number of Workstations X X
- -----------------------------------------------------------------------------------------------------------------------------------
34 Active Owned or Leased Communication Channels X X
- -----------------------------------------------------------------------------------------------------------------------------------
35 Avg. Peak Load for past Three Years X
- -----------------------------------------------------------------------------------------------------------------------------------
36 Coal Company Combination X
- -----------------------------------------------------------------------------------------------------------------------------------
37 AEPSC past 3 Months Total Bill Dollars X X X
- -----------------------------------------------------------------------------------------------------------------------------------
38 AEPSC Prior Month Total Bill Dollars X X X
- -----------------------------------------------------------------------------------------------------------------------------------
39 Direct X X X
- -----------------------------------------------------------------------------------------------------------------------------------
40 Equal Share Ratio X X X
- -----------------------------------------------------------------------------------------------------------------------------------
41 Fossil Plant Combination X
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
1 of 2
<PAGE> 2
EXHIBIT B-3.3
AMERICAN ELECTRIC POWER SERVICE CORPORATION
ATTRIBUTION BASES - CLASS OF CLIENT COMPANIES BILLED
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Attribution Basis Client Companies
- -----------------------------------------------------------------------------------------------------------------------------------
No. Description AEP Company, AEP Operating Nonregulated
Inc. Companies(*) Affiliates
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
- -----------------------------------------------------------------------------------------------------------------------------------
42 Functional Department's past 3 Months Total Bill Dollars X X X
- -----------------------------------------------------------------------------------------------------------------------------------
43 KWH Sales (Ultimate Customers) X
- -----------------------------------------------------------------------------------------------------------------------------------
44 Level of Construction - Distribution X
- -----------------------------------------------------------------------------------------------------------------------------------
45 Level of Construction - Production X
- -----------------------------------------------------------------------------------------------------------------------------------
46 Level of Construction - Transmission X
- -----------------------------------------------------------------------------------------------------------------------------------
47 Level of Construction - Total X
- -----------------------------------------------------------------------------------------------------------------------------------
48 MW Generating Capability X
- -----------------------------------------------------------------------------------------------------------------------------------
49 MWH's Generation X
- -----------------------------------------------------------------------------------------------------------------------------------
50 Current Year Budgeted Salary Dollars X X X
- -----------------------------------------------------------------------------------------------------------------------------------
51 Past 3 Mo. MMBTU's Burned (All Fuel Types) X
- -----------------------------------------------------------------------------------------------------------------------------------
52 Past 3 Mo. MMBTU's Burned (Coal Only) X
- -----------------------------------------------------------------------------------------------------------------------------------
53 Past 3 Mo. MMBTU's Burned (Gas Type Only) X
- -----------------------------------------------------------------------------------------------------------------------------------
54 Past 3 Mo. MMBTU's Burned (Oil Type Only) X
- -----------------------------------------------------------------------------------------------------------------------------------
55 Past 3 Mo. MMBTU's Burned (Solid Fuels Only) X
- -----------------------------------------------------------------------------------------------------------------------------------
56 Peak Load / Avg. # Cust./KWH Sales Combination X
- -----------------------------------------------------------------------------------------------------------------------------------
57 Tons of Fuel Acquired X
- -----------------------------------------------------------------------------------------------------------------------------------
58 Total Assets X X X
- -----------------------------------------------------------------------------------------------------------------------------------
59 Total Assets less Nuclear Plant X X X
- -----------------------------------------------------------------------------------------------------------------------------------
60 AEPSC Annual Costs Billed (Less Interest and/or Income Taxes
as Applicable) X X X
- -----------------------------------------------------------------------------------------------------------------------------------
61 Total Fixed Assets X X
- -----------------------------------------------------------------------------------------------------------------------------------
62 Total Gross Revenue X
- -----------------------------------------------------------------------------------------------------------------------------------
63 Total Gross Utility Plant (Including CWIP) X X
- -----------------------------------------------------------------------------------------------------------------------------------
64 Total Peak Load (Prior Year) X
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(*) Includes coal mining and generating subsidiaries of the operating
companies
2 of 2
<PAGE> 1
EXHIBIT B-3.4
AMERICAN ELECTRIC POWER SERVICE CORPORATION
(Post Merger)
ORGANIZATION CHART
[Including Locations]
Chairman, President and Chief Executive Officer [Columbus]
Vice Chairman [Columbus]
EVP Corporate Development [Columbus]
Corporate Development and Mergers & Acquisitions [Columbus]
AEP Communications [Columbus]
New Ventures [Columbus]
Business Development [Columbus]
Finance and Accounting [Columbus]
European Development [London]
Asia Pacific Development [Singapore]
Latin American Development [Reston, Va]
EVP Legal, Policy and Corporate Communications [Columbus]
Legal [Columbus, Washington DC and Dallas]
Public Policy [Columbus]
Governmental Affairs [State capitals in the states served by AEP,
except Tennessee and Arkansas]
Corporate Communications [Columbus and Austin]
Environmental Affairs [Columbus]
EVP Finance and Analysis [Columbus]
Controller [Columbus, Canton and Tulsa]
Tax [Columbus]
Internal Audits [Columbus, Tulsa, Dallas and other locations
across AEP's operating territory]
Treasurer [Columbus and Dallas]
Risk Management [Columbus]
Strategic Analysis [Columbus]
Corporate Planning and Budgeting [Columbus]
EVP North American Energy Delivery [Columbus]
Transmission [Various locations within the Regions of the AEP
East and AEP West zones]
Distribution [Columbus and Region offices in Indiana, Ohio, West
Virginia, Virginia, Texas and Oklahoma]
Customer Interface [Columbus, plus Call Center locations in Fort
Wayne, Groveport, Ashland, Hurricane, WVa, Tulsa, Shreveport,
Corpus Christi and Pharr, Tx]
Regulatory, Planning and Budgeting [Columbus and Austin]
Customer and Community Services [Columbus and other locations
across AEP's service territory]
Supply Chain [Columbus]
<PAGE> 2
EXHIBIT B-3.4
EVP Wholesale / Energy Services [Columbus]
Trading [Columbus]
Marketing and Business Origination [Columbus and Houston]
Operations and Technical Services [Columbus plus Region and plant
locations]
Administration [Columbus]
AEP Global Wholesale Development [Dallas]
Analysis [Columbus]
Europe [London]
Energy Services [Columbus]
Business Systems and Operations [Columbus]
Business Development [Columbus]
Supply Chain [Columbus]
EVP Shared Services [Columbus]
Human Resources [Columbus, Roanoke, Fort Wayne and distributed
locations]
Information Technology [Columbus and distributed
locations across AEP's network and business unit locations]
Supply Chain [Columbus]
General Services [Columbus and distributed locations]
- ------------------------------------------------
NOTE: Staffing and selection of employees for the post-merger organization began
in early February 2000. Officer positions have been filled through the Senior
Vice President level across the organization, with some Vice President positions
also having been determined. The above-noted organization structure and
locations reflect staffing decisions made through March 15, 2000.
<PAGE> 1
EXHIBIT B-3.5
AMERICAN ELECTRIC POWER SERVICE CORPORATION
(Post-Merger)
SERVICES TO BE PERFORMED BY GROUP AND ASSOCIATED PRIMARY ATTRIBUTION BASES
EVP CORPORATE DEVELOPMENT
- CORPORATE DEVELOPMENT AND MERGERS & ACQUISITIONS - Coordinates mergers and
acquisitions and integrates new operations.
Attribution Bases: Direct (Parent or applicable subsidiary).(1)
- AEP COMMUNICATIONS - Provides fiber and wireless communications services
and energy management services.
Attribution Bases: Direct.
- NEW VENTURES - Invests in new ventures, including selected new technology
companies, which will support the strategic plan of AEP.
Attribution Bases: Direct.
- BUSINESS DEVELOPMENT - Coordinates business development activities related
to corporate development.
Attribution Bases: Direct (Parent or applicable subsidiary).
- FINANCIAL AND ACCOUNTING - Provides specialized accounting, tax and other
financial services related to corporate development.
Attribution Bases: Direct, and total assets.
- EUROPEAN DEVELOPMENT - Coordinates business development activities in the
U.K. and Europe.
Attribution Bases: Direct.
- ASIA PACIFIC DEVELOPMENT - Coordinates business development activities in
the Asia-Pacific region.
Attribution Bases: Direct
- --------
(1) AEPSC's accounting and billing treatment of costs incurred in
performing services related to mergers and acquisitions will be disclosed in
AEPSC's Annual Report on Form U-13-60 either in Schedule XIV, Notes to
Financial Statements, or Schedule XVIII, Notes to Statement of Income.
<PAGE> 2
EXHIBIT B-3.5
- LATIN AMERICAN DEVELOPMENT - Coordinates business development activities
in Latin America.
Attribution Bases: Direct.
EVP LEGAL, POLICY AND CORPORATE COMMUNICATIONS
- LEGAL - Provides legal services related to contracts, litigation, claims,
and regulatory and other business matters.
Attribution Bases: Direct, Peak Load/Avg. # Customers/KWH Sales
Combination, Total Assets, Total AEPSC Bill Dollars, and Total Fixed
Assets.
- PUBLIC POLICY - Coordinates and develops communications on public policy
issues.
Attribution Bases: Direct (including Parent), Total Assets, and Total
AEPSC Bill Dollars.
GOVERNMENTAL AFFAIRS - Supports customer service and restructuring
activities at the state level.
Attribution Bases: Direct, Number of Electric Retail Customers, and
Total Assets.
- CORPORATE COMMUNICATIONS - Coordinates internal and external
communications and media relations.
Attribution Bases: Direct (including Parent), Number of Employees,
Total Assets, and Total AEPSC Bill Dollars.
- ENVIRONMENTAL AFFAIRS - Coordinates all environmental affairs activities.
Attribution Bases: Direct, Peak Load/Avg. # Customers/KWH Sales
Combination, and Total Assets.
EVP FINANCE AND ANALYSIS
- CONTROLLER - Provides accounting services and prepares financial,
statistical and regulatory reports; includes corporate accounting.
Attribution Bases: Direct, Number of GL Transactions, Number of Stores
Transactions, Number of Invoice Payments, Past 3 Mos. MMBTU's Burned,
Total Assets, Total Fixed Assets, and Total Gross Utility Plant.
- TAX - Provides tax research, consultation and compliance services at the
state and Federal levels.
<PAGE> 3
EXHIBIT B-3.5
Attribution Bases: Direct, and Total Assets.
- INTERNAL AUDITS - Provides internal audit services, including audits of
service company billings.
Attribution Bases: Direct, Number of Employees, and Total Assets.
TREASURER - Performs cash management, financing and investing
activities.
Attribution Bases: Direct, Number of Bank Accounts, Total Assets, Total
AEPSC Bill Dollars, and Total Fixed Assets.
- RISK MANAGEMENT - Arranges insurance coverage and coordinates and
implements risk management policies.
Attribution Bases: Direct, Total Assets, and Total Fixed Assets.
- STRATEGIC ANALYSIS -Provides strategic planning services.
Attribution Bases: Direct, and Total Assets.
- CORPORATE PLANNING AND BUDGETING - Provides budgeting and forecasting
services, financial analysis and service company billing oversight.
Attribution Basis: Direct, and Total Assets.
EVP NORTH AMERICAN ENERGY DELIVERY
- TRANSMISSION - 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.
Attribution Bases: Direct, Number of Transmission Pole Miles, and Level
of Construction - Transmission.
- DISTRIBUTION - Provides mapping services, project management, design and
development of construction projects, drafting and engineering services,
contract administration, forestry services and administrative and planning
services.
Attribution Bases: Direct, Number of Electric Retail Customers, Level
of Construction - Distribution, and Peak Load/Avg. # Customers/KWH
Sales Combination.
- CUSTOMER INTERFACE - Prints and mails customer bills and other required
mailings for electric service customers. Also provides support services
for the customer information system, remittance processing, power billing,
credit and collections, customer accounting, and customer call centers.
<PAGE> 4
EXHIBIT B-3.5
Attribution Bases: Direct, Number of CIS Customer Mailings, Number of
Electric Retail Customers, Number of Phone Center Calls, and Number of
Remittance Items.
- REGULATORY, PLANNING AND BUDGETING - Coordinates all state regulatory
activities, through the use of state regulatory offices that have
centralized and regional support. This organization will be responsible
for all regulatory filings, including restructuring filings that are
mandated from time-to-time in the various states. This group will also
administer budgeting for the North American Energy Delivery unit.
Attribution Bases: Direct, Total Assets, and Past 3 Mos. MMBTU's Burned.
- CUSTOMER AND COMMUNITY SERVICES - Coordinates a targeted customer and
community relations strategy, which includes economic development, new
service coordination and other community relations activities.
Attribution Basis: Direct, Number of Electric Retail Customers, Peak
Load/Avg. # Customers/KWH Sales Combination, and Total AEPSC Bill
Dollars.
- SUPPLY CHAIN [NORTH AMERICAN ENERGY DELIVERY] - Provides procurement and
supply chain management services related to energy delivery.
Attribution Bases: Direct, Number of Stores Transactions, and Number of
Purchase Orders Written.
EVP WHOLESALE / ENERGY SERVICES
- TRADING - Provides electric, gas, coal and ancillary energy product
trading services and optimizes physical generation and transportation
assets against commodity markets.
Attribution Bases: Direct, MW Generating Capability, and Past 3 Mos.
MMBTU's Burned (Coal Only).
- MARKETING AND BUSINESS ORIGINATION - Originates term business with
non-trading counterparts, such as municipals and cooperatives.
Attribution Bases: Direct, and MW Generating Capability.
- OPERATIONS AND TECHNICAL SERVICES - Operates and maintains the AEP
generating, mining and transportation assets. This group also provides
engineering and other technical services for AEP assets as well as third
party customers.
<PAGE> 5
EXHIBIT B-3.5
Attribution Bases: Direct, Coal Company Combination, Fossil Plant
Combination, Level of Construction - Production, MW Generating
Capability, MWH's Generated, Past 3 Mos. MMBTU Burned (All Fuels, Coal
Only, Gas Type Only, Oil Type Only, and Solid Fuels Only), Peak
Load/Avg. # Customers/KWH Sales Combination, and Tons of Fuel Acquired.
- ADMINISTRATION - Provides administrative support and specialized
accounting services related to wholesale and energy services.
Attribution Bases: Direct, Coal Company Combination, MWH's Generated,
and Tons of Fuel Acquired.
- AEP GLOBAL WHOLESALE DEVELOPMENT - Provides generation asset development
services, as well as related energy asset development.
Attribution Bases: Direct, MW Generating Capability, and Past 3 Mos.
MMBTU's burned.
- ANALYSIS - Performs market analysis and forward price curve projections.
This group also provides economic analysis to support capital budgeting
and operational decisions.
Attribution Bases: Direct, Fossil Plant Combination, Level of Construction
- Production, MW Generating Capability, and Peak Load/Avg. # Customers/KWH
Sales Combination.
- EUROPE - Provides electric and gas trading services in the U.K. and
Europe.
Attribution Bases: Direct.
- ENERGY SERVICES - Markets energy-related products and services to
commercial and small industrial customers
Attribution Bases: Direct, Number of Commercial Customers, and Number
of Industrial Customers.
- BUSINESS SYSTEMS AND OPERATIONS - Supports and maintains business and
information systems related to wholesale and energy services.
Attribution Bases: Direct, and MW Generating Capability.
- BUSINESS DEVELOPMENT - Performs analysis of business development
opportunities and marketing of energy and energy-related products.
<PAGE> 6
EXHIBIT B-3.5
Attribution Bases: Direct, and Number of Electric Retail Customers.
- SUPPLY CHAIN [WHOLESALE/ENERGY SERVICES] - Provides procurement and supply
chain management services related to wholesale and energy services.
Attribution Bases: Direct, Number of Stores Transactions, and Number of
Purchase Orders Written.
EVP SHARED SERVICES
- HUMAN RESOURCES - 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.
Attribution Bases: Direct, and Number of Employees.
- INFORMATION TECHNOLOGY - Provides information processing, electric
customer billing support, application development, client computing, and
technical software support.
Attribution Bases: Direct, Number of Electric Retail Customers, Number
of Employees, and Number of Help Desk Calls.
- SUPPLY CHAIN - Provides general procurement and supply chain management
services.
Attribution Bases: Direct, Number of Purchase Orders Written, and
Number of Stores Transactions.
- GENERAL SERVICES - Provides various services, including travel services,
land management, facilities management, fleet management and equipment
services.
Attribution Bases: Direct, Number of Employees, Number of Travel
Transactions, Number of Vehicles, and Total Fixed Assets.
<PAGE> 1
EXHIBIT B-3.6
[AEP LOGO]
AMERICAN ELECTRIC POWER
SERVICE CORPORATION
COST ALLOCATION
POLICIES AND PROCEDURES
POST MERGER - YEAR 2000
<PAGE> 2
American Electric Power Service Corporation
Cost Allocation
POLICIES AND PROCEDURES
TABLE OF CONTENTS
OVERVIEW _________________________________________________________________ 3
WORK ORDER ACCOUNTING _____________________________________________________ 4
SERVICE REQUEST GUIDELINES _______________________________________________ 7
ACTIVITY REQUEST CHANGE FORM _________________________________________ 7
PROJECT ID REQUEST FORM ____________________________________________ 8
ATTRIBUTION BASES ________________________________________________________ 9
CONTROLS ________________________________________________________________ 10
ACCOUNTABILITY ______________________________________________________ 10
BUDGETING ___________________________________________________________ 11
TIME REPORTING ______________________________________________________ 11
BILLING REVIEW ______________________________________________________ 12
DISPUTE RESOLUTION ________________________________________________ 12
SERVICE EVALUATIONS _________________________________________________ 12
INTERNAL AUDIT REVIEW _____________________________________________ 13
EXHIBITS __________________________________________________________________
2
<PAGE> 3
POLICIES AND PROCEDURES
(POST-MERGER)
OVERVIEW
American Electric Power Service Corporation (AEPSC), a subsidiary
service company of American Electric Power Company, Inc. (AEP), a registered
holding company, provides administrative, management, engineering, construction,
technical and support services pursuant to Sections 13 and 15 of the Public
Utility Holding Company Act of 1935 (the Act) and Rules 80 through 94
promulgated under the Act by the Securities and Exchange Commission (the SEC).
Such services are provided to AEP, the electric utility subsidiaries of AEP
(collectively referred to as the Regulated Operating Companies) and their
subsidiaries, and to non-regulated affiliates in the AEP System.
AEPSC maintains an organization of employees who are experienced in
management matters and operations of public utilities and related businesses,
together with appropriate facilities and equipment. AEPSC provides its services
under the terms of the Service Agreements it has filed with the SEC. All
services provided to associate companies are billed "at cost" in accordance with
Rules 90 and 91 under the Act. AEPSC also provides services to non-associate
companies such as computer time-sharing. The revenue earned from non-associates
offsets the cost AEPSC charges to its associate companies.
As required by the SEC, AEPSC maintains a work order system for
allocating and billing costs. Service IDs are used to identify the nature of the
services performed. Billing allocations are performed in accordance with
attribution bases approved by the SEC. The cost billed to associate companies by
AEPSC is also identified using FERC account numbers. This provides the Regulated
Operating Companies with enough detail to allow
3
<PAGE> 4
them to record the billed costs and to report on them as required by the Federal
Energy Regulatory Commission (the FERC).
WORK ORDER ACCOUNTING
The SEC, in the Uniform System of Accounts it prescribes for mutual and
subsidiary service companies, defines a work order system as "a system for the
accumulation of service company cost on a job, project or functional basis. It
includes schedules and worksheets used to account for charges billed to single
and groups of associate and nonassociate companies." As a subsidiary service
company, AEPSC accumulates work order costs (i.e., Service ID costs) using three
transaction coding blocks also known as chartfields: Activity, Project ID and
Benefiting Location. Each of the applicable chartfields is defined as follows:
ACTIVITY - Work performed in support of a function, project or business
process. Examples of defined activities are: "Respond to Customer
Inquiries," "Process Payroll" and "Coordinate Federal Income Tax
Returns & Reports."
PROJECT ID - A planned undertaking with a set beginning date, a
projected end date and an estimated cost to complete. Projects include
construction and retirement work, R&D work, IT projects, non-regulated
activities, special projects and other transactions.
BENEFITING LOCATION - The location or area that benefits from the
service (i.e., the activity or project) being performed. A benefiting
location can define, among other things, a power plant, a generating
unit at a power plant, or a region. Each benefiting
4
<PAGE> 5
location further defines the company or group of companies applicable
to the particular location or area. For example, benefiting location
482G applicable to Unit 3 at the Kammer plant pertains to Ohio Power
Company while benefiting location 654T applicable to the Southern
Transmission Region pertains to Kingsport Power Company, Appalachian
Power Company and Kentucky Power Company.
Service IDs are derived by linking Activity and Benefiting Location. Service IDs
can also be viewed on a project basis by linking Project ID and Benefiting
Location.
Service IDs are used to allocate costs to the appropriate associate and
non-associate client companies. Each transaction recorded by AEPSC includes the
chartfield codes needed to identify the applicable Service ID. AEPSC uses the
following types of Service IDs:
"DIRECT" SERVICE ID - A Direct Service ID is used when the service
being provided benefits a single client company. The monthly cost
accumulated for a Direct Service ID is billed 100 % to the company for
which the service is being performed as designated by the assigned
Benefiting Location.
"SHARED" SERVICE ID - A Shared Service ID is used when the service
being performed benefits two or more client companies. The monthly cost
accumulated for a Shared Service ID is allocated and billed to the
companies for which the service is being performed as designated by the
assigned Benefiting Location. The AEPSC billing system uses specific
company cost-causative allocation factors (i.e., attribution bases)
that have been approved by the SEC to allocate the costs to the
applicable companies. The allocation factors are used to derive a
reasonable approximation of each company's activity level and
proportion of service received. Each Shared
5
<PAGE> 6
Service ID is assigned an Attribution Basis (i.e., an allocation factor
or method) which is used in the billing process to determine the amount
of cost to be billed to each company.
"SCFRINGE" SERVICE ID - The SCFringe Service ID is used to accumulate
the cost of labor overhead. Labor overhead includes, among other
expenses, payroll taxes and employee benefits such as pension and
medical expense. SCFringe is charged to client companies in proportion
to the distribution of labor dollars. The cost of compensated absences
such as vacation and holiday pay is also charged to client companies
based on the distribution of labor dollars.
"SCOCCUOH" OVERHEAD SERVICE ID - The SCOCCUOH Service ID is used to
accumulate the cost of occupancy overhead related to office space
(including rents, depreciation and property taxes), office furniture
and equipment, mail service, cafeteria expenses, building maintenance
and security, utilities and other occupancy-related expenses. Occupancy
overhead is first charged to each department based on the square
footage occupied by each department and then to client companies in
proportion to the total costs charged by each department.
"SCCRU" SERVICE ID - The SCCRU Service ID is used to accumulate
computer-related cost. Computer-related cost includes the expense
incurred to operate and maintain the mainframe computer and related PC
networking. The monthly cost is allocated to Direct and Shared Service
IDs based on computer resource usage (i.e., CRUs). From there the cost
is allocated to client companies either directly or is shared based on
the Attribution Basis attached to each Shared Service ID.
6
<PAGE> 7
"COMPANY OVERHEAD" SERVICE ID - The Company Overhead Service ID (i.e.,
Benefiting Location 61A, the designator for AEPSC) is used to identify
the expenses incurred in support of AEPSC's overall operations. For
example, the expenses incurred in processing the payroll for AEPSC's
employees and in paying AEPSC's vendors are included in Company
Overhead. Company overhead is allocated to client companies in
proportion to the total cost charged to each company.
SERVICE REQUEST GUIDELINES
Service requests fall into two major categories: Activity and Project
ID. The Corporate Planning and Budgeting group in AEPSC processes all requests
for adding or deleting Activities as part of its oversight of the budgeting
process. The Corporate Accounting group in AEPSC processes all requests to open
and close Project IDs. The Corporate Planning and Budgeting group must approve
all requests for both Activities and Project IDs. Separate forms are used for
requesting new Activities and new Project IDs.
ACTIVITY REQUEST CHANGE FORM
The activity request change form requires the following information:
- --------------------------------------------------------------------------------
Process Group The requesting business
unit provides the name of the
high-level process group to
which the new activity is
related (e.g., "Generate
Energy").
- --------------------------------------------------------------------------------
Major Process The requesting business
unit provides the name of the
high-level major process to
which the new activity is
related (e.g., "Procure,
Produce & Deliver Fuel").
- --------------------------------------------------------------------------------
Business Process The requesting business unit
provides the name of the
high-level business process to
which the activity is related
(e.g., "Procure Coal").
- --------------------------------------------------------------------------------
Activity Number (Provided only when an existing
activity is being changed)
- --------------------------------------------------------------------------------
Activity Title The requesting business
unit provides the proposed name
of the new activity (e.g.,
"Develop Coal Delivery
Forecast").
- --------------------------------------------------------------------------------
7
<PAGE> 8
- --------------------------------------------------------------------------------
Effective Date The requesting business
unit recommends an effective
date for use of the new
activity.
- --------------------------------------------------------------------------------
Source The requesting business unit
provides the name of the
requesting unit.
- --------------------------------------------------------------------------------
Location The requesting business unit
indicates its business
location.
- --------------------------------------------------------------------------------
Site Coordinator The requesting business unit
provides the name of the site
coordinator for its business
location.
- --------------------------------------------------------------------------------
Recommendation The requesting business unit
selects the "Add Activity" menu
box and provides a description
of the new activity and related
tasks on page 2.
- --------------------------------------------------------------------------------
Disposition Corporate Planning and
Budgeting accepts or declines
each request.
- --------------------------------------------------------------------------------
See EXHIBIT A for a copy of the Activity Request Change Form.
PROJECT ID REQUEST FORM
The project id request form requires the following information:
- --------------------------------------------------------------------------------
Requested By Name of requestor. Electronic
requests are automatically
stamped with requestor's name,
date and time.
- --------------------------------------------------------------------------------
Recommended Project Title The requesting business unit
provides the recommended
project title.
- --------------------------------------------------------------------------------
Benefiting Location Code The requesting business unit
supplies the applicable
benefiting location code based
on the company or class of
companies that will benefit
from the project.
- --------------------------------------------------------------------------------
Project Description The requesting business unit
supplies a description of the
project based on the nature and
scope of the project to be
performed.
- --------------------------------------------------------------------------------
Recommended Attribution Basis The requesting business unit
supplies the recommended
attribution basis code for the
project. The attribution basis
code identifies the proposed
method of allocation for shared
projects. Projects that pertain
to a single company should be
assigned an attribution basis
code of "39, Direct".
- --------------------------------------------------------------------------------
Estimated Duration of Work To Be
Performed The requesting business unit
supplies the projected start
and end dates of the project
based on current estimates.
- --------------------------------------------------------------------------------
8
<PAGE> 9
- --------------------------------------------------------------------------------
Estimated Total Cost To Be Incurred By The requesting business unit
AEPSC supplies the expected cost of
AEPSC's services if currently
known.
- --------------------------------------------------------------------------------
Additional Remarks The requesting business unit
provides any special project or
accounting instructions related
to the project.
- --------------------------------------------------------------------------------
Others To Be Notified When The requesting business unit
Request Is Approved provides a list of employees to
be notified when the Project ID
is opened for charges.
- --------------------------------------------------------------------------------
Sponsoring Supervisor's Approval A sponsoring supervisor must
review and approve each
request.
- --------------------------------------------------------------------------------
Other Reviewers The Corporate Accounting and
Corporate Planning and
Budgeting groups must accept or
decline each request.
- --------------------------------------------------------------------------------
See EXHIBIT B for a copy of the Project ID Request Form.
ATTRIBUTION BASES
An SEC-approved attribution basis is assigned to each Shared Service ID.
The attribution basis is the statistical factor, company-specific values and
percentages used to allocate a Shared Service ID. An attribution basis is
assigned according to the nature of the service performed. The requestor of a
new Activity or new Project ID recommends the appropriate attribution basis
since the requestor is most knowledgeable about the work that will be performed
and the inherent cost drivers. All attribution basis selections are reviewed by
the Corporate Accounting group for reasonableness.
Any request to use an attribution basis not previously approved by the
SEC is referred by Corporate Accounting to the Legal group for filing of a
60-day letter request with the SEC's Office of Public Utility Regulation.
Filings with certain state commissions may also be required.
9
<PAGE> 10
The attribution basis assigned to a Shared Service ID should be the most
relevant cost-causative cost driver specifically applicable to the service being
provided. An attribution basis consisting of a combination of allocation factors
or a single general allocation factor may be used when a primary cost driver is
not evident. Examples of appropriate attribution bases are captured in the
following table:
- --------------------------------------------------------------------------------
ACTIVITY/SHARED SERVICE ATTRIBUTION BASIS
- --------------------------------------------------------------------------------
243. Respond to customer inquiries 16. Number of phone center calls
- --------------------------------------------------------------------------------
340. Process payroll 09. Number of employees
- --------------------------------------------------------------------------------
656. Coordinate Federal Income Tax 58. Total assets
returns and reports
- --------------------------------------------------------------------------------
An accounting administrator in the Corporate Accounting group has
primary responsibility for ensuring that the attribution basis assigned to each
Shared Service is relevant. Corporate Accounting is also responsible for
ensuring that the company specific statistical values needed for each
attribution basis are accurate and kept up to date as part of that group's
overall responsibility for maintaining and operating the service corporation
billing system.
CONTROLS
Effective operation of the service corporation billing system is tied to
AEP's overall system of internal controls. The more relevant controls and
administrative procedures are
10
<PAGE> 11
discussed under the following sub-headings: Accountability, Budgeting, Time
Reporting, Billing Review, Dispute Resolution, Service Evaluations, and Internal
Audit Review.
The primary goal of these controls and procedures is threefold: (1) to
encourage efficiency in operations and continuous improvement which gives
AEPSC's clients the best possible service at the lowest possible cost; (2) to
make certain that the billings are based on cost and approved allocation bases;
and (3) to ensure there is no cross-subsidization of non-regulated operations by
the Regulated Operating Companies or vice versa.
ACCOUNTABILITY
All approved chartfield values and descriptions, including those related
to Activity, Project ID and Benefiting Location, are maintained in an electronic
database which can be accessed by employees from their workstations. The
business units and process owners who approve and code transactions for
processing through the AEPSC billing system are responsible for the final
results. The monthly billings have to result in a fair and equitable allocation
of cost among all client companies, regulated and non-regulated. Clients are
only to be billed for the services and costs that pertain to them. Changes in
facts and circumstances that affect the billing process must be addressed in a
rapid and responsible manner. All employees will be well informed and trained to
achieve these results within their areas of responsibility.
The Corporate Planning and Budgeting group, along with Corporate
Accounting, is responsible for assisting the business units and AEPSC's client
companies in evaluating the monthly billing results on a company by company
basis. Also, see "Billing Review" below.
11
<PAGE> 12
BUDGETING
Each year an annual budget is prepared for the services that will be
provided by AEPSC during the next calendar year on a business group and Activity
basis . The budget system generates monthly reports that compare actual cost
against the budget. Results can be viewed by process group, major process,
business process or by Activity, and by company. AEPSC's group managers and
process owners are primarily responsible for analyzing and explaining the cost
variances incurred while performing all corporate governance activities. AEPSC
and its clients are jointly responsible for analyzing and explaining the cost
variances incurred while performing all discretionary services.
The annual budgets are consistent with and support AEP's corporate-wide
strategic performance objectives. AEP's Board of Directors, with the assistance
of executive management, approves the annual budgets for AEPSC, the Regulated
Operating Companies, and all the other AEP affiliates (including AEP itself).
TIME REPORTING
AEPSC uses a positive time reporting process whereby time records are
prepared by or for each AEPSC employee, including every officer, for each
reporting period. Survey-based time reporting and exception time reporting are
not used. The appropriate group supervisor, or a designated delegate, is
responsible for approving each time record. The reported hours and fractions of
hours are priced at each employee's hourly rate for accumulating the cost
applicable to each Service ID.
BILLING REVIEW
Employees in the Corporate Planning and Budgeting group monitor and
track the company-by-company amounts billed by AEPSC each month. These employees
work
12
<PAGE> 13
with the Corporate Accounting group and the performing organizations to
obtain explanations of any unusual monthly variances in the amounts billed. The
services performed and the amounts billed are reviewed for accuracy on behalf of
the Regulated Operating Companies and AEPSC's other affiliated clients. The
performing organizations initiate all needed corrections and the Corporate
Accounting group processes the corrections.
DISPUTE RESOLUTION
In the event there appears to be an uncorrectable billing dispute with a
Regulated Operating Company or any other AEPSC client, the sponsoring AEPSC
service provider and representatives from the Regulated Operating Company or
other client will meet to discuss the nature of the dispute and all proposed
resolutions. Other internal experts may also be requested to participate as
appropriate. If a resolution cannot be reached among the parties, the dispute
will be referred to the Chief Financial Officer or another appropriate member of
executive management.
SERVICE EVALUATIONS
Customer input and a customer-oriented philosophy are necessary in order
to keep AEPSC operating efficiently and at cost-competitive levels.
Customer surveys are used to measure performance and customer
satisfaction. The surveys, along with the budgeting process, seek customer input
relative to the quantity, quality and value of the services being provided by
AEPSC.
All groups in AEPSC measure their performance against established
performance objectives. Whenever feasible, and to the extent necessary, cost
levels and business practices are benchmarked against other companies both
within and outside the electric
13
<PAGE> 14
utility industry. The findings are used to establish new or modified performance
objectives.
INTERNAL AUDIT REVIEW
The AEPSC Internal Audit group performs an audit of the AEPSC billing
system at least every two years. The purpose of the audits is to examine the
internal controls over the billing process and to ascertain that all billing
allocations are being performed in accordance with the attribution bases
approved by the SEC and in accordance with the Service Agreements AEPSC has with
its associated clients.
EXHIBITS
Exhibit A - Activity Request Change Form (2 pages)
Exhibit B - AEPSC Project ID Request Form (2 pages)
Exhibit C - Transaction Coding Block (2 pages)
Exhibit D - Description of Services to be Provided with Related
Attribution Bases (8 pages)
Exhibit E - Description of Attribution Bases (5 pages)
14
<PAGE> 15
EXHIBIT A
1 of 2
ACTIVITY REQUEST CHANGE FORM
Process Group __________________________________________________________________
Major Process __________________________________________________________________
Business Process _______________________________________________________________
Activity No. (Existing) ________________________________________________________
Activity Title _________________________________________________________________
Effective Date _________________________________________________________________
Source: ________________________________________________________________________
Location: ______________________________________________________________________
Site Coordinator: ______________________________________________________________
= = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = =
Recommendation:
Add Activity (see page 2). . . / / Delete Activity. . . . . . . . . . / /
Change Activity Name . . . . . / / Edit Activity Description. . . . . / /
Add Tasks . . . . . . . . . . / / Delete Tasks . . . . . . . . . . . / /
Edit Tasks . . . . . . . . . . / / Output Measure Change. . . . . . . / /
Cost Driver Change . . . . . . / / Move Activity. . . . . . . . . . . / /
Question . . . . . . . . . . . / /
= = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = =
Disposition :
Accept. . . . . . . . . . . . . . . . . . . / /
Accept w/Modification . . . . . . . . . . . / /
Decline . . . . . . . . . . . . . . . . . . / /
Respond To Question . . . . . . . . . . . . / /
Other: ____________________________
Explanation:
= = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = =
ABMS Review Team Member: _______________________________________________________
Date: ___________________________
15
<PAGE> 16
EXHIBIT A
2 of 2
ACTIVITY REQUEST CHANGE FORM
PAGE 2 - NEW ACTIVITY
Activity Title__________________________________________________________________
Activity Description:
________________________________________________________________________________
________________________________________________________________________________
________________________________________________________________________________
________________________________________________________________________________
________________________________________________________________________________
________________________________________________________________________________
________________________________________________________________________________
________________________________________________________________________________
________________________________________________________________________________
________________________________________________________________________________
Major Tasks:
________________________________________________________________________________
________________________________________________________________________________
________________________________________________________________________________
________________________________________________________________________________
________________________________________________________________________________
________________________________________________________________________________
________________________________________________________________________________
________________________________________________________________________________
________________________________________________________________________________
________________________________________________________________________________
16
<PAGE> 17
EXHIBIT B
1 of 2
[AEP LOGO] AEPSC PROJECT ID REQUEST
REQUESTED BY
RECOMMENDED TITLE:
RECOMMENDED TITLE:
ABMS PROJECT CODE (IF ANY):
BENEFITING LOCATION CODE:
SELECT BY NAME: SELECT BY NUMBER:
DESCRIPTION OF SERVICE(S)
TO BE RENDERED:
COMPANY(IES)/GENERATING PLANT(S) TO BE BENEFITED:
NOTE: The Benefiting Location is used to bill the cost of the Project ID to
companies. If the Company(ies) / Generating Plant(s) benefited do not
match the Company(ies) billed by the Benefiting Location, this Project
ID request will be returned.
RECOMMENDED ATTRIBUTION BASIS CODE:
NOTE: See "Using This Database" for an explanation of how attribution bases are
used.
ESTIMATED DURATION OF WORK TO BE PERFORMED:
START: END:
ESTIMATED TOTAL COST TO BE INCURRED BY AEPSC:
ADDITIONAL REMARKS AND/OR FILE ATTACHMENTS:
OTHERS TO BE NOTIFIED WHEN REQUEST IS APPROVED:
ARE YOU THE ROLL GROUP SUPERVISOR FOR THIS REQUEST? ___ YES ___ NO
ROLL GROUP SUPERVISOR/FIRST APPROVER:
17
<PAGE> 18
EXHIBIT B
2 OF 2
SPONSORING ROLL GROUP SUPERVISOR
APPROVER 2 STATUS LIST:
APPROVER 3 STATUS LIST:
APPROVER 4 STATUS LIST:
18
<PAGE> 19
EXHIBIT C
1 OF 2
AMERICAN ELECTRIC POWER SERVICE CORPORATION
TRANSACTION CODING BLOCKS
(Post-Merger)
<TABLE>
<S> <C> <C> <C> <C> <C>
BUSINESS AFFILIATE ACCOUNT ACTIVITY BENEFITING COST
UNIT CODE NUMBER CODE LOCATION COMPONENT
DEPARTMENT PROJECT ID EQUIPMENT STATE/ STATISTICAL TRACKING
ID CLASS JURISDICTION CODE CODE
</TABLE>
Chartfields (i.e., coding blocks) are used to classify and accumulate
transactions for financial and managerial accounting and reporting. Each
chartfield is used for the following purposes:
BUSINESS UNIT-- Identifies the AEP System company for which the transaction is
recorded. Each AEP System company is assigned a unique code. For example,
Columbus Southern Power Company is Business Unit 10.
AFFILIATE CODE-- Identifies transactions conducted with an affiliate. The
BUSINESS UNIT code of the affiliate is entered in this coding block, if
applicable. The codes in this chartfield are used in preparing consolidated
financial statements.
ACCOUNT NUMBER--Records the transaction in the appropriate balance sheet or
income statement account. AEPSC's accounting conforms to the Uniform System of
Accounts prescribed by the SEC for mutual and subsidiary service companies
pursuant to the Public Utility Holding Company Act of 1935.
ACTIVITY CODE-- Connects the transaction to a defined work activity. Examples of
defined work activities are: "Respond to Customer Inquires," "Process Payroll"
and "Coordinate Federal Income Tax Returns & Reports."
BENEFITING LOCATION-- Identifies the location or area that benefits from the
work (i.e., the activity or project) which is being performed. A benefiting
location can define, among
19
<PAGE> 20
EXHIBIT C
2 OF 2
other things, a power plant, a generating unit at a power plant, or a region.
Each benefiting location further defines the company or group of companies that
operate in the
TRANSACTION CODING BLOCKS (CONTINUED)
particular location or area. For example, benefiting location 482G applicable to
Unit 3 at the Kammer plant pertains to Ohio Power Company while benefiting
location 654T applicable to the Southern Transmission Region pertains to
Kingsport Power Company, Appalachian Power Company and Kentucky Power Company.
COST COMPONENT-- Relates the transaction to a specific type of cost such as
labor, materials, or outside services.
DEPARTMENT ID-- Connects the transaction to the responsible organization for
performance reporting purposes.
PROJECT ID-- Connects the transaction with a defined project, if applicable. A
project is generally a planned undertaking with a set beginning date, a
projected end date and an estimated cost to complete. Projects include
construction and retirement work, R&D work, IT projects, non-regulated
activities, and other special projects and transactions.
EQUIPMENT CLASS-- Identifies maintenance costs and transactions with the
applicable equipment numbers or classes.
STATE/JURISDICTION--Classifies transactions for special reporting purposes
largely related to tax and rate case matters. Valid values include, among other
things, state abbreviations.
STATISTICAL CODE--Matches transactions with related input, output or other
statistical measures such as kilowatt-hours. This is a required field for some
revenue, purchased power, and common and preferred stock accounts. Statistical
codes are also required for certain purchasing transactions.
TRACKING CODE--Sub-divides accounting transactions for cost tracking purposes.
Among other things, the tracking code is used to track vehicle and building
expenditures by vehicle number or building number.
20
<PAGE> 21
EXHIBIT D
1 OF 8
DESCRIPTION OF SERVICES TO BE PROVIDED BY
AMERICAN ELECTRIC POWER SERVICE CORPORATION
WITH RELATED ATTRIBUTION BASES
(Post-Merger)
DESCRIPTION OF SERVICES
A description of services to be provided by American Electric Power Service
Corporation is presented in the following table. To the maximum extent possible,
costs will be directly assigned to the benefiting company. The costs of
providing services of a general nature that cannot be directly assigned or
distributed to a specific client are allocated using the Attribution Bases noted
in the table below or by using other Attribution Bases approved by the SEC as
appropriate for the services performed. An attribution basis of "Direct" is used
for all costs that can be directly assigned to a specific client.
TABLE
EVP CORPORATE DEVELOPMENT
- - Corporate Development and Mergers and Acquisitions
Description: Coordinates mergers and acquisitions and integrates new
operations.
Attribution Bases: Direct.
- - AEP Communications
Description: Provides fiber and wireless communications services and
energy management services.
Attribution Bases: Direct
- - New Ventures
Description: Invests in new ventures, including selected new technology
companies, which will support the strategic plan of AEP.
Attribution Bases: Direct.
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<PAGE> 22
EXHIBIT D
2 OF 8
- - Business Development
Description: Conducts business development coordination activities
related to corporate development.
Attribution Bases: Direct.
- - Financial and Accounting - Corporate Development
Description: Provides specialized accounting, tax and other financial
services related to corporate development.
Attribution Bases: Direct, and Total Assets.
- - European Development
Description: Provides business development services in the United
Kingdom and Europe.
Attribution Bases: Direct.
- - Asia Pacific Development
Description: Provides business development services in the Asia-Pacific
region.
Attribution Bases: Direct.
- - Latin American Development
Description: Provides business development services in Latin America.
Attribution Bases: Direct.
EVP LEGAL, POLICY AND CORPORATE COMMUNICATIONS
- - Legal
Description: Performs legal services related to contracts, litigation,
claims, and regulatory and other business matters.
Attribution Bases: Direct, Peak Load/Avg. # Customers/KWH Sales
Combination, Total Assets, Total AEPSC Bill Dollars, and Total Fixed
Assets.
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<PAGE> 23
EXHIBIT D
3 OF 8
- - Public Policy
Description: Development and coordination of communications on public
policy issues.
Attribution Bases: Direct, Total Assets, and Total AEPSC Bill Dollars.
- - Governmental Affairs
Description: Provides customer supporting services relating to customer
service and restructuring activities at the state level.
Attribution Bases: Direct, Number of Electric Retail Customers, and
Total Assets.
- - Corporate Communications
Description: Coordinates internal and external communications and media
relations.
Attribution Bases: Direct, Number of Employees, total Assets, and Total
AEPSC Bill Dollars.
- - Environmental Affairs
Description: Coordinates all environmental affairs activities.
Attribution Bases: Direct, Peak Load/Avg. # Customers/KWH Sales
Combination, and Total Assets.
EVP FINANCE AND ANALYSIS
- - Controller
Description: Provides accounting services and prepares financial,
statistical and regulatory reports; including corporate accounting.
Attribution Bases: Direct, Number of GL Transactions, Number of Stores
Transactions, Number of Invoice Payments, Past 3 Mos. MMBTU's Burned,
Total Assets, Total Fixed assets, and Total Gross Utility Plant.
- - Tax
Description: Provides tax research, consultation and compliance
services at the state and Federal levels.
Attribution Bases: Direct, and Total Assets.
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<PAGE> 24
EXHIBIT D
4 OF 8
- - Internal Audits
Description: Provides internal audit services, including periodic
audits of service company billing system.
Attribution Bases: Direct, Number of Employees, and Total Assets.
- - Treasurer
Description: Performs cash management, financing and investing
activities.
Attribution Bases: Direct, Number of Bank Accounts, Total Assets, Total
AEPSC Bill Dollars, and Total Fixed Assets.
- - Risk Management
Description: Arranges insurance coverage and coordinates and implements
risk management policies.
Attribution Bases: Direct, Total Assets, and Total Fixed Assets.
- - Strategic Analysis
Description: Provides strategic planning services.
Attribution Bases: Direct, and Total Assets.
- - Corporate Planning and Budgeting
Description: Provides budgeting and forecasting services, financial
analysis and service company billing oversight.
Attribution Bases: Direct, and Total Assets.
EVP NORTH AMERICAN ENERGY DELIVERY
- - Transmission
Description: 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.
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<PAGE> 25
EXHIBIT D
5 OF 8
Attribution Bases: Direct, Number of Transmission Pole Miles, and Level
of Construction - Transmission.
- - Distribution
Description: Provides mapping services, project management, design and
development of construction projects, drafting and engineering
services, contract administration, forestry services, and
administrative and planning services.
Attribution Bases: Direct, Number of Electric retail Customers, Level
of Construction - Distribution, and Peak Load/Avg. # Customers/KWH
Sales Combination.
- - Customer Interface
Description: Prints and mails customer bills and other required
mailings for electric service customers. Also provides support services
for the customer information system, remittance processing, power
billing, credit and collections, customer accounting and customer call
centers.
Attribution Bases: Direct Number of CIS Customer Mailings, Number of
electric retail Customers, Number of Phone Center Calls, and Number of
Remittance Items.
- - Regulatory, Planning and Budgeting
Description: Coordinates all state regulatory activities through the
use of state regulatory offices that have centralized and regional
support. This service includes oversight of all regulatory filings,
including restructuring filings that are mandated from time-to-time in
the various states. This service also includes planning and budgeting
for the North American Energy Delivery function.
Attribution Bases: Direct, Total assets, Past 3 Mos. MMBTU's Burned.
- - Customer and Community Service
Description: Coordinates a targeted customer and community relations
strategy that includes economic development, new service coordination
and other community relations activities.
Attribution Bases: Direct, Number of Electric Retail Customers, Peak
Load/Avg. # Customers/KWH Sales Combination, and Total AEPSC Bill
Dollars.
- - Supply Chain - North American Energy Delivery
25
<PAGE> 26
EXHIBIT D
6 OF 8
Description: Provides procurement and supply chain management services
related to energy delivery.
Attribution Bases: Direct, Number of Stores Transactions, and Number of
Purchase Orders Written.
EVP WHOLESALE/ENERGY SERVICES
- - Trading
Description: Provides electric, gas, coal and ancillary energy product
trading services and optimizes physical generation and transportation
assets against commodity markets.
Attribution Bases: Direct, MW Generation Capability, and Past 3 Mos.
MMBTU's Burned (Coal Only).
- - Marketing and Business Origination
Description: Originates term business with non-trading counterparts,
such as municipals and cooperatives.
Attribution Bases: Direct, and MW Generating Capability.
- - Operations and Technical Services
Description: Operates and maintains the AEP generating, mining and
transportation assets. This group also provides engineering and other
technical services for AEP assets as well as third party customers.
Attribution Bases: Direct, Coal Company Combination, Fossil Plant
Combination, Level of Construction - Production, MW Generating
Capability, MWH's Generated, Past 3 Mos. MMBTU's Burned (All Fuels.
Coal Only, Gas Type only, Oil Type Only, and Solid Fuels Only), Peak
Load/Avg. # Customers/KWH Sales Combination, and Tons of Fuel Acquired.
- - Administration
Description: Provides administrative support and specialized accounting
services related to wholesale and energy services.
Attribution Bases: Direct, Coal Company Combination, MWH's Generated,
and Tons of Fuel Acquired.
- - AEP Global Wholesale Development
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<PAGE> 27
EXHIBIT D
7 OF 8
Description: Provides generation asset development services, as well as
related energy asset development.
Attribution Bases: Direct, MW Generating Capability, and Past 3 Mos.
MMBTU's burned.
- - Analysis
Description: Performs market analysis and forward price curve
projections. This service also includes economic analysis to support
capital budgeting and operational decisions.
Attribution Bases: Direct, Fossil Plant Combination, Level of
Construction - Production, MW Generating Capability, and Peak Load/Avg.
# Customers/KWH Sales Combination.
- - Europe
Description: Provides electric and gas trading services in the United
Kingdom and Europe.
Attribution Basis: Direct.
- - Energy Services
Description: Markets energy-related products and services to commercial
and small industrial customers.
Attribution Bases: Direct, Number of Commercial Customers, and Number
of Industrial Customers.
- - Business System and Operations
Description: Supports and maintains business information systems
related to wholesale and energy service.
Attribution Bases: Direct, and MW Generating Capability.
- - Business Development
Description: Performs analysis of business development and marketing of
energy and energy-related products.
Attribution Bases: Direct, and Number of Electric Retail Customers.
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<PAGE> 28
EXHIBIT D
8 OF 8
- - Supply Chain - Wholesale/Energy Services
Description: Provides procurement and supply chain management services
related to wholesale and energy services.
Attribution Bases: Direct, Number of Stores Transactions, and Number of
Purchase Orders Written.
EVP SHARED SERVICES
- - Human Resources
Description: Provides administrative and coordination of the employees
benefit plans, labor relations, certain employee management training,
centralized processing of medical benefit claims, and human resources
management.
Attribution Bases: Direct, and Number of Employees.
- - Information Technology
Description: Provides information processing, electric customer billing
support, application development, client computing and technical
software support.
Attribution Bases: Direct, Number of electric Retail Customers, Number
of Employees, and Number of Help Desk Calls.
- - Supply Chain
Description: Provides general procurement and supply chain management
services.
Attribution Bases: Direct, Number of Purchase Orders Written, and
Number of Stores Transactions.
- - General Services
Description: Provides various corporate services, including travel
services, land management, facilities management, fleet management and
equipment services.
Attribution Bases: Direct, Number of Employees, Number of Travel
Transactions, Number of Vehicles, and Total Fixed Assets.
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<PAGE> 29
EXHIBIT E
1 of 5
DESCRIPTION OF ATTRIBUTION BASES
(Post-Merger)
DESCRIPTION OF ATTRIBUTION BASES
The Attribution Bases described in the following table will be used to
allocate and bill for the services rendered by American Electric Power
Service Corporation.
TABLE
<TABLE>
<CAPTION>
TITLE CALCULATION DESCRIPTION
- ------------------------------------------------------------------------------------------------------------------
<S> <C>
1 NUMBER OF BANK ACCOUNTS Number of Bank Accounts Per Company
Total Number of Bank Accounts
2 NUMBER OF CALL CENTER TELEPHONES Number of Call Center Telephones Per Company
Total Number of Call Center Telephones
3 NUMBER OF CELL PHONES / PAGERS Number of Cell Phones/Pagers Per Company
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 MAILINGS Number of Customer Information System (CIS) Customer Mailings Per
Company
Total Number of CIS Customer Mailings
6 NUMBER OF COMMERCIAL CUSTOMERS Number of Commercial Customers Per Company
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 CUSTOMERS Number of Electric Retail 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 PLANT EMPLOYEES Number of Generating 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 CUSTOMERS Number of Industrial Customers per Company
Total Number of Industrial Customers
</TABLE>
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<PAGE> 30
EXHIBIT E
2 of 5
<TABLE>
<S> <C>
14 NUMBER OF JCA TRANSACTIONS Number of Lines of Accounting Distribution 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 EMPLOYEES Number of Non-UMWA or All Non-Union Employees Per Company
Total Number of Non-UMWA or All Non-Union Employees
16 NUMBER OF PHONE CENTER CALLS Number of Phone Calls Per Phone Center Per Company
Total Number of Phone Center Phone Calls
17 NUMBER OF PURCHASE ORDERS WRITTEN Number of Purchase Orders Written Per Company
Total Number of Purchase Orders Written
18 NUMBER OF RADIOS Number of Radios (Base/Mobile/Handheld) Per Company
(BASE/MOBILE/HANDHELD) Total Number of Radios (Base/Mobile/Handheld)
19 NUMBER OF RAILCARS Number of Railcars Per Company
Total Number of Railcars
20 NUMBER OF REMITTANCE ITEMS Number of Electric Bill Payments Processed Per Company Per Month
(non-lockbox)
Total Number of Electric Bill Payments Processed Per Month (non-lockbox)
21 NUMBER OF REMOTE TERMINAL UNITS Number of Remote Terminal Units Per Company
Total Number of Remote Terminal Units
22 NUMBER OF RENTED WATER HEATERS Number of Rented Water Heaters Per Company
Total Number of Rented Water Heaters
23 NUMBER OF RESIDENTIAL CUSTOMERS Number of Residential Customers Per Company
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 TRANSACTIONS Number of Stores Transactions Per Company
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 POLE MILES Number of Transmission Pole Miles Per Company
Total Number of Transmission Pole Miles
29 NUMBER OF TRANSTEXT CUSTOMERS Number of Expected Transtext Customers Per Company
Total Number of Expected Transtext Customers
30 NUMBER OF TRAVEL TRANSACTIONS Number of Travel Transactions Per Company Per 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 PAYMENTS Number of Vendor Invoice Payments Per Company Per Month
Total Number of Vendor Invoice Payments Per Month
</TABLE>
30
<PAGE> 31
EXHIBIT E
3 of 5
<TABLE>
<S> <C>
33 NUMBER OF WORKSTATIONS Number of Workstations (PCs) Per Company
Total Number of Workstations (PCs)
34 ACTIVE OWNED OR LEASED COMMUNICATION Number of Active Owned/Leased Communication Channels Per Company
CHANNELS Total Number of Active Owned/Leased Communication Channels
35 AVG PEAK LOAD FOR PAST THREE Average Peak Load for Past Three Years Per Company
YEARS Total of Average Peak Load for Past Three 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
Twelve Months
The Sum of the Same Factors for All Coal Companies
37 AEPSC PAST 3 MONTHS TOTAL BILL AEPSC Past Three Months Total Bill Dollars Per Company
DOLLARS Total AEPSC Past Three Months Bill Dollars
38 AEPSC PRIOR MONTH TOTAL BILL AEPSC Prior Month Total Bill Dollars Per Company
DOLLARS 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 Three Years by
the Total Scheduled Maintenance of All Fossil Generating Plants During
the Same Three Years
Two (2)
42 FUNCTIONAL DEPARTMENT'S PAST 3 MONTHS Functional Department's 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 - DISTRIBUTION Construction Expenditures for All 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 Twelve Months
Total of the Same for All Companies
45 LEVEL OF CONSTRUCTION - PRODUCTION Construction Expenditures for All 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 Twelve Months
Total of the Same for All Companies
46 LEVEL OF CONSTRUCTION- Construction Expenditures for All Transmission Plant Accounts Except Land
TRANSMISSION 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 Twelve Months
Total of the Same for All Companies
</TABLE>
31
<PAGE> 32
EXHIBIT E
4 of 5
<TABLE>
<S> <C>
47 LEVEL OF CONSTRUCTION-TOTAL Construction Expenditures for Plant Accounts 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 Twelve 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 SALARY Current Year Budgeted AEPSC Payroll Dollars Billed Per Company
DOLLARS Total Current Year Budgeted AEPSC Payroll Dollars Billed
51 PAST 3 MO. MMBTU'S BURNED (ALL FUEL Past Three Months MMBTU's Burned Per Company (All Fuel Types)
TYPES) Total Past Three Months MMBTU's Burned (All Fuel Types)
52 PAST 3 MO. MMBTU'S BURNED (COAL Past Three Months MMBTU's Burned Per Company (Coal Only)
ONLY) Total Past Three Months MMBTU's Burned (Coal Only)
53 PAST 3 MO. MMBTU'S BURNED (GAS TYPE Past Three Months MMBTU's Burned Per Company (Gas Type Only)
ONLY) Total Past Three Months MMBTU's Burned (Gas Type Only)
54 PAST 3 MO. MMBTU'S BURNED (OIL TYPE Past Three Months MMBTU's Burned Per Company (Oil Type Only)
ONLY) Total Past Three Months MMBTU's Burned (Oil Type Only)
55 PAST 3 MO. MMBTU'S BURNED (SOLID FUELS Past Three Months MMBTU's Burned Per Company (Solid Fuels Only)
ONLY) Total Past Three Months MMBTU's Burned (Solid Fuels Only)
56 PEAK LOAD/AVG # CUST/KWH SALES Average of Peak Load, # of Retail Customers, and KWH Sales to Retail
COMBINATION 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 LESS NUCLEAR PLANT Total Assets Amount Less Nuclear Assets Per Company
Total Assets Amount Less Nuclear Assets
60 TOTAL AEPSC BILL DOLLARS LESS INTEREST Total AEPSC Bill Dollars Less Interest and/or Income Taxes and/or Other
AND/OR INCOME TAXES AND/OR OTHER Indirect Costs 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 Twelve Months Per Company
Total Gross Revenue Last Twelve Months
</TABLE>
32
<PAGE> 33
EXHIBIT E
5 of 5
<TABLE>
<S> <C>
63 TOTAL GROSS UTILITY PLANT Total Gross Utility Plant Amount Per Company (Including CWIP)
(INCLUDING CWIP) Total Gross Utility Plant Amount (Including CWIP)
64 TOTAL PEAK LOAD (PRIOR YEAR) Total Peak Load for Prior Year Per Company
Total Peak Load for Prior Year
</TABLE>
33
<PAGE> 1
EXHIBIT D-1.7
1999 WL 1061502
*1 ALJ Decisions and Reports
American Electric Power Company and Central and South West Corporation
Docket Nos. EC98-40-000, ER98-2770-000 and ER98-2786-000
Initial Decision
(Issued November 23, 1999)
Joseph R. Nacy, Administrative Law Judge.
Appearances
Stephen Angle; Thomas L. Blackburn; J. A. Bouknight, Jr.; Edward J.
Brady; Kevin F. Duffy; Carmen L. Gentile; Douglas G. Green, Charles Hokanson,
Jr., B. Kelly Kiser; James F. Mauz (acute)e, Jane I. Ryan; Samuel T. Perkins,
and Linda L. Walsh for American Electric Power Company Clark Evans Downs,
Kenneth B. Driver, Martin V. Kirkwood and Shelby Provencher for Central and
South West Corporation Cynthia S. Bogorad, Ben Finkelstein, David B. Lieb, Tony
Lin, Robert C. McDiarmid, David E. Pomper, Jeffrey A. Schwarz, Scott H. Strauss,
and Sara C. Weinberg for American Electric Group Intervenors Randolph Lee
Elliott, Susan N. Kelly, Richard Meyer, Allen Mosher, David W. Penn, Debra
H.Rednik, and Wallace F. Tillman for American Public Power Association and
National Rural Electric Cooperative Association Mary W. Cochran and Paul R.
Hightower for Arkansas Public Service Commission Brian Donahue and Zachary David
Wilson for Arkansas Water and Light Commission and the City of Hope Christopher
C. O'Hara and Frederick H. Ritts for Blue Ridge Power Agency Adrienne E. Clair,
Montina M. Cole, T. Alana Deere, and Sherry A. Quirk for Brazos Electric Power
Cooperative, Inc. Ronald J. Brothers and Jeffrey A. Gollomp for Cincinnati Gas &
Electric Company and PSI Energy, Inc. Mary Margaret Farren, Jeffrey A. Gollomp,
and Mike Naeve for Cinergy Services, Inc. Robert A. Jablon and Thomas C. Trauger
for Cities of Dowagiac and Sturgis, Mich. Paul A. Cunningham, Richard B. Herzog,
and Peter Thornton for Commonwealth Edison Company Daniel T. Donovan, Mitchell
F. Hertz, Michelle T. Palmer, and Edward N. Rizer for Dayton Power and Light
Company Howard Benowitz and Alan I. Robbins for East Kentucky Power Cooperative
and City of Hamilton, Ohio William H. Burchette, Matthew J. Jones, A. Hewitt
Rose, and Christine C. Ryan for East Texas Electric Cooperative; Northeast Texas
Electric Cooperative; Tex- La Electric Cooperative of Texas, Inc.; and Blue
Ridge Power Agency Mark R. Haskell, Daniel A. King, James W. Moeller, and
Kathryn L. Patton for Electric Clearinghouse, Inc. Samuel Behrends IV, Andrea J.
Chambers, Joseph Hartsoe, and Sarah G. Novosel for Enron Power Marketing, Inc.
Kim Despeaux, Mary Margaret Farren, and William S. Scherman for Entergy
Services, Inc. Susan Hedman and Michael Mullett for the Environmental Coalition
*2 Eric A. Eisen and Nikki Shoultz for Indiana Utility Regulatory Commission
Samuel Grossman, David M. Kleppinger, Samuel Randazzo, Kimberly Wile, and
Derrick P. Williamson for Industrial Energy Users-Ohio and West Virginia
<PAGE> 2
EXHIBIT D-1.7
Energy Users Group James Boyle and Brian Lederer for International Brotherhood
of Electrical Workers and Locals 1002 and 738 David D'Alessandro, Kelly A. Daly,
Mylie A. Needle, and Richard Raff for Kentucky Public Service Commission John
Michael Adragna, Patrick Henry, and John M. Sharp for Louisiana Cooperatives
Noel J. Darce, Michael R. Fontham, and Paul L. Zimmering for Louisiana Public
Service Commission David L. Schwartz and Joseph A. Simei for McKinsey & Co. and
Morgan Stanley Dean Witter Patricia S. Barrone, Henry J. Boynton, David
D'Alessandro, Jennifer M. Granholm, Gregory O. Olaniran, and David A. Voges for
Michigan Public Service Commission and the State of Michigan David S. Berman,
Paul M. Flynn, Arnold B. Podgorsky, and Michael E. Small for Midwest ISO
Participants Steven Dottheim, Scott Hempling, and R. Blair Hosford for Missouri
Public Service Commission Barry Cohen for the Ohio Consumers' Counsel Gregg D.
Ottinger and Jon R. Stickman for Ohio Municipal Energy Group Scott A. Campbell
and Robert P. Mone for Ohio Rural Electric Cooperatives, Inc., and Buckeye
Power, Inc. Robert L. Daileader, Jr.; Karen Georgenson Gach; John Harver; and
Robert Stewart for Oklahoma Gas and Electric Company Ben Finkelstein for
Oklahoma Municipal Power Authority J. Cathy Fogel, Sang Y. Paek, and Robin E.
Remis for Ormet Primary Aluminum Corporation Steven M. Sherman for ProLiance
Energy, LLC Duane W. Luckey and Thomas W. McNamee for Public Utilities
Commission of Ohio John R. Garry and Howard Zelbo for Salomon Smith Barney Inc.
Steven M. Kramer and Bret A. Sumner for Sharyland Utilities, L.P. Douglas F.
John for South Texas Electric Cooperative, Medina Electric Cooperative, and City
of Robstown William F. Dudley, Wendy N. Reed, and Alan J. Statman for
Southwestern Public Service Company Kim M. Clark for Texas Electric Cooperative;
Medina Electric Cooperative; and City of Robstown, Tex. Floyd L. Norton IV and
Bruce L. Richardson for Texas Utilities Electric Company Randolph Lee Elliott,
Milton J. Grossman, Carrie L. Hill, Robert A. O'Neil, Debora H. Rednik, and
Benjamin L. Willey for Transmission Dependent Utility Systems Grant Crandall,
Douglas Parker, and Judith Rivilin for United Mine Workers of America, AFL-CIO
Joanne F. Goldstein for Utility Workers Union of America, AFL-CIO C. Meade
Browder, Jr. and James C. Dimitri for Virginia State Corporation Commission and
its Staff *3 Charles W. Ritz III for Wabash power Association Daniel E. Frank,
Keith R. McCrea, and J. M. Shafer for Western Farmers Electric Cooperative Becky
M. Bruner for Western Resources, Inc. John J. Bartus, Edith A. Gilmore, Gary D.
Levenson, James A. Pepper, Charles F. Reusch, Stanley A. Berman, and Richard L.
Miles for the Staff of the Federal Energy Regulatory Commission
I. Procedural History
On April 30, 1998, American Electric Power Company (AEP) and Central
and Southwest Corporation (CSW) (collectively Applicants) filed a joint
application under Section 203 of the Federal Power Act (FPA or Act), 16 U.S.C. s
824b (1994), seeking authorization to consolidate their jurisdictional
facilities through a merger whose closing date was to be March 31, 1999.
Applicants also made additional filings relating to the operation of the system
after the merger is consummated.
In Docket No. ER98-2770-000, Applicants filed (1) a System Integration
Agreement, pursuant to which the system will operate on a coordinated basis
after the merger is consummated; (2) a System Transmission Integration Agreement
governing transmission system
<PAGE> 3
EXHIBIT D-1.7
coordination; and (3) a Transmission Reassignment Tariff providing for the sale
and reassignment of unused transmission capacity.
In Docket No. ER98-2786-000, Applicants filed a Joint Open Access
Transmission Tariff and Standards of Conduct, under which the system will offer
transmission services after the merger is consummated.
On July 17, 1998, the Commission requested from the Applicants
additional information and explanation of the Competitive Analysis Screening
Model (CASM) that the Applicants submitted to evaluate the effect of the merger
on competition. Applicants provided such information on August 11, 1998.
On November 10, 1998, the Commission issued its order [FN1]
establishing hearing procedures. By order issued November 12, 1998, this
Commission's Chief Administrative Law Judge designated me to preside at the
hearing and to issue an initial decision.
After extensive discovery supervised by a special Discovery Judge,
public hearing was held in Washington, D.C., June 29-July 19, 1999. Applicants,
numerous Intervenors, and the Commission's Staff (Staff) presented testimony and
evidence. After evidentiary submissions had been completed, due-dates of briefs
were established, [FN2] but page limitations were not imposed. [FN3] The
evidentiary record was closed July 19, 1999.
[FN4]
Since the close of the hearing, a number of intervenors have withdrawn
their opposition to the merger or to some of its aspects. On August 17, 1999, I
certified to the Commission an uncontested offer of partial settlement submitted
by the Applicants on July 14, 1999, calculated to dispose of all issues
outstanding in these proceedings between them and the Missouri Public Service
Commission (PSCMo).
On October 15, 1999, Dayton Power & Light Company (DP&L) filed a motion
requesting that I take official notice of the Alliance Companies' supplement to
their RTO application. Applicants answered, opposing that motion, on October 26,
1999. I have examined the motion and all its attachments and cannot find that
they tend to prove or disprove any substantial issue in these proceedings.
*4 Meanwhile, on June 28, 1999, Applicants had filed a motion seeking a
waiver of the initial decision in Docket Nos. EC98-40-000 and ER98-2770-000.
Staff and a number of Intervenors answered, opposing that motion. By order [FN5]
issued July 28, 1999, the Commission (1) denied Applicants' motion and (2) set a
due-date of November 24, 1999, for the initial decision in Docket Nos.
EC98-40-000 and ER98-2990-000. The third proceeding, Docket No. ER98-2786, was
not affected by that motion or that order, but, for the sake of efficiency, it
is being decided on the same time schedule.
The Commission's order of July 28, 1999, necessitated a recasting of
the briefing arrangements to accommodate the November 24 deadline. On July 29,
1999, therefore, I issued an order accelerating the brief due-dates and imposing
page limitations on all briefs.
<PAGE> 4
EXHIBIT D-1.7
Timely initial and reply briefs have been filed and duly considered.
Any finding or conclusion urged in any of them, but not made or drawn in this
initial decision, has been evaluated and found either to lack merit or
significance or to tend only to lengthen this decision without altering its
substance or effect.
II. Findings of Fact
AEP owns seven utility operating subsidiaries that serve approximately
3 million customers in Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia,
and West Virginia. AEP also owns a subsidiary that sells power and energy at
wholesale to affiliated and unaffiliated purchasers. It has 38 power plants with
a capacity aggregating about 23,800 megawatts (MW). CSW owns four utility
operating subsidiaries that serve approximately 1.7 million customers in
Arkansas, Louisiana, Oklahoma, and Texas. AEP will continue as a registered
holding company and will be the parent of AEP's and CSW's subsidiaries (jointly,
the Combined System). The electric systems of AEP and CSW are not directly
interconnected.
Applicants indicate that they have obtained rights to a 250 MW
east-to-west firm transmission contract path to integrate the operations of the
Combined System, and claim that this path is the equivalent of locating a 250 MW
AEP generator directly within the CSW-Southwest Power Pool (SPP) market. This
path increases the Herfindahl Hirschman Index (HHI), used to measure market
concentration in certain markets of SPP and the Electric Reliability Council of
Texas (ERCOT). Applicants propose measures to mitigate concerns that arise out
of the increased market concentration, including, among other things, a proposed
320 MW power sale in the SPP and ERCOT markets over a four-year period.
The intervenors expressed a number of concerns regarding the
competitive effect of the proposed merger, including the data, assumptions, and
analytic approach used in Apphcanes screen analysis; the competitive effects
associated with transmission and generation; and mitigation measures.
In its November 10, 1998, order, the Commission applied the guidelines
set forth in its Merger Policy Statement [FN6] and focused its review on the
effect of the proposed merger on competition, rates, and regulation. In its
review of competition issues, the Commission found that the three factors set
forth in the Merger Policy Statement that would require a hearing are present.
That is, (1) Applicants failed their own screen analysis; (2) there are problems
concerning the assumptions and data used in Applicants' screen analysis; and (3)
there are other factors that appear to suggest that Applicants' screen analysis
may not fully capture the effects of the merger on competition.
*5 With respect to retail competition, the Commission set for hearing
the request of PSCMo for analysis of the impact of the merger on retail
competition in Missouri. Further, the Commission indicated that Applicants'
ratepayer- protection proposals may not be sufficient-but concluded that the
proposed merger will not have an adverse impact on regulation.
<PAGE> 5
EXHIBIT D-1.7
The Commission also approved the use of the "pooling of interests"
method of accounting for this merger and directed the Applicants to submit their
accounting for the merger within six months after the merger is completed. In
this regard, merger costs (transition, transaction, and regulatory processing
costs) are estimated to be approximately $289 million. The Commission will
require all AEP and CSW subsidiaries, subject to its jurisdiction, to charge
transaction costs and regulatory processing costs to Account 426.5, and
transition costs to operating expenses as incurred. To the extent that rate
recovery of the merger costs is determined to be probable by the jurisdictional
subsidiaries, such costs may be accounted for as regulatory assets in Account
182.3, and amortized over five years, commensurate with their recovery.
Two trial stipulations between Applicants and Staff were filed. The
first, dated May 24, 1999, would resolve all issues between Staff and Applicants
with the exception of issues pertaining to system integration agreements and
ratepayer protection, and one reserved issue (the May 24 Stipulation). Staff's
prefiled testimony addressed only the issues not resolved by that stipulation.
The second stipulation, dated July 13, 1999, resolves all issues pertaining to
the system integration agreements, except for one reserved issue related to the
pricing of energy exchanges between AEP (AEP East) and CSW (AEP West) (the July
13 Stipulation). The trial stipulations also indicated an agreement among Staff
and Applicants that the two reserved issues not resolved by the stipulations
were to be presented directly to the Commission for resolution. By order issued
August 27, 1999, I denied a Joint Motion of Applicants and Staff requesting
adoption of limited briefmg procedures concerning the two reserved issues.
III. Discussion and Conclusions
The issues in these proceedings may be reduced to three: First, whether
Applicants' merger request is consistent with the public interest; second,
whether the rates, terms, and conditions of the three rate schedules related to
post-merger coordinated operations, filed in No. ER98-2770-000, are just and
reasonable; and third, whether the joint open access transmission tariff
providing for post-merger transmission and ancillary services filed in No.
ER98-2786-000 is just and reasonable. These issues must be addressed in the
context of the Merger Policy Statement.
This Commission's authority over mergers stems from Section 203 of the
Federal Power Act (Act), 16 U.S.C. s 824b (1994). If the Commission finds a
merger to be consistent with the public interest, it must approve it. In 1996,
the Commission updated and clarified its merger procedures in the Merger Policy
Statement. Since then, the Commission has concentrated on three issues: the
effect of the merger on competition; its effect on rates; and its effect on
regulation. Only the first two are set for hearing here.
*6 A. Effect on Competition
Applicants have borne their burden of establishing that this merger
would not produce adverse competitive effects. Its analyses and mitigation
commitments remove any such danger. They have committed to the divestiture of
550 MW of specified low-cost generating capacity in Texas and Oklahoma as soon
as feasible, consistent with reliability, besides agreeing to sell
<PAGE> 6
EXHIBIT D-1.7
interim equivalent amounts of energy on terms that relinquish control over that
energy. Their analysis, as supported by Witness Hieronymus confirms that
Applicants' mitigation plans eliminate any Guidelines screen failures
attributable to a combination of Applicants' generating facilities.
Intervenors' attacks on Hieronymus's evidence was unpersuasive. In all
their criticisms of that evidence, I have been unable to find any convincing
evidence of defects that would weaken the overall effect of that evidence. They
rely on an assumption that Applicants will renege on their mitigation
commitments-an assumption I am not willing to indulge on the strength of this
record.
Applicants' Witness Henderson disposed of fears of vertical market
power being vested in the merger partners. He demonstrated that the merger will
not give Applicants the ability to use transmission to affect competition in an
adverse manner. Exh. AC-900 at p. 8. Further, he reviewed data from the AEP and
CSE OASIS sites, and was unable to find patterns of transmission refusals
indicating that transmission personnel might have been providing preferential
treatment to marketing affiliates. AC-900 at p. 9.
Witness Henderson also examined whether or not a combination of
Applicants' transmission systems would create ability and incentive for the use
of transmission to frustrate competition, and concluded persuasively that it
would be difficult to the point of improbability. This was challenged by Witness
Tabors for Enron Power marketing (Enron), but that challenge did not produce any
direct evidence, but relied on raw OASIS data of requests for transmission
service and the frequency of grants or refusals. This was clearly overborne by
Henderson's evidence. AC-900, at pp. 43 and 49.
But this was not the end of it. AEP has committed to join a Regional
Transmission Organization (RTO) that will be responsible to transmission access
and/or the OASIS site, obviating even an appearance of preference by AEP.
Other attacks on Henderson's evidence were equally unavailing. Cinergy
witness Fox-Penner criticized it for not addressing certain types of potential
foreclosure behavior, but Henderson properly explained that such forms of non-
targeted foreclosure behavior would not be realistic methods of frustrating
competitors' transmission access. The Fox-Penner attack was fanciful and based
on assumptions that have no support in the record. It also failed to show that
the conduct he assumed would, in fact, be attractive to Applicants. If the
fakeries he envisions cannot be done with profit, where would be the incentive
to indulge in them? Fox-Penner did not explain.
*7 Henderson's refutation of any suspicion that this merger will create
an ability or incentive for Applicants to use transmission to frustrate
competition was unshaken by cross-examination of the witness and by anything
offered by intervenors.
Intervenors' attempts to demonstrate a necessity for AEP's joining the
Midwest ISO are not convincing. As demonstrated by Witness Baker, excluding
Allegheny Power System from the
<PAGE> 7
EXHIBIT D-1.7
Midwest ISO (and its inclusion has not been established here) leaves AEP's tie
capacity with the four Midwest ISO member is 16,138 MVA-less than the capacity
of its interconnections with the four other Alliance participants, 18,359 MVA.
Exh AC-408 at p. 15. It has even more interconnected transfer capability with
the ten transmission owners that have not joined an RTO. Id., at p. 6.
AEP's proposed acquisition of the LIG Pipeline raises no danger of
vertical market power. There are sufficient alternative natural gas transporters
and providers in Louisiana available to meet generation needs. Any small amount
of generating capacity not directly connected to other transportation systems is
generally uneconomical, operating on low capacity factors. The combination of
generating plants supplied only by LIG and Applicant's plants does not cause HHI
increases sufficient to cause concern. Exh. AC-500, at p. 73.
B. Effect on Rates
1. Applicants' Ratepayer Protection Measures Fully Shield Customers
from Any Potential Adverse Effects of the Merger on Rates
Applicants have proposed a comprehensive series of measures that
provide full protection for wholesale requirements and transmission customers
from any adverse rate consequences resulting from the proposed merger.
Exh. AC-403 at p. 16. These protections include:
a. Applicants will hold wholesale customers harmless from merger costs in
excess of merger savings;
b. Applicants will provide an open season for requirements customers under
cost of service rates if Applicants increase their rates;
c. Applicants will cap the production charge and freeze the transmission
charge for formula rate customers through 2002;
d. Applicants will give formula rate customers the option to freeze their
production charges through 2003 at levels that do not include merger costs;
e. Applicants will give transmission customers the option to switch to
Applicants' open access tariff rates.
See Exh. AC-403 at p. 23 and AC-1600 at p. 11. These ratepayer
protections augment protections already contained in Applicants' contracts with
wholesale customers, and insulate the customers from adverse rate impacts due to
the merger.
The Commission has urged merger applicants to negotiate ratepayer
protection measures with their customers, and that is what Applicants have done.
As a result, there are only two customers remaining in this proceeding that have
sponsored testimony challenging Applicants'
<PAGE> 8
EXHIBIT D-1.7
ratepayer protections, but neither of these customers' concerns has anything to
do with the merger. Although the customers for which Applicants' ratepayer
protections are designed are largely satisfied with Applicants' ratepayer
protections, Staff witness McAndrew nevertheless argues that the protections are
not adequate to protect ratepayers. McAndrew proposes additional measures that
the customers have not sought (and in some cases oppose), that the Commission
has rejected in other merger proceedings, and that Applicants have shown are
unnecessary and unduly burdensome. His objections to Applicants' proposals must
be rejected.
*8 2. Ratepayer Protection Measures
Applicants have proposed ratepayer protection measures for each
ratepayer group. These protections are more than sufficient to ensure that
affected ratepayers do not pay any merger costs that Applicants incur in excess
of merger benefits. See New York State Elec. & Gas Corp., 86 FERC P 61,284, at
p. 62,023 (1999).
a. Requirements Customers Under Negotiated Rates and Cos-of-Service Rates
Applicants will protect requirements customers served under
cost-of-service rates through Applicants' hold harmless commitment and open
season proposal. Exh. AC-403 at pp. 35-36. Requirements customers that are now
served under negotiated rates are protected from merger-related costs by the
terms of their existing contracts. These contracts provide for fixed rates, so
the merger cannot affect them.
Under the hold-harmless commitment, in any Section 205 or 206
proceeding that develops rates using a test year that begins within five years
after consummation of the merger, Applicants will bear the burden of proof that
any merger costs included in the proposed rates are offset by merger savings
included in the proposed rates. Under the open season proposal, requirements
customers under cost-of-service rates will have an open season if Applicants
file a rate increase that uses a test year that begins within five years of the
consummation date of the merger and the Commission accepts the filing. -6. The
Commission has stated that in the majority of circumstances the most meaningful
ratepayer protection is an open season provision. Merger Policy Statement at p.
30,124. These ratepayer protections are sufficient to ensure that ratepayers do
not pay merger costs in excess of merger savings.
b. Stranded Cost Waiver
Staff Witness McAndrew argues that Applicants should be required to
waive their right to seek to recover stranded costs from requirements customers
under negotiated rates and cost-of-service rates after their contracts expire
(whether those expirations occur pursuant to the contract provisions or pursuant
to the customer's exercise of its open season rights). His recommendation would
only have an impact in those cases where the Commission would find stranded cost
recovery warranted.
Although Witness McAndrew offered his proposal in the name of customer
protection, the only remaining customers in these proceedings that have voiced
concerns about Applicants'
<PAGE> 9
EXHIBIT D-1.7
recovery of stranded costs are the Cities of Dowagiac and Sturgis, Michigan, and
neither of these customers' stranded cost claims has anything to do with this
merger. Sturgis gave notice to terminate wholesale service in 1996, more than a
year before this merger was announced. That notice became effective in July
1999. Exh. AC-408 at p. 50. As a result, Sturgis is potentially liable for
stranded costs, but this would be so regardless of whether the merger ever
occurred. The Commission has rejected customer attempts to escape stranded cost
responsibility in similar circumstances. See Duke Power Co., 79 FERC P 61,236,
at pp. 62,040-41 (1997).
*9 The other customer's stranded cost argument is even more remote.
Dowagiac gave notice to terminate wholesale service from AEP in 1997, effective
in 1998. Dowagiac, which is not even a wholesale requirements customer of
Applicants, argues that Applicants should be required to waive any stranded cost
claims that they may have if Dowagiac acquires some of Applicants' existing
retail customers. The potential recovery of these retail stranded costs is
unrelated to the merger, and is a matter for the Michigan Public Service
Commission. No intervenors remaining in the proceeding has expressed any concern
as to wholesale stranded cost recovery by Applicants due to any actions in the
future. None of the witnesses arguing in favor of a stranded cost waiver
explained how the merger would increase these customers' exposure to stranded
costs. Without any connection to the merger, these arguments fail.
The Commission has repeatedly ruled that arguments about stranded costs
in merger proceedings are premature until customers seek to terminate their
contracts, and that customers' arguments about stranded costs should be made in
a separate proceeding when the stranded cost claim is made. For example, in WPS
Resources Corp., the Commission rejected the customers' request that the
applicants be required to waive stranded cost claims, ruling that "no condition
addressing the recovery of stranded costs should be placed on approval of the
mergee" and that "any claims for stranded cost recovery should be addressed in a
separate proceeding." 83 FERC P 61,196, at p. 61,840 (1998). In IES Utilities,
the Commission rejected the customers' request that the applicants' open season
proposal be modified to include a stranded cost waiver, ruling that stranded
cost issues should be pursued in a separate complaint proceeding. 81 FERC P
61,187, at p. 61,838. In Duke Power Co., customers sought waiver of stranded
costs as a merger condition, arguing that a stranded cost obligation undermined
the Applicants' pre-granted open season because it prevented them from taking
full advantage of competition. The Commission ruled that the customers' stranded
cost arguments were unrelated to the merger, and were already being considered
in ongoing stranded cost proceedings. 79 FERC P 61,236, at pp. 62,040-1. In
addition, the Commission has repeatedly approved other mergers without requiring
a stranded cost waiver. While some utilities have voluntarily agreed to waive
stranded costs in certain situations, the Commission has never ruled in a merger
case that a stranded cost waiver was required to protect customers from
merger-related costs.
Witness McAndrew asserts that his proposal is consistent with the
Merger Policy Statement, but the Merger Policy Statement says nothing about
eliminating stranded cost recovery in connection with an open season or
otherwise, and the cases discussed above (all of which post-date the Merger
Policy Statement) show that the Commission does not share that interpretation.
The Commission stated in Order 888 [FN7] that "the recovery of legitimate,
prudent and verifiable stranded costs is critical to the successful transition
of the electric utility
<PAGE> 10
EXHIBIT D-1.7
industry to a competitive, open access environment," and reaffirmed that view in
Order 888-A, [FN8] issued less than three months after the Merger Policy
Statement. Order 888 at pp. 31,634-35, 31,788-89; Order 888-A at pp. 30,176 and
30,347-48. The Commission added that it had "a responsibility" to allow for the
recovery of stranded costs resulting from its open access regime, Order 888 at
p. 31,790, and that it is fair for departing customers to pay costs legitimately
incurred to provide service to them and which are now stranded, Order 888-A at
pp. 30,347-49 and 30,353. Nothing in the Merger Policy Statement reflects any
intent to abrogate these fundamental principles.
*10 Mr. McAndrew also claimed that a stranded cost waiver is needed for
these departing customers to avoid creating a barrier to entry into the
competitive marketplace following their contract termination, but he offered no
explanation for this assertion, other than citation to the testimony sponsored
by Sturgis and Dowagiac. Both of these customers' stranded cost arguments,
however, are unrelated to the merger.
In addition, Witness Baker explained why McAndrew's assertion was
erroneous. Exh. AC-415 at p. 12. Stranded cost charges compensate a supplier for
charges that the supplier had a reasonable expectation of recovering but which
are now above the market price. At the end of a contract, a wholesale customer
may have to compensate its existing supplier for the above-market costs incurred
to provide service to the customer, but that obligation remains whether the
customer stays with its current supplier (and pays rates that include the
pre-existing obligation) or finds a new one (and makes stranded cost payments
for the pre-existing obligation). Its incremental supply costs, beyond the pre-
existing obligations, will be determined in the competitive market, whether it
takes service from its existing supplier or from a new supplier. McAndrew's
unstated (and unproven) assumption is that by staying with its existing
supplier, the customer will somehow secure (1) a discount below the market price
or (2) the expected value of litigation over the size of the pre-existing
obligation. This is illogical, because in addition to the market price the
supplier is entitled to receive payment for the pre-existing obligation,
regardless of whether the customer stays or leaves.
Further, even if McAndrew's "barrier to entry" argument were correct,
which it is not, it would only relate to the merger if the alleged "barrier"
somehow led the customer to remain with the existing supplier and to pay
cost-based rates that included merger costs in excess of merger benefits. This
unlikely scenario is appropriately addressed not by discarding the Commission's
stranded cost policy, but rather by holding such customers harmless from rates
that include merger costs in excess of merger benefits. McAndrew's proposal is
unwarranted and at odds with Commission policy and should be rejected.
c. Calculation of Merger Costs and Benefits for Hold Harmless Commitment
Applicants propose to use estimated merger costs and benefits to
demonstrate compliance with the hold harmless commitment so as to reduce
unnecessary litigation expense for all parties. Staff Witness McAndrew opposes
Applicants' proposal. His arguments fail.
First, contrary to McAndrew's apparent assumption, Applicants are not
proposing that
<PAGE> 11
EXHIBIT D-1.7
estimated merger costs and benefits be used without regard to their
reasonableness. Applicants would bear the burden of proof that their estimates
are reasonable for purposes of determining whether merger costs included in
rates exceed merger benefits. The proposal is similar to the use of projected
data for setting rates, which is the Commission's preferred method. See Southern
California Edison Co., 8 FERC P 61,099, at p. 61,375 (1979). As in any rate
case, the Commission will judge whether Applicants have met their burden of
showing that the use of their estimates is reasonable. If the Applicants can
meet this burden, rate payers will be fully protected.
*11 Second, McAndrew ignores the fact that any method for determining
merger benefits-including his own-must rely on estimates, because Applicants
will have to estimate what their costs would have been absent the merger.
Third, McAndrew ignores the fact that none of the customers that his
proposal is designed to protect filed testimony opposing Applicants' proposal,
and the one customer that submitted testimony on the subject supported
Applicants' proposal to use estimated data.
Witness McAndrew proposes several other modifications to Applicants'
hold- harmless commitment. First, he argues that Applicants should be required
to present proof that system integration benefits exceed the cost of
transmission required for system integration in order to include such
transmission costs in rates. This proposal must be rejected. The relevant
inquiry under the Commission's ratepayer protection policies is whether total
merger costs included in rates are offset by total merger benefits; how
individual cost and benefit items compare is irrelevant.
Second, McAndrew offers his recommendation on how specific cost items
should be calculated in determining Applicants' compliance with their hold
harmless commitment. This proposal must also be rejected. The Commission can
review the propriety of Applicants' method if the issue arises.
Third, McAndrew offers his recommendation on what information should be
included in Applicants' future Section 205 filings to demonstrate compliance
with the hold harmless commitment. This proposal cannot be accepted, since the
amount and kind of information will depend upon the filing. It is appropriately
reviewed in the proceeding in which the filing is submitted, not here.
d. Requirements Customers Under Formula Rates
Applicants have provided requirements customers receiving service under
comprehensive formula rates (all of which are Southwestern Electric Power
Company ("SWEPCO") customers) several overlapping ratepayer protections that
will ensure that they do not pay merger costs in excess of merger benefits.
First, these formula rate customers will not be subject to merger transaction
costs (even if offset by merger benefits included in rates) because these costs
(which include regulatory costs) are not included in the formulas.
<PAGE> 12
EXHIBIT D-1.7
Second, these customers will receive the benefit of merger savings
which are expected to exceed merger transition costs-because these benefits
automatically flow through the rate formulas.
Third, the customers will not experience any merger-related rate
increase through the year 2002, because (1) the production demand charges in
SWEPCO's formula rates will be capped at 1998 levels (which include no merger
costs) through the end of 2002, and (2) Applicants propose to freeze the
transmission demand charges in these rates at 1998 levels (which include no
merger costs) through the end of 2002. [FN9] This cap and freeze provide
adequate protection because, most, if not all, merger costs are expected to be
incurred within two years of the merger (i.e., Spring 2002, assuming a Spring
2000 closing), well before this cap and freeze end. Exhs.
AC-403 at p. 30, AC-1600 at pp. 12:13.
*12 Fourth, if merger transition costs do occur after 2002, Applicants'
hold-harmless commitment will prevent their inclusion in formula rates unless
offset by merger savings included in rates. This would remain in effect for test
years that begin within five years of the consummation date of the merger. Exh.
AC-415 at p. 30.
Fifth, in response to Witness Gross's argument that SWEPCO's rates
should be fixed at the levels that SWEPCO projected before the merger was
proposed, these customers can make a one-time election to fix the production
demand charges for 2000-2003 at the levels that Applicants projected before the
merger was proposed, subject to adjustment to reflect new capacity additions.
Exh. AC-1600 at p. 11.
Together, these protections provide ample assurance that formula rate
customers will not experience merger costs in excess of merger savings. While
some of Applicants' formula rate customers initially raised some concerns
regarding Applicants' ratepayer protections for customers under formula rates,
Applicants have offered additional ratepayer protections for formula rate
customers, and all of Applicants' formula rate customers have now settled and
withdrawn from the proceeding. Thus, no customer that remains a party to this
proceeding has presented any objection to Applicants' ratepayer protections for
formula rate customers. This should be dispositive of the question of whether
Applicants' ratepayer protections are adequate for formula rate customers.
e. Annual Compliance Filing
Despite the fact that formula rate customers are protected by rate
freezes and rate caps through 2002, can fix their production demand charges
through 2003, and receive the benefit of a hold harmless commitment for five
years, Staff Witness McAndrew argued that Applicants should also be required to
make annual "compliance filings" documenting all merger costs and benefits.
Shortly before the close of the hearing, McAndrew changed his compliance filing
(now redesignated an "informational filing," but still just as burdensome) to
include what he claimed was less detail. He contended that his new proposal was
modeled after a filing requirement imposed in Cincinnati Gas & Electric Co., 64
FERC P 61,237 (1993) (Cinergy).
<PAGE> 13
EXHIBIT D-1.7
The new McAndrew proposal would be more burdensome than that approved
in Cinergy. McAndrew admitted that in Cinergy, the merging parties filed an
annual Period I (historical) study drawn from FERC Form I data, and compared it
to a single Period II (projected) study. Tr. 2430. McAndrew would require
Applicants to submit, on an annual basis, both historical and projected data.
Exh. S-208 at p. 7. McAndrew, who admitted he had never performed a merger
savings study (Tr. 2433), reasoned that preparing annual projections added no
more work since subsequent years' studies would build on prior years' studies.
He initially claimed that factoring in changed circumstances each year would be
the same under his and the Cinergy proposal, but later admitted that under the
Cinergy requirement the changed circumstances would only have to be reflected in
a Form 1-based historical study, not in a new projection. McAndrew explained in
supplemental testimony that his original (and new) filing proposal was directed
to formula rate customers alone. Exh. S-208 at p. 6.
*13 McAndrew's compliance filing is unnecessary, unduly burdensome,
and, like his stranded cost waiver proposal, at odds with Commission policy. The
filing requirement in the Cinergy case-the sole case upon which McAndrew relies
was designed to implement a ratepayer protection standard that the Commission no
longer follows. McAndrew admitted that, at the time the Cinergy case was
decided, the Commission required merger applicants to show that merger benefits
exceeded merger costs. Tr. 2433. Consistent with that requirement, the
Commission required Cinergy to make an annual compliance filing to show whether
merger benefits exceeded merger costs. McAndrew conceded that the Commission has
eliminated the requirement that merger applicants make a showing of merger
benefits. Tr. 2433; see Merger Policy Statement at p. 30,123.
Although Mr. McAndrew admitted that he was aware of the Commission's
policy shift, [FN10] he failed to appreciate its significance to his
recommendation. He also failed to check the Commission's reported decisions to
see whether the Commission continued to require the informational filing
required in Cinergy in any cases issued after the Merger Policy Statement. Tr.
2436. In fact, no merger case involving a hold-harmless commitment, decided
after the Merger Policy Statement imposed an annual merger cost and benefits
filing requirement, [FN11] a fact of which Mr. McAndrew was unaware. Tr. 2436.
The same factor that led McAndrew to propose his filing requirement for
Applicants- the presence of formula rates-was present in many of these cases,
yet no filing requirements were imposed.
The filing Witness McAndrew proposes is not warranted and is likely to
produce more litigation involving Trial Staff, not less. McAndrew ignores the
fact that formula rate customers are already protected by a rate freeze and rate
cap through the end of 2002-well after the period when most if not all merger
costs would be expected to occur, and can secure fixed production charges
through the end of 2003. There is no need to track merger benefits and
transition costs in view of these protections (merger transaction costs are
already excluded from rates). McAndrew also ignores the fact that the formula
rate hold-harmless commitment-the commitment that Mr. McAndrew's proposal is
directed to does not even begin until 2003 in view of these protections. Mr.
McAndrew's proposal also adds unnecessary complexity by requiring Applicants to
catalog all costs and benefits rather than provide sufficient information to
show that benefits exceed costs. There is no need for Applicants to establish
the precise level of merger costs and benefits;
<PAGE> 14
EXHIBIT D-1.7
indeed, there is no need for Applicants to establish that merger costs are
outweighed by merger benefits. Applicants need only show that merger costs
included in rates are outweighed by merger benefits included in rates.
Applicants will demonstrate compliance with that requirement if the issue
arises; as the Commission's prior orders show, no filing requirement is
necessary to trigger that obligation. Finally, while McAndrew downplayed the
burdensome nature of his proposal in his pre-filed testimony, he admitted on
cross examination that he had no idea how much work a merger benefits study
entailed. Tr. 2433. His proposal is rejected.
*14 f. Other Proposals
Witnesses Gross and McAndrew argue that the formula rate caps and
freezes should remain in effect until the end of 2005. Exhs. ETC-500 at p. 12
(Gross), and S-208 at p. 5 (McAndrew). This is unnecessary. As discussed above,
most if not all merger transition costs are expected to be incurred within two
years of the consummation of the merger, well before the end of 2002; and
formula rate customers can fix their production demand charges through the end
of 2003 at levels endorsed by Gross. Exhs. AC-403 at p. 30 and AC-1600 at p. 11.
(Merger transaction costs will be amortized over a longer period, but are not
included in the formula rates.) In addition, formula rate customers will be
protected by Applicants' hold harmless commitment after this period.
Witness Gross also argues that the open season should be extended to
formula rate customers. This too is unnecessary. The availability of fixed
demand charges during the rate protection period will protect formula rate
customers from possible merger-related costs that exceed the merger-related
savings, making an open season unnecessary. None of Mr. Gross's other proposals
is necessary to ensure that merger costs included in rates are offset by merger
savings.
g. Transmission Customers
Transmission customers served under cost-of-service rates are protected
from merger-related costs by Applicants' hold harmless commitment, discussed
above. Mr. McAndrew addresses together Applicants' hold harmless commitment as
it applies to transmission and requirements customers under cost-of service
rates, and the discussion above refutes those arguments.
Transmission customers served under formula rates are protected from
merger-related costs by Applicants' proposed rate freeze and hold harmless
commitment. In addition, McAndrew's concerns about the ratepayer protections for
these formula rate customers ignore the transmission customers' open season
option to switch to Applicants' open access tariff. This gives any transmission
customer that is concerned about merger costs being passed through its formula
rate the option to take service under a stated rate, where any merger costs
included in rates would be subject to review in a Section 205 proceeding.
3. The Rate Schedules in Docket No. ER98-2770-000, as Applicants Have
Agreed to Modify Them, Are Just and Reasonable
<PAGE> 15
EXHIBIT D-1.7
In conjunction with their filing in Docket No. EC98-40-000 for
authorization to merge, Applicants filed in Docket No. ER98-2770-000: (1) the
System Integration Agreement; (2) the System Transmission Integration Agreement;
and (3) the Transmission Reassignment Tariff. The System Integration Agreement
("A") (Exh. AC-416) is an agreement among the AEP operating companies that
governs the integration and coordination of their power supply resources post-
merger. Exh. AC-1300 at p. 3 (Baker). The SIA provides for the distribution of
power supply costs and benefits between the two zones (corresponding to the
pre-merger AEP and CSW systems). It will function in addition to, but not in
substitution of, the existing AEP system interconnection agreement and the
existing CSW system operating agreement. Id. at p. 4. Those existing agreements
will continue to govern the distribution of costs and benefits within the zones.
Ibid.
*15 The System Transmission Integration Agreement ("STIA") (Exh.
AC-1401) establishes a framework under which the transmission facilities of the
AEP operating companies and the CSW operating companies will be planned,
operated, and maintained on a coordinated basis. Exh. AC-1400 at p. 5 (Bethel).
The STIA is intended to supplement-not replace-the existing intra-system
transmission agreements (id. at p. 5), which will continue to govern costs
relating to transmission facilities that were in commercial operation
pre-merger. Id. at p. 7.
The Transmission Reassignment Tariff ("TRT") (Exh. AC-417) governs the
rates, terms, and conditions under which American Electric Power Service
Corporation ("AEPSC") may resell, assign, or transfer all or a portion of its
reserved right to use the transmission system of the post-merger operating
companies, or rights that it has reserved or otherwise acquired on the
transmission systems of other providers. Id. at p. 2.
4. Parties' Concerns
a. Blue Ridge/ETC/TDU
Only two witnesses raised issues concerning the SIA, STIA, and/or TRT
in their direct testimonies. J. Bertram Solomon (Exhs. BRP-200, ETC-400,
TDU-400), on behalf of Blue Ridge, ETC, and TDU, [FN12] was one of them. He
argued that the SIA and STIA grant AEP unbridled discretion over the assignment
of certain future costs because those agreements provide for "the Agent" (i.e.,
AEPSC) to determine certain of the elements that affect those costs. Exh.
BRP-200 at p. 74. Claiming that Applicants are, in effect, seeking "to be
granted pre-approval of any allocation methodology chosen by the Agent" (id. at
p. 76), Solomon advocated removing the phrase "as determined by the Agent" from
the SIA and STIA and adding the phrase "subject to regulatory approval."
As Applicants' Witness explained, however, Applicants are not
requesting pre-approval of the allocation methodologies that AEPSC may use in
the future. Exh. AC-1110 at p. 100. Rather, any such allocations will be subject
to review and challenge under the Act when made. Thus, the rationale for
Solomon's proposed modifications to the SIA and STIA fails.
<PAGE> 16
EXHIBIT D-1.7
b. Trial Staff
System Integration Agreement: Staff Witness Patterson raised several
issues relating to the SIA. Applicants agreed to make certain additions and
modifications to the SIA to address her concerns, but argued strenuously against
modifications that would be at odds with the fundamental objectives of the SIA.
Ultimately, Applicants and Staff resolved all but one of their differences
concerning the SIA and memorialized their agreement in the July 13, 1999
Stipulation (Ex. AC-1307).
The July 13, 1999 Stipulation specifically provides for:
1. An addition to SIA Service Schedule A, T A2, concerning the allocation of
capacity costs, requiring AEP to notify wholesale customers and state regulators
when AEPSC determines an allocation among operating companies of new capacity
that AEP has constructed or purchased, at which time those entities can exercise
their rights to challenge the allocation determination. Exh. AC-1307 at p. 2.
This satisfied the concern that Ms. Patterson expressed about the SIA's lack of
a list of allocation criteria and the up-front allocation of generation costs
for the life of the new facilities. Exh. S-100 at p. 8.
*16 2. A clarifying modification to Article 7:3 ofthe SIA, concerning
capacity exchanges between the two zones, and the addition of definitions of the
terms "foregone opportunity cost" and "decremental capacity cost." Exh. AC-1307
at pp. 1 and 2. These amendments satisfied Patterson's concern that the
circumstances under which capacity exchanges will be made between the two zones
post-merger were unclear. Exh. S-100 at p. 9.
3. An addition to SIA service Schedule D, P D3, concerning the allocation
between the zones of revenues realized from off-system sales, to require the
Applicants to make an FPA Section 205 filing to justify their allocation
methodology for the period after the fifth full calendar year following the
consummation of the merger, and the addition of a definition for "owned
generating capacity." Exh. AC-1307 at pp. 2 and 3. These additions satisfied
Patterson's concerns that the SIA's method of allocating revenues from off-
system sales, which allows each zone to receive the equivalent off-system sales
credits that it would have absent the merger (and thus keep its ratepayers
whole), could be misinterpreted, and could become stale and inappropriate.
Applicants will implement the modifications set forth in the July 13,
1999 Stipulation via a compliance filing after merger approval. Exh. AC-415 at
p. 39. Applicants and Staff agree that the SIA, as modified by the Stipulation,
is just and reasonable.
System Transmission Integration Agreement: With respect to the STIA,
Staff Witness Patterson raised only one issue: In her view, the STIA did not
consistently treat the allocation of transmission costs between the two zones
for (1) charges paid to third parties for transmission capacity to link the two
zones, and (2) costs to build transmission to link the two zones. Exh. S-I 00 at
p. 24. She proposed amending the STIA to provide that the costs associated with
acquiring or installing new transmission facilities to link the two zones be
allocated equally between the two zones. Id.
In their rebuttal testimony, Applicants agreed to make such a change to
the STIA. Exh. AC-110 at p. 104. Their proposed amendment, to which Staff
agreed, is set forth in the July 13
<PAGE> 17
EXHIBIT D-1.7
Stipulation. Exh. AC-1307 at p. 4. With this agreed-upon change, the STIA is
just and reasonable.
Transmission Reassignment Tariff: Witness Patterson, the only witness
who challenged any provision of the TRT, raised several issues regarding this
tariff, which governs the resale, assignment, or transfer of transmission
capacity that the merged company has reserved on the systems of its operating
companies or third parties. 89 Applicants and Trial Staff later resolved all
differences regarding the TRT. In the July 13, 1999 Stipulation, Applicants
agreed to modify the TRT as follows:
1. Add "in accordance with Commission regulations" to Section 3.3 of the
Form of Service Agreement, the provision governing termination of service (Exh.
AC-1307 at p. 3). See Exh. S-100 at p. 33.
*17 2. Add a clarifying sentence to Article III.D (see Exh. AC-1307 at
p. 3) addressing refunds for interrupted service. See Exh. S-100 at p. 30.
3. Add a sentence to Section IV.C (see Exh. AC-1307 at pp. 3 and 4), stating
that termination of the TRT terminates underlying service agreements. See Exh
S-100 at p. 33.
The TRT, as modified by the July 13, 1999 Stipulation, is just and reasonable.
5. Applicants-Staff Stipulation
The Stipulation between Applicants and Trial Staff (Exh. AC-603) makes
it unnecessary to resolve all of the intervenors' issues relating to Applicants'
filed rates in Docket No. ER 98-2786-000, the joint open access transmission
tariff under which the merged company will provide transmission and ancillary
services. Applicants' filed cost of service was $494,055,109 for AEP East and
$211.828,157 for AEP West. Exhs. AC-1102 and AC-1103. The Stipulation contains
rates that are based on costs of service of $349,712,000 for AEP East and
$162,036,000 for AEP West. These figures are substantially below Applicants'
filed cost of service and only about 20 percent above the cost of service
proposed by AEGIS, the only intervenor that performed a comprehensive cost of
service analysis. Exh. AEG-1 (Reising). While the Commission should use
Applicant's filed rates as a starting point, this proceeding will have an effect
on the rates only if the adjustments to the cost of service would produce rates
lower than the stipulated rates.
6. Two Cost of Service Issues Already Have Been Resolved
In American Elec. Power Service Co., 88 FERC P 61,141, at pp. 61,441-42
(1999) (Opinion 440), the Commission held that AEP's use of a gross plant,
levelized rate for transmission service was not just and reasonable. The
Commission also rejected Applicants' inclusion of generator step-up transformers
in the transmission cost of service. Applicants will adopt the Commission's
final order (i.e., the Commission's rehearing order) in that docket on both
issues, both with respect to this proceeding and with respect to the rates that
they will file before consummating the merger. Exh. AC-1110 at pp. 9 and13.
There is no need to address those issues in this decision.
7. Intervenors' Other Proposed Adjustments to the Transmission Cost of
Service Are Not
<PAGE> 18
EXHIBIT D-1.7
Just and Reasonable
a. Applicants' Test Year Is Just and Reasonable
Applicants' development of their proposed rates based on a 1996 test
year was just and reasonable. They will refile their rates prior to consummation
of the merger. Exh. AC-1110 at p. 3. Thus the purpose of the rates litigation is
to establish cost of service and rate design principles, and not specific rate
levels. Hearing Order at p. 61,825. The intervenors' proposed 1998 test year
(Exh.AEG-1 at pp. 15 and 16) would have no more probative value with respect to
the principles applicable to the post-merger rates than would a 1996 test year.
*18 Intervenors have not offered a just and reasonable alternative to
Applicants' 1996 test year. AEGIS' so-called 1998 test year is based on a
hodgepodge of estimates derived from 1996 and 1997, together with unaudited 1998
data. Exh. AEG-1 at pp. 14 and 19. That test year violates basic cost of service
principles. See Pacific Gas and Elec. Co., 53 FERC P 61,146 at p. 61,520 (1990).
b. Applicants' Calculation of Transmission Revenue Credits Based on 1996 Data Is
Just and Reasonable
Applicants developed their transmission cost of service by crediting
1996 revenues from short-term and non-firm transmission service against their
1996 costs. In contrast, the intervenors have proposed to adjust the 1996 cost
of service by crediting revenues received from short-term and non-firm
transmission service in 1998. Exh. AEG-1 at p. 19. The intervenors' proposal to
mix 1996 costs and 1998 revenues is inconsistent with basic ratemaking
principles. The Commission does not permit post-test year adjustments to the
cost of service unless the test year estimates were unreasonable when made or
subsequent events demonstrate that the estimates would produce unreasonable
results. Pacific Gas, 53 FERC at p. 61,520.Applicants have used a historic test
year, and there is no question of the reasonableness of estimates. Also, post-
test year events do not indicate that the use of the historic data would produce
unreasonable results in the future because Applicants will refile their rates
prior to consummation of the merger.
c. Other Intervenor Positions
Intervenors unsuccessfully urged a number of other proposals that do
not require extensive treatment. Their value was simply not convincingly
demonstrated on this record. The most important among them were:
1. AEGIS' proposed functionalization of GSU-related equipment.
2. Exclusion of radial facilities from the transmission cost of service.
3. Challenges to Applicants' West Zone rates.
4. Selective exclusion of items of cost of service.
5. Rate of Return on Common Equity
Applicants' Witness Barber recommended a 1 1.75 percent rate of return
on common equity for AEP and CSW as a combined entity. He applied the standards
for determining the rate
<PAGE> 19
EXHIBIT D-1.7
of return established in Bluefield Water Works & Improvement Co. v. PSC of West
Virginia, 262 U.S. 679 (1923) and FPC v. Hope Natural Gas Co., 320 U.S. 591
(1944).
In Bluefield, the Court said:
A public utility is entitled to such rates as will permit it to earn a
return on the value of the property which it employs for the convenience of the
public equal to that generally being made at the same time and in the same
general part of the country on investments in other business undertakings which
are attended by corresponding risks and uncertainties; but it has no
constitutional right to profits such as are realized or anticipated in highly
profitable enterprises or speculative ventures. 262 U.S. 679 at 692-693
(emphasis added*19
In Hope, the Court stated that:
Rates enable the company to operate successfully, to maintain its
financial integrity, to attract capital, and to compensate its investors for the
risks assumed . It is not the theory but the impact of the rate order which
counts. 320 U.S. 591 at 605.
Applying the Bluefield and Hope standards requires the analysis of all
available data. Thus rather than rely on a single methodology, Barber considered
several methods of determining the cost of common equity.
Witness Barber considered variations of the DCF methodology. The first,
or "conventional" DCF methodology resulted in a minimum cost of common equity of
approximately 5.65 percent for AEP (Exh. AC-1209) and 6.44 percent for C SW
(Exh. AC-1215). He testified that very little reliance should be placed on the
results obtained using this method because the unrealistic assumptions produce
such a low return as to conclusively demonstrate its invalidity. Exh. AC-1200 at
p. 13. Two modifications to conventional DCF methodology produce more realistic
results. The first alternative replaces the market value of stock with its book
value because the market value ignores the fact that the current market price is
in part based upon actual recent and anticipated future market appreciation.
Exh. AC-1200 at p. 15. This alternative calculation results in a minimum cost of
common equity of 10.13 percent for AEP and 10.30 percent for CSW. Exhs. AC-1209
and AC-1215. The second alternative recognizes that stock prices are based on
factors other than dividend expectations. Barber identified three elements to be
considered: current yields, expected gains in dividends and expected change in
market value. AC-1200 at p. 16. He looked at actual annual increases in the
market value of AEP and CSW common stock over the last ten years, excluded the
highest and lowest years and then assumed that investors are anticipating ating
that future market appreciation will be less than was realized over the past ten
years. The result is a minimum required return on equity of 10. 3 9 percent for
AEP and 11.44 percent for CSW. Exhs. AC-1209 at p. 2 and AC-1215 at p. 2.
Barber also considered and explained the effect on the DCF method of
stock prices' divergence from book values, other methods of determining the
proper return for Applicants, comparable earnings methodology, and the risk
premium methodology. The results are
<PAGE> 20
EXHIBIT D-1.7
summarized in Exh. AC-1208 at p. 12.
The effect of Barber's evidence, which was persuasive and not weakened
by any cross-examination or contradictory evidence, is a finding that reasonable
rates of return on common equity are 12.0 percent for AEP, 11.5 percent for CSW,
and 11.75 percent for the merged company.
6. Rate Design
AEGIS Witness Reising proposes that AEP's rates for point-to-point
transmission service be designed using a 1-CP allocator. That proposition is
untenable. There is no factual or legal basis on which to base it. The
Commission decides whether a transmission rate should be designed on a 1-CP
basis or a 12-CP basis on the facts of each case. Order 888 at p. 31,738. A
transmission system must be designed to meet the changes in demands placed on
it, which are a function of peak loads, changes in customer load patterns,
scheduled maintenance and unscheduled outages on the transmission system and
generator outages. Exhs. AC-1110 at p. 86 and AC-1108. Consequently, AEP plans
its transmission system to meet each monthly peak and to deal with all
reasonable contingencies.
*20 AEP's peak loads meet the tests established by the Commission for
determining whether a utility is a 12-CP company. See Illinois Power Co., 11
FERC P 63,040, at pp. 65,248-49 (1980), modified, 15 FERC P 61,050 (1981);
Carolina Power & Light Co., 4 FERC P 61,107, at p. 61,230 (1978). See also Exh.
AC-1108. The Commission has continued to apply these tests in designing
transmission rates after the issuance of Order 888, demonstrating that the tests
are appropriate for the design of transmission rates. Niagara Mohawk Power
Corp., 82 FERC P 63,018, at p. 65,143 (1998); Consumers Energy Co., 86 FERC P
63,004, at p. 65,032 (1999). It follows that a 12-CP rate design is appropriate
for AEP.
It is a basic principle of ratemaking that rate design should have no
impact on the recovery of revenues. Rate design is revenue-neutral if the
determinants that are used to calculate customer bills are consistent with the
determinants that are used to design the unit charges. Northeast Utils. Serv.
Co., 62 FERC P 61,294, at pp. 62,906-07 (1993). AEGIS violated this basic
principle of rate design by proposing to design the Applicants' rates based on
the annual peak, but to bill customers based on their monthly peak loads. The
result of that would be unreasonable because it would guarantee that the
transmission provider could not recover its cost of service. See Exh. AC-1110 at
p.86.
Applicants' rate design, as proposed, must be approved.
IV. Ultimate Findings and Conclusions
Pursuant to the Commission's orders, and upon consideration of the
entire record of these proceedings, I find and conclude:
1. Applicants' request to merge their jurisdictional facilities, with the
mitigation measures to which they have committed, is consistent with the public
interest;
<PAGE> 21
EXHIBIT D-1.7
2. The rates, terms, and conditions of the three rate schedules filed in
Docket No. ER98-2770-000, as modified by the stipulation entered into by
Applicants and Staff, are just, reasonable, and not otherwise unlawful; and
3. The Joint Open Access Transmission Tariff providing for post-merger
transmission and ancillary services filed in Docket Nol ER98-2786-000, as
modified by the stipulation entered into by Applicants and Staff, is just,
reasonable, and not otherwise unlawful.
V. Orders
It is, therefore, ordered:
1. DP&L's motion for official notice, described above, is denied;
2. The merger herein proposed is approved to the extent set out in the body of
this initial decision;
3. If refunds are due any customer as a consequence of any action, revision,
or amendment required to conform to the rulings, findings, or conclusions made
in this initial decision, then 90 days after the Commission approves such
action, revision, or amendment, Applicants must refund all amounts collected in
excess of those that would have been payable under any such action, revision, or
amendment, with interest from the date of payment to the date of refund as
provided in this Commission's rules and regulations. See 18 C.F.R. s 35.19(a)(2)
(1999); and
*21 4. Within 60 days after making any refund payment required by this initial
decision, Applicants must file with this Commission a report in writing
describing the payee of such payment, the amount of refund paid, the amount of
interest paid, and the methods by which such refund and interest were determined
and calculated.
FN1 85 FERC P 61,201 (1998).
FN2 Tr. 2459, confirmed by my order issued July 21, 1999.
FN3 Tr. 2464.
FN4 Tr. 2460.
FN5 88 FERC P 61,121 (1999).
FN6 Inquiry Concerning the Commission's Merger Policy Under the Federal
Power Act: Policy Statement Order No. 592, 61 Fed. Reg. 68,595 (1996), FERC
Statutes and Regulations P 31,044 (1996), order on reconsideration, Order No.
592-A, 62 Fed. Reg. 33,341 (1997), 79 FERC P 61,321 (1997).
FN7 Order No. 888, Promoting Wholesale Competition Through Open Access
Non-Discriminatory Transmission Services by Public Utilities; Recovery of
Stranded Costs by Public Access Utilities and Transmitting Utilities, FERC
Statutes and Regulations, Regulation Preambles January 1991-June 1996 P 31,036
(1996) ("Order 888").
FN8 Order No. 888-A, Promoting Wholesale Competition Through Open Access
<PAGE> 22
EXHIBIT D-1.7
Non-Discriminatory Transmission Services by Public Utilities; Recovery of
Stranded Costs by Public Access Utilities and Transmitting Utilities, FERC
Statutes and Regulations, Regulations Preambles P 31,048 (1997) ("Order 888-A").
FN9 In the alternative, these customers can elect an annual option to
switch to Applicants' open access tariff. Exh. AC-403 at pp. 30:13-19.
FN10 He also admitted that, while he relied on the Merger Policy
Statement for the Cinergy case, in fact the Merger Policy Statement makes no
reference tothe portion of Cinergy-the required annual filing-that he relied
upon. Tr. 2435. See Merger Policy Statement at p. 30,122.
FN11 See PacifiCorp, 87 FERC P 61,288 (1999); New England Power Co., 87
FERC P 61,287 (1999); SierraPacific Power Co., 87 FERC P 61,077 (1999);
Wisconsin Energy Corp., 83 FERC P 61,069 (1998); WPS Resources Corp., 83 FERC P
61,196 (1998); Louisville Gas & Elec. Co., 82 FERC P 61,308 (1998); Long Island
Lighting Co., 82 FERC P 61,129 (1998) (divestiture case decided under Merger
Policy Statement criteria); IES Util., Inc., 81 FERC P 61,187 (1997); Union
Elec. Co., 81 FERC P 61,011 (1997); AtlanticCity Elec. Co., 80 FERC P 61,126
(1997); First Energy I, 80 FERC P 61,039 (1997); 81 FERC P 61,110 (1997); San
Diego Gas & Elec. Co., 79 FERC P 61,372 (1997); Duke Power Co., 79 FERC P 61,236
(1997); and Public Serv. Co. of Colorado, 78 FERC P 61,267(1997).
FN12 ETC withdrew its opposition to the merger August 17, 1999; Blue
Ridge, November 18, 1999.
Federal Energy Regulatory Commission
89 FERC P 63,007, 1999 WL 1061502 (F.E.R.C.)
END OF DOCUMENT
<PAGE> 1
EXHIBIT D-1.8
1999 WL 1212980 (F.E.R.C.)
*1 Commission Opinions, Orders and Notices
Alliance Companies
American Electric Power Service Corporation, Consumers Energy Company, Detroit
Edison Company, First Energy Corporation, and Virginia Electric and Power
Company
Docket No. ER99-3144-000
Docket No. EC99-80-000
Order on Proposed Disposition and Related Rate Filings
(Issued December 20, 1999)
Before Commissioners: James J. Hoecker, Chairman; William L. Massey, Linda
Breathitt, and Curt H (acute)ebert, Jr.
In this order, the Commission conditionally authorizes the application
of several transmission-owning public utilities (Alliance Companies or
Applicants) [FN1] to transfer ownership and/ or functional control of their
jurisdictional transmission facilities to the Alliance regional transmission
organization (Alliance). The order also conditionally accepts under Section 205
of the Federal Power Act (FPA) certain agreements filed as part of the
application. We are conditionally approving the general framework of the filing
to the extent discussed in this order. Other issues will be addressed as part of
our review of Applicants' compliance filing.
We are encouraged by the Applicants' substantial efforts to form a new
transmission entity to own or control their transmission facilities. The
Applicants have developed creative and innovative approaches to several
important issues involved in the formation of such regional entities,
particularly tax issues related to divestiture. The Commission is open to
transcos (for-profit regional transmission entities) and has carefully
considered the Applicants' proposed transco in this order. While certain aspects
of their proposal require modification or further development, we appreciate the
difficult work the Applicants have done already and believe that their proposal,
if modified to address the concerns of this order, can provide significant
benefits to the industry and consumers. Our Final Rule on regional transmission
organizations (RTO), which is being issued concurrently, [FN2] provides for a
collaborative process in developing RTOs and we look forward to working with the
Applicants and others as part of such a process.
I. The Filing
<PAGE> 2
EXHIBIT D-1.8
On June 3, 1999, the Alliance Companies filed an application under
Section 203 of the FPA, 16 U.S.C. s 824b (1994), seeking an order approving the
transactions necessary to create Alliance. The Alliance Companies indicate that
these transactions will include one or more of the following: (1) the transfer
of ownership of jurisdictional transmission facilities owned by one or more of
the Alliance Companies to Alliance Transmission Company, LLC (Alliance Transco)
and the transfer of control over operations of jurisdictional transmission
facilities owned by the remaining Alliance Companies to the Alliance Transco;
(2) the transfer of control over operations of jurisdictional transmission
facilities owned by the Alliance Companies to the Alliance Independent
Transmission System Operator, Inc. (Alliance ISO); and (3) the transfer of
control over operations of the jurisdictional transmission facilities of the
Alliance Companies from the Alliance ISO to the Alliance Transco.
*2 The Alliance Companies analyzed their proposal under the minimum
characteristics and functions set forth in the RTO NOPR. [FN3] The Alliance
Companies also include an analysis to demonstrate that their proposal satisfies
the eleven independent system operator (ISO) principles adopted in Order No.
888. [FN4] According to Applicants, their proposal meets each of the
Commission's eleven ISO principles set forth in Order No. 888. In addition,
Applicants contend that their proposal substantially complies with the four
required characteristics and seven required functions set forth in the
Commission's RTO NOPR. In the event that the Commission is unable to find that
the Alliance proposal satisfies any element of the minimum characteristics and
functions proposed in the RTO NOPR, the Applicants request that the Commission
find that the Alliance proposal is just and reasonable in light of its
substantial compliance with the proposed RTO NOPR and its satisfaction of the
ISO principles. The Applicants acknowledge that, as public utilities owning and
operating transmission facilities, the Alliance Companies will be required to
comply with any requirements emanating from the RTO Final Rule.
The Alliance Companies submitted a companion filing in Docket No.
ER99-3144-000, pursuant to Section 205 of the FPA, requesting that the
Commission permit these transactions to occur pursuant to the terms of the
"Alliance Agreement Establishing the Alliance Independent Transmission System
Operator, Inc., the Alliance Transmission Company, Inc., and the Alliance
Transmission Company, LLC (Alliance Agreement)." The Alliance Companies also
seek Commission approval of an Alliance open access transmission tariff (OATT or
Tariff).
On October 1, 1999, the Alliance Companies amended their Sections 203
and 205 applications to include a list of transmission facilities that will be
transferred to the Alliance. In addition, the Alliance Companies filed two
amendments to its Pricing Protocol and the methodology for calculating the fee
under which Alliance will recover its administrative costs.
The Alliance Companies request that the Commission approve the entire
Alliance proposal at this time and permit the Alliance Companies to implement
the components of the proposal without being required to receive further
approvals from the Commission. The Alliance Companies explain that they have
submitted a detailed mechanism to implement all aspects of the proposal and,
thus, Applicants argue that the Commission will be able to satisfy itself fully
<PAGE> 3
EXHIBIT D-1.8
that the proposal is consistent with the public interest. Applicants claim that
this aspect of the requested authorization is the cornerstone of its proposal.
II. Summary of the Alliance Proposal
The Alliance Companies propose to create a for-profit transmission
entity (Alliance Transco) that would own, control, and operate the
jurisdictional transmission facilities of one or more of the Alliance Companies
and would control-but not own-the transmission facilities of the remaining
Alliance Companies. [FN5] Alternatively, if certain triggering conditions
required to initiate the Alliance Transco are not met, the Alliance Companies
would initially establish a non-profit independent system operator (i.e., the
Alliance ISO) to control their jurisdictional facilities until the trigger
conditions are later satisfied, allowing the transition to Alliance Transco.
*3 If the Alliance Companies elect to form the Alliance Transco, they
will do so by forming two companies, the Alliance Publico and the Alliance
Transco. The Alliance Transco will be a Delaware limited liability company and
will own all the transmission assets divested by the divesting transmission
owners. The Alliance Transco will have one managing member and one or more
non-managing members. The managing member will be Alliance Publico, a registered
public utility holding company that will be owned and controlled by the public
through the sale of voting securities in an initial public offering. Any
Alliance Company that chooses to divest its transmission facilities to the
Alliance Transco in exchange for a membership interest in the Alliance Transco,
rather than a cash sale, will be a non-managing member of the Alliance Transco.
According to Applicants, the Alliance Publico will be governed by a
Board of Directors appointed by the shareholders. Directors of Alliance Publico
may not be affiliated with any of the Alliance Companies. In addition, no
Alliance Company or "Transmission User" under the Alliance Tariff may purchase
more than 5 percent of the stock of the Alliance Publico, or hold contract
rights otherwise entitling it to direct the voting percentage of such stock.
[FN6] The Alliance Transco also will have an advisory committee consisting of
stakeholders from all segments of the industry.
Applicants state that, within 90 days after the Commission issues an
order approving the instant submittal, the Alliance Companies will make an
initial declaration of their intent to transfer ownership of their transmission
facilities to the Alliance Transco. The Alliance Transco will be created if the
initial declaration results in the satisfaction of the following Transco Trigger
Conditions: (1) one or more of the Alliance Companies that have transmission
facilities with a gross book value of at least $1 billion in aggregate declares
that it (or they) intends to divest its transmission facilities to the Alliance
Transco (Divesting Transmission Owner); and (2) at least 50 percent of the
remaining Alliance Companies concur with the establishment of the Alliance
Transco (Non-Divesting Transmission Owner). [FN7] Non-Divesting Transmission
Owners will transfer functional control over their transmission facilities to
the Alliance Transco which will
<PAGE> 4
EXHIBIT D-1.8
perform the functions of an ISO with respect to those facilities. [FN8] Under
this option, Alliance will function as a hybrid Transco/ISO. Each Alliance
Company will sign an Agency Agreement which will permit Alliance to provide
transmission service over the respective transmission and distribution
facilities that are not transferred to Alliance. Prior to the election of the
Board of Directors of the Alliance Publico, any Alliance Company may withdraw
from the Alliance Agreement on 30 days' notice. In addition, after the Board of
Directors are elected, any Alliance Company may withdraw from the Alliance
Agreement upon 12 months' notice and the receipt of any required governmental
approvals.
*4 As previously discussed, within 90 days of the Commission's approval
of the instant submittal, the Alliance Companies will declare their intentions.
However, if the triggering conditions needed to form the Alliance Transco are
not met, the Alliance Companies will create the Alliance ISO. Each Alliance
Company will execute an Operation Agreement which will transfer control of that
Alliance Company's transmission facilities to Alliance which will operate these
facilities pursuant to the Operating and Planning Protocols. As with the
Alliance Transco, each Alliance Company will also sign an Agency Agreement for
transmission service over the facilities that are not transferred to the
Alliance ISO. The Alliance ISO will continue in operation until one or more of
the Alliance Companies triggers the transition from the Alliance ISO to the
Alliance Transco. Once the transition is complete, the Alliance ISO would be
dissolved. Alliance Companies also may withdraw from the Alliance Agreement
within the same time periods and under the same conditions pending election of
the Board of Directors of the Alliance ISO.
Any time after the Alliance ISO commences operations, any Alliance
Company may formally request a vote of the Alliance Companies with respect to
their intent to divest their transmission assets. If the previously discussed
trigger conditions are met, the Divesting Transmission Owners will transfer
title of their transmission facilities to the Alliance Transco and the Alliance
ISO will transfer control over all remaining transmission facilities to the
Alliance Transco. When the Alliance Transco becomes operational, the Alliance
ISO will be dissolved.
According to Applicants, if the Commission approves the application,
including the transition mechanism, and the Alliance Companies initially form
the Alliance ISO, the Alliance Companies commit that the Alliance Transco
trigger conditions will be met no later than three years after the Alliance ISO
commences operations. The Alliance Companies request that the Commission approve
the entire Alliance proposal and permit the Alliance Companies to implement the
components of the proposal without being required to receive further approvals
from the Commission. Applicants state that they need the ability to divest their
transmission assets at a time when the financial markets will be receptive to an
initial public offering of stock in Alliance Publico. In addition, Applicants
contend that, as an incentive to the Alliance Companies to divest, the
divestiture and initial public offering must take place at a time when the
financial markets will place a high value on the transmission assets to be
divested. [FN9]
III. Summary of Proposed Agreements
<PAGE> 5
EXHIBIT D-1.8
The Alliance Agreement is the umbrella agreement signed by the Alliance
Companies that provides the mechanisms for forming the Alliance Publico/Alliance
Transco, or in the alternative, the Alliance ISO. The Alliance Agreement also
provides the transition from the Alliance ISO to the Alliance Publico/Alliance
Transco if Alliance initially takes the form of the Alliance ISO. The Alliance
Agreement includes the following: (1) Term Sheet for the Alliance Publico; (2)
Term Sheet for the Alliance Transco; (3) Bylaws for the Governance of the
Alliance ISO; (4) Alliance Operating Protocol; (5) Alliance Planning Protocol;
(6) Alliance Protocol for Transmission Service Pricing, Discounting, Revenue
Distribution, and Grandfathered Contracts; (7) Alliance Operation Agreement; and
(8) Alliance Agency Agreement. [FN10]
*5 The Applicants also filed a proposed open access transmission
tariff. We will address the tariff in a future order.
IV. Notice of Filing and Responses
Notices of Applicants' filings, in Docket Nos.EC99-80-000 and
ER99-3144-000 were published in the Federal Register, 64 Fed. Reg. 32,851 (1999)
and 64 Fed. Reg. 32,038 (1999) (respectively), as jointly supplemented, 64 Fed.
Reg. 58,392 (1999), with comments, protests and interventions due on or before
November 12, 1999.
The state commissions of Ohio, Illinois, Indiana, Michigan, Missouri,
Maryland and West Virginia have filed notices of intervention. In addition, a
number of other parties have filed motions to intervene and protests in one or
both dockets, as listed in Appendix A to this order. Several parties have moved
for various other forms of relief, including motions to consolidate Docket Nos.
ER99-3144-000 and EC99-80-000, requests for hearing on aspects of the filing,
requests for imposition of certain conditions, and a suggestion for limited
referral to the Office of Dispute Resolution Services. [FN11]
V. Discussion
I. Procedural Matters
The notices of intervention of the state commissions and the timely,
unopposed motions to intervene serve to make the intervenors listed in Appendix
A parties to this proceeding. See 18 C.F.R. s 385.214 (1998). Given the stage of
this proceeding, and the absence of undue delay or prejudice, we find good cause
to grant the untimely, unopposed motions to intervene by parties listed in
Appendix A.
Certain parties also filed answers to various requests for relief and
protests. Although the Commission's Rules of Practice and Procedure do not
permit answers to protests, [FN12] given the complex nature of this proceeding,
and given that the answers help in clarifying certain issues, we will accept the
answers.
<PAGE> 6
EXHIBIT D-1.8
II. Standards to be Used to Analyze the Alliance Proposal
A. Statutory Authority
Our review of this application is based on our statutory authority
under Sections 203 and 205 of the FPA. The transfer of ownership or operational
control of the jurisdictional transmission facilities of public utilities to
Alliance is a disposition of jurisdictional facilities requiring prior
Commission authorization under Section 203. [FN13] The Commission shall approve
such a disposition if "consistent with the public interest," and may condition
its approval as it finds necessary or appropriate "to secure the maintenance of
adequate service and the coordination in the public interest of facilities
subject to the jurisdiction of the Commission." We must also review the related
agreements under Section 205 to ensure that they are just and reasonable, and
not unduly discriminatory or preferential.
B. Standard to Review this Proposal
The RTO NOPR indicated that the Commission would apply the eleven ISO
principles set forth in Order No. 888 to proposals to create regional
transmission institutions prior to the effective date of the RTO Final Rule.
Accordingly, as discussed below, we will analyze the Alliance Companies'
proposal in the context of the eleven ISO principles. However, we will also
provide certain guidance on the Alliance Companies' proposal based on the RTO
Final Rule, which is being issued concurrently.
*6 III. Analysis Under the Eleven ISO Principles
Principle No. 1: Governance should be structured in a fair and non-
discriminatory manner.
Applicants
Applicants contend that the governance structure of Alliance is fair
and non-discriminatory and satisfies ISO Principle No. 1. Applicants contend
that the Transco's governance structure is unique to Alliance and reflects the
inherent differences between a for-profit transco and a not-for-profit ISO.
Applicants maintain that aspects of the governance structure are necessary to
protect investment and to create an entity that is attractive to outside
investors and will encourage voluntary participation by utilities in RTOs.
Intervenors
Intervenors argue that Alliance fails to meet the independence
principle for an ISO described in Order No. 888. Intervenors contend that
Alliance fails the independence standard in several areas. [FN14] First,
Alliance would permit the transmission owners (and any transmission user) to
individually own up to 5 percent of the voting stock of Alliance Publico.
Intervenors argue that this would permit the Alliance Companies to control 25
percent of the voting stock of Alliance Publico. Intervenors assert that 25
percent of the votes of a publicly held
<PAGE> 7
EXHIBIT D-1.8
corporation is a sizable block that could have a significant impact on the
management of the Alliance Publico. Intervenors argue that, if other utilities
join, the voting block would also increase.
In addition, Intervenors note that Applicants' proposed Alliance
Transco suffers from a similar independence problem. According to Intervenors,
an Alliance Company that divests its transmission assets to the Alliance Transco
could have a substantial ownership interest in the Alliance Transco because of
the optional compensation package. A divesting Alliance Company may receive
either cash or an ownership interest (or a combination of the two) in the
Alliance Transco. Thus, an Alliance Company may divest its transmission assets
but reacquire an ownership interest in the transmission entity that now operates
the same divested assets. [FN15] Chaparral objects to this structure generally
and requests that the Commission direct Alliance to be formed as a publicly
traded firm with limitations on ownership by utility participants. [FN16]
According to Intervenors, a transmission owner that divests its
transmission assets to the Alliance Transco could have a substantial ownership
interest in the Alliance Transco because of the optional compensation package. A
divesting transmission owner may receive either cash or an ownership interest
(or a combination of the two) in the Alliance Transco. Thus, a transmission
owner may divest its transmission assets but reacquire an ownership interest in
the transmission entity that now operates the same divested assets. [FN17] While
this ownership interest will be "passive," Intervenors argue that governing
business organization law makes it quite clear that the Transco's Directors and
management will owe a fiduciary duty to the transmission owners. NCEMC contends
that the actual ownership interest of the transmission owners on the Alliance
Transco could exceed the ownership interest of the Publico. [FN18]
*7 NCEMC argues that the Commission should impose a timetable under
which a divesting transmission owner would have no more than three full tax
years from the time of the initial divestiture of its transmission assets to the
Alliance Transco to sell or otherwise dispose of its ownership interest in the
Alliance Transco. [FN19] As currently structured, NCEMC contends that an
Alliance Company may retain an ownership interest in the Alliance Transco
indefinitely. [FN20] Moreover, while Applicants describe the Alliance Companies'
interest in Alliance Transco as "passive," NCEMC argues that Applicants have
reserved a series of rights that will adversely affect the Publico's ability to
manage the business of the Transco free of the control of the divesting
transmission owners.
Intervenors assert that Applicants retain control over the most
fundamental decisions that Alliance may make. Ohio Counsel, Coalition and
Midwest Customers note that, before the RTO may expand through the addition of
new transmission owners, a majority of the existing Alliance Companies must
approve the addition. Intervenors argue that Applicants could use this veto to
keep out lower cost competitors. Moreover, Ohio Counsel and Coalition note that
the Alliance Companies may veto both the acquisition or disposition of assets
and the decision to enter or exit lines of business. Wolverine argues that a
single Alliance member could use these provisions to block a merger with the
Midwest ISO.
<PAGE> 8
EXHIBIT D-1.8
Discussion
Order No. 888 stated that "an ISO should be independent of any
individual market participant or any one class of participants (e.g.,
transmission owners or end-users)." Order No. 888 also stated that the ISO's
rules of governance "should prevent control, and appearance of control, of
decision-making by any class of participants." [FN21]
As previously discussed, the Alliance Transco proposal would allow the
Alliance Companies to own passive interests in Transco and would allow each
transmission user (including each of the Alliance Companies) to own up to five
percent of Transco's managing member, Publico. In aggregate, the initial
Alliance Companies could own up to 25 percent of Publico.
We find that the Alliance Transco does not meet Order No. 888's
independence standard. The Alliance Companies' ownership of up to 25 percent of
Publico's stock at formation could allow effective control of Publico. In
addition, any new utilities that join Alliance could increase the amount of
control exercised over Alliance Publico. Also, the Alliance Companies' rights as
passive owners in Transco would allow them to veto the addition of new members
or existing facilities owned by others. Moreover, the application does not
adequately address fiduciary responsibilities of the Transco board and
management to passive owners. In short, the Transco/Publico proposal would not
"prevent control, and appearance of control, of decision-making by any class of
participants." We will direct the Applicants to address these concerns in their
compliance filing.
*8 If Applicants form an interim ISO, Applicants contend that they have
modeled their ISO governance structure after the Midwest ISO. According to
Applicants, the Alliance ISO will be governed by a seven person Board of
Directors elected by the Alliance ISO members from a pool of candidates (which
are not affiliated with any of the Alliance Companies) chosen by an independent
executive search firm (which is also chosen by the Alliance ISO members). The
Board of Directors would then elect the president of the Board of Directors. An
Advisory Committee, consisting of sixteen representatives from various
stakeholder groups, would advise the Board; however, the Advisory Committee
would have no control over the actions of the Board of Directors.
If the Alliance Companies pursue the formation of Alliance ISO, the
Alliance Companies' governance structure would meet the Commission's ISO
Principle No. 1 with some modifications to the filing. As filed, only the
Alliance Companies would be members in the Alliance ISO at the time of the
selection of the executive search firm and subsequent election of the Board. A
similar situation existed in the Midwest ISO application. The Commission
required an open season for initial membership in the Midwest ISO and
established a caretaker to process the applications in order to have as many
parties as possible to vote for the ISO Board. [FN22] The Alliance Companies are
directed to do the same if they opt to form an ISO. We do not believe that the
<PAGE> 9
EXHIBIT D-1.8
proposed $10,000 membership fee will discourage interested groups from joining
the Alliance ISO. There are no restrictions to preclude potential members from
pooling their resources in order to have a collective membership interest.
[FN23]
In addition, the Alliance Companies have reserved for themselves the
right to remove the ISO Board for various reasons and have adopted several other
special provisions that would hamstring the independence of the ISO Board.
Consistent with our discussion in Midwest ISO, [FN24] we direct the Alliance
Companies to amend Section 2.1.1(g)(ii) of the ISO Bylaws to delete the
exclusive right of the Alliance Companies to remove the Board of Directors. The
ISO Board of Directors are elected by the members of the ISO and, accordingly,
all of the members of the ISO should act to remove the Board of Directors.
The term sheet for Alliance Transco, which sets forth the preliminary
framework, includes several rights for the Alliance Companies that are not
adequately justified or explained. For instance, each transmission owner must
consent to any merger or consolidation with Alliance Publico that results in the
Alliance Publico no longer controlling Alliance Transco. Moreover, any
acquisition or disposition of transmission facilities that dilutes the value of
the Alliance Companies' interest in Alliance Transco requires the consent of
each. This provision does not define what constitutes a dilution of value. The
Applicants must remove these provisions or provide additional justification and
explanation.
*9 In addition, the Commission will require that those corporate
documents provide that any notice of withdrawal of transmission facilities by an
Alliance Company from the Alliance Transco or Alliance ISO must be filed with
the Commission and may only become effective upon the Commission's approval.
[FN25] In addition, any withdrawal of transmission facilities by an Alliance
Company from the Alliance Transco or Alliance ISO will require a Section 203
filing to transfer the control of the jurisdictional facilities back to the
Alliance Company.
Lastly, we decline to amend the Advisory Committee structure that will
advise the Alliance ISO Board of Directors. The Advisory Committee is strictly
an advisory body which does not exercise any control over the ISO board.
Moreover, numerous stakeholder groups are well-represented on the Advisory
Committee. However, the Commission will require that the ISO Bylaws be modified
to prohibit a corporate entity from participating in more than one stakeholder
group. The ability to participate in more than one stakeholder group could skew
the advice provided to the ISO Board to favor one or two parties that may be
able to stack the Advisory Committee in their favor. Principle No. 2: An ISO and
its employees should have no financial interest in the economic performance of
any power market participant. An ISO should adopt and enforce strict conflict of
interest standards.
Applicants
Applicants assert that Alliance will not have an impermissible
financial interest in the
<PAGE> 10
EXHIBIT D-1.8
economic performance of market participants because the five percent limit on
Publico stock will preclude it from being an affiliate of any market
participant. If the Alliance Companies form an ISO, Applicants assert that it
would be the policy of the ISO that directors, agents, officers and employees of
the organization will not have a direct financial interest in or conflict of
interest with any Transmission Owner, ISO Member, or Transmission User.
Employees (and Directors, agents and Officers) of the Alliance ISO must dispose
of any securities in a market participant within 6 months of employment with the
Alliance ISO. [FN26] In addition, the Alliance ISO will operate in such a manner
that it will be separate from the wholesale merchant functions of any
Transmission Owner, ISO Member or Transmission User. However, notwithstanding
the provisions of the Standards of Conduct, the Alliance ISO may employ, as its
agent, a Transmission Owner or its employees to carry out its functions.
Intervenors
Midwest Customers contend that AEP's plans to transfer its present
system control center employees to the RTO violate the ISO bylaws that provide
for the Board of Directors to select its employees. [FN27] In addition, Midwest
Customers and Industrial Consumers question the independence of these employees
from the Alliance members (particularly AEP). Intervenors argue that Applicants
have not defined what type of "material interest" directors of the ISO will be
permitted to have with market participants, nor have Applicants specified any
qualifications regarding the financial independence of directors, officers or
employees of the Transco or Publico. [FN28] Moreover, Dayton argues that the
lack of specificity with respect to the independence of the Transco and Publico
directors and employees illustrates the undeveloped nature of Applicants'
filing.
*10 Discussion
If the Alliance Companies own a significant amount of voting stock in
Publico, Publico's directors, officers and employees may perceive career-
preserving value in protecting or preferring the interests of these stockholders
over other market participants. In other words, Publico's staff would have a
financial interest in enhancing the economic performance of the Alliance
Companies, in violation of ISO Principle No. 2. [FN29] Accordingly, we find that
this aspect of Applicants' proposal does not satisfy ISO Principle No. 2.
With respect to the financial interest restrictions proposed by
Applicants, our analysis indicates that they have been largely modeled on those
accepted by the Commission for the Midwest ISO. Therefore, if the Alliance
Companies elect to form the Alliance ISO, the Commission finds that this aspect
of Applicants' proposal satisfies ISO Principle No. 2.
AEP's plan to transfer its control center and associated employees is
entirely consistent with the transfer of employees and control centers
associated with the formation of the PJM and New York ISOs. In those instances,
the existing employees and control centers of the power pools were transferred
to the ISO. Any existing Alliance Company employees transferred to the
<PAGE> 11
EXHIBIT D-1.8
Alliance ISO would have to divest their securities within six months of their
transfer. [FN30] Thus, we are satisfied that the Directors, agents, Officers,
and employees of the Alliance ISO will be independent of any market
participants.
However, we will require that, before the Alliance ISO may hire a
transmission owner or any other market participant to act as an agent of the
Alliance ISO, the position must be competitively bid and open to all eligible
market participants. Principle No. 3: An ISO should provide open access to the
transmission system and all services under its control at non-pancaked rates
pursuant to a single, unbundled grid-wide tariff that applies to eligible users
in a non-discriminatory manner.
Applicants
Applicants state that their proposal satisfies Principle No. 3 by
providing non-discriminatory open access under a single system tariff and
adopting a grid-wide rate after a reasonable transition period. Applicants state
that, in developing the transmission pricing proposal, they were committed to a
simple principle-that no customer should be "worse off" under the new rate
proposal than it is today.
According to Applicants, Alliance will implement a grid-wide rate that
will eliminate all rate pancaking within Alliance within six years of the
transmission service date. During the interim, Alliance proposes to charge a
maximum of two pancaked rates for each transaction. Every customer would pay an
embedded cost access charge based on the costs of the Alliance company where the
point of delivery is located, while transactions involving the system of more
than one Alliance company will pay a second embedded cost access charge.
Applicants contend that the transition rate is necessary to avoid the loss of
transmission revenues that result when transactions currently priced under
pancaked rates are provided at a single charge. Because the current pancaked
revenues are used to defray the transmission costs incurred to serve native
loads, the Applicants conclude that moving away from pancaked rates will result
in higher transmission rates for native load, i.e., cost shifts.
[FN31]
*11 Applicants state that the proposed transitional rate is also
important to encourage the expansion of Alliance to include additional
transmission owning participants. Applicants assert that the proposal avoids the
"original member deal syndrome" whereby new members face a potential
disincentive to joining an RTO because they will lose revenue from historical
pancaking. [FN32] According to Applicants, the proposed transitional rate
lessens the disincentives that many transmission owners would otherwise face
when considering RTO membership. Furthermore, Applicants contend that the
transitional rate and the flexible business structure of Alliance are likely to
be attractive features to other transmission owners, and, as Alliance expands in
geographic scope, customers will enjoy greater transmission access with no
increase in rates.
<PAGE> 12
EXHIBIT D-1.8
Intervenors
Intervenors complain that Applicants' proposal perpetuates rate
pancaking and undermines the very foundation of an RTO. Intervenors [FN33] argue
that Applicants' proposal to charge pancaked rates violates the Commission's ISO
principles and RTO NOPR. In addition, they contend that pancaked pricing will
enhance the market power of Applicants. Midwest ISO argues that transmission
customers will actually see a rate increase because they will continue to pay
pancaked rates plus an additional charge to fund Alliance.
Michigan Customers [FN34] and ABATE [FN35] note that they currently pay
a single system transmission rate for transmission service across the Michigan
systems of Consumers Energy and Detroit Edison which would be eliminated under
Applicants' proposal. They argue that, within Michigan, Applicants' proposal is
a step back toward the days of pancaked rates.
Chaparral, AMP-Ohio, and Wolverine argue that Applicants have failed to
file any assurances that Alliance will file a single system tariff after the
six-year transition period. Intervenors note that because a unanimous vote of
the Alliance Companies is required to shift to a new uniform pricing
methodology, a single grid-wide rate may never occur. [FN36] Chaparral and
Coalition request that the Commission order Applicants to commit to a date
certain for filing a single-system rate along with the methodology to be used.
In response, Applicants contend that their proposed two-part rate is
similar to the Midwest ISO's pricing approach for bundled retail load. [FN37] In
addition, Applicants state that concerns with respect to Michigan transmission
users are unfounded because Detroit Edison has given notice to Consumers Energy
of its intent to terminate the underlying pooling agreement, thus making the
future of the joint tariff uncertain. Moreover, Applicants assert that under the
Alliance OATT, Michigan Consumers would benefit by greater transmission access
and a broadened competitive market.
Discussion
Applicants largely meet the tariff administration requirements.
However, we will reserve judgment on Applicants' non-rate terms and conditions,
and most of the issues on rates and transmission pricing (e.g., administrative
fee, penalty levels, congestion pricing) pending a compliance filing addressing
Alliance's full compliance with the ISO principles (or with the requirements in
the RTO Final Rule). We will address the issue of rate pancaking below.
*12 Applicants' proposal to assess a single embedded cost access charge
to some transactions and assess two access charges to other transactions
violates a fundamental tenet of ISO Principle No. 3, that services under the ISO
tariff should neither favor nor disfavor any user or class of users. Under
Applicants' proposal, those transactions that enjoy a single charge are those
involving generators and loads located within a single corporate boundary of a
transmission owner and, thus, continue a preference for the transmission owners'
generation resources.
<PAGE> 13
EXHIBIT D-1.8
Applicants' claim that its proposal is better than the status quo because users
will pay two charges instead of five is misleading. While this may be true for
north-south transactions, these are not the predominant trading patterns.
Transactions tend to involve east to west, or west to east, flows and these are
not likely to see lower rates.
We are sympathetic to Applicants' desire to avoid loss of revenue and
potential cost shifts, but cannot accept a proposal that presents multiple
access fees and adversely impacts competitors. While the proposal is intended to
address Applicants' cost shift concerns, it does so by favoring Applicants'
generators which will be sheltered from the second charge for their own loads.
Moreover, while Applicants state that they have reduced the rate pancaking
charges from five to two, the fact remains that Alliance will be a critical
gateway for west to east and east to west transfers which involve distances that
are only two utilities deep. Thus, the proposed two-part rate appears to
perpetuate the status quo for many of the Alliance customers.
We are also concerned that the interim rate proposal makes the
transmission customers of Michigan Electric Coordinating Systems worse off.
Currently these customers enjoy a single rate for use of the systems of
Consumers and Detroit Edison. Under Applicants' proposed interim pricing, these
customers would revert to paying rates over both the Consumers and Detroit
Edison systems. Accordingly, we direct Applicants to eliminate the pancaked
rates. Our directive is without prejudice to the proposal of a different
transition mechanism that addresses quantifiable revenue lost from the movement
to non-pancaked rates in a non-discriminatory manner.
Under ISO Principle No. 3, Order 888 also stated that the "portion of
the transmission grid operated by a single ISO should be as large as possible,
consistent with the agreement of market participants."
The Commission has previously approved the Midwest ISO as meeting this
requirement, in a case which raised many of the same geographic arguments raised
here by intervenors. In doing so, the Commission stated:
To ensure that the formation of the Midwest ISO, as well as other new
transmission entities, results in the coordination in the public interest of
jurisdictional facilities (as described in FPA Section 203(b)), we will
carefully examine the interaction of new proposals for sub-regional transmission
entities in this region. In reviewing such proposals, we will consider whether
any sub-regional transmission entity could lead to balkanization of the
interconnected grid from the perspective of reliability, competition and
transmission service availability. [FN38]
*13 Consistent with our decision in Midwest ISO, and for the same reasons stated
therein, we find that Alliance meets this aspect of ISO Principle No. 3. [FN39]
Principle No. 4: An ISO should have the primary responsibility in ensuring
short-term reliability of grid operations. Its role in this responsibility
should be well-defined and comply with all applicable standards set by NERC and
<PAGE> 14
EXHIBIT D-1.8
the regional reliability council.
Applicants
Applicants contend that Alliance satisfies this principle since it will
have exclusive authority for maintaining short-term reliability of the grid. In
support of their contention, Applicants state that the Operating Agreement
specifies the responsibilities of Alliance, the transmission owners, the
generation owners, and the transmission customers necessary to ensure that
reliability standards are met. Applicants also state that the Operating Protocol
specifies that Alliance will be responsible for maintaining the security and
reliability of the integrated transmission system.
Furthermore, Applicants note that Alliance will be the NERC security
coordinator and will direct the control area operations of the transmission
owners that operate control areas. Applicants state that as such, Alliance will:
(1) engage in transmission security monitoring and analysis; (2) coordinate with
other security coordinators; (3) coordinate with and direct control areas within
Alliance; (4) implement reliability procedures; (5) direct responses to
emergency situations; and (6) provide congestion clearing solutions. In
addition, Applicants observe that the initial membership of Alliance will
include companies that belong to different NERC Reliability Councils (i.e., ECAR
and SERC). Applicants assert, however, that the operating requirements
established by Alliance will meet NERC requirements and will allow for
continuance of specific implementation differences between regions as long as
NERC and Alliance requirements are met.
Finally, Applicants state that Alliance will have the authority to
designate must-run units in order to ensure system security. Applicants note
that the Operating Protocol specifies that transmission owners' operation of
their respective facilities will be subject to Alliance's direction, and that it
specifically requires that transmission owners will be required to comply with
Alliance's instructions in its role as system security coordinator.
Intervenors
Dayton argues that Applicants' proposal falls short of ISO Principle
No. 4 because the RTO will not consolidate control areas. Thus, the existing
operational problems concerning multiple control area wheels will continue.
Discussion
The Alliance proposal is different from the previous ISOs addressed by
the Commission (apart from the Midwest ISO) because Alliance will not be a
control area operator carrying out both transmission and generation control
functions. While Alliance will not be the control area operator, it will be the
NERC security coordinator and will direct the control area operations of the
transmission owners that operate control areas (18 months after commencement of
service
<PAGE> 15
EXHIBIT D-1.8
they will report to the Commission on possible consolidation of control area
functions). In addition, while the Alliance Companies belong to two different
NERC Reliability Councils (ECAR and SERC) which use different practices to
implement NERC operating requirements, Alliance will establish operating
requirements that will allow for the continuation of differences between regions
as long as the NERC requirements are met. The RTO will also have the authority
to designate must-run units in order to ensure system security. A draft of the
reliability must-run agreement will be filed in the future. The Operating
Protocol submitted by the Alliance Companies provides Alliance with the
necessary responsibility for ensuring the short-term reliability of the grid.
While many of the specific details are not provided in the Alliance Companies
submittal, the general framework satisfies ISO Principle No. 4.
*14 The Alliance Companies commit to evaluate the consolidation of
control areas within 18 months of the commencement of service under the Alliance
OATT and make a report of their findings with the Commission. We believe that
this report is a good starting point for the eventual consolidation of control
areas requested by Dayton.
However, the Alliance Companies propose to permit Alliance to delegate
certain security monitoring functions to the existing control area operators.
[FN40] Before these functions may be delegated, Alliance must specifically
define what functions are being delegated and the reason for the transfer.
Alliance should post these delegated functions on its OASIS site at least 30
days (if practicable) prior to the temporary transfer of these functions to the
control area operators.
Principle No. 5: An ISO should have control over the operation of the
interconnected transmission facilities within its region.
Applicants
Applicants propose that Alliance will control transmission facilities
with a voltage greater than 100 kV and a response factor of 3 percent or more to
power transfers across interconnection systems. [FN41] Alliance will have
functional control over transmission lines and towers, voltage control devices
(e.g., fixed and switched capacitors, reactors, synchronous condensers, and
static VAR controllers), power control flow devices, and substation equipment
(e.g., circuit breakers, disconnect switches, relays, and wave traps). Alliance
will, pursuant to the Agency Agreement, provide service over non-transferred
transmission facilities when service over such facilities is required to satisfy
a transmission request under the Alliance OATT.
Applicants assert that Alliance satisfies this principle because the
RTO will exercise, at a minimum, functional control over the facilities
transferred to it by the transmission owners. [FN42] Applicants note that to the
extent necessary, Alliance may exercise temporary functional control over any
non- transferred transmission facilities or generation facilities of a
transmission owner in order to prevent or to remedy a system emergency. [FN43]
Intervenors
<PAGE> 16
EXHIBIT D-1.8
Midwest Customers argue that Alliance lacks the requisite control over
the transmission facilities in the region. Midwest Customers contend that
because Alliance will not have absolute real-time operational control over the
facilities, the existing control area operators (i.e., the transmission owners)
will be able to discriminate against potential customers. [FN44]
Intervenors argue that Applicants retain control over the operation of
the RTO. [FN45] For example, the RTO must act in accordance with the
transmission owners operating guidelines pending the use of alternative dispute
resolution. Midwest Customers argue that Alliance has no authority to direct
transmission owners to place additional facilities under its control if they are
needed for transmission service or to maintain reliability.
[FN46]
*15 Discussion
We reject Midwest Customers' concerns regarding the level of facility
control proposed for Alliance. The Commission has previously found that the
exercise of functional control by an ISO-rather than direct operational
control-is an appropriate method of providing for control of an ISO's
transmission system. [FN47] Simply put, Midwest Customers have provided us with
no persuasive arguments as to why we should disregard that standard in this
proceeding (i.e., we find no evidence in the record to persuade us to require
Applicants to operate the grid through direct physical operation only).
Furthermore, pursuant to Section 2.1.3 of the Alliance Operating Protocol,
[FN48] Alliance may exercise temporary functional control over Non-Transferred
Transmission Facilities in order to prevent or remedy a system emergency and,
therefore, to ensure the reliability of Alliance. Accordingly, we find Midwest
Customers' concerns in that regard to be without merit and find that Applicants'
proposal satisfies ISO Principle No. 5. Principle No. 6: An ISO should identify
constraints on the system and be able to take operational actions to relieve
those constraints within the trading rules established by the governing body.
Those rules should promote efficient trading.
Applicants
Applicants state that they expect an energy market to form in the
Alliance region to provide economic solutions for congestion within one year of
operation consistent with the RTO NOPR, but do not explain how they will
facilitate the development of or manage that market. Prior to development of an
energy market, Alliance will implement congestion management to maintain firm
transmission service. [FN49] Alliance will not, however, undertake redispatch to
accommodate requests for new firm service when there is insufficient ATC.
Rather, in the absence of sufficient ATC, Alliance will facilitate (through its
OASIS site) bilateral redispatch contracts between a transmission customer and
generation owner, solicit bids for providing redispatch, post bids, and
coordinate schedule changes as necessary (Operating Protocol 10.4.1), and
identify on OASIS potential counter-flow transactions that, if enacted, would
have a significant mitigating impact on congestion, and an estimate of the per-
unit mitigation each transaction can be expected to provide. Applicants state
that Alliance may also solicit bids for
<PAGE> 17
EXHIBIT D-1.8
reassignment of firm transmission on the secondary market.
Applicants state that they will file estimated congestion management
fees prior to the transmission service date, and that they will compensate
parties that provide congestion management up to 110% of incremental costs, not
to exceed demonstrable foregone opportunity costs. If the Alliance Companies
form the Alliance Transco, the congestion management fee may take the form of a
performance based rate to be filed with the Commission.
Intervenors
Intervenors [FN50] complain that the proposal lacks a plan for
developing an energy market or a commitment to a mechanism for relieving
congestion, e.g., the Planning Protocol fails to specify the obligation to plan
and build transmission facilities.
*16 In addition, Intervenors raise concerns regarding numerous aspects
of Applicants' congestion management proposals to maintain transmission service
and to accommodate new service. For example, Clearinghouse [FN51] states that
the proposal fails to provide customers with rate certainty. In addition,
Intervenors [FN52] question Alliance's effectiveness at facilitating redispatch
for new service given the lack of generator obligation to submit bids, coupled
with pancaked rates. Also in question is whether leaving redispatch in the hands
of existing generators and not Alliance creates a bias toward existing trading
patterns rather than new generator entry and whether spreading costs among all
transmission users will convey necessary price signals. [FN53] Intervenors
[FN54] also complain that Alliance has not justified its deviation from the
Commission's pro forma tariff requirement to redispatch for new service.
Applicants respond that Intervenors alleging that the congestion
management approach is not fully developed are proposing a standard beyond that
contemplated by the Commission in the RTO NOPR. Applicants also state that,
since they will not control or own generation resources, they have designed an
interim congestion management proposal with a market service that is the
functional equivalent of the redispatch service required under the Commission's
pro forma tariff.
Discussion
Since we are not accepting the Alliance OATT in this order, we provide
general guidance to Applicants. Applicants' proposal is largely consistent with
the proposal the Commission accepted in Midwest ISO. However, under the pro
forma tariff, if the transmission provider rejects a transaction for lack of
ATC, it must offer to redispatch its system if it is cheaper than expansion, and
may only charge the higher of the embedded cost or the redispatch cost. While
Applicants' proposal to not redispatch to accommodate a request for new service
is not consistent with the requirements of the pro forma tariff for new service,
it appears to offer a reasonable alternative with some modification. In Midwest
ISO, the Commission accepted a redispatch proposal similar to the one proposed
by Applicants because the Midwest ISO required all generators on the system and
owned by ISO members to make a bid to provide the redispatch.
<PAGE> 18
EXHIBIT D-1.8
There does not appear to be such a requirement in Applicants' proposal. Without
this obligation, it is not clear that Alliance will be effective.
Intervenors' concerns that the proposal lacks a detailed market plan
for congestion management are premature. Similarly, Intervenors' concerns over
Applicants' reference to a future proposal to use performance based rates for
congestion management are premature. Any such proposal would be triggered by the
termination of the transition period, and also would be subject to filing with
and acceptance by the Commission.
Principle No. 7: The ISO should have appropriate incentives for efficient
management and administration and should procure the services needed for such
management and administration in an open, competitive market.
*17 Applicants
Applicants contend that the Alliance proposal satisfies this principle.
Applicants argue that if formed as an ISO, Alliance will be independent of
market participants and will operate in accordance with the ISO Bylaws to ensure
efficient management and administration. Applicants further argue that if formed
as a Transco, Alliance will "be economically motivated to operate efficiently
and to procure services in an open, competitive market." [FN55]
Intervenors
According to Dayton, the proposal fails ISO Principle No. 7 because
there is no prohibition or limitation on the RTO from contracting with market
participants. [FN56]
Discussion
We find Dayton's argument to be persuasive and, therefore, we direct
Applicants to revise their proposal so that it requires competitive bidding for
any contracting of functions. With this modification, Applicants' proposal will
satisfy ISO Principle No. 7.
Principle No. 8: An ISO's transmission and ancillary services pricing policies
should promote efficient use of and investment in generation, transmission, and
consumption. An ISO or an RTG of which it is a member should conduct such
studies as may be necessary to identify operational problems or appropriate
expansions.
Applicants
Applicants assert that Alliance's transmission pricing policies will
promote more efficient use of and investment in generation, transmission, and
consumption. In support of their assertion, Applicants state that their proposal
provides for the following: (1) both the Operating Protocol and the Planning
Protocol provide Alliance with broad authority to conduct studies necessary to
identify operational problems and to identify appropriate expansions; (2) the
Operating Protocol
<PAGE> 19
EXHIBIT D-1.8
requires Alliance to have a procurement function for ancillary services and
locational congestion relief for providing these services to transmission
customers; (3) the procurement process is expected to be market-based and to
depend heavily on one or more regional power exchanges; [FN57] (4) the Planning
Protocol specifically prohibits Alliance from discriminating in favor of any
transmission assets, including assets that it owns; and (5) expansion of the
system will be done in the most efficient fashion without regard of ownership of
transmission, distribution, or generation facilities.
Intervenors
Intervenors have filed myriad comments which overlap with those
discussed under ISO Principle No. 3.
Discussion
The Alliance Companies have not demonstrated the justness and
reasonableness of several rate provisions. These include rate formulas
(including return on equity), losses, penalties, and congestion management
costs. Applicants have also failed to justify numerous non-rate terms and
conditions, e.g., restriction of network service to within a pricing zone,
elimination of specific negotiated terms for self provision of ancillary
services without justification, no obligation to redispatch to accommodate
requests for new transmission service by either Alliance or the generators on
the Alliance system which are required to enter into interconnection agreements
with Alliance, failure to justify the proposed flexible non-firm point-to-point
service, and an unexplained generation interconnection policy that appears to
result in "and" pricing.
*18 In addition, Applicants propose to be the provider of last resort
for ancillary services; however, Applicants intend to let the market determine
how ancillary services will be provided. The Application lacks detail in how the
market will provide ancillary services and is therefore incomplete in this
regard. However, Applicants state that they will study and identify operational
problems and take steps necessary to correct those problems.
In view of our above concerns, we direct Applicants to amend their
filing in Docket No. ER99-3144-000 to provide greater detail and justification
regarding their proposed rate, non-rate, and ancillary service provisions. We
will address these issues in the future order on Applicants' OATT.
Principle No. 9: An ISO should make transmission system information publicly
available on a timely basis via an electronic information network consistent
with the Commission's requirements.
Applicants
Applicants state that Alliance will operate an Alliance OASIS to
receive and process all
<PAGE> 20
EXHIBIT D-1.8
transmission service requests in accordance with the Alliance OATT, and that the
OASIS will fully meet the requirements of Order No. 889. Applicants also state
that, in the interim, the Alliance Companies will individually operate their
existing OASIS sites and they commit to consolidate these operations as early as
possible.
Intervenors
No substantive comments were filed regarding Applicants' proposal.
Discussion
Applicants' proposed framework satisfies ISO Principle No. 9.
Principle No. 10: An ISO should develop mechanisms to coordinate with
neighboring control areas.
Applicants
Applicants observe that the Operating Protocol describes the role that
Alliance is expected to have as a NERC security coordinator. In addition,
Applicants state that Alliance will coordinate with neighboring control areas
and security coordinators to ensure reliability and to manage loop flow issues.
Thus, Applicants contend, the Alliance proposal satisfies ISO Principle No. 10.
Intervenors
No substantive comments were filed regarding Applicants' proposal.
Discussion
While Applicants have not provided any specific details, we find that
their proposed framework satisfies ISO Principle No. 10. Applicants must provide
and support the specifics of their proposal in their compliance filing.
Principle No. 11: An ISO should establish an ADR process to resolve disputes in
the first instance.
Applicants
Applicants contend that Alliance fully satisfies this principle. In
support of their contention, Applicants provide the following statements: (1)
the Alliance Agreement includes a Dispute Resolution Procedure for disagreements
among the transmission owners; [FN58] (2) the term sheet for the Alliance
Transco contemplates the establishment of alternative dispute resolution
procedures and, in particular, a complaint procedure providing for ADR
procedures will be established for alleged violations of any of the standards of
conduct; [FN59] and (3) the
<PAGE> 21
EXHIBIT D-1.8
Alliance ISO Bylaws and the pro forma Operation Agreement both include dispute
resolution procedures. [FN60]
*19 Intervenors
No substantive comments were filed regarding Applicants' proposal.
Discussion
Applicants' proposal satisfies ISO Principle No. 11.
IV. RTO Final Rule
The Applicants argue that their proposal substantially complies with the RTO
NOPR. The Commission is concurrently issuing the RTO Final Rule, so we will
provide guidance on three of the key principles set forth in the RTO Final Rule
that are implicated by the Alliance Companies' application-independence, scope
and configuration, and tariff administration and design (i.e., rate pancaking).
Each of these three issues is addressed below.
Independence
The RTO Final Rule establishes the following requirement:
The [RTO] must be independent of market participants. (i) The [RTO],
its employees, and any nonstakeholder directors must not have financial
interests in any market participants. (ii) A[n] [RTO] must have a decision
making process that is independent of control by any market participant or class
of participants. The application of these requirements is further explicated in
the RTO Final Rule.
The Alliance proposal raises two types of independence concerns:
whether the arrangements for active ownership of Publico are consistent with the
Final Rule and whether the proposed passive ownership arrangements in the
limited liability company by Divesting Transmission Owners of Transco are
consistent with the Final Rule?
Active Ownership
The RTO Final Rule articulates a five percent safe harbor for ownership
by a market participant of a transco for a period of five years subject to
extension upon a showing of public interest. It allows applicants to propose an
ownership level above five percent if they justify their proposal based on
various factors identified in the RTO Final Rule. The RTO Final Rule states
that, in making its case-by-case determinations, the Commission will look at the
voting interests held by other class members, the amount of passive ownership
held by market participants, the
<PAGE> 22
EXHIBIT D-1.8
degree of dispersion of voting interests among other market participants and the
general public, and the rights retained by the owners as suppliers of facilities
and services to the RTO. The RTO Final Rule also addresses the need for a class
cap on ownership, adopting a benchmark of fifteen percent of the RTO's voting
securities in the aggregate.
As noted above, the Applicants would allow each transmission user to
own up to five percent of Publico, and thus allow the Applicants to own up to 25
percent. The Applicants argue that these ownership levels are needed to ensure
the viability of Publico in the financial markets. However, they offer virtually
no evidence or support for this assertion. They argue that investment in Publico
by industry participants "will assure other (non-energy industry) investors that
the Alliance Transco (and thus Alliance Publico) will be a financial success."
However, even if we assume that their proposal is necessary to the financial
viability and success of the new venture, Applicants have not adequately
explained why they need to maintain any particular level of voting control and
whether such voting control-exercised either individually or jointly-might
influence future operational decisions of the Transco in ways that could favor
the Divesting Transmission Owners.
*20 In order to comply with the RTO Final Rule, Applicants may seek to
justify their proposal based on the guidance provided in the Rule. If so,
Applicants must submit additional detail and support-including actual bylaws,
quorum requirements, and other relevant information that would permit the
Commission to assess the degree to which each Divesting Transmission Owner
retaining an active ownership interest in the Publico could affect the
independence of transmission decision-making by the RTO.
Alternatively, Applicants may amend their proposal to establish
mechanisms that would effectively restrict their ability to exercise voting
control over operating decisions by the RTO Publico (e.g., placing their stock
in some form of trust) or which would otherwise limit their ability to control
decisions by the Board of Directors of Publico (e.g., they could place limits on
the number of board members that Divesting Transmission Owners could elect).
Passive Ownership
The RTO Final Rule states that passive ownership may be acceptable
subject to an audit requirement. The RTO Final Rule also states that passive
ownership must be demonstrated to be truly independent based on certain factors
(i.e. the Commission will approve a proposal only if we are satisfied that the
RTO has a decisionmaking process that is independent of control by the passive
owners).
Here, the Applicants have proposed to retain veto power over new
transmission members and over the acquisition and disposition of transmission
facilities because of concerns that this might dilute the value of their passive
ownership interests. The Applicants have offered little information about what
fiduciary obligations, if any, the directors of Alliance Publico, as the manager
and director of Alliance Transco, may owe to the passive Divesting Transmission
<PAGE> 23
EXHIBIT D-1.8
Owners.
In order to comply with the RTO Final Rule, Applicants would need to
revise and support their proposal in light of the discussion of the RTO Final
Rule.
Scope and Configuration
The RTO Final Rule establishes the following requirement:
The [RTO] must serve an appropriate region. The region must be of
sufficient scope and configuration to permit the RTO to maintain reliability,
effectively perform its required functions and support the efficient and non-
discriminatory power markets. The application of these requirements is further
explicated in the RTO Final Rule.
Because of their geographic location, the Alliance Companies form a
line running from Michigan southeast to Virginia. Alliance would isolate PJM on
the east from utilities west of Alliance. This configuration appears to have
strategic implications and does not meet several factors identified in the RTO
Final Rule. For example, rather than supporting a regional market based on
historical trading patterns, Alliance would perpetuate the existing situation
where the Alliance Companies separate the buyers and sellers that constitute the
predominant west-east trading patterns. Also, because the benefits of reduced
rates will accrue to north-south transactions, the existing west-east trading
patterns will derive little or no benefit from the proposal. This exemplifies
the concern raised in the Final Rule about strategically located "toll-gates."
Because Alliance does not include utilities west of AEP, its configuration also
would not internalize or otherwise address the significant loop flow issues
which involve AEP and its western neighbors. Also, the Alliance configuration is
at odds with the Final Rule's expectation that RTOs will not disrupt existing
regional institutions because it severs two existing NERC reliability councils.
Based on these factors, the Alliance configuration raises concerns with regard
to its proposed scope and configuration.
*21 We will not prescribe at this time how the Applicants should
resolve these concerns. One option would be for Applicants to form or join an
RTO that satisfies the regional scope and configuration requirements of the RTO
Final Rule. The Final Rule introduces the concept of effective scope, and
discusses the possibility that, through coordination and agreements with
neighboring RTOs or adopting hierarchal control, the seams can be managed in a
way that simulates greater scope. For example, it may be possible that Alliance,
Midwest ISO and PJM could negotiate procedures and rate treatments that would
eliminate the toll-gate aspect of Alliance's configuration, deal with loop flow
issues, and eliminate concerns about reliability impairment that arise as a
result of the lack of symmetry between these institutions and the NERC councils.
Rate Pancaking
<PAGE> 24
EXHIBIT D-1.8
The RTO Final Rule establishes the following requirement:
Customers under the [RTO] tariff must not be charged multiple access
fees for the recovery of capital costs for transmission service over facilities
that the [RTO] controls. The application of these requirements is further
explicated in the RTO Final Rule.
Applicants propose to continue a form of rate pancaking for up to six
years. While they do not commit to a specific rate form thereafter, they commit
to revisit the issue. Alliance says that its proposal (which assesses a single
license plate rate to some transactions and assesses two rates to other
transactions) reduces rate pancaking because the maximum pancake stack is two,
not the five that each company could charge individually. Applicants state that
the transition rate is necessary to avoid the loss of revenues that result when
transactions currently priced under non-pancaked rates are provided at a single
charge. Because the current pancaked revenues are used to defray the
transmission costs incurred by native loads, Applicants conclude that moving
away from pancaked rates will result in higher transmission rates for native
load (which they characterize as a cost shift issue).
This aspect of the proposal violates one of the fundamental tenets of
the Final Rule. Continuing pancaked rates of any type has significant impacts on
the development of regional markets because it assigns a higher transmission
cost on some users solely as a result of the existing transmission owner's
corporate boundaries. Those transactions that will enjoy a single charge are
those involving generators and loads located within a single corporate boundary
of each transmission owner and, thus, continue a preference for the transmission
owners' generation resources. Applicants' claim that their proposal is better
than the status quo because users will pay two pancaked charges instead of five
is misleading. While this may be true for north-south transactions, these are
not the predominate trading patterns. Transactions involving east-west flows are
not likely to see lower rates. Also, this proposal reinstitutes a pancaked rate
for the Consumers/Detroit system which currently offers a joint single-system
rate.
*22 We note that, because Applicants did not have the benefit of the
Final Rule when their proposal was filed, they were not aware that the
Commission would offer substantial flexibility in innovative pricing that does
not involve pancaked rates. We expect that, with the options described in the
Final Rule, Alliance Companies will be able to develop innovative rate proposals
that do not suffer the deficiencies of pancaked rates. We note that the
Commission is not closing the door on transition mechanisms that address cost
shifts. For instance, if there were a quantifiable revenue loss caused by the
movement from pancaked rates to non-pancaked rates, it may have a slight impact
on the single access charge if spread over the entire RTO region, where all
customers are affected similarly. Thus a transition mechanism to address cost
shifts might be supportable.
V. Conclusion
<PAGE> 25
EXHIBIT D-1.8
As discussed above, we conditionally approve the Alliance Companies'
proposal under Order No. 888's ISO principles. This approval is conditioned upon
the Alliance Companies making the revisions that we direct to the Alliance
proposal and the related agreements. Any such changes to the proposal and
agreements pursuant to this order will be subject to Commission review and
approval of the compliance filing. The Commission will consider the merits of
any other changes on a case-by-case basis as part of a separate filing and
proceeding, and interested parties will have the opportunity to comment on any
such proposal.
The Commission orders:
(A) The Alliance Companies' request for authorization under Section 203
to dispose of the jurisdictional facilities of its public utility members is
hereby granted, subject to the conditions and requirements discussed in the body
of this order.
(B) The untimely motions to intervene in these dockets are hereby
granted as discussed in the body of this order.
(C) The motions to consolidate and requests for an evidentiary hearing
are hereby denied, as discussed in the body of this order.
(D) The Alliance Companies are hereby directed to submit a compliance
filing as discussed in the body of this order, including therein the complete
agreements necessary to implement Applicants' proposal.
(E) The Applicants' agreements (apart from the open access transmission
tariff) are hereby conditionally accepted, as modified pursuant to Ordering
Paragraph D.
(F) The foregoing authorization is without prejudice to the authority
of the Commission or any other regulatory body with respect to rates, services,
accounts, valuation, estimates or determinations of cost, or any other matter
whatsoever now pending or which may come before the Commission.
(G) Nothing in this order shall be construed to imply acquiescence in
any estimate or determination of cost or any valuation of property claimed or
asserted.
(H) The Commission retains authority under Section 203(b) of the FPA to
issue supplemental orders as appropriate.
*23 Commissioner H (acute)ebert dissented with a separate statement
attached.
FN1 The Alliance Companies are: American Electric Power Service
Corporation (AEP) on behalf of the public utility operating company subsidiaries
of the AEP system
<PAGE> 26
EXHIBIT D-1.8
(Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan
Power Company, Kentucky Power Company, Kingsport Power Company, Ohio Power
Company, and Wheeling Power Company), Consumers Energy Company (Consumers),
Detroit Edison Company (Detroit Edison), FirstEnergy Corp. (FirstEnergy) on
behalf of the transmission-owning FirstEnergy Operating Companies (The Cleveland
Electric Illuminating Company, Ohio Edison Company, Pennsylvania Power Company,
and The Toledo Edison Company), and Virginia Electric and Power Company (VEPCO).
FN2 Regional Transmission Organizations, Final Rule, 89 FERC P 61,285
(1999) (RTO Final Rule).
FN3 Notice of Proposed Rulemaking, Regional Transmission Organizations,
Docket No. RM99-2-000, 87 FERC P 61,173 (RTO NOPR).
FN4 Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery of Stranded
Costs by Public Utilities and Transmitting Utilities, Order No. 888, 61 Fed.
Reg. 21,540 (1996), FERC Statutes and Regulations, Regulations Preambles January
1991-June 1996 P 31,036 (1996), order on reh'g, Order No. 888-A, 62 Fed. Reg.
12,274 (1997), FERC Statutes and Regulations P 31,048 (1997), order on reh'g,
Order No. 888-B, 81 FERC P 61,248 (1997), order on reh'g, Order No. 888-C, 82
FERC P 61,046 (1998), appeal docketed, Transmission Access Policy StudyGroup, et
al. v. FERC, Nos. 97-1715, et al. (D.C. Cir.).
FN5 Section 203 application at 6.
FN6 Section 203 application at 8.
FN7 Each Alliance Company that is not a Divesting Transmission owner
will receive one vote as to whether it agrees in the creation of the Alliance
Transco. However, the concurrence of the Non-Divesting Transmission Owners is
not required if the total number of Non-Divesting Transmission Owners is less
than 25 percent of the number of Alliance Companies or there is only one Non-
Divesting Transmission Owner. Applicants' Section 203 application at 9.
FN8 The Alliance Transco will operate all the transmission facilities
under its control pursuant to Operating and Planning Protocols.
FN9 Section 203 application at 15.
FN10 Section 2.2 of the Alliance Agreement.
FN11 The Comments, protests and motions to intervene raise concerns on
some of the specific components of this proposal. We note that many aspects of
the Alliance Companies'
<PAGE> 27
EXHIBIT D-1.8
proposal are incomplete and thus our review is limited. Accordingly, our silence
on a particular subject does not indicate either our approval or disapproval.
FN12 See 18 C.F.R. s 385.213(a)(2) (1998).
FN13 Atlantic City Electric Company, et al., 76 FERC P 61,306, at p.
62,513 (1996).
FN14 Wabash Valley at 6, TDU Systems at 11-13, Ohio Counsel 6-14, APPA
& NRECA at 10-14, Citizen Power at 6-7, Midwest Customers at 17-26, Industrial
Consumers at 17-18, Wolverine at 10-14, Virginia Committee at 6-7, Clearinghouse
at 4-6, NCEMC at 9-18, AMP-Ohio at 15-26, Indiana Commission at 9-11, Ohio
Commission at 4-5, Coalition at 16-26.
FN15 TDU Systems at 12-13, South Carolina Authority 8-12.
FN16 Chaparral at 12.
FN17 TDU Systems at 12-13, South Carolina Authority 8-12.
FN18 NCEMC and AMP-Ohio contend that the ownership interest of the
transmission owners in the Alliance Transco raises a host of questions
concerning the fiduciary duty of the Alliance Publico to the
divesting transmission owners.
FN19 NCEMC at 14.
FN20 NCEMC notes that the divesting transmission owners have granted a
"put right" that allows them to require the Alliance Transco to purchase their
ownership interests five years after divestiture and every year thereafter.
Thus, the divesting transmission owners have the right to require the Alliance
Transco to buy their ownership interests, but no obligation to sell them. NCEMC
at 14, footnote 3.
FN21 Order No. 888 at p. 31,730.
FN22 See Midwest ISO, 84 FERC P 61,231, at p. 62,148 (1998).
FN23 In PJM we accepted a proposed application fee of $1,500 and an
annual membership fee of $5,000 and stated that some small fee is required to
ensure that applicants have a financial interest in the ISO. See PJM, 81 FERC at
p. 62,265.
FN24 See Midwest ISO, 84 FERC at p. 62,151.
FN25 Midwest ISO, 84 FERC at p. 62,151 citing PJM, 81 FERC at p.
62,265.
FN26 Participation in a pension plan is permissible if the plan is a
defined-benefit plan
<PAGE> 28
EXHIBIT D-1.8
that does not involve ownership of the securities.
FN27 Midwest Customers at 24-26.
FN28 Dayton at 11 and Wolverine at 14.
FN29 This same conflict could also arise if other transmission users
owned a significant amount of voting stock in Publico.
FN30 ISO Bylaws at Section 2.6.2(e)(i).
FN31 Section 205 application, Attachment 3 at 7.
FN32 Id. at 8-9.
FN33 Wabash Valley at 7, ABATE at 6-8, TDUSystems at 14-16, Ohio
Counsel at 15, Chaparral at 17, Midwest Customers at 31-33, Wolverine at 5-7,
Dayton at 17, Industrial Consumers at 11-13, Cleveland at 9-12, Michigan
Customers at 4- 8, Virginia Committee at 9-10, NCEMC at 18-25, AMP-Ohio at 4-10,
Ohio Commission at 6-8 Coalition at 28-47.
FN34 Michigan at 4-5.
FN35 ABATE at 10.
FN36 Enron at 9, Dayton at 17, and Wolverine at 7.
FN37 The analogy with Midwest ISO is not on point. If a member utility
chooses not to place its bundled retail load under the Midwest ISO tariff, the
transmission costs associated with those loads must be recovered from the
bundled retail customers. If the member utility wants to use the Midwest ISO
tariff to transmit power to serve bundled retail load, it must pay for that
service separately.
FN38 See Midwest ISO, 84 FERC at pp. 62,145-46.
FN39 We reach a different conclusion on scope in our discussion below
on guidance under the RTO Final Rule.
FN40 Operating Agreement at Section 5.3.4.
FN41 FirstEnergy is the exception to this rule, and proposes to
transfer its transmission facilities with a voltage greater than 69 kV.
FN42 Applicants note that the Commission previously approved a similar
proposal for
<PAGE> 29
EXHIBIT D-1.8
operations of a regional transmission system. Section 205 application at 57,
citing Midwest ISO, 84 FERC at p. 62,167.
FN43 Id., citing Appendix 5 at Article II.
FN44 Midwest Customers at 26-28.
FN45 Ohio Counsel, Coalition and AMP-Ohio.
FN46 Midwest Customers at 29. Coalition requests that the Commission
require the transmission owners to turn over functional control of any
transmission assets that the RTO deems are necessary to perform its duties.
Coalition at 82.
FN47 See Midwest ISO, 84 FERC at p. 62,161.
FN48 Appendix 5 at Section 2.1.3.
FN49 Congestion management to maintain firm service is discussed in the
Alliance RTO OATT.
FN50 Dayton at 18, Midwest Customers at 36, Coalition at 88-94.
FN51 Clearinghouse at 18-19.
FN52 Coalition at 91-92.
FN53 Virginia Commission at 13-15, Midwest ISO at 12-15.
FN54 AMP-Ohio at 13-14, Coalition at 90.
FN55 Id. at 58.
FN56 Dayton at 20-21.
FN57 Id., citing Appendix 5 at Article XI.
FN58 Id. at 59, citing Appendix 1 at Article XII.
FN59 Id., citing Appendix 3.
FN60 Id. at 60, citing Appendix 4 at Article III and Appendix 8 at
Article VII, respectively.
<PAGE> 30
EXHIBIT D-1.8
Appendix A
*24 Listed parties have filed notices of intervention or motions to intervene in
the referenced dockets. Short-hand references to parties referred in the order
are indicated in parenthesis after the name.
<TABLE>
<CAPTION>
Company Name Docket Docket
No.EC99-80-000 No.ER98-3144-000
<S> <C> <C>
American Municipal Power-Ohio, Inc. X X
(AMP-Ohio)
American Public Power Association and X X
National Rural Electric Cooperative
Association (APPA & NRECA)
Arkansas Cities X
Arkansas Public Service Commission X
(Arkansas Commission)
Association of Businesses Advocating X
Tariff Equity (ABATE)
California Electricity Oversight Board X
Carolina Power and Light Company X
Chaparral (Virginia), Inc. (Chaparral) X X
Cinergy Services, Inc. X X
Citizen Power, Inc. (Citizen Power) X X
City of Cleveland, Ohio (Cleveland) X
Coalition of Midwest Transmission X X
Customers (Midwest Customers)
Coalition of Municipal and Cooperative X X
Users of Alliance Companies'
Transmission (Coalition)
Commonwealth Edison Company X X
(Commonwealth Edison)
Consumer Advocate Division of the Public X
Service Commission of West Virginia
(West Virginia Consumer Advocate)
Consumers Energy Company (Consumers) X
Dairyland Power Cooperative X
Dayton Power & Light Company (Dayton) X
Division of Consumer Counsel, Office of X X
the Attorney General of Virginia
Duke Energy Trading and Marketing, L.L.C. X
Duke Energy Corporation X
Duquesne Light Company X
</TABLE>
<PAGE> 31
EXHIBIT D-1.8
<TABLE>
<S> <C> <C>
Electric Clearinghouse, Inc. X X
(Clearinghouse)
Electricity Consumers Resource Council, X X
American Iron and Steel Institute, and
Indiana Industrial Energy Consumers, Inc.
(Industrial Consumers)
Enron Power Marketing, Inc. (Enron) X X
Entergy Services, Inc. X
Great Lakes Energy X
Haddington Ventures, L.L.C. X
Illinois Commerce Commission X X
(Illinois Commission)
Indiana and Michigan Municipal X X
Distributors Association
Indiana Office of Utility Consumer X
Counselor
Indiana Utility Regulatory Commission X X
(Indiana Commission)
Indianapolis Power & Light Company X X
Louisiana Public Service Commission X
(Louisiana Commission)
Maryland Public Service Commission X
(Maryland Commission)
Michigan Public Service Commission and X
the State of Michigan
Michigan Wholesale Customers X X
(Michigan Customers)
Midwest Generation, L.L.C. and Edison X X
Mission Marketing & Trading, Inc.
Midwest ISO Participants (Midwest ISO) X X
Mississippi Public Service Commission X
(Mississippi Commission)
Missouri Public Service Commission X
Monongahela Power Company, The Potomac X X
Edison Company, and West Penn Power
Company (collectively Allegheny Power)
New York Mercantile Exchange X
North Carolina Electric Membership X X
</TABLE>
<PAGE> 32
EXHIBIT D-1.8
<TABLE>
<S> <C> <C>
Corporation (NCEMC)
Northern Indiana Public Service Company X X
Ohio Consumers' Counsel (Ohio Counsel) X X
The Ohio Municipal Energy Group X X
Ohio Rural Electric Cooperatives, Inc. X X
and
Buckeye Power, Inc.
Ormet Primary Aluminum Corporation X
Ontario Power Generation Inc. X
PG&E Generating Company (PG&E Gen) X
PJM Interconnection, L.L.C. (PJM) X X
PP&L, Inc. X X
Pennsylvania Office of Consumer Advocate X
(Pennsylvania Advocate)
Public Service Commission of West X
Virginia
(West Virginia Commission)
Public Service Electric and Gas Company X
Public Utilities Commission of Ohio X X
(Ohio Commission)
Reliant Energy Power Generation, Inc. X
Shell Energy Services Company, L.L.C. X
South Carolina Public Service Authority X X
(South Carolina Authority)
Southeastern Power Administration X
Steel Dynamics, Inc. X X
TransEnergie U.S. Ltd. (TransEnergie) X X
Transmission Dependent Utility Systems X X
(TDU Systems)
Virginia Committee for Fair Utility Rates X X
(Virginia Committee)
Virginia Independent Power X X
Producers, Inc.
Virginia State Corporation Commission X
(Virginia Commission)
Wabash Valley Power Association, Inc. X
(Wabash Valley)
Wolverine Power Supply Cooperative, Inc. X X
(Wolverine)
</TABLE>
Curt H (acute)'SCebert, jr., C'ECommissioner, dissenting:
<PAGE> 33
EXHIBIT D-1.8
*25 This order conditionally accepts the proposal from the Alliance
Companies (Alliance) to form a for-profit transmission company, a transco. As
opposed to requiring further information and explanations, I would approve the
transco now. The majority raises questions with the application in a manner that
opponents of transco's could interpret as inconsistent with Order No. 2000 (RTO
Rule) that we issue today. To avoid confusion about the RTO Rule, and to
emphasize that FERC will, in fact, favor stand-alone transmission companies,
transco's, I explain my arguments in writing.
The majority rejects the Alliance's justifications for the
"configuration" of the company and calls it a "tollgate." Slip op. at 33. The
order requires further information. The majority also suggests that, instead,
the Alliance join a new or "existing" Regional Transmission Organization (RTO).
No RTO currently exists. The uninformed could view the order as favoring an ISO
for the Midwest. Nothing could be further from the truth.
Given that, we have yet to approve any ISO as an RTO, and that ISO's
fall short of the goal we stated in the RTO Rule's Preamble for a stand-alone
transmission business, any reasonable person should consider such a conclusion
illogical and inconsistent with Order No. 2000. Moreover, in the RTO Rule, we
require audits for ISO boards (subject to comments on rehearing). Therefor, we
could hardly endorse one.
Substantively, I disagree with the holding on configuration. The
majority completely ignores the record evidence that the area the Alliance
comprises encompasses a natural trading area. For example, American Electric
Power Corporation (AEP), the backbone of the Alliance trades about three times
greater volume with the companies running along the "line from Michigan to
Virginia" than it does with the Midwest ISO. Alliance Answer to Protests at 17.
I have said publicly many times that the Alliance significantly exceeds the
National Grid Company of England, a successful transco in everyone's mind, in
miles of line, customers and capital investment. The majority confuses political
boundaries with economic. We want RTO's as economic enterprises, not political
institutions. The Alliance constitutes a going economic enterprise. More
information would only reinforce my conclusion.
The majority also objects to the "veto power" the Alliance Companies
hold over new members, acquisitions and disposition of property, as well as the
authority to remove the board. Slip op. at 32. My colleagues regard this as
potentially evincing control, unless the Alliance further explains its
reservation of rights. Biased observers, or the unfamiliar, would say this shows
that under the RTO Rule, passive investors can have "no control" over
operations. I commend reading the Preamble that explicitly draws the line at
"preservation of capital investment."
Moreover, as an agency dealing in the real world, we should approve the
provision. Non-voting, or passive, interests have no control over the day-to-
day conduct of a business. Common shareholders exercise that power. This is
clear to those understanding real-world finance.
<PAGE> 34
EXHIBIT D-1.8
Therefore, the "veto power" the majority decries applies to actions that would
jeopardize capital investment. What the majority places under a cloud here
preservation of passive owners' capital investment - we permit under the RTO
Rule. There, we acknowledge, that passive owners may reserve rights to protect
their capital investment. These provisions fall within the line.
*26 In addition to the principles of corporate economics, the majority
overlooks the qualifier on the so-called veto that appears in the Alliance
agreement: to protect the value of the owners' equity. That phrase comes from
countless, standard business instruments. Ordinary home mortgages include the
same concept. All would agree that the Alliance should not admit members with
bad credit records. Similarly, reasonable people would agree that passive owners
should step in when the company management dissipates the treasury and should
remove board members for cause. Corporate fiduciary duty requires no less.
Finally, the majority questions the six-year transition period for zone
rates. Slip op. at 19. In the RTO NOPR, we acknowledged the need for a
transition. Moreover, the majority ignores the fact that, in the ISO context, we
allow differences in rates based on the location of the customer. Some of my
colleagues consider a permanent difference just and reasonable. That arrangement
they call "license plate rates," a benign-sounding name. These transitional zone
rates, a temporary rate disparity, they call "pancaked rates," an
oppressive-sounding name. These same colleagues justify "license plate rates" as
a pragmatic departure from pure comparability. They do so in the name of
extending the scope of the market. Yet these same people overlook the same
argument with regard to zone rates. The Michigan consumers, in whose behalf the
majority claims to act, id., benefit from a large market. I consider that a
small price to pay for a short-term deviation from our ideal. Delivered price
will be the hallmark of the competitive market, if only the FERC will believe.
I understand that the majority wants further explanation, and, in fact,
the Chairman has expressed enthusiasm for the Alliance business model.
Nevertheless, I see harm in subjecting the RTO Rule to misinterpretation,
whether deliberate or innocent. I also see harm in the majority's delaying an
RTO, especially when the RTO Rule establishes ambitious deadlines. I would
approve now the arrangement FERC will eventually accept anyway. The foundation
of the Alliance business model is solid and the opportunity for a stand alone
transmission business can be built on these principles. We have yet to see a
perfect pool, RTG, or ISO. The foundation must be in place before the walls and
roof of transmission, as a viable alternative to new generation, can be built.
If the majority (FERC) is to be true to comments made before Congress and the
press releases describing the RTO rule as VOLUNTARY, then we must allow these
formations to take place and flourish in this ERA of Competitive Opportunity. I
respectfully dissent.
Federal Energy Regulatory Commission
89 FERC P 61,298, 1999 WL 1212980 (F.E.R.C.)
<PAGE> 35
EXHIBIT D-1.8
END OF DOCUMENT
<PAGE> 1
EXHIBIT D-1.9
UNITED STATES OF AMERICA
90 FERC (Paragraph) 61,242
FEDERAL ENERGY REGULATORY COMMISSION
OPINION NO. 442
American Electric Power Company
Docket Nos. EC98-40-000,
And ER98-2770-000, and
ER98-2786-000
Central and South West Corporation
OPINION AND ORDER REVERSING IN PART,
AFFIRMING IN PART, VACATING IN PART,
AND MODIFYING IN PART THE INITIAL DECISION
Issued: March 15, 2000
<PAGE> 2
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
OPINION NO. 442
American Electric Power Company
Docket Nos. EC98-40-000,
And ER98-2770-000, and
ER98-2786-000
Central and South West Corporation
APPEARANCES
Thomas L. Blackburn, J. A. Bouknight, Jr., Edward J. Brady, Kevin F. Duffy,
Carmen L. Gentile, Stephen Angle, Douglas G. Green, Charles Hokanson,
Jr., B. Kelly Kiser, James F. Mauze, Jane I. Ryan, Samuel T. Perkins,
and Linda L. Walsh for AMERICAN ELECTRIC POWER COMPANY
Clark Evans Downs, Kenneth B. Driver, Martin V. Kirkwood and Shelby
Provencher for CENTRAL AND SOUTH WEST CORPORATION
Cynthia S. Bogorad, Ben Finkelstein, David B. Lieb, Tony Lin, Robert C.
McDiarmid, David E. Pomper, Jeffrey A. Schwarz, Scott H. Strauss, and
Sara C. Weinberg for AMERICAN ELECTRIC GROUP INTERVENORS
Randolph Lee Elliott, Susan N. Kelly, Richard Meyer, Debra H. Rednik, and
Wallace F. Tillman for AMERICAN PUBLIC POWER ASSOCIATION and NATIONAL
RURAL ELECTRIC COOPERATIVE ASSOCIATION
Mary W. Cochran and Paul R. Hightower for ARKANSAS PUBLIC SERVICE COMMISSION
Brian Donahue and Zachary David Wilson for ARKANSAS WATER AND LIGHT
COMMISSION and the CITY OF HOPE
Christopher C. O'Hara and Frederick H. Ritts for BLUE RIDGE POWER AGENCY
Adrienne E. Clair, Montina M. Cole, T. Alana Deere, and Sherry A. Quirk for
BRAZOS ELECTRIC POWER COOPERATIVE, INC.
Ronald J. Brothers and Jeffrey A. Gollomp for CINCINNATI GAS & ELECTRIC
COMPANY and PSI ENERGY, INC.
Mary Margaret Farren, Jeffrey A. Gollomp, and Mike Naeve for CINERGY
SERVICES, INC.
Robert A. Jablon and Thomas C. Trauger for CITIES OF DOWAGIAC AND STURGIS,
MICH.
<PAGE> 3
Docket No. EC98-40-000, et al. ii
Paul A. Cunningham, Richard B. Herzog, and Peter Thornton for COMMONWEALTH
EDISON COMPANY
Daniel T. Donovan, Mitchell F. Hertz, Michelle T. Palmer, and Edward N. Rizer
for DAYTON POWER AND LIGHT COMPANY
Howard Benowitz and Alan I. Robbins for EAST KENTUCKY POWER COOPERATIVE and
CITY OF HAMILTON, OHIO
William H. Burchette, Matthew J. Jones, A. Hewitt Rose, and Christine C. Ryan
for EAST TEXAS ELECTRIC COOPERATIVE, NORTHEAST TEXAS ELECTRIC
COOPERATIVE, TEX-LA ELECTRIC COOPERATIVE OF TEXAS, INC., and BLUE RIDGE
POWER AGENCY
Mark R. Haskell, Daniel A. King, James W. Moeller, and Kathryn L. Patton for
ELECTRIC CLEARINGHOUSE, INC.
Samuel Behrends IV, Andrea J. Chambers, Joseph Hartsoe, and Sarah G. Novosel
for ENRON POWER MARKETING, INC.
Kim Despeaux, Mary Margaret Farren, and William S. Scherman for ENTERGY
SERVICES, INC.
Susan Hedman and Michael Mullett for the ENVIRONMENTAL COALITION
Eric A. Eisen and Nikki Shoultz for INDIANA UTILITY REGULATORY COMMISSION
Samuel Grossman, David M. Kleppinger, Samuel Randazzo, Kimberly Wile, and
Derrick P. Williamson for INDUSTRIAL ENERGY USERS - OHIO and WEST
VIRGINIA ENERGY USERS GROUP
James Boyle and Brian Lederer for INTERNATIONAL BROTHERHOOD OF ELECTRICAL
WORKERS and LOCALS 1002 AND 738
David D'Alessandro, Kelly A. Daly, Mylie A. Needle, and Richard Raff for
KENTUCKY PUBLIC SERVICE COMMISSION
John Michael Adragna, Patrick Henry, and John M. Sharp for LOUISIANA
COOPERATIVES
Noel J. Darce, Michael R. Fontham, and Paul L. Zimmering for LOUISIANA PUBLIC
SERVICE COMMISSION
David L. Schwartz and Joseph A. Simei for MCKINSEY & CO. and MORGAN STANLEY
DEAN WITTER
Patricia S. Barrone, Henry J. Boynton, David D'Alessandro, Jennifer M.
Granholm, Gregory O. Olaniran, and David A. Voges for MICHIGAN PUBLIC
SERVICE COMMISSION and the STATE OF MICHIGAN
David S. Berman, Paul M. Flynn, Arnold B. Podgorsky, and Michael E. Small for
MIDWEST ISO PARTICIPANTS
<PAGE> 4
Docket No. EC98-40-000, et al. iii
Steven Dottheim, Scott Hempling, and R. Blair Hosford for MISSOURI PUBLIC
SERVICE COMMISSION
Barry Cohen for the OHIO CONSUMERS' COUNSEL
Gregg D. Ottinger and Jon R. Stickman for OHIO MUNICIPAL ENERGY GROUP
Scott A. Campbell and Robert P. Mone for OHIO RURAL ELECTRIC COOPERATIVES,
INC., and BUCKEYE POWER, INC.
Robert L. Daileader, Jr., Karen Georgenson Gach, John Harver, and Robert
Stewart for OKLAHOMA GAS AND ELECTRIC COMPANY
Ben Finkelstein for OKLAHOMA MUNICIPAL POWER AUTHORITY
J. Cathy Fogel, Sang Y. Paek, and Robin E. Remis for ORMET PRIMARY ALUMINUM
CORPORATION
Steven M. Sherman for PROLIANCE ENERGY, LLC
Duane W. Luckey and Thomas W. McNamee for PUBLIC UTILITIES COMMISSION OF OHIO
John R. Garry and Howard Zelbo for SALOMON SMITH BARNEY INC.
Steven M. Kramer and Bret A. Sumner for SHARYLAND UTILITIES, L.P.
Douglas F. John and Kim M. Clark for SOUTH TEXAS ELECTRIC COOPERATIVE, MEDINA
ELECTRIC COOPERATIVE, and CITY OF ROBSTOWN, TEX.
William F. Dudley, Wendy N. Reed, and Alan J. Statman for SOUTHWESTERN PUBLIC
SERVICE COMPANY
Floyd L. Norton IV and Bruce L. Richardson for TEXAS UTILITIES ELECTRIC
COMPANY
Randolph Lee Elliott, Milton J. Grossman, Carrie L. Hill, Robert A. O'Neil,
Debora H. Rednik, and Benjamin L. Willey for TRANSMISSION DEPENDENT
UTILITY SYSTEMS
Grant Crandall, Douglas Parker, and Judith Rivilin for UNITED MINE WORKERS OF
AMERICA, AFL-CIO
Joanne F. Goldstein for UTILITY WORKERS UNION OF AMERICA, AFL-CIO
C. Meade Browder, Jr. and James C. Dimitri for VIRGINIA STATE CORPORATION
COMMISSION AND ITS STAFF
Charles W. Ritz III for WABASH VALLEY POWER ASSOCIATION
Daniel E. Frank, Keith R. McCrea, and J. M. Shafer for WESTERN FARMERS
ELECTRIC COOPERATIVE
<PAGE> 5
Docket No. EC98-40-000, et al. iv
Becky M. Bruner for WESTERN RESOURCES, INC.
John J. Bartus, Edith A. Gilmore, Gary D. Levenson, James A. Pepper, Charles
F. Reusch, Stanley A. Berman, and Richard L. Miles for the TRIAL STAFF
OF THE FEDERAL ENERGY REGULATORY COMMISSION
<PAGE> 6
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Before Commissioners: James J. Hoecker, Chairman;
William L. Massey, Linda Breathitt,
and Curt Hebert, Jr.
American Electric Power Company
Docket Nos. EC98-40-000,
and ER98-2770-000, and
ER98-2786-000
Central and South West Corporation
OPINION NO. 442
OPINION AND ORDER REVERSING IN PART,
AFFIRMING IN PART, VACATING IN PART,
AND MODIFYING IN PART THE INITIAL DECISION
(Issued March 15, 2000)
I. Introduction
This Opinion conditionally authorizes, under section 203 of the Federal
Power Act,(1) the proposed merger between American Electric Power Company (AEP)
and Central and South West Corporation (CSW) (jointly, Applicants). This
Opinion reverses the Presiding Judge's finding that Applicants have carried
their burden of establishing that the proposed merger will not adversely
affect competition. However, as conditioned below, we find that the proposed
merger is consistent with the public interest. This Opinion also affirms the
Presiding Judge's findings related to the rates, terms, and conditions of the
three rate schedules filed in Docket No. ER98-2770-000. Furthermore, this
Opinion affirms the Presiding Judge's rulings regarding the stipulated rates
for the joint open access transmission tariff (Joint OATT) filed in Docket
No. ER98-2786-000, and vacates the Presiding Judge's rulings regarding
cost-of-service treatments and rate design principles for the Joint OATT.
II. Background
A. The Applicants
AEP is a registered public utility holding company under the Public
Utility Holding Company Act of 1935,15 U.S.C. (Section) 79 et seq. (PUHCA). AEP
owns seven electric utility operating subsidiaries that serve approximately
three million customers in Indiana, Kentucky,
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(1) 16 U.S.C. (Section) 824b (1994).
<PAGE> 7
Docket No. EC98-40-000, et al. 2
Michigan, Ohio, Tennessee, Virginia, and West Virginia.(2) AEP also owns AEP
Generating Company, which sells power and energy at wholesale to some of the
operating subsidiaries and to unaffiliated purchasers. AEP owns thirty-eight
power plants, which have an aggregate capacity of approximately 23,800
megawatts, and owns approximately 22,000 miles of transmission lines. AEP is
also involved in other business ventures both within and outside the United
States.
CSW is a registered public utility holding company under PUHCA. CSW
owns four companies that are engaged in generating, purchasing, transmitting,
distributing, and selling electricity.(3) The four electric operating
subsidiaries serve approximately 1.7 million customers in Arkansas,
Louisiana, Oklahoma, and Texas. CSW also owns other businesses in the United
States and abroad.
B. The Proposed Merger
On April 30, 1998, Applicants filed a joint application seeking
authorization to consolidate their jurisdictional facilities through a
merger. As part of the merger, each share of CSW common stock will be
converted into 0.6 of a share of AEP common stock, and CSW shareholders will
become AEP shareholders. The merger will not affect any debt securities of
AEP, CSW, or any of their affiliates. AEP will continue as a registered
holding company, and will be the parent of the seven AEP utility operating
subsidiaries as well as the four CSW utility operating subsidiaries (jointly,
the Combined System). AEP will also remain the parent of its existing
non-utility subsidiaries and become the parent of CSW's non-utility
subsidiaries. American Electric Power Service Corporation (AEPSC) will
assume the responsibilities of Central and South West Services, Inc., and
survive the merger, providing management, accounting, financial, legal, and
other support services to AEP, the eleven operating utilities, and the
non-utility subsidiaries.
The electric systems of AEP and CSW are not directly interconnected.(4)
Applicants have obtained rights to a 250 MW AEP (AEP East) to CSW (AEP West)
firm transmission contract path to integrate the operations of the Combined
System. The contract path runs from the interconnection between AEP and
Central Illinois Public Service Company, a subsidiary of Ameren Corporation,
to the interconnection between Union Electric Company, also an Ameren
subsidiary, and PSO, a CSW subsidiary. After the merger, Applicants plan to
operate the Combined System through a single control center.
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(2) The seven subsidiaries are Appalachian Power Company, Columbus Southern
Power Company, Indiana Michigan Power Company, Kentucky Power Company, Kingsport
Power Company, Ohio Power Company, and Wheeling Power Company (collectively, AEP
Operating Companies).
(3) The four companies are Central Power and Light Company (Central P&L),
Public Service Company of Oklahoma (PSO), Southwestern Electric Power Company
(SWEPCO), and West Texas Utilities (West Texas) (collectively, CSW Operating
Companies).
(4) AEP is directly interconnected with utilities in the East Central Area
Reliability Coordination Agreement (ECAR), Southern Electric Reliability
Council (SERC), and Mid-America Interconnected Network (MAIN). CSW is
interconnected with utilities in the Electric Reliability Council of Texas
(ERCOT) and Southwest Power Pool (SPP).
<PAGE> 8
Docket No. EC98-40-000, et al. 3
To mitigate concerns raised by the merger, Applicants commit to: (1)
divest 550 MW of generating capacity; (2) limit their ability to contract for
firm transmission capacity from AEP East to AEP West to 250 MW, unless
authorized to contract for more by the Commission; (3) schedule available
capacity between ERCOT and SPP on the HVDC ties on a first-in-time basis; (4)
waive their native load priority into the CSW-SPP control area for nonfirm
imports; (5) waive their native load priority for transfers of energy from
AEP West to AEP East for a four-year period following the consummation of the
merger; and (6) adopt certain ratepayer protection measures.
Also, Applicants commit to joining a Commission-approved RTO (AEP is a
signatory to the Alliance Proposal that the Commission conditionally
authorized in Docket Nos. ER99-3144-000, et al.)(5) and transferring to the RTO
functions related to transmission service, transmission security and
reliability, and control area responsibilities.
C. The Hearing Order
On November 10, 1998, the Commission issued a hearing order in this
case.(6) The Commission determined that the proposed merger would not have an
adverse impact on regulation and approved the use of the "pooling of
interests" method of accounting for the merger. The Commission concluded,
however, that a hearing was necessary on the effect of the merger on
wholesale competition. The Commission noted that:
Applicants' own analysis shows that the proposed merger fails the
screen thresholds in several markets .... [and] there are other factors
that appear to suggest that Applicants' screen analysis may not fully
capture the effects of the merger on competition. For example, the
merger may create or enhance the ability and incentive for AEP and/or
CSW to use transmission to frustrate competitors' access to relevant
markets. Such action could constrain competition and thereby raise
electricity prices in markets in which the merged firm can sell. The
competitive effect of such action would not be detected by pre- to
post-merger changes in concentration statistic.(7)
The Commission, therefore, directed that "the full range of potential
competitive harm potentially caused by the merger based on the most recently
available data and the mitigation necessary to remedy any such harm"(8) should
be addressed at the hearing.
The Commission also set for hearing the effect of the merger on
wholesale rates and on retail competition in Missouri.(9) In addition, the
Commission consolidated and set for hearing
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(5) Alliance Companies, 89 FERC (Paragraph) 61,298 (1999) (Alliance) (reh'g
pending).
(6) American Electric Power Co. and Central and South West Corp., 85 FERC
(Paragraph) 61,201 (1998) (Hearing Order); reh'g denied, 87 FERC (Paragraph)
61,274 (1999).
(7) Hearing Order, 85 FERC at (Paragraph) 61,818-19 (footnotes omitted).
(8) Id. at 61,819.
<PAGE> 9
Docket No. EC98-40-000, et al.
4
three rate schedules designed to integrate and operate Applicants' systems on a
coordinated basis after the merger, the Joint OATT, and procedures to comply
with the Standards of Conduct set forth in 18 C.F.R. (Section) 37.4 (1999).(10)
D. Procedural Record
On May 24, 1999, Applicants and Trial Staff filed a trial stipulation
resolving all issues between Trial Staff and Applicants, except for issues
concerning the system integration agreements, ratepayer protections, and the
timing of divestiture (May 24 Stipulation). In the May 24 Stipulation,
Applicants make certain commitments, such as joining an RTO and transferring
transmission service, security, and control area responsibilities for a
portion of the merged system to an RTO.
The hearing before the Presiding Judge began on June 29, 1999, and
concluded on July 19, 1999. On July 13, 1999, Applicants and Trial Staff
entered into a second stipulation (July 13 Stipulation) resolving all issues
concerning the system integration agreements except for the pricing of energy
exchanges between AEP East and AEP West. After the close of the hearing,
certain Intervenors withdrew their opposition to the merger. The Presiding
Judge issued an Initial Decision on November 23, 1999.(11) Briefs on
Exceptions were filed on December 15, 1999, and Briefs Opposing Exceptions
were filed on December 29, 1999.
E. Settlements Reached With Certain Parties
The following parties have reached settlements with the Applicants
and/or withdrawn their objections to the merger: Arkansas Electric
Cooperative Corporation, Oklahoma Gas & Electric Company, Commonwealth Edison
Company (Commonwealth Edison), CPL Wholesale Customer Group (consisting of
South Texas Electric Cooperative, Medina Electric Cooperative, and the City
of Robstown, Texas), Hope Water & Light Commission, Entergy Services, Inc.,
Cinergy Services, Inc. (Cinergy), Blue Ridge Power Agency, International
Brotherhood of Electrical Workers, Public Utilities Board of Brownsville,
Brazos Electric Power Cooperative, Inc., Cajun Electric Power Cooperative,
Indiana Municipal Power Agency, North Carolina Electric Membership
Corporation, Oklahoma Municipal Power Authority, Magic Valley Electric
Cooperative, American Municipal Power-Ohio, Inc., Southwestern Public Service
Company, Mid-Tex Generation and Transmission Electric Cooperative, Indiana &
Michigan Municipal Distributors Association, East Texas Cooperatives
(consisting of Northeast Texas Electric Cooperative, Tex-La Electric
Cooperative, and East Texas Electric Cooperative), Rayburn County Electric
Cooperative, Buckeye Power, Inc., Indiana & Michigan Municipal Distributors
Association, and the Missouri, Ohio, and Michigan Commissions. In addition,
the Wabash Valley Power Association (Wabash) and Lafayette Utilities System
(Lafayette) withdrew their
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(9) Id. Subsequently, Applicants and the Missouri Commission reached a
settlement, which was approved by the Commission. 90 FERC (Paragraph) 61,094
(2000).
(10) Id. at 61,823.
(11) 89 FERC (Paragraph) 63,007 (1999)(Initial Decision).
<PAGE> 10
Docket No. EC98-40-000, et al.
5
opposition to the stipulated rates for transmission service and ancillary
services in Docket No. ER98-2786-000.
F. Briefs On and Opposing Exceptions
Briefs On Exceptions were filed by Trial Staff, Dayton Power & Light
Company (Dayton), Enron Power Marketing, Inc. (Enron), Midwest ISO
Participants, American Public Power Association and National Rural Electric
Cooperative Association (jointly, APPA/NRECA), Wabash, Indiana Municipal
Power Agency, Lafayette, and Environmental Coalition.
Briefs Opposing Exceptions were filed by Trial Staff, Applicants, and
the Arkansas and Louisiana Public Service Commissions.
Environmental Coalition filed its Brief On Exceptions on the date
established for filing Briefs Opposing Exceptions and incorporated by
reference the exceptions listed in Dayton's Brief On Exceptions, as permitted
by Rule 711(a)(1)(iii) of the Commission's Rules of Practice and Procedure.
18 C.F.R. 385.711(a)(1)(iii). In addition, Environmental Coalition raised
other arguments and summarized its prepared testimony. On January 18, 2000,
Applicants filed a motion to strike the portion of Environmental Coalition's
Brief On Exceptions that went beyond incorporating by reference Dayton's list
of exceptions, claiming that such portion is not permitted under Rule
711(a)(1)(iii) and deprives Applicants of the opportunity to respond to
Environmental Coalition's arguments. In the alternative, Applicants seek to
respond to such arguments in a supplemental Brief Opposing Exceptions.
The Commission will grant Applicants' motion to strike part of
Environmental Coalition's Brief On Exceptions, since it is not consistent
with Rule 711(a)(1)(iii). We will deny Applicants' alternative motion to
file a supplemental Brief Opposing Exceptions as moot.
G. State Approvals Of The Merger
The Louisiana, Arkansas, Indiana, Kentucky, Oklahoma, and Texas
Commissions have conditionally approved the merger, pending the outcome of
this proceeding and final action by other relevant authorities.
H. Motion Concerning Protected Status of Documents
Wabash and Lafayette filed a motion to remove certain documents from
protected status, claiming that the protected designation was unwarranted and
it was not clear from the record whether the Presiding Judge had ruled on the
motion during the hearing. Applicants argue that there is no need to rule on
this motion because the Presiding Judge has already denied it.
We agree with Applicants.(12)
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(12) See Tr. 2457.
<PAGE> 11
Docket No. EC98-40-000, et al.
6
III. Effect of the Merger on Competition
A. Market Power Analysis
1. Issues Associated with Consolidating Generation
Applicants' witness, Dr. William H. Hieronymus, presents testimony
regarding the competitive implications of consolidating generation controlled by
CSW and AEP. Applicants identify nonfirm energy and short-term capacity as the
relevant products and use, among other measures, economic capacity as a proxy
for suppliers' ability to participate in the relevant product market. Dr.
Hieronymus identifies as potentially affected customers those directly
interconnected with the Applicants and those who are historical customers of AEP
and/or CSW. Dr. Hieronymus identifies and defines 58 relevant geographic
("destination") markets using the approach described in Appendix A of the Merger
Policy Statement.(13) He evaluates pre- to post-merger changes in market
concentration over ten time periods.(14) Dr. Hieronymus reports increases that
exceed the thresholds specified in the Merger Policy Statement in numerous time
periods for the CSW-SPP, CSW-ERCOT, Oklahoma Gas & Electric, Western Farmers,
and Missouri Public Service markets, but argues that for the most part the
increases are largely caused by the 250 MW transfer from AEP to CSW. He contends
that since it is low-cost energy coming from AEP to CSW, the effect will be to
lower market prices in the CSW-SPP markets, rather than increase them. Dr.
Hieronymus states that Applicants' proposed divestiture of 550 MW of capacity in
the CSW-SPP and CSW-ERCOT regions reduces, for the most part, pre- to
post-merger increases in concentration in the affected relevant markets to
acceptable levels.
Discussion
Regarding Applicants' proposed commitment, we find the amount of the
capacity proposed to be divested to be acceptable. While certain Intervenors
argue that more than 550 MW of capacity should be divested, the record does
not demonstrate the need for such a requirement. However, we do not find the
divestiture proposal, as outlined in the May 24 Stipulation, to be an
effective remedy due to Applicants retaining operational control of such
generation, as addressed below in the discussion of remedies.
2. Issues Associated with Consolidating Generation and
Transmission
In the Hearing Order, the Commission stated that the proposed merger
raised the competitive concern that the merged company could use transmission
to frustrate competitors' access to relevant electricity markets. The
parties refer to this as a vertical competitive issue raised by the proposed
merger. They state that the primary way the merged company could
successfully accomplish such a strategy is by "foreclosing" competitors'
access to the
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(13) See Inquiry Concerning the Commission's Merger Policy Under the Federal
Power Act: Policy Statement, Order No. 592, FERC Stats. & Regs. 68,595 (1996),
order on reconsideration, Order No. 592-A, 79 FERC (Paragraph). 61,321 (1997)
(Merger Policy Statement).
(14) Time periods evaluated are super-peak, peak, and off-peak for summer,
winter, and shoulder seasons, and a summer super-super-peak period.
<PAGE> 12
Docket No. EC98-40-000, et al.
7
transmission necessary to sell into relevant electricity markets, thereby
profiting from higher electricity prices. They adopt, for the purposes of their
own analyses, the approach to evaluating such issues that the Commission
articulated in Enova and the Filing Requirements NOPR.(15) The parties therefore
evaluate whether the merger would create or enhance the ability and/or incentive
for the merged company to adversely affect prices in relevant markets.
Applicants' witness, Dr. J. Stephen Henderson, analyzes the possibility
that the proposed merger could create the incentive for the merged company to
adversely affect prices or output in relevant markets through foreclosure. He
assumes that foreclosure is implemented by the merged company by denying certain
requests for transmission service, which would have the effect of preventing
competitors from reaching relevant markets. Such requests are those that occur
between sellers directly interconnected to one Applicant (i.e., AEP or CSW) and
buyers directly interconnected to the other Applicant, for which the least-cost
contract path involves AEP or CSW facilities. Dr. Henderson then determines the
potential suppliers in 28 relevant markets. He computes market concentration
(using the HHI statistic) for both economic and available economic capacity for
a number of time periods.(16) Of the 11 southwestern relevant markets over four
time periods that Dr. Henderson evaluated using economic capacity (for a total
of 44 cases), his results show that in 29 cases, markets are highly concentrated
(ranging from 1,818 to 8,495 HHI). Of the 17 Midwestern relevant markets over
four time periods that Dr. Henderson evaluated using economic capacity (for a
total of 68 cases), his results show that in 50 cases, markets are highly
concentrated (ranging from 1,818 to 7,048 HHI). Dr. Henderson reports that
increases in market concentration attributable to foreclosure are less than 50
HHI Because these increases do not violate the thresholds specified in the
Merger Policy Statement, Dr. Henderson concludes that the proposed merger will
not adversely affect competition.
A number of Intervenors challenge Applicants' analysis and provide
their own analyses of the vertical competitive effects of the proposed
merger. These Intervenors include: Dayton, Wabash, and Enron.
Dayton relies on the vertical competitive analysis contained in the
testimony of Dr. Fox-Penner and Dr. Craig Roach. Dr. Fox-Penner critiques a
number of aspects of Dr. Henderson's analysis. He first contends that Dr.
Henderson inappropriately limits his evaluation to cases where the merger
creates the incentive for the merged company to exercise vertical market power
(i.e., where there was no pre-merger) thereby missing the cases where such an
incentive existed pre-merger and is increased by the merger. Dr. Fox-Penner next
argues that Dr. Henderson ignores how the merger creates or enhances the ability
of the merged company to exercise vertical market power. For example, Dr.
Fox-Penner notes that ATC (the manipulation of which could be one way for the
merged company to implement foreclosure) remains
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(15) San Diego Gas & Electric Company and Enova Energy, Inc., et al., 79 FERC
(Paragraph) 61,372 (1997), order denying reh'g, 85 FERC (Paragraph) 61,037
(1998) (Enova) and the Revised Filing Requirements Under Part 33 of the
Commission's Regulations, Notice of Proposed Rulemaking, FERC Stats. & Regs.
(Paragraph) 32,528 (1998) (Filing Requirements NOPR).
(16) Time periods evaluated are summer peak and super peak, winter super peak
and shoulder off-peak.
<PAGE> 13
Docket No. EC98-40-000, et al.
8
unchanged in all cases examined by Dr. Henderson.(17) He also contends that by
denying only those transactions in which the buyer is directly interconnected to
one of the Applicants and the seller is directly interconnected to the other
Applicant, Dr. Henderson misses other potentially affected transactions.(18)
Finally, Dr. Fox-Penner points out that Dr. Henderson incorrectly relies on
changes in post-merger market concentration attributable to foreclosure as a
standard for evaluating whether the merger would adversely affect competition.
Dr. Fox-Penner notes that a change in market concentration arising from
foreclosure is an incomplete measure of an entity's incentive to exercise market
power.
Dr. Fox-Penner explains that strategically operating the transmission
system is one method for the merged company to potentially manipulate
transmission in order to engage in foreclosure so as to increase profit.(19)
Dr. Fox-Penner focuses on AEP or CSW calling TLR over a single critical
flowgate as one such way to strategically manipulate the transmission system
and analyzes the resulting effect in two relevant markets: Entergy and
Ameren. He calculates market concentration with and without foreclosure
pre-merger and concentration with and without foreclosure post-merger. Dr.
Fox-Penner explains that the difference in market concentration with and
without foreclosure pre-merger indicates the pre-existing incentive for CSW
and AEP to individually foreclose competitors whereas post-merger, the
difference indicates the merged company's incentive to foreclose. The
difference between the two "differences" in market concentration therefore
indicates the degree to which the incentive to foreclose is enhanced by the
merger.
In his analysis of the Entergy market, Dr. Fox-Penner explains that the
effect of the merger is to combine AEP's generating capacity and control over
certain flowgates (i.e., a pre-existing incentive and ability to foreclose,
respectively) with CSW's control of certain flowgates (i.e., a pre-existing
ability to foreclose). The effect of this combination is to enhance the
merged company's ability to foreclose and create the incentive for the merged
company to foreclose in the highly concentrated Entergy market (3,893 HHI,
with an increase in concentration related to an enhanced incentive to
foreclose of 2,793 HHI). In the Ameren market, Dr. Fox-Penner explains that
the effect of the merger is to combine AEP's and CSW's economic capacity
(i.e., pre-existing incentive to foreclose) with AEP's and CSW's control of
certain flowgates (i.e., pre-existing ability to foreclose). The effect of
this combination is to enhance the merged company's ability and incentive to
foreclose in the highly concentrated Ameren market (2,298 HHI, with an
increase in concentration related to an enhanced incentive to foreclose of
1,144 HHI).(20)
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(17) To emphasize the importance of changes in ATC on market concentration, he
points to the results of Dr. Hieronymus' analysis showing significant
differences in market concentration when ATC changes from pre- to post-merger.
(18) For example, Dr. Henderson does not examine those cases where the buyer and
seller are directly interconnected to the same Applicant. He also misses
transactions involving systems that are indirectly interconnected with AEP or
CSW.
(19) Dr. Fox-Penner cites to witness Mr. John C. Procario's (Exhibit No. MWP-1)
testimony.
(20) Dr. Fox-Penner notes that in 1997, CSW made sales to Ameren of 160,000 MWh
worth $6.1 million and AEP made sales to Ameren of 42,000 MWh worth $1.3
million. Exhibit Nos. CIN-1 at 38 and CIN-4 at 1.
<PAGE> 14
Docket No. EC98-40-000, et al.
9
Dayton's witness, Dr. Craig Roach, contends that Dr. Henderson
underestimates the foreclosure potential because he erroneously assumes that
AEP or CSW could foreclose competitors' access to transmission along only
least-cost contract paths involving AEP or CSW facilities. He notes that if
a least-cost path becomes constrained, then other more expensive contract
paths could be used to allocate the remaining capacity in the relevant
market. For example, according to Dr. Roach, the least-cost path through TVA
is capacity-constrained relative to the amount of economic capacity Carolina
Power & Light Co. (CP&L) has to sell. As a result, an unconstrained, but
higher-cost, AEP path could be utilized to deliver CP&L capacity into the
Ameren market. However, since that path was not least-cost, the CP&L
transaction was not a potential candidate for foreclosure in Dr. Henderson's
analysis. Dr. Roach, therefore, concludes that AEP could foreclose CP&L from
the Ameren market.
Wabash's witness, Dr. John Wilson, focuses on how the merged company
could strategically operate generation facilities so as to reduce ATC and
"crowd out" competitors. He looks specifically at cases where CSW increases
generation for export to AEP and AEP increases generation for export to CSW
in excess of the 250 MW along the integration path. Dr. Wilson presents
results for the AEP market assuming 500 MW and 1,850 MW transfers from CSW to
AEP. He reports a pre-merger market concentration of 1,723 HHI and
post-merger foreclosure-related increases of 83 and 316 HHI, respectively
using total capacity.(21) Dr. Wilson points out that, assuming Commonwealth
Edison's Northern Illinois nuclear plants are in service, a transfer of 700
MW from CSW to AEP is necessary to increase market concentration levels
beyond the thresholds specified in the Merger Policy Statement. In regard to
the CSW market, Dr. Wilson explains that the merged parties would have an
incentive to schedule otherwise uneconomic generation in order to increase
concentration and, thereby, the possibility that prices would rise after the
merger.(22) Dr. Wilson assumes a 500 MW transfer from AEP to CSW and reports
highly concentrated post-merger markets in the six time periods analyzed
(market concentration ranging from 1,967 to 4,919 HHI with
foreclosure-related increases ranging from 585 to 852 HHI).(23) Dr. Wilson
concludes that, because foreclosure-related increases in market concentration
exceed the thresholds in the Merger Policy Statement, the proposed merger
would extend the substantial market power AEP and CSW already have.
Enron states that the OASIS site maintained by AEP has significant
defects which inhibit competition. Enron alleges that AEP provides
preferential access to its transmission system by its affiliates. In support
of these allegations, Enron's witness, Dr. Richard Tabors, performs an
analysis of transmission service denials by AEP over a period of
approximately six months in
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(21) In these scenarios, Dr. Wilson assumes that 5,000 MW of Commonwealth
Edison's nuclear plants are out of service and explains that the transfers above
250 MW crowd out a corresponding amount of competing capacity in the AEP market.
Dr. Wilson explains that he uses total capacity in his analysis to model the
super peak period since all capacity is likely to meet the delivered price test
when market prices are the highest.
(22) Dr. Wilson defines the relevant product as short-term energy and performs a
delivered price test for the summer super peak, summer peak, two shoulder
periods, and two off-peak periods. Direct Testimony of Dr. John Wilson,
Corrected Exhibit No. AEG-53.
(23) Dr. Wilson also examines the case where ATC along the Ameren portion of the
transmission path connecting AEP and CSW is increased by 500 to 900 MW and
reports high levels of foreclosure-related increases in concentration.
<PAGE> 15
10
Docket No. EC98-40-000, et al.
1998. He reports, for example, that based on the number of records the average
acceptance rate for non-affiliated companies was 97.2 percent, as opposed to an
acceptance rate of 99.7 percent for AEP System Power Markets and 98.5 percent
for OVEC.(24) Dr. Tabors states that, due to the size and location of AEP's
transmission system, additional data (e.g., generator status) should be required
on the OASIS to offset the anticompetitive effects of the merger.
Applicants challenge Intervenors' analyses. They argue that by
considering cases where the merger increases the incentive for the merged
company to adversely affect prices and output, Dayton erroneously focuses on
AEP's pre-existing market power that, based on the Commission's determination
in PacifiCorp, has nothing to do with the merger.(25) Applicants also state
that, contrary to Dayton's claim, the Commission's standard of review is
whether changes in market concentration exceed the thresholds in the Merger
Policy Statement. Furthermore, Applicants assert that because CSW is not a
security coordinator, CSW cannot strategically manipulate the transmission
system. In regard to Wabash's concerns, Applicants argue that Dr. Wilson's
analysis hinges on the assumption that the merged company would violate its
binding merger agreement by reserving more than 250 MW. Applicants also
explain that additional transfers from AEP to CSW are unlikely because AEP
has better alternatives, and has not historically sold power to CSW.
Additionally, transfers from CSW to AEP are unlikely because CSW is capacity
deficient. Applicants further contend that the OASIS ATC postings, as
described in Order 889, eliminate any information advantage the merged
company may have regarding nonfirm ATC.
Applicants challenge Dayton's claims that AEP or CSW could foreclose
the Ameren market to competitors such as CP&L. They conclude that TVA
transmission capacity is clearly sufficient to accommodate the historical
level of CP&L sales into Ameren and obviously could not be foreclosed by
AEP. Finally, Applicants sponsor an additional witness, Dr. Robert Willig,
to respond to Dr. Fox-Penner's analysis of the vertical effects of the
proposed merger. Dr. Willig states that Dr. Fox-Penner's analysis should be
disregarded because it is not accompanied by an analysis of whether the
merged firm could profit from a foreclosure strategy.
Dr. Henderson challenges Dr. Tabors by analyzing transmission requests
and denials from the AEP and CSW OASIS sites for calendar year 1998. Based
on that analysis, he concludes that there was not a single instance of
preference granted to an AEP or CSW marketer or marketing affiliate. In
explaining denials of requests for transmission service, Dr. Henderson argues
that: (1) many of the refusals cited by Dr. Tabors were due to procedural
reasons because customers' request contained incorrect price information; (2)
multiple transmission service requests were submitted for the same service;
(3) customers sometimes requested transmission service on paths for which
zero ATC was indicated; and (4) affiliated marketers seldom make these types
of procedural errors. He points out that Dr. Tabor's analysis indicates that
on an absolute numerical basis, there is an insignificant difference in
results (i.e., a 97.2 percent acceptance rate for non-affiliated entities, as
opposed to 99.7 percent for AEP and 98.5 percent for OVEC). Dr. Henderson
states that, in any event, AEP's participation in a Commission-
- --------------
(24) AEP has 44 percent equity ownership in OVEC Power Marketing (OVEC).
(25) PacifiCorp, 87 FERC (Paragraph) 61,288 at 62,151 (1999) (PacifiCorp).
<PAGE> 16
11
Docket No. EC98-40-000, et al.
approved RTO will eliminate any concerns related to the manipulation of ATC and
the denial of transmission requests.
The Presiding Judge ruled that the merger will not give Applicants
vertical market power. He found that a combination of Applicants'
transmission systems would not create an ability or incentive to use
transmission to frustrate competition. He noted that AEP's commitment to join
an RTO eliminates the possibility of AEP providing preferential treatment to
its marketing affiliates. The Presiding Judge rejected Intervenors'
arguments that AEP should be required to join the Midwest ISO, because he
found that AEP's tie capacity with the Midwest ISO Participants is less than
its tie capacity with the Alliance Participants, and that AEP has even more
interconnected transfer capability with the ten transmission owners that have
not joined an RTO.(26)
Discussion
In Enova, the Commission addressed the possibility that a merger
involving jurisdictional public utilities raises vertical competitive
concerns. In that case and subsequent cases,(27) the Commission expressed
concern that combining firms with interests in relevant upstream input
markets that are used in the production of electricity in relevant downstream
markets can create or enhance the ability and/or incentive for the merged
firm to adversely affect prices or output in relevant markets. As stated in
Enova, the Commission's primary concern in a vertical merger is whether the
merger would adversely affect competition in downstream electricity markets
resulting from, among other possibilities, raising rivals' costs or
foreclosure. Such an adverse effect on competition could occur if upstream
and downstream relevant markets are not conducive to competitive outcomes (as
indicated by a highly concentrated market, i.e., HHI of 1,800 or above).(28)
While we articulated the above issues in Enova in the context of a
merger involving delivered gas in relevant upstream markets (i.e., delivered
gas is an input for the generation of electricity), we agree with Applicants
and Intervenors that it equally applies to mergers, such as this one, where
the input is transmission. We note that the parties to this proceeding have
based their analyses on the vertical framework set forth in Enova and the
Filing Requirements NOPR. These analyses address whether the merged company
could effectively foreclose competitors' access to transmission necessary to
compete in relevant downstream electricity markets, thereby resulting in
higher electricity prices.
We find that Dr. Henderson's analysis contains several shortcomings.
First, Dr. Henderson examines cases exclusively in which the merger would
create the incentive to adversely affect prices or output. He therefore
ignores those cases where the merger potentially
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(26) Initial Decision, 89 FERC at 65,032.
(27) See, e.g., Dominion Resources, Inc. and Consolidated Natural Gas Company,
89 FERC (Paragraph) 61,477 (1999) (Dominion).
(28) Enova, 79 FERC at 62,560-563.
<PAGE> 17
12
Docket No. EC98-40-000, et al.
enhances incentive. The merger may enhance such an incentive (e.g., by combining
Applicants' economic capacity) and, therefore, it merits evaluation. We disagree
with Applicants that examining the question of enhanced incentive equates to
evaluating pre-existing market power. An enhanced incentive increases the
likelihood that Applicants may engage in foreclosure to adversely affect prices
or output. Applicants' reliance on PacifiCorp is misplaced because that merger
did not raise any vertical competitive issues.
Second, also omitted by Dr. Henderson are those cases where the merger
creates or enhances the ability to adversely affect prices or output in
relevant markets. In his analysis, Dr. Henderson models foreclosure by
assuming that the merged company simply denies certain requests for
transmission service. He therefore overlooks a variety of possible ways, as
explained by Intervenors, in which the merger creates or enhances the ability
of the merged company to adversely affect prices or output through
foreclosure. Intervenors appropriately identify and evaluate several
possible mechanisms (e.g., strategic manipulation of transmission or
generation) by which the merged company could frustrate competitors' access
to transmission and how the merger creates or enhances the ability to use
those mechanisms to adversely affect electricity prices or output.
Third, as demonstrated by Intervenors, Dr. Henderson's assumptions
regarding which transactions could be prevented by AEP or CSW to foreclose
markets are highly restrictive. For example, Dr. Henderson focuses only on
transmission transactions involving buyers and sellers directly
interconnected with one or the other Applicants utilizing least-cost contract
paths involving AEP or CSW facilities. This approach overlooks the fact that
power does not always flow on least-cost contract paths and therefore that
other transactions could potentially be frustrated.
Finally, Dr. Henderson claims that the proposed merger will not impair
competition because differences in market concentration with and without
foreclosure do not exceed the thresholds specified in the Merger Policy
Statement. This claim is without merit. Such a statistic in the context of
a vertical merger does not impart useful information as to whether the merger
will adversely affect competition, as the Commission explained in
Dominion.(29) We note that the purpose of examining a pre- to post-merger
change in market concentration is to provide information on how market
structure changes after the merger, due to the merged company controlling
more resources than it did prior to the merger. A successful foreclosure
strategy does not require that the merged company control more generation
than it did before the merger. Instead, it requires that the merged company
be able to frustrate competitors' access to an input necessary for selling in
downstream electricity markets, thereby narrowing the scope of relevant
markets and increasing the concern that, in highly concentrated markets,
prices will rise after the merger. We note that Dr. Henderson's analysis, in
fact, shows highly concentrated relevant markets.
We therefore find that, as indicated by Intervenors' independent
analyses, Applicants' analysis provides an incomplete and inaccurate
evaluation of the potential vertical effect of the
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(29) 89 FERC at 61,480-82.
<PAGE> 18
13
Docket No. EC98-40-000, et al.
proposed merger, which likely understates such potential effect. Consequently,
we conclude that Applicants failed to show that the proposed merger will not
adversely affect competition as a result of combining their generation and
transmission. Accordingly, in order to find that the proposed merger will not
adversely affect competition as a result of combining transmission and
generation, we find it necessary to impose certain remedies and conditions, as
discussed in subsequent sections.
B. Remedies
1. RTO/ISO Formation
Applicants claim that the merger will not create the ability and
incentive for AEP and/or CSW to use transmission to frustrate competitors'
access to relevant markets. In any event, Applicants assert that their
commitment to join a Commission-approved RTO should eliminate any such
concerns.(30) Applicants argue that Intervenors want AEP to join the Midwest
ISO regardless of the merger, because the Midwest ISO Participants stand to
benefit financially by paying lower rates over AEP's transmission system.
In addition, Applicants argue that AEP should not be required to join
the Midwest ISO because: (1) actual transaction data for the past ten years
show that the volume of electricity transfers from AEP to the Midwest ISO
members is only one-third of the volume of transfers from AEP to the
remaining Alliance members; (2) AEP is more electrically integrated with the
remaining Alliance members than with the Midwest ISO as evidenced by its tie
capacity;(31) (3) the Commission has never required applicants to join a
particular ISO in a merger proceeding; (4) two of the biggest proponents of
AEP's participation in the Midwest ISO (Cinergy and Commonwealth Edison) have
withdrawn their opposition to the merger; and (5) Commonwealth Edison no
longer seeks AEP's participation in the Midwest ISO as a merger condition.
Moreover, Applicants argue that most of the parties simply rehash their
arguments about pancaked rates and boundary issues from the Alliance
proceeding in Docket No. ER99-3144-000.
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(30) On June 3, 1999, AEP together with several other transmission-owning public
utilities (Alliance Companies) filed, in Docket No. ER99-3144-000, an
application under section 203 of the FPA, 16 U.S.C. (Section) 824b (1994),
seeking an order approving: (1) the transfer of ownership of jurisdictional
transmission facilities owned by one or more of the Alliance Companies to
Alliance Transmission Company, LLC (Alliance Transco) and the transfer of
control over operations of jurisdictional transmission facilities owned by the
remaining Alliance Companies to the Alliance Transco; (2) the transfer of
control over operations of jurisdictional transmission facilities owned by the
Alliance Companies to the Alliance Independent Transmission System Operator,
Inc. (Alliance ISO); and (3) the transfer of control over operations of the
jurisdictional transmission facilities of the Alliance Companies from the
Alliance ISO to the Alliance Transco. The entire Alliance filing is referred to
as the Alliance Proposal. On December 20, 1999, we conditionally authorized the
application of Alliance Companies to transfer ownership and/or functional
control of their jurisdictional transmission facilities to Alliance. We directed
the Alliance Companies to modify their proposal in a compliance filing. 89 FERC
at 61,929. Alliance Companies requested rehearing on January 19, 2000 and made a
compliance filing on February 17, 2000.
(31) Applicants explain that Intervenors overstate AEP's tie capacity with the
Midwest ISO because they incorrectly assume that Allegheny Power System
(Allegheny) is part of the Midwest ISO.
<PAGE> 19
14
Docket No. EC98-40-000, et al.
Many Intervenors argue that Applicants' commitment to join the Alliance
Proposal is not an effective mitigation measure because: (1) Applicants will
be free to control, until an RTO is operational, an extremely large,
strategically located transmission network to advance their own competitive
position and foreclose competition; and (2) Applicants retain the right to
withdraw from the Alliance Proposal without Commission approval.
Some Intervenors claim that AEP's participation in the Alliance
Proposal will enhance AEP's market power instead of mitigating it for the
following reasons: (1) the Alliance Proposal would not form a rational
boundary, since it divides the Midwest market and creates market barriers
between low cost suppliers in the Midwest ISO and other high cost suppliers;
(2) the Alliance Proposal will preserve pancaked rates; and (3) the Alliance
transmission owners retain control of key decisions affecting competition,
such as the ability to block grid expansion, ATC and Capacity Benefit Margin
(CBM) calculations.
Several Intervenors assert that if AEP joins the Midwest ISO rather
than the Alliance Proposal, it will serve as an effective mitigation measure
because: (1) the Midwest ISO transmission systems are located between the
AEP and CSW systems; (2) AEP is more electrically integrated with the Midwest
ISO than the Alliance Proposal; (3) any transactions between the AEP and CSW
systems will flow through the Midwest ISO systems permitting effective
congestion management solutions; (4) it will result in improved coordination
for many AEP generation and transmission facilities that are jointly owned
with a Midwest ISO member; (5) reliability issues such as ATC calculation,
loop flow, congestion management and transmission planning can be dealt with
more effectively; and (6) the Midwest ISO will be operational by June 1,
2001, whereas it is uncertain when the Alliance Proposal will be operational.
With regard to Applicants' commitment to transfer AEP West transmission
facilities to a Commission-approved RTO in the region, certain Intervenors
argue that there is no guarantee that AEP West will ever join an RTO, since
the May 24 Stipulation only requires AEP West to apply for such transfer and
does not require AEP West to take further steps to join and remain in an
RTO. Therefore, Intervenors allege that the May 24 Stipulation may simply
turn out to be an empty promise.
Trial Staff believes that the May 24 Stipulation eliminates any
potential for the merged company to exercise vertical market power because
Applicants have committed to transfer control of the: (1) AEP East
transmission facilities to a Commission-approved RTO in the region; and (2)
AEP West transmission facilities in SPP to a Commission-approved RTO in the
region.
The Presiding Judge ruled that AEP's commitment to join the Alliance
Proposal removes any concerns that AEP will be able to use transmission to
frustrate competition or favor marketing affiliates. The Presiding Judge
dismissed the Intervenors' concerns that the Applicants will renege on their
commitments to join a Commission-approved RTO. As described above, the
<PAGE> 20
15
Docket No. EC98-40-000, et al.
Presiding Judge also rejected Intervenors' arguments that AEP should be required
to join the Midwest ISO.(32)
Discussion
Given the competitive concerns identified above, we will condition our
approval of the proposed merger upon the adoption of adequate mitigation
measures.(33) The Merger Policy Statement identifies various ways in which an
identified market power concern can be remedied.(34)
We conclude that an adequate remedy to the market power concerns
arising from the proposed merger would be for Applicants to transfer
operational control of their transmission facilities to a Commission-approved
RTO. We note that Applicants have committed to transfer operational control
of: (a) AEP East's transmission facilities to a Commission-approved RTO that
is directly interconnected with AEP East,(35) and (b) AEP West's transmission
facilities to a Commission-approved RTO that is directly interconnected with
AEP West,(36) but have not committed to do so before the merger is
consummated. However, the Merger Policy Statement requires that mitigation
must be fully effective in remedying an identified market power problem and
in place at the time of consummation. Merger Policy Statement at 30,136.(37)
We therefore agree with many of the Intervenors that there is a need
for interim mitigation measures. We are concerned that Applicants would be
able to use their combined transmission and generation to frustrate
competition. We will condition our merger approval on AEP East and AEP West
transferring operational control of their transmission facilities to a
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(32) Initial Decision, 89 FERC at 65,032.
(33) Applicants have made further commitments as described in the May 24
Stipulation, including transferring control area responsibility to a
Commission-approved RTO. We will hold Applicants to those commitments.
(34) Merger Policy Statement at 30,137.
(35) We observe that Applicants' commitment requires them to join either a
Commission-approved RTO or the Midwest ISO. See, also, note 30.
(36) On December 30, 1999, SPP filed a proposal to be recognized as an ISO and
an RTO in Docket No. ER00-975-000 (SPP Proposal). CSW is a signatory to that
proposal.
(37) Applicants argue that in Ohio Edison Co., et al., 81 FERC (Paragraph)
61,110 (1997) (First Energy), the Commission approved the merger in reliance on
the applicants' commitment to join a Commission-approved ISO at some unspecified
time after the merger was consummated. Applicants' reliance on First Energy is
misplaced. In that case, we conditioned our approval of the merger on
modifications to applicants' proposed mitigation. Such mitigation was in place
at the time of merger consummation. As we have already explained on rehearing
of First Energy:
[O]ur explicit statement that we expected the merged company to engage
in a post-merger ISO process was a specifically identified step that
would serve not as a pre-merger condition but rather as a post-merger
backstop to address any uncertainties regarding an open and competitive
market post-merger and to ensure future coordination in the public
interest of jurisdictional facilities pursuant to Section 203. 85 FERC
(Paragraph) 61,203 at 61,845.
<PAGE> 21
16
Docket No. EC98-40-000, et al.
fully-functioning, Commission-approved RTO(s) by December 15, 2001, the date
specified in the RTO Final Rule for RTO formation.
We will further condition our merger approval on Applicants
implementing interim mitigation measures, consisting of two functions
outlined in the RTO Final Rule in the AEP East service territory upon
consummation of the merger. Those two functions relate to independent
calculation and posting of ATC and market monitoring. We believe that the
implementation of these two functions: (1) will address several concerns
raised by the Intervenors, such as manipulation of ATC and transmission
service denials; (2) can be performed by independent third parties; and (3)
can be implemented in a relatively short time frame. Moreover, these two
functions can be transferred to a Commission-approved RTO, when it becomes
operational.
With regard to independent calculation and posting of ATC, the RTO
Final Rule requires an RTO to calculate ATC values based on data developed
partially or totally by the RTO. In the RTO Final Rule, we further stated
that: "The [RTO] must be the single OASIS site administrator for all
transmission facilities under its control and independently calculate TTC and
ATC."(38) In addition, we stated that: "[W]e will allow an RTO the
flexibility to contract out OASIS responsibilities to another independent
entity . . . ."(39) Thus, consistent with the RTO Final Rule, AEP East can
implement this function by contracting out OASIS responsibilities to an
independent entity.
We believe that market monitoring by an independent party is also
needed upon consummation of the merger to protect against anticompetitive
effects in electricity markets until a fully functional RTO is available.(40)
Since market monitoring is evolving as trading markets are created, the
Commission did not prescribe a particular market monitoring plan or the
specific elements of such a plan in the RTO Final Rule. However, we note
that, under the May 24 Stipulation, Applicants have committed to provide
generation dispatch information necessary for the Midwest ISO to monitor the
effects of such dispatch on the loading of the Midwest ISO's constrained
transmission facilities. We will require AEP East to provide similar
generation dispatch information to an independent party in order to monitor
the effects of such dispatch on the loading of AEP East's constrained
transmission facilities. In addition, we will require AEP East to provide to
the independent party additional data, such as TLR events, details of binding
transmission constraints, any redispatch to relieve constraints, the
effectiveness of redispatch in relieving constraints, and volume and pricing
of energy before and after redispatch. We believe that such data are
necessary to determine whether operations or wholesale transactions involving
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(38) 18 C.F.R. (Section) 35.34(k)(5), new regulation promulgated by the RTO
Final Rule, FERC Stats. & Regs. (Paragraph) 31,089 (2000).
(39) RTO Final Rule at 31,145.
(40) We stated in the RTO Final Rule:
To ensure that the [RTO] provides reliable, efficient and not unduly
discriminatory transmission service, the [RTO] must provide for objective
monitoring of markets it operates or administers to identify market design
flaws, market power abuses and opportunities for efficiency improvements,
and propose appropriate actions. 18 C.F.R. (Section) 35.34(k)(6), new
regulation promulgated by the RTO Final Rule.
<PAGE> 22
17
Docket No. EC98-40-000, et al.
Applicants are unduly discriminatory or preferential or show evidence of the
exercise of market power. The independent party will analyze the data and
submit the analysis and the data to the Commission for review.
Accordingly, Applicants should notify the Commission within 15 days of the
date of this Opinion whether they agree to the condition that they transfer
operational control of their transmission facilities to a fully-functioning,
Commission-approved RTO by December 15, 2001 and to the condition requiring the
interim mitigation measures described above. In the event that Applicants
accept these conditions but subsequently do not comply with them, we will use
our authority under section 203(b) of the FPA to address any concerns, and order
further procedures as appropriate.(41) In addition, at least 60 days prior to
consummation of the merger, Applicants must make a compliance filing describing
their plan to implement independent calculation and posting of ATC for the AEP
East service territory and describing their market monitoring plan, which will
be effective upon consummation of the merger.
Should Applicants decline to accept these conditions, we will approve
the merger only on the condition that they transfer operational control of
their transmission facilities to a fully-functioning, Commission-approved
RTO prior to consummation of the merger. In this circumstance, the interim
mitigation measures described above would not be required.
2. Divestiture
Applicants claim that their proposal to divest 550 MW of generating
capacity (300 MW in SPP and 250 MW in ERCOT) over a two-year period after
merger consummation,(42) eliminates horizontal market power concerns raised by
the merger. Applicants intend to divest minority interests in certain
generating units totaling 550 MW, instead of divesting entire generating
plants. Applicants state that the ERCOT divestiture (250 MW) could begin
immediately (i.e., within 60 days of a Commission order approving the
merger). Applicants maintain that a two-year delay in the SPP divestiture is
necessary until their obligation to serve native load is reduced and in order
for Applicants to use the pooling of interests accounting method.(43)
Applicants also state that they will retain operational control of the
generating facilities.
Certain Intervenors object to Applicants' divestiture proposal, citing
the lack of a date certain for the divestitures. Intervenors argue that
Applicants' proposed delay of the SPP divestiture could be longer, since the
implementation of retail restructuring could take years and retail
competition may not result in a sufficient reduction in CSW's native load
responsibility.
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(41) See, e.g., Louisville Gas and Electric Company, et al., 82 FERC (Paragraph)
61,308 at 62,222-3.
(42) Applicants also state that, pursuant to a settlement with the Texas
Commission, they have agreed to divest an additional 1354 MW of capacity in
ERCOT. Applicants further state that the timing of this divestiture is
dependent on certain accounting issues.
(43) Applicants have sought guidance from the Securities and Exchange Commission
(SEC) as to when divestiture of capacity may be made without violating the
pooling rules. Applicants filed a motion on December 28, 1999, requesting that
we take official notice of the guidance sought and the SEC's request for
additional information.
<PAGE> 23
18
Docket No. EC98-40-000, et al.
Certain Intervenors also argue that the divestitures are ineffective to mitigate
market power, because the purchasers will not gain operational control of the
generating plants, and will only have the right to have the units dispatched up
to their ownership interests. Furthermore, Intervenors object to Applicants'
proposal to restrict the capacity sales to only purchasers that will not cause
an increase in HHI levels above the thresholds. Intervenors claim that this
restriction will preclude CSW's actual competitors from purchasing the divested
capacity.
Certain Intervenors request that the Commission: require divestiture
before merger consummation; require divestiture of entire plants; and require
Applicants to negotiate a swap of shares in jointly-owned generating plants.
Intervenors take the position that the merged company and its affiliates
should be precluded from acquiring or constructing generation assets in SPP
for a number of years.
Certain state commissions(44) oppose Intervenors' recommendations on the
grounds that such recommendations ignore Applicants' obligation to serve
native load at the lowest reasonable rate.
Applicants respond to Intervenors' objection to Applicants retaining
operational control of the partially divested generating facilities by
committing to enter into operation and maintenance agreements (O&M
Agreements) with the purchasers of the generating capacity. Applicants also
claim that they will not gain a competitive advantage by retaining
operational control of the units to be partially divested, since Applicants
have committed that planned maintenance outages will be scheduled by mutual
agreement between Applicants and the purchasers.
Trial Staff maintains that the 550 MW divestiture agreed to in the May
24 Stipulation resolves all concerns regarding horizontal market power.
However, Trial Staff argues for immediate divestiture, claiming that
Applicants have not shown that immediate divestiture invalidates the pooling
of interests accounting method. Trial Staff also notes that the May 24
Stipulation provides for a buy-back clause allowing AEP West to purchase
power required for native load. Therefore, Trial Staff concludes that
delaying the divestitures is unnecessary, and is inconsistent with the Merger
Policy Statement that "[f]ull and effective mitigation must be in place at
the time the merger is consummated."(45)
The Presiding Judge determined that Applicants' commitment to divest
550 MW of generating capacity as soon as feasible, and their commitment to
sell equivalent amounts of energy in the interim, eliminates any potential
horizontal market power caused by the merger.
Discussion
Applicants admit that they will retain operational control of the
partially divested plants. Applicants' witness Steven B. Jones testifies
that CSW will maintain operational control of the
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(44) The state commissions are Louisiana, Arkansas and Oklahoma.
(45) Merger Policy Statement at 30,136.
<PAGE> 24
19
Docket No. EC98-40-000, et al.
Northeastern and Frontera plants.(46) Applicants propose to enter into operation
and maintenance agreements (O&M Agreements) and other agreements regarding the
timing of planned maintenance, which they claim should be sufficient to address
Intervenors' concerns. In support of this claim, Applicants note that joint
operating agreements and O&M Agreements are common in the electric utility
industry. However, Applicants' argument is misplaced, because this is not a
section 205 proceeding to establish just and reasonable terms and conditions for
a joint operating agreement. Rather, this is a proposed merger in which
Applicants' own analysis demonstrates that they have exceeded the thresholds
adopted in the Merger Policy Statement. Furthermore, in light of Applicants'
admission that they will retain operational control, we find that divesting up
to a 50 percent share in certain generating units is not an effective remedy.
Since Applicants will retain control over the divested output, there is the
potential for Applicants to gain a competitive advantage, regardless of whether
they enter into O&M and other agreements.
In Allegheny,(47) the Commission expressed concern over the ability of
the merged company to control the output of divested generating capacity and
thus be in a position to withhold the output from the market and affect
electricity prices. While the proposed remedy in Allegheny involved
short-term sales and the instant proceeding involves divestiture of partial
ownership interests in generating units, the Commission's primary concern
remains the same: Applicants have retained operational control over the
output of the generating capacity. By retaining operational control of the
generating facilities, Applicants will have the ability to withhold capacity
from the market and thus affect electricity prices. The transfer of
ownership and, in turn, control of an entire generating plant to a market
participant other than the merged company, would ensure that the merged
company could not retain control of the output. Consequently, we will
require Applicants to divest their entire ownership interest in the
generating facilities that are to be divested. We note that divestiture of
Applicants' entire ownership interest provides the maximum assurance that
control has been transferred to a third party. Alternatively, Applicants may
choose to divest the same or greater amount of capacity from different
generating plants in their entirety, however, such generating plants must be
of similar cost, operation, and location characteristics as the generating
plants Applicants originally proposed.
Regarding the timing of the SPP and ERCOT capacity divestitures, we agree
with Applicants that the ERCOT capacity can be divested immediately upon
consummation of the merger.(48) We also find Applicants' arguments for delaying
the SPP capacity divestiture for a minimum of two years persuasive, given the
interim measures described below. We recognize the importance of Applicants'
obligation to reliably serve native load and therefore we will
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(46) Exhibit No. AC-600 at 5 and 11. See also Tr. at 1147-9, 1242, 1271 and
1338.
(47) Allegheny Energy, Inc. and DQE, Inc., 84 FERC (Paragraph) 61,223 (1998)
(Allegheny).
(48) Applicants commit to commence the divestiture process within 60 days after
the Commission issues an order approving the merger. We will hold Applicants to
this commitment and require Applicants to complete the ERCOT divestiture within
one year of the issuance of this Opinion.
<PAGE> 25
20
Docket No. EC98-40-000, et al.
permit Applicants to delay the SPP divestiture as they have proposed. We
will require Applicants to complete the SPP divestiture by July 1, 2002.(49)
With respect to Applicants' proposal that the divested generating
capacity not be sold in a way that would cause changes in market
concentration to exceed acceptable thresholds, we find such condition to be
reasonable since it preserves competition and we will accept it.
4. Interim Sales
Recognizing the requirement that appropriate mitigation be in place
upon consummation of the merger, and that the proposed divestitures would not
be completed in time to meet this requirement, Applicants propose to make
interim sales equivalent to the capacity to be divested. These sales would
continue until each divestiture is completed.(50)
ERCOT Interim Sale
In ERCOT, Applicants propose an interim unit sale from the Frontera
plant of 250 MW of capacity and associated energy at the plant's operating
cost which is expected to be $17/MWh.(51) The Frontera Plant is being built as
a merchant plant and thus is not intended to serve Applicants' native load.
Accordingly, Applicants do not propose to retain recall rights to this
capacity and associated energy. Applicants argue that the ERCOT interim sale
will be fully subscribed because the expected price is economic in all time
periods.(52) Accordingly, Applicants contend that the ERCOT interim sale will
constitute effective mitigation of market power in ERCOT. Intervenors have
not opposed this interim measure.
SPP Interim Sales
In SPP, Applicants propose an interim system sale of energy equivalent
to a total of 300 MW per hour on a "financially firm" basis.(53) Applicants
will make the interim sale pursuant to
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(49) Oklahoma has set a statutory goal of full consumer choice by July 1, 2002.
Applicants note that the Oklahoma Legislature may relieve incumbent utilities of
their public service obligations as of July 1, 2002 in which case divestiture
could occur on or about that date.
(50) Applicants indicate that the interim sale in ERCOT will commence upon
consummation of the merger and the interim sale in SPP will commence three
months later following an auction process that will begin upon consummation of
the merger. Direct Testimony of Stephen B. Jones, Exhibit No. AC-600 at 8-13.
(51) While Applicants style this interim ERCOT sale as a sale of both capacity
and associated energy, there does not appear to be a separate capacity charge
associated with the sale.
(52) Direct Testimony of William H. Hieronymus, Exhibit No. AC-500 at 35.
(53) Applicants define "financially firm" to mean that if Applicants are forced
to recall this energy they will compensate the purchaser for the purchaser's
replacement cost. Tr. 1267, lines 1-5. The replacement cost will be either the
price the purchaser pays to replace the recalled energy or, if the purchaser is
unable to secure replacement energy, the market price as determined by
"[w]hatever market indicia exists at the time; there will probably be plenty of
them." Tr. 1268 lines 21-22 (Testimony of Stephen B. Jones).
<PAGE> 26
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Docket No. EC98-40-000, et al.
contracts to be sold via auction. The amount of energy sold through each
contract will be no less than the equivalent of 50 MW per hour and no more than
the equivalent of 150 MW per hour.(54) These contracts will provide for an
energy price of $14/MWh.(55) As with the ERCOT interim sale, Applicants contend
that these sales will be fully subscribed since the energy price is well below
the market price.(56) In contrast with their ERCOT proposal, Applicants propose
to retain the right to recall all or a portion of this energy during generation
emergencies where their SPP operating companies (PSO and SWEPCO) would otherwise
be unable to meet their native load. Of particular significance, this recall
provision cannot be triggered unless Applicants are also completely unable to
make purchases from third parties sufficient to meet their native load.(57) In
that case, Applicants will compensate the purchaser for the purchaser's
replacement cost.
Intervenors object to the interim sale of 300 MW in the SPP pending the
divestitures as ineffective mitigation because CSW retains control of the
capacity to satisfy SPP rules on reserve requirements, the sales are not
firm, and the purchased power cannot be designated as the purchaser's network
resource or used by the purchaser to meet SPP reserve requirements. In
addition, Intervenors argue that Applicants' proposal to restrict the sales
to purchasers that will not cause an increase in HHI levels above the
Appendix A thresholds, may disqualify CSW's actual competitors from
purchasing the capacity. Furthermore, Intervenors maintain that purchasers
of this nonfirm energy will not be able to compete with CSW due to CSW's
recall right. Intervenors contend that when Applicants are unable to
purchase replacement energy at any price, the interim purchaser will not be
able to make such purchases either. Accordingly, Intervenors question
Applicants' assertion that some appropriate market indicia will always exist
to determine the appropriate replacement cost of energy which is not
available on the market. Therefore, Intervenors claim that the proposed
pricing method will fail to properly discipline Applicants' use of the recall
right.
Discussion
We find that sales in the SPP and ERCOT, if they are governed by terms
and conditions that would effectively eliminate the merged company's ability
to withhold output, would be reasonable and effective interim mitigation
measures in this particular case until completion of the ERCOT and SPP
divestitures. Since Applicants have not provided us with such terms and
conditions, we will require them to do so as discussed below. In this
regard, we recognize Applicants' need to meet their SPP reserve requirements
and native load obligations.
With regard to timing, while Applicants' proposal to begin the ERCOT
interim sale at the time the merger is consummated is acceptable, Applicants'
proposal to begin the SPP interim sale
- ------------------
(54) Thus the interim sale energy will be divided among at least two purchasers.
Furthermore, as with the permanent divestiture proposals, only entities who will
not cause Appendix A screen violations will be allowed to purchase this energy.
(55) Direct Testimony of Stephen B. Jones, Exhibit No. AC-600 at 8.
(56) Rebuttal Testimony of Stephen B. Jones, Exhibit No. AC-601 at 10-11.
(57) Tr. 1265-1267 (Testimony of Stephen B. Jones).
<PAGE> 27
22
Docket No. EC98-40-000, et al.
three months after consummation of the merger is not. Interim mitigation for
identified market power problems must be in place and effective upon
consummation of the merger. We will therefore require Applicants' proposed
interim measures to be in effect when the merger is consummated.
With respect to the requirement that this energy not be sold in a way
that would cause changes in market concentration to exceed acceptable
thresholds, we find such condition to be reasonable since it preserves
competition and we will accept it.
With respect to Intervenors' concerns regarding the "market indicia"
and the terms and conditions of the contracts under which the interim sales
will be made, we will direct Applicants to file with the Commission prior to
consummation of the merger their proposed terms and conditions of the interim
sales contracts that would effectively eliminate the merged company's ability
to withhold output. These filings should contain the terms and conditions of
the sales contracts, including substantive information about the "market
indicia" that will be used to determine replacement cost when the interim
purchaser is unable to purchase replacement energy during a recall event.
IV. Effect on Rates
Ratepayer Protection Measures
Applicants assert that their proposed ratepayer commitments are
sufficient to protect wholesale customers against the potential adverse
effects of the merger on rates. Applicants state that their hold harmless
commitment provides that in any section 205 or 206 proceeding that develops
rates using a test year that begins within five years after merger
consummation, Applicants will bear the burden of proof that any
merger-related costs included in the proposed rates are offset by merger
savings. Applicants state that this hold harmless commitment will apply to
transmission customers and all wholesale customers except those served under
fixed-rate contracts.
Applicants state that their open season proposal provides the option
for transmission customers to switch to Applicants' Joint OATT and for
requirements customers served under cost-of-service rates to terminate their
existing contracts if Applicants file a rate increase that uses a test year
that begins within five years of merger consummation. For requirements and
transmission customers under formula rates, Applicants commit to cap the
generation demand charges and freeze the transmission demand charges at 1998
levels through the end of 2002. Furthermore, Applicants offer to allow
requirements customers under formula rates to make a one-time election to fix
the generation demand charges for the period 2000 through 2003 at the levels
that Applicants projected before the merger was proposed. Applicants assert
that they have reached settlements with all their formula rate customers, and
note that these customers have withdrawn from the proceeding.
<PAGE> 28
23
Docket No. EC98-40-000, et al.
Applicants also assert that only two of the customers remaining in the
proceeding have expressed concern about Applicants' recovery of stranded
costs, and the stranded costs associated with the termination of these
customers' contracts are unrelated to the merger.(58)
Wabash and Lafayette assert that the hold harmless provision is
worthless, because the protection is nothing more than reasonable ratemaking
methodology. Wabash and Lafayette argue that more concrete protections are
required, including an open season in which Wabash can elect to terminate its
contract without being exposed to stranded costs. Certain Intervenors object
to Applicants' use of estimates for merger-related costs and savings, noting
that the estimates Applicants rely on were stricken from the record.
APPA/NRECA argue that the open season proposal is essentially a choice
between paying higher rates or paying stranded costs, and therefore offers no
protection to the ratepayer.
Trial Staff contends that Applicants' proposed ratepayer protections
are limited, ineffective and unenforceable. Trial Staff argues that the open
season provision is ineffective ratepayer protection because of the potential
for stranded costs. Trial Staff contends that the existence of stranded
costs could create a barrier to entry into the competitive market place.
Trial Staff therefore proposes that wholesale customers who exercise their
option to terminate early under the open season proposal, or whose contracts
terminate, not be subject to stranded cost claims by Applicants.
Trial Staff argues that the hold harmless provision is not enforceable
because Applicants intend to rely on estimates of merger costs and savings
and have not made any commitment to track or calculate merger costs or
savings prior to filing for a rate increase. Trial Staff therefore proposes
that Applicants be required to file annual reports showing that merger
savings are equal to or greater than merger costs.
The Presiding Judge found Applicants' ratepayer protection proposal
adequate to protect wholesale requirements and transmission customers from
any adverse rate consequences of the merger.(59) The Presiding Judge was
unpersuaded by Intervenors' and Trial Staff's stranded cost argument, noting
that the Commission has repeatedly held that stranded costs arguments in
merger proceedings are premature and should be made in separate proceedings
when the stranded cost claim is made. He further noted that the Commission
has not required a stranded cost waiver in any merger case to protect
customers from merger-related costs.(60) The Presiding Judge noted that
Applicants have negotiated ratepayer protection measures with all but two of
their customers. The Presiding Judge also rejected all of Trial Staff's
arguments concerning the
- --------------
(58) Cities of Dowagiac and Sturgis, Michigan. According to Applicants, Sturgis
gave notice to terminate wholesale service more than one year before the merger
was announced, and Dowagiac's concern is with retail stranded costs that
Applicants may seek to recover if Dowagiac acquires any of Applicants' existing
retail customers.
(59) Initial Decision, 89 FERC at 65,032-33.
(60) Id. at 65,033.
<PAGE> 29
24
Docket No. EC98-40-000, et al.
insufficiency of the ratepayer protection measures, including the need for an
annual filing documenting merger costs and benefits.(61)
Trial Staff excepts to the Presiding Judge's failure to consider Trial
Staff's proposal in its entirety. Trial Staff claims that the Presiding
Judge misstated Trial Staff's position on stranded costs and failed to
recognize that customers will not take advantage of the open season proposal
if they are subjected to unspecified stranded cost claims. Trial Staff's
position, therefore, is that such customers not be subject to stranded cost
claims or, alternatively, that they be provided some additional protection.
Trial Staff maintains that the Presiding Judge erred in relying on other
merger cases where the Commission has not required stranded cost waivers to
protect customers, because in those cases, sufficient and effective ratepayer
protection mechanisms were offered.
Discussion
In the Merger Policy Statement, we explained that our primary focus
regarding the effects of a merger on rates is ratepayer protection. The
Merger Policy Statement also describes various commitments that may be an
acceptable means of protecting ratepayers in particular cases, such as hold
harmless provisions, open seasons for wholesale customers, rate freezes,
and/or rate reductions.(62) In this case, Applicants have offered several
ratepayer protection commitments. With one minor modification, we find
Applicants' ratepayer protection measures adequate to protect wholesale
customers from potential adverse effects of the proposed merger on rates.
In the Merger Policy Statement, the Commission stated that the most
meaningful ratepayer protection mechanism is an open season provision.(63)
Applicants' ratepayer protection includes an open season for wholesale
requirements customers served under cost-of-service rates.(64) Trial Staff
argues that the open season provision is ineffective because of Applicants'
right to seek recovery of stranded costs. We disagree. The Commission has
previously held that no condition addressing the recovery of stranded costs
should be placed on approval of a merger, and that any claims for stranded
cost recovery should be addressed in a separate proceeding.(65)
As an alternative to restricting stranded cost claims, Trial Staff
argues that there is a need for additional ratepayer protection because
Applicants' hold harmless commitment is limited and unenforceable. We
disagree and find additional protection to be unnecessary. Applicants' hold
harmless commitment is similar to those hold harmless commitments accepted by
the
- ---------------
(61) Id. at 65,032-37.
(62) Merger Policy Statement at 30,123-24.
(63) Id.
(64) We note that Applicants have offered an open season to transmission
customers in which they can switch to Applicants' Joint OATT.
(65) WPS Resources Corporation, et al., 83 FERC (Paragraph) 61,196 at 61,840
(1998).
<PAGE> 30
Docket No. EC98-40-000, et al. 25
Commission in other merger cases.(66) While Applicants' approach relies on
estimates of merger costs and merger savings, we believe that their approach
is enforceable. We note that Applicants have the burden of proof in any
section 205 or 206 proceeding to demonstrate the reasonableness of the cost
and savings estimates. Furthermore, in the Merger Policy Statement the
Commission stated that, rather than requiring estimates of merger benefits,
and addressing whether the applicant has adequately substantiated those
benefits, we will focus on ratepayer protection.(67) Although the proposed
hold harmless commitment does not require that any of the projected merger
savings be reflected in reduced rates, wholesale customers have the option to
file a section 206 complaint seeking a reduction in rates.
Applicants have also committed to cap the generation demand charges and
to freeze the transmission demand charges at 1998 levels through the end of
2002, i.e., for 30-month period after the merger closing date, assuming the
merger closes in the Spring of 2000. Since the closing date of the merger
may shift, we will modify the period of Applicants' commitment to be the
30-month period following the actual merger closing date.
Furthermore, in the Merger Policy Statement, the Commission stated that
the most promising and expeditious means of addressing ratepayer protection
is for the parties to negotiate an agreement on ratepayer protection
mechanisms.(68) We note that Applicants have negotiated ratepayer protection
measures with almost all of their customers.
Accordingly, we affirm the Presiding Judge's finding that Applicants'
proposed ratepayer protection, as modified here, is sufficient.
V. Other Requested Remedies and Conditions
Certain arguments raised by Intervenors are not relevant to our
determination of the issues in this case and are beyond the scope of this
proceeding. Several parties propose alternative conditions and remedies if
the Commission does not impose the condition or remedy they consider to be
the most effective. For example, if the Commission does not order complete
divestiture, certain Intervenors recommend that the merged entity be required
to sell all of its generation output to a power exchange and purchase the
power needed to serve its load for a minimum five-year period. They also
recommend that the merged entity be precluded from acquiring new generation
capacity for a ten-year period. APPA/NRECA argue for a two-year moratorium
on large mergers.
These proposals, and any others not expressly addressed above, will be
denied as unwarranted based on the record of this case.
- ---------------
(66) Sierra Pacific Power Co., et al., 87 FERC T 61,077 (1999); Public Service
Company of Colorado, et al., 78 FERC (Paragraph) 61,267 (1997).
(67) Merger Policy Statement at 30,123.
(68) Id.
<PAGE> 31
Docket No. EC98-40-000, et al. 26
VI. Rate Schedule Issues
As noted earlier, we set for hearing all issues concerning the three
rate schedules and the Joint OATT that Applicants filed at the time they
filed the proposed merger. Applicants filed in Docket No. ER98-2770-000:
(1) a System Integration Agreement (SIA) governing the distribution of power
supply costs and benefits between AEP West and AEP East after the merger is
consummated; (2) a System Transmission Integration Agreement (STIA) governing
the coordinated planning, operation, and maintenance of the transmission
facilities of the AEP and CSW operating companies after the merger is
consummated; and (3) a Transmission Reassignment Tariff (TRT) governing the
rates, terms, and conditions under which AEPSC can sell, assign, and transfer
transmission capacity. In Docket No. ER98-2786-000, the Applicants filed a
Joint OATT and Standards of Conduct, under which the merged system will offer
transmission services.
A. The SIA, STIA and TRT
Pursuant to the July 13 Stipulation, Applicants and Trial Staff
resolved all but one of their differences regarding both rate and non-rate
terms and conditions of the SIA, STIA, and TRT. Applicants and Trial Staff
agreed to reserve the remaining issue for decision by the Commission. The
Presiding Judge approved the SIA, STIA, and TRT as modified by the July 13
Stipulation and, consistent with the terms of the stipulation, did not
address the reserved issue. No parties filed exceptions to this finding.
The Reserved Issue
The SIA, filed in Docket No. ER98-2770-000, governs, among other
things, the allocation of power supply costs and benefits between the two
zones of the merged company. The SIA provides for economic transfers between
the zones, but the price varies depending upon whether the energy transfers
are within or exceed firm transmission entitlements between the zones.
Transfers within the firm transmission entitlements are priced at the lower
of: (1) the recipient zone's decremental cost or (2) half of the sum of
supplier zone's out-of-pocket cost and the recipient zone's decremental
cost.(69) Transfers above the firm transmission entitlements between zones are
priced at half the sum of: (1) the supplier zone's out-of-pocket cost,
including all incremental transmission costs; and (2) the recipient zone's
decremental cost.
Trial Staff characterizes this as a split-the-savings price methodology
under which the seller could receive up to 100 percent of the savings. Trial
Staff argues that Commission policy does not permit the seller to receive
more than 50 percent of the savings in a shared savings transaction.(70)
Applicants answer that this proposal is not a ratemaking issue subject to the
- ------------------
(69) The recipient zone's decremental cost (also known as buyer's decremental
cost or BDC) equals the cost of the next unit of generation that the buyer is
able to refrain from dispatching due to the economy energy transaction.
Applicants define the supplier's out-of-pocket cost to be the opportunity cost
of foregone revenues from power sales to third parties.
(70) Trial Staff cites Montaup Electric Co. and Newport Electric Corp., 59 FERC
(Paragraph) 61,198 (1992) (Montaup). Under this methodology, a split-the-savings
rate would be set midway between the seller's incremental cost (SIC) and the
BDC. The SIC equals the cost of the last increment of generation used to provide
the economy energy.
<PAGE> 32
Docket No. EC98-40-000, et al. 27
Commission's split-the-savings methodology because it involves a merger.(71)
Instead, Applicants argue, this proposal represents an internal cost allocation
issue resulting from the proposed merger. Applicants assert that unless they are
permitted to take into account the opportunity cost of these economy energy
transactions (i.e., substituting lost revenues for SIC when calculating the
split-the-savings rate), cost shifts will occur between the zones thus violating
the goal of holding existing ratepayers harmless.(72)
We agree with Applicants that the Commission's historic formula for
split-savings rates are not dispositive, because the issue presented here is
the reasonableness of the inter-affiliate cost allocation method employed
when there are energy transactions as the result of joint dispatch. As we
understand it, Applicants' proposal is attempting to satisfy two principles.
The first principle is that an equal sharing of the benefits is a reasonable
approach for pricing inter-affiliate sales. The second principle is that, as
a means of maintaining the hold harmless commitments Applicants have made to
existing customers, there should be some assurance that the selling company
receives no less than it would have received if it had sold power on the
market instead of providing it to the affiliate company. However, these two
principles are incompatible in most circumstances, i.e., in some
circumstances, a split savings rate will be higher than the market rate and,
in other circumstances, the market rate will be higher than the split savings
rate. Also, as noted by Trial Staff, the particular formula proposed by
Applicants is defective because, in some instances, it results in a rate that
exceeds both the market price and a rate set halfway between the seller's
out-of-pocket costs and the buyer's avoided cost.
We shall direct Applicants to amend the pricing formula to adopt the
rate that the seller could have charged if it could have sold the power
elsewhere. This will satisfy the principle of holding the selling company
harmless, but will not result in a price above market for the buying
company. As a default to be used in the unlikely event that there are hours
when there are no alternative selling options, the parties may use a
split-savings rate that is set halfway between the selling party's
incremental costs (defined as the actual out-of-pocket variable costs
incurred to provide the energy) and the buying party's decremental costs
(defined as the actual out-of-pocket variable costs that the buyer avoided as
a result of the purchase). These definitions of incremental and decremental
cost are consistent with those that the parties have traditionally included
in their coordination sales agreements which are priced on the basis of
out-of-pocket costs.
We find that the SIA, STIA, and TRT, as modified by both the July 13
Stipulation and our determination above, are just and reasonable.
B. The Joint OATT And Standards of Conduct
- -----------------
Accordingly, the SIC associated with a given sale should always be lower than
the out-of-pocket cost (lost revenues) associated with the same sale.
(71) Applicants do not dispute that the proposed methodology can lead to one
zone retaining more than 50 percent of the savings.
(72) Applicants' Brief Opposing Exceptions at 98.
<PAGE> 33
Docket No. EC98-40-000, et al. 28
Prior to issuance of the Hearing Order, Applicants asked the Commission to
approve only their cost-of-service treatments and rate design principles for
transmission and ancillary services rates. Applicants then planned to file
updated test period data to develop the actual rate levels to be effective when
the merger is consummated. In accordance with Applicants' proposal, the Hearing
Order set for hearing the cost-of-service treatments and rate design principles,
but not the specific rate levels.(73) Later, with the May 24 Stipulation,
Applicants adopted stipulated rates to be effective upon consummation of the
merger and abandoned further efforts to gain approval, in this proceeding, of
their proposed cost-of-service treatments and rate design principles.
Accordingly, in any subsequent rate proceeding, Applicants will need to fully
support their proposed cost-of-service treatments and rate design principles.
The May 24 Stipulation resolved all issues between Trial Staff and Applicants
regarding the Joint OATT.
While the Presiding Judge found that the proposed transmission and
ancillary services rates contained in the May 24 Stipulation are just and
reasonable, he nevertheless ruled on certain cost-of-service treatment and
rate design issues which were rendered moot by the May 24 Stipulation. Trial
Staff, Applicants, and the remaining parties all urge the Commission to
vacate these findings in light of the May 24 Stipulation. Additionally, no
remaining party has objected to the stipulated rate levels nor to the
non-rate terms of the Joint OATT.
We affirm the Presiding Judge's approval of the stipulated rates
contained in the May 24 Stipulation and of the Joint OATT, and vacate the
Presiding Judge's rulings regarding cost-of-service treatment and rate design
principles. We also approve the proposed Standards of Conduct.
The Commission orders:
(A) Applicants' proposed merger is hereby approved, as conditioned in the
body of this Opinion.
(B) Applicants are hereby directed to notify the Commission within 15 days
of the date of this Opinion whether they accept the condition that they transfer
operational control of their transmission facilities to a fully-functioning,
Commission-approved RTO by December 15, 200l and the condition requiring the
interim mitigation measures, as discussed in the body of this Opinion. If the
Applicants accept these conditions, the Applicants must make a compliance filing
at least 60 days before consummation of the merger describing their plan to
implement the interim mitigation measures.
(C) Applicants' commitments are hereby accepted as modified and discussed
in the body of this Opinion.
(D) Applicants shall promptly notify the Commission when the proposed
merger is consummated.
- --------------
(73) Hearing Order, 85 FERC at 61,825.
<PAGE> 34
Docket No. EC98-40-000, et al. 29
(E) The foregoing authorization is made without prejudice to the
authority of the Commission or any other regulatory body with respect to
rates, service, accounts, valuation, estimates, determinations of cost, or
any other matter whatsoever now pending or which may come before the
Commission.
(F) The Commission retains authority under section 203(b) of the FPA
to issue supplemental orders, as appropriate.
(G) The Presiding Judge's approval of the stipulated rates contained
in the May 24 Stipulation and of the Joint OATT is hereby affirmed as
discussed in the body of this Opinion.
(H) The Presiding Judge's rulings regarding cost-of-service treatment
and rate design principles related to the Joint OATT are hereby vacated as
discussed in the body of this Opinion.
(I) Applicants' proposed SIA, STIA, and TRT in Docket No.
ER98-2770-000 and the proposed Standards of Conduct in Docket No.
ER98-2786-000 are approved as discussed in the body of this Opinion, to be
effective upon consummation of the merger.
(J) Wabash and Lafayette's motion is hereby denied as moot, as
discussed in the body of this Opinion.
(K) The May 24 Stipulation and July 13 Stipulation, as modified in
the body of this Opinion, are hereby approved.
(L) Applicants' motion to strike part of Environmental Coalition's
Brief On Exceptions is hereby granted and Applicants' alternative motion to
file a supplemental Brief Opposing Exceptions is denied, as discussed in the
body of this Opinion.
By the Commission. Commissioner Hebert dissented with a
separate statement attached.
(SEAL)
David P. Boergers,
Secretary.
<PAGE> 35
American Electric Power Company
Docket Nos. EC98-40-000,
and ER98-2770-000, and
ER98-2786-000
Central and South West Corporation
(Issued March 15, 2000)
HEBERT, Commissioner, dissenting:
As part of the legislative debate on restructuring, policy makers are
engaging in a lively discussion about the wisdom of involving FERC in
reviewing mergers and our competence in that arena. Two weeks ago, a
bipartisan group, the Department of Justice's International Competition
Advisory Committee, issued a report on how to make merger review more
effective. Most members recommended ending FERC's role. The rest urged
reducing it. Along comes this order that should, once and for all, end the
debate. In imposing conditions beyond those the companies offered, allegedly
to remedy anti-competitive harm, the majority here proves Congress should
remove us from the merger business.
The majority uses alleged problems with market power as the basis for
setting a deadline by which the applicants must join a regional transmission
organization (RTO). The date just happens to coincide with the one Order No.
2000 established for the whole industry. The merging utilities are trying
very hard to join an RTO. In fact, the order points out they have filed as
parties to the Alliance Transmission Company seeking approval of a for-profit
transmission company. Slip op. at 16 n.30; 19 nn.35, 36. Today's exercise,
an empty gesture in practical terms, provides watery grist for breast-beating
speeches on how "tough" FERC will act and how "seriously" the Commission
takes formation of RTO's.
Our claimed expertise leads today's majority to invent market power out
of thin air. The Commission reverses the findings of fact of a capable,
experienced Administrative Law Judge. The Commission disregards the
testimony of a former Deputy Assistant Attorney General for Antitrust. The
Commission finds errors in the analysis of FERC's own former chief antitrust
economist, who, as Associate Director of Economics for Electricity, had a
large hand in writing FERC's merger policy. Once again, the experts are
treated as children, with FERC acting as the all-knowing merger agency.
Indeed, in the discussion of competition, slip op. at 14-17, neither
the text of the findings nor the footnotes contain even one citation to the
hearing record. In contrast, the Initial Decision and the Briefs Opposing
Exceptions, that find no problem, rely on specific testimony properly in the
record.
As I explain in the next section, the majority applies a wrong, new
legal standard to this case and indulges in bad economics. In short, the law
and the facts compel approval of the merger the companies submitted, with the
conditions they agreed to. Therefore, I dissent on principle.
<PAGE> 36
Docket No. EC98-40-000, et al. 2
Economics and Law
The discussion on competition begins by equating the merger of two
integrated electric utilities with that of a gas and an electric company. Slip
op. at 14, 90 FERC (Paragraph) _______ at _______ (2000). The majority
concludes that vertical merger analysis applies where "the input is
transmission." Theoretically, I suppose, a merger between integrated utilities
can have vertical aspects. If, in a geographic market, one utility sells
transmission only, and, with the merger, acquires generating units, a vertical
combination occurs in that location. A merger that adds generating plants to a
gas pipeline company also falls under the vertical variety. This order,
however, has no analysis to support the proposition that anything like this
occurs in any of the markets American Electric Power Company (AEP) or Central
and Southwest Corporation (CSW), each an integrated utility with generation and
transmission, serves.
Labeling this merger vertical turns economic analysis on its head. It
converts a pro-competitive merger that adds an entrant to a market, or a
neutral one that changes nothing, into a problematic case that, to the
majority, decreases competition. That the parties to this case "based" their
testimony on vertical principles results from our discussion of vertical
mergers in the order setting the matter for hearing. Though we asked for
testimony on potential vertical effects, we still have the burden of
justifying our conclusion that this merger has vertical characteristics.
This order makes no attempt.
Moreover, having ignored the economics, the majority misconstrues the law.
The order dismisses on spurious grounds our longstanding criterion for reviewing
mergers. The standard "consistent with the public interest" in section 203 the
Federal Power Act narrows our remedial authority to changes in market power the
merger creates. We restated that doctrine just last year in PacifiCorp, 87 FERC
(Paragraph) 61,288 at 62,151 (1999). The majority gives a flimsy reason for
overturning our precedent. PacifiCorp involved horizontal issues (direct
competitors), while, to the majority, this case implicates vertical (supplier
and buyer), slip op. at 15, 90 FERC at ______. Even if true, so what? The
provisions of section 203 apply to both.
The Record
Next, the majority finds fault with the testimony of Dr. Henderson, the
former FERC economist. Dr. Henderson considered the exercise of potential
market power in transmission as a denial of service. Not so, according to
the majority. Dr. Henderson should have examined other means, the order
finds. In particular, the majority holds, harm also results from "strategic
manipulation of transmission or generation by which the merged company could
frustrate competitors' access." Id. The first claim, the one about
transmission, I find amorphous. The second, involving generation, I consider
irrelevant to market power over transmission.
The majority also criticizes Dr. Henderson for considering only the
least costly transmission path in his conclusion that the companies have no
market power. The reasoning rejecting that analysis consists of the truism
that power flows everywhere on a grid. Id. While accurate as physics, that
response misunderstands the effects of mergers. The Applicants point out in
their Brief Opposing Exceptions, "if the merged company does not provide the
least cost path, any foreclosure attempt can be avoided by a supplier
arranging for service over
<PAGE> 37
Docket No. EC98-40-000, et al. 3
the transmission system" of another company. Brief Opposing Exceptions at 75-76,
citing, Ex. AC-936 at 6.
The order, slip op. at 15, calls irrelevant Dr. Henderson's indicator
of lack of transmission market power. He used data on the degree of
concentration in the generation market. I find the information
enlightening. Competition among generators defeats the attempt of the
merging parties to force purchases of the generation they acquire. Buyers
can go elsewhere. One may argue whether enough competition in generation
exists to defeat exercise of any market power in transmission. The majority,
however, rushes past the issue. The order simply concludes summarily that
"Dr. Henderson's analysis, in fact, shows highly concentrated relevant
markets." So much for our "expertise" on the electric industry in the
context of mergers.
The majority adopts "Intervenors' independent analyses . . . ." Slip op. at
16. Preliminarily, I disagree with the characterization. Parties with
economic interests in the merger, such as the intervenors here, present as
much of an "independent" analysis as the applicants. I would argue that,
given that the burden of proof lies with the merging companies, perhaps less
so. In any event, the majority fails to cite any support for this embrace.
In contrast, the Administrative Law Judge and the Briefs Opposing Exceptions,
including the Trial Staff's, examined the record.
I find important the testimony on rebuttal of Dr. Robert D. Willig,
Professor of Economics at Princeton and the former Deputy Assistant Attorney
General, who served as Chief Economist for Antitrust. Enron's competition
witness, Dr. Peter Fox-Penner, hypothesized that AEP will falsely call an
emergency to curtail power flows and, in that way, restrict capacity. Dr.
Willig convincingly proved the claim spurious. Dr. Fox-Penner ignored the
fact that AEP would then commit an illegal act that the relevant regional
reliability councils could detect. As Dr. Willig stated, antitrust
adjudicators properly "discard . . . rank speculation about what firms could
do, in the imagination of the 'analyst' and without grounding in [reality] .
. ." Ex. AC-1900 at 12. The majority should have followed that good advice.
The Intervenors pressed another claim of vertical market power. Dr.
Fox-Penner claimed that AEP actually favored its own generation in granting
requests for transmission. In response, the record shows that Dr. Henderson
examined the patterns of power flows across AEP's system. (He saw no need to
analyze CSW's because the Texas Independent System Operator and the Southwest
Power Pool tariff control the grids.) He found random patterns of acceptance
and refusal between AEP's own generation and those of competitors and
explained a vast majority of the alleged refusals. Ex. AC-900 at 43, 49.
As Dr. Willig instructed, to find a realistic exercise of vertical
market power, we would need to answer three questions. How high could the
merged firm raise prices in the market? How great a risk of detection does
illegal conduct create? How profitable would the exercise of market power
turn out to be Ex. AC-1900 at 12. From the majority I hear silence on each.
The testimony shows, however: not high enough, very risky and not profitable.
Finally, I would accept as sufficient to cure any problem with market
power the merging companies' commitment to join an RTO. Given the deadlines
we outlined in Order No. 2000, the success of our first collaboration meeting
in Cincinnati and the companies' eagerness to join, an RTO in the region will
form soon enough. Artificially imposing a date we know the applicants
<PAGE> 38
Docket No. EC98-40-000, et al. 4
will meet and an expensive scheme of third-party control over calculating
transmission capacity and market monitoring serves no reasonable purpose.
I respectfully dissent.
--------------------------
Curt L. Hebert, Jr.
Commissioner
<PAGE> 1
Exhibit D-1.10
March 31, 2000
The Honorable David P. Boergers
Secretary
Federal Energy Regulatory Commission
888 First Street, N.E.
Washington, D.C. 20426
Re: American Electric Power Company and
Central and South West Corporation
Docket Nos. EC98-40-000, et al.
Dear David P. Boergers:
By separate filing of even date the Applicants' in the above
referenced proceeding reported to the Commission regarding the manner in which
they propose to implement certain of the interim mitigation measures required by
the Commission's March 15, 2000 Order. Attached to this letter, please find a
description of the means by which the Applicants' will implement the interim
energy sales discussed at pages 27-28 of the Order.
Copies of this filing are being served on all parties to the
restricted service list.
Very truly yours,
Clark Evans Downs
<PAGE> 2
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March 31, 2000
Honorable David P. Boergers
Secretary
Federal Energy Regulatory Commission
888 First Street, N.E.
Washington, D.C. 20426
Re: American Electric Power Company and
Central and South West Corporation
Docket Nos. EC98-40-000, et al.
Dear Mr. Boergers:
In accordance with Ordering Paragraph (B) of the Commission's
March 15, 2000 order in the referenced proceeding ("Merger Order"), American
Electric Power Company ("AEP") and Central and South West Corporation ("CSW")
(collectively, the "Applicants") hereby submit their compliance filing
describing their plan to implement certain of the interim mitigation measures
required by the Merger Order. The Commission required that these interim
mitigation measures be submitted prior to the consummation of the merger.
Among other things, the Merger Order required the Applicants to
implement two interim mitigation measures that would be in place from the date
that the merger is consummated through the date that the AEP transmission system
("AEP East") is subject to the operational control of a Commission-approved RTO.
First, the Merger Order required that AEP implement independent calculation and
posting of Available Transmission Capability ("ATC"). Consistent with these
directives, American Electric Power Service Corporation ("AEPSC")(1) has engaged
Southwest Power Pool, Inc. ("SPP") to make independent ATC calculations and
postings.(2) In addition, SPP will have the additional responsibility for
performing the OASIS function of disposing of transmission service requests for
customers (including marketers affiliated with AEP) seeking service over the AEP
East zone. The Merger Order also required the Applicants to put in place an
independent monitor that would review the effects of AEP's generation dispatch
on the loading of the AEP East zone's constrained transmission facilities. For
the monitoring requirement, AEPSC has entered into an agreement with Dr. Douglas
R. Bohi, who will be responsible for overseeing the implementation of the
attached Monitoring Plan under which Dr. Bohi's team will review data of
transmission constraints, the effectiveness of redispatch to alleviate such
constraints, and the impacts of redispatch on the volume and price of energy
before and after redispatch.
- --------
1 AEPSC is a service company that provides various services for the
AEP utility operating companies.
2 For informational purposes, the Applicants have attached a copy of the
agreement between AEPSC and SPP (the "SPP Agreement").
<PAGE> 3
-3-
Each aspect of the compliance plan is discussed below. Submitted with
this compliance filing are (i) the Affidavit of Nicholas A. Brown, Senior Vice
President and Corporate Secretary of Southwest Power Pool, Inc. ("Brown
Affidavit"), and (ii) the Affidavit of Dr. Douglas R. Bohi, Vice President at
Charles River Associates ("Bohi Affidavit").
A. The SPP Agreement
The SPP Agreement sets out the scope of the services that SPP will
undertake for AEPSC in connection with the administration of AEPSC's open access
transmission tariff ("OATT") for services in the AEP East zone. The scope of
SPP's responsibilities and a description of the SPP and how it satisfies the
Commission's independence requirement are more fully described in the Brown
Affidavit. Mr. Brown, who is a Senior Vice President and Corporate Secretary of
SPP, will have overall management responsibility for overseeing the
administration of the SPP Agreement and will directly supervise those SPP
managers that will have day-to-day implementation responsibilities.
The SPP is an independent regional reliability council, security
coordinator, and tariff administrator for the interconnected electric systems in
the Southwest part of the United States. SPP currently administers the SPP
regional tariff that provides for all the services required under FERC's
Proforma tariff. In addition, SPP is responsible for performing calculations of
Total Transmission Capability ("TTC") and ATC, posting TTC and ATC and other
required information on the SPP OASIS, processing all requests for transmission
service under the tariff, and serving as the security coordinator for the
region. As the Commission is aware, on December 30, 1999, SPP filed in Docket
No. EL00-39 a petition seeking recognition as an Independent System Operator
consistent with Order 888, and as a Regional Transmission Organization fully
compliant with the requirements of Order 2000. As described in that filing and
in Mr. Brown's affidavit, while CSW has one member on the twenty-one member SPP
board, under the governance structure, no single company or sector (such as
transmission owners) can band together to force or veto any board action.
The AEP East zone is not within the SPP, but two of the CSW operating
utilities (Southwestern Electric Power Company and Public Service Company of
Oklahoma) do operate within the SPP. As such, the SPP tariff provides for
service over the systems of those two CSW utilities. However, as Mr. Brown
explains, SPP's employees have completely severed any prior relationships with
member utilities. Thus, no SPP employees have any affiliation with the CSW
utilities and no CSW employees have any role in administering the SPP regional
tariff or in calculating or posting ATCs. Moreover, CSW and SPP employees
perform pursuant to the Standards of Conduct which, consistent with Order 889,
are on file with the Commission.
Under the SPP Agreement, SPP has agreed to calculate and post
on the AEP OASIS short-term and long-term ATC, and to process requests for
transmission service under the AEP OATT. SPP will perform these functions until
AEPSC transfers operational control of the AEP transmission system to a
FERC-approved RTO. Upon termination of the Agreement, SPP will work with AEPSC
on the transition to the RTO. The SPP Agreement provides that SPP will perform
the agreed-upon functions in accordance with Good Utility Practice, and to
conform to the applicable NERC and East Central Area Reliability Coordination
Agreement ("ECAR") rules and regulations as well as to AEPSC's specific
reliability requirements and guidelines.
<PAGE> 4
-4-
Mr. Brown explains that the SPP personnel that will perform the functions under
the SPP Agreement will be experienced transmission operators that are familiar
with the AEP transmission system and the ECAR region in general. This is
extremely important in order to preserve reliability and limit disruption to the
greatest extent possible, especially considering that AEPSC will be transferring
important and integral functions for a large and comprehensive transmission
system such as that in the AEP East zone on the eve of the summer peak system.
Prior to the actual time that SPP begins performing these functions,
SPP will establish operating protocols and practices, and will begin installing
equipment and establishing communication links necessary for SPP to perform the
required functions without interruption. The SPP Agreement further provides for
AEPSC to supply SPP all data that SPP deems necessary to perform the functions,
and enables SPP to enter into various hardware and software leases or licensing
agreements with AEPSC as SPP determines necessary.
In addition, the SPP Agreement requires that the required functions be
performed only by SPP employees. However, in order to ensure that SPP has access
to persons with broad knowledge of the AEP transmission system and expertise in
the ECAR rules and protocols, it is imperative that SPP have the ability and
discretion to seek to hire AEPSC employees to carry out the various functions
under the SPP Agreement. It should be stressed, however, that any former AEPSC
employees hired by SPP immediately will sever their employment with AEPSC
(although they will have six months to divest securities in any affiliate of
AEPSC). Mr. Brown further explains that no employees that work for SPP and are
tasked to implement the SPP Agreement will have any financial interest in AEP
(including any affiliates) or in any "market participant" as that term is
defined in the new Order 2000 regulations. Likewise, no employees of SPP that
are performing any of the functions under the Agreement will share office space
with any transmission or marketing employees of AEPSC or any of its affiliates.
The Applicants submit that the SPP Agreement fully complies with the
Commission's requirements as to the TTC/ATC calculations and disposition of
transmission requests. SPP is an existing reliability council that already is
performing these functions for the transmission-owning utilities in its region.
Indeed, SPP has sought recognition as an Order 2000-compliant RTO. SPP is
staffed with skilled and highly-skilled personnel who obviously have relevant
experience and training in the functions to be provided under the SPP Agreement.
Moreover, AEPSC will make available to SPP employees familiar with the AEP
system, as well as the data, hardware, and software that SPP deems necessary.
As to independence, SPP's employees have no financial interest in the
CSW utilities and likewise will have none in the AEP utility companies. While
SPP employees naturally will need access to AEPSC facilities, such as the
control center, the SPP Agreement provides explicitly that those SPP employees
that work at the AEPSC facilities will be subject to oversight by SPP managers,
will not share office space with AEPSC persons that perform merchant or
transmission reliability functions for AEPSC (or any of its affiliates).
Finally, all employees of SPP that perform the various functions under the SPP
Agreement will be treated as "transmission function employees" under FERC's
Order No. 889 Standards of Conduct and, therefore, will be restricted from
relating transmission reliability information to merchant employees of AEPSC (or
any marketing affiliates). And, all SPP employees are required to abide by the
Standards of Conduct which are on file with the Commission.
<PAGE> 5
-5-
B. The Monitoring Plan
To address the Merger Order's requirements, AEPSC has engaged Dr.
Douglas R. Bohi to perform a monitoring function. Dr. Bohi will head a team from
Charles River Associates that will develop a plan to monitor to protect against
anticompetitive effects in electricity markets until a fully functional RTO is
available, and will submit to the Commission reports of its findings,
accompanied by supporting data. Dr. Bohi is an expert in the area of
competition, market power analysis and energy policy, having formerly served,
among other things, as the Chief Economist and Director of the Commission's
Office of Economic Policy.
Consistent with the Merger Order, Dr. Bohi will monitor whether AEP has
attempted to create binding transmission constraints with the idea of
substantially increasing prices in the wholesale marketplace. (A copy of Dr.
Bohi's Monitoring Plan is attached for informational purposes.) As explained in
the Bohi Affidavit, such actions potentially could be accomplished through
transmission operations and/or through generation operations. Transmission
actions, for example, could include unjustifiable deration of transmission
facilities, strategically taking facilities out of service, or calling for
unjustified line loading relief (TLRs). On the generation side, the strategic
action that Dr. Bohi will monitor includes the operation of generating resources
out of economic merit or in a manner inconsistent with good utility practice in
an effort to create or exacerbate binding transmission constraints, which has
the effect of driving up wholesale prices on the constrained side of the
facilities.
In order to determine whether such strategic actions were taken, Dr.
Bohi's team routinely will receive and review information relating to AEP's
recent operations. Dr. Bohi explains that he contemplates that the monitoring
team will review: (i) the hourly output of the AEP generating resources; (ii)
transmission limits and deratings for monitored flowgates or other facilities
that, during the prior two years, have limited transmission capability; (iii)
the hourly flow over such limiting facilities; (iv) generation redispatch and
other actions taken by AEPSC to manage transmission congestion; (v) generation
and transmission outage data; (vi) information concerning wholesale transactions
of AEP (and affiliated) marketers before and after the implementation of TLRs or
other congestion management actions, and (vii) information concerning the level
of transactions and prices in the market place as a whole before and after AEPSC
implements TLRs or other congestion management actions.
The monitoring team also will develop and utilize various screens and
indices for reviewing, correlating and interpreting the various information that
is gathered. Dr. Bohi states the monitoring team intends to seek the input of
AEPSC, AEP customers, market participants and other interested persons to
develop such screens and indices. Should this review and analyses indicate that
further investigation is warranted, the monitoring team will gather additional
information and, perhaps, seek explanations from AEPSC representatives regarding
the matters under investigation. In addition to the information routinely
gathered from AEPSC, any interested party (including members of the Commission's
staff) may submit requests that the monitoring team investigate specific
incidents or activities. The team will review any such requests and conduct
further investigations as it deems appropriate.
The monitoring team will submit to the Commission
semi-annually a report detailing the results of its findings. The report will
summarize the data that was reviewed and analyzed,
<PAGE> 6
-6-
evaluate the performance of the AEP transmission system and the conduct of the
AEPSC transmission and generation functions, and comment on the overall impact
of AEPSC's transmission and generation activities on the competitive performance
of the wholesale market within AEPSC's control area and immediately adjacent
areas. In addition, to the extent requested by the Commission, the monitoring
team would provide additional reports or address individual inquiries and
conduct briefings with the Commission's staff. The reports submitted to the
Commission will contain all the findings and will include workpapers and other
relevant data necessary to support those findings.
Applicants submit that the Monitoring Plan meets the criteria specified
in the Merger Order and provides the Commission complete assurance that actions
taken by AEP that affect constrained transmission facilities will be thoroughly
reviewed by an independent and highly qualified monitoring team. Dr. Bohi is a
highly respected economist who has assembled a very strong team, none of the
members of which has any business affiliation with the Applicants. The
Commission will be provided, on a semi-annual basis, a comprehensive report of
Dr. Bohi's findings, complete with workpapers and relevant supporting data.
The Applicants also have attached to this compliance a Notice for
Filing for publication in the Federal Register with an accompanying electronic
version. This compliance filing has been served on all parties to this
proceeding. If you have any questions concerning this filing, please do not
hesitate to contact any of the undersigned.
Respectfully submitted,
--------------------------
Clark, Evans Downs J.A. Bouknight, Jr.
Martin V. Kirkwood Douglas G. Green
Shelby Provencher Steven J. Ross
Jones, Day, Reavis & Pogue Steptoe & Johnson LLP
51 Louisiana Avenue, N.W. 1330 Connecticut Ave., N.W.
Washington, D.C. 20001 Washington, D.C. 20036
(202) 879-3939 (202) 429-6222
Attorneys for Central and South
West Corporation Carmen L. Gentile
Thomas L. Blackburn
Bruder, Gentile & Marcoux, LLP
1100 New York Ave., N. W.
Suite 510 East
Washington D.C. 20005
(202) 783-1350
Attorneys for American Electric
Power Company, Inc.
cc: Restricted Service List
<PAGE> 7
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
American Electric Power Company )
and ) Docket Nos. EC98-40-000,
Central and South West Corporation ) ER98-2770-000, and
ER98-2786-000
NOTICE OF FILING
(April __, 2000)
On March 31, 2000, American Electric Power Company and Central and
South West Corporation made their compliance filing as required under Ordering
Paragraph (B) of the Commission's March 15, 2000 order in the referenced
dockets. Copies of the filing were served on all parties to the proceeding.
Any person desiring to be heard or to protest this filing should file a
petition to intervene, comments, or protest with the Federal Energy Regulatory
Commission, 888 First Street, N.E., Washington, D.C. 20426, in accordance with
Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR
Section 385.211 and 18 CFR Section 385.2 14). All petitions to intervene,
comments, or protests should be filed on or before __________________. Comments
and protests will be considered by the Commission in determining the appropriate
action to be taken, but will not serve to make protestants parties to the
proceeding. Any person wishing to become a party must file a petition to
intervene. Copies of the filing are on file with the Commission and are
available for public inspection. This filing also may be viewed on the Internet
at http://www. ferc.fed.us/online/rims.htm (call 202-208-2222 for assistance).
---------------------------
David P. Boergers
Secretary
<PAGE> 8
CERTIFICATE OF SERVICE
----------------------
I hereby certify that I have this day served the foregoing
document on each person designated on the official service list compiled by the
Secretary in this proceeding.
Dated at Washington, D.C. this 31st day of March, 2000.
------------------------------
Steven J. Ross
Steptoe & Johnson LLP
1330 Connecticut Ave., N.W.
Washington, D.C. 20036
(202) 429-6279
<PAGE> 9
EXHIBIT D-1.10
AGREEMENT
This Agreement is entered into this ___ day of March, 2000, between
American Electric Power Service Corporation ("AEPSC"), a New York corporation
and Southwest Power Pool, Inc. ("SPP"), an Arkansas non-profit corporation,
which are sometimes individually referred to herein as a "Party" and
collectively as "Parties".
WHEREAS, AEPSC is a service company providing services for the
affiliated companies of the American Electric Power ("AEP") System, a multistate
public utility holding company system registered under the Public Utility
Holding Company Act of 1935; and
WHEREAS the operating companies of the AEP system own, among other
things, an integrated electric transmission system, which they use to provide
electric service to their customers, and to provide non-discriminatory open
access transmission service pursuant to an open access transmission Tariff
("OATT") filed with and subject to the jurisdiction of the Federal Energy
Regulatory Commission ("FERC"); and
WHEREAS, AEPSC as agent for the AEP operating companies, administers
the OATT, which administration includes the determination and public posting of
Total Transmission Capability ("TTC") and Available Transmission Capability
("ATC"); and the acceptance and approval or denial of reservations for
transmission service;
WHEREAS SPP is an independent Regional Reliability Council, security
coordinator, and tariff administrator for interconnected electric systems in the
Southwest part of the United States; and
WHEREAS, in order to fulfill certain conditions specified by the FERC
in an Opinion and Order ("Opinion No. 442") conditionally approving a merger
between companies of the AEP System and Companies of the Central and South West
System ("AEP/CSW Merger"), AEPSC wishes to transfer control of certain functions
as described in this Agreement related to its administration of its OATT in the
East Zone of its transmission system to an independent party; and
WHEREAS, SPP is independent from AEPSC, possesses the necessary
competency and experience to perform the functions in question and is willing to
perform such functions under the terms and conditions of this Agreement;
NOW THEREFORE, in consideration of the mutual promises contained
herein, and other good and valuable consideration, the receipt of which is
hereby acknowledged, the Parties agree as follows:
SECTION 1 - SCOPE OF SERVICES.
1.1 SPP shall perform the following functions on behalf of AEPSC,
associated with administration of the OATT in the AEP East Zone: (i) Long-term
ATC calculation and posting; (ii) Short-term ATC calculation and posting and
(iii) acceptance and approval or denial of reservations for transmission
service.
<PAGE> 10
-2-
SECTION 2 - INDEPENDENCE.
2.1 All functions shall be performed by employees of SPP. No such
employees shall be employed by AEPSC or any affiliate of AEPSC, or have a
financial interest in any Market Participant as defined in 18 C.F.R.
Section 35.34(a)(2). Any employee owning securities in any affiliate of AEPSC or
any Market Participant shall divest such securities within six months of his or
her employment by SPP. Nothing in this section shall be interpreted to preclude
any such SPP employee from indirectly owning securities issued by any affiliate
of AEPSC or any Market Participant through a mutual fund or similar arrangement
(other than a fund or arrangement specifically targeted toward the electric
industry or the electric utility industry or any segment thereof) under which
the employee does not control the purchase or sale of such securities.
Participation in a pension plan of AEPSC or any affiliate of AEPSC or any Market
Participant shall not be deemed to be a direct financial interest if the plan is
a defined-benefit plan that does not involve ownership of the securities.
2.2 No employees of SPP performing such functions shall share office
space with any transmission/reliability employee or merchant employee of AEPSC
or of any affiliate of AEPSC, or those of any Market Participant.
2.3 All employees of SPP performing functions on behalf of AEPSC under
this Agreement shall be treated, for purposes of the FERC's Standards of Conduct
set forth in 18 C.F.R. Section 37.4, as the equivalent of
transmission/reliability employees of AEPSC, and all restrictions relating to
information sharing and other relationships between merchant employees of AEPSC
or its affiliates and transmission/reliability employees of AEPSC or its
affiliates shall apply to such employees. Such employees shall also abide by the
SPP Standards of Conduct.
SECTION 3 - COMPENSATION, BILLING AND PAYMENT.
3.1 AEPSC shall reimburse SPP for all reasonable and necessary costs
incurred by SPP in performing functions on behalf of AEPSC pursuant to this
Agreement. Reimbursable expenses shall include employee salaries and benefits,
office space, supplies and equipment, computer hardware and software lease costs
and other information technology costs, reasonable travel and other business
expenses, legal, accounting and other necessary corporate services [others?].
Such expenses shall be directly assigned to SPP's performance of its
responsibilities under this agreement when possible, and shall be based upon
time billing or other reasonable allocation methods when such direct assignment
is not possible.
3.2 SPP shall render to AEPSC monthly statements by regular mail,
facsimile, electronic mail or other acceptable means. Such statement shall set
forth any reimbursable costs incurred during the month in question by SPP. AEPSC
shall make payment of the amount shown to be payable by AEPSC by wire transfer
to an account specified by SPP not later than the twentieth (20th) day after
receipt of the statement, unless such day is not a business day, in which case
AEPSC shall make payment on the next business day. All such payments shall be
deemed to be made when said wire transfer is received by SPP. Overdue payments
shall accrue interest daily at the then current prime interest rate (the base
corporate loan interest rate) published in the Money and Investing Section of
the The Wall Street Journal, or, if no longer
<PAGE> 11
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published, in any mutually agreeable publication, plus 2% per annum, from the
due date of such unpaid amount until the date paid.
3.3 Upon the occurrence of a default, SPP may terminate this Agreement.
In the event of a billing dispute between the Parties, SPP will proceed to
perform its responsibilities under this Agreement as long as AEPSC (i) continues
to make all payments not in dispute, and (ii) pays into an independent escrow
account the portion of the invoice in dispute, pending resolution of such
dispute.
3.4 SPP shall allow AEPSC access to SPP's books and records, at
reasonable times and under reasonable conditions, as necessary to verify
transactions and billings under this agreement. SPP's books and records related
to this agreement shall be subject to and part of the SPP's annual audit
performed under National Accounting Standards with results made available to
AEPSC. SPP shall maintain such books and records for one year after termination
of expiration of this Agreement or longer if necessary to resolve a pending
dispute.
SECTION 4 - TERM AND TERMINATION.
4.1 The initial term of this Agreement shall begin on the date that it
has been executed by both Parties and shall end on May 31, 2001. During the
initial term, the Agreement may be terminated upon three months' notice if AEPSC
reasonably determines that the AEP/CSW Merger will not be consummated. SPP shall
be compensated for reasonable costs incurred prior to such cancellation. After
the initial term, the Agreement shall continue in effect for periods of one
month until terminated by AEPSC by giving at least three months' written notice.
The Parties may mutually agree to allow a shorter notice period, so long as SPP
is compensated for any costs it may incur as a result of such earlier
termination.
4.2 SPP shall begin performing the functions required by Section 1.1 at
1200 hours on the earlier of June 1, 2000 or the date upon which the AEP/CSW
Merger is consummated ("Date of Transfer") and shall cease performing such
functions at 1200 hours on the date the Agreement expires or is terminated,
except as otherwise agreed pursuant to Section 4.4.
4.3 It is the intent of the Parties to allow the transfer of functions
from AEPSC to SPP to occur without any interruption in the normal administration
of the OATT. To this end, the Parties shall, prior to the Date of Transfer,
cooperate to establish the necessary practices, routines, installation of
equipment, establishment of communication links, and all other activities
necessary to allow SPP to begin to perform its required functions without any
such interruption.
4.4 The Parties recognize that it is the intention of AEPSC to transfer
to the Alliance Regional Transmission Organization ("RTO") the functions being
performed by SPP for AEPSC pursuant to this Agreement, when the Alliance RTO
becomes operational, which is expected to occur in 2001. The notice and
termination provisions in Section 4.1 are intended to facilitate such transfer.
The Parties shall cooperate to facilitate the intended transfer, including
agreement upon an alternative time at which SPP ceases to perform its required
functions under this Agreement, if necessary. AEP shall not give notice of
termination except to transfer the functions described in Section 1.1 to an RTO
or other independent party.
<PAGE> 12
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4.5 If the FERC places additional conditions on the AEP/CSW merger, or
interprets existing conditions in a manner that causes this Agreement to be
burdensome to AEPSC, in AEPSC's sole judgment, then the Parties shall negotiate
in good faith to amend this Agreement so as to remove such burdens, and if
unable to agree on such amendments, AEPSC may terminate this Agreement during
the initial term upon three months' notice. SPP shall be compensated for
reasonable costs incurred prior to such cancellation.
SECTION 5 - STANDARD OF PERFORMANCE.
5.1 SPP shall perform the functions specified in this Agreement in
accordance with Good Utility Practice and shall conform to applicable
reliability criteria, policies, standards, rules regulations and other
requirements of SPP, NERC and the East Central Area Reliability Coordination
Agreement ("ECAR"), AEPSC's specific reliability requirements and operating
guidelines (to the extent these are not inconsistent with other requirements
specified in this paragraph) and all applicable requirements of federal and
state regulatory authorities.
SECTION 6 - DATA, SYSTEMS AND PERSONNEL.
6.1 AEPSC shall supply to SPP, both initially and throughout the term
of this Agreement, all data that SPP deems necessary to perform the functions
required to be performed under this Agreement. The Parties shall agree upon the
necessary data and the format and manner in which it shall be provided prior to
the Date of Transfer.
6.2 AEPSC shall reimburse SPP in accordance with Section 3 for computer
hardware and software and any incremental licensing costs necessary to allow SPP
to perform its responsibilities under this Agreement. Such arrangements may
involve hardware and/or software lease and/or maintenance agreements with AEPSC,
as determined by SPP.
6.3 The Parties recognize that to allow SPP to begin performing its
responsibilities on the Date of Transfer, in accordance with Section 4.3 and
4.4, it may be necessary for it to hire certain personnel who have previously
been employed by AEPSC. The Parties shall cooperate to assure, insofar as
possible, the availability of such personnel. All such former employees of AEPSC
shall comply with the independence requirements set forth in Section 2.
SECTION 7 - WAIVER OF LIABILITY AND INDEMNIFICATION.
7.1 SPP, its directors, officers, agents and employees shall not be
liable to AEPSC for damages arising out of or related to performance of SPP's
obligations under this Agreement; provided, however, that this section shall not
apply to actions which are unlawful, undertaken in bad faith, or are the result
of gross negligence or willful misconduct.
7.2 AEPSC hereby agrees to indemnify and hold harmless SPP, its
directors, officers, agents and employees against and from any and all claims,
demands, causes of action, losses and liabilities (including any cost and
expense of litigation and reasonable attorneys fees incurred by SPP in defending
any action, suit or proceeding, provided that SPP affords AEPSC a reasonable
opportunity in such action, suit or proceeding to conduct SPP's defense and to
approve any settlement agreements) for or on account of (i) injury, bodily or
otherwise, to, or the death of, persons, or for damage to, or destruction that
arises from negligent acts of AEPSC associated
<PAGE> 13
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with (a) facilities, property and equipment owned or controlled by AEPSC or ifs
affiliates, or AEPSC's operation and maintenance thereof; (b) the transmission
and delivery of electricity by AEPSC; and (ii) damages arising out of or related
to performance by SPP of its obligations under this Agreement, except to the
extent that such claims, demands, causes of action, losses and liabilities are
attributable to actions of SPP or its directors, officers, agents or employees
which are unlawful, undertaken in bad faith, or are the result of gross
negligence or willful misconduct.
SECTION 8 - DISPUTE RESOLUTION.
8.1 Any dispute under this Agreement shall be resolved in accordance
with the dispute resolution procedures set forth in Section 3.13 of the SPP
Bylaws. For purposes of such disputes, AEPSC shall be regarded as a "consenting
non-member".
SECTION 9 - DATA MANAGEMENT.
9.1 "Data" means all information, text, drawings, diagrams, images or
sounds which are embodied in any electronic or tangible medium and which are
supplied or in respect of which access is granted to SPP by AEPSC under this
Agreement
9.2 "Processes" means software, base data models and operating
procedures for software or base data models.
9.3 SPP acknowledges that AEPSC's Data and Processes are the property
of AEPSC and AEPSC hereby reserves all Intellectual Property Rights which may
subsist in AEPSC's Data and Processes. SPP shall not delete or remove any
copyright notices contained within or relating to AEPSC's Data.
9.4 Having due regard for the nature of their respective obligations
under this Agreement:
9.4.1 SPP shall use its best efforts to preserve the integrity of
AEPSC's Data and Processes, to prevent any corruption or loss of
AEPSC's Data, and
9.4.2 AEPSC shall use its best efforts to preserve the integrity
of AEPSC's Data and Processes by, as a minimum, continuing to employ
its own established internal procedures in relation to the same.
9.5 Without limiting the foregoing obligations of either Party, AEPSC
shall reasonably assist SPP in establishing measures to preserve the integrity
and prevent any corruption or loss of AEPSC's Data, and shall reasonably assist
SPP in the recovery of any corrupted or lost data.
9.6 SPP shall retain and preserve AEPSC's Data until such data is
transferred as a result of AEP's membership in an RTO. At the end of the
retention period, SPP shall request AEPSC's approval before disposing of AEPSC's
Data. If AEPSC refuses to approve of the disposal, SPP may deliver AEPSC's Data
retained information to AEPSC at AEPSC's expense.
<PAGE> 14
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SECTION 10 - INSURANCE.
10.1 SPP shall furnish and require its Sub-contractors to furnish
insurance listed in Sections 10.11 through 10.14. Insurance shall be placed with
insurance carriers acceptable to AEPSC, such acceptance not to be unreasonably
withheld. SPP shall maintain and cause its Sub-contractors to maintain this
insurance at all times during the performance of this Agreement:
10.1.1 coverage for the legal liability of SPP or its Sub-contractors
under the workers' compensation and occupational disease law of the state in
which the services are performed according to the following:
10.1.1.1 in the states of Ohio and West Virginia, SPP or its
Sub-contractors shall be contributors to the state workers'
compensation fund and shall furnish a certificate to that effect.
10.1.1.2 in states other than Ohio or West Virginia, SPP or its
Sub-contractors shall maintain an insurance policy for workers'
compensation from an insurance carrier approved for contracting
workers' compensation business in the state in which the services
are to be performed.
10.1.1.3 if SPP or its Sub-contractor is a legally permitted and
qualified self-insurer in the state in which the Services are to
be performed, it may furnish proof that it is such a self-insurer
in lieu of submitting proof of insurance.
10.1.2 commercial general liability insurance with limits of not less
than $1,000,000 (one million dollars) each occurrence and aggregate.
10.1.3 professional liability insurance with a limit of not less than
$30,000,000 (thirty million dollars) each occurrence and aggregate, providing
coverage for claims arising out of the performance of professional services
under this Agreement and resulting from any error, omission, or negligent act
for which SPP is held liable. SPP shall maintain this insurance for a minimum
period of 5 (five) years after the completion of the Agreement.
10.1.4 property insurance with a limit of liability necessary to
restore and replace all physical and intellectual assets necessary to the
Services under this Agreement including AEPSC Data. This insurance shall
include, but not be limited to the following coverages:
10.1.4.1 mechanical breakdown and artificially generated
electrical current;
10.1.4.2 changes in temperature and humidity;
10.1.4.3 computer viruses;
10.1.4.4 off-premises services;
10.1.4.5 transportation of goods;
<PAGE> 15
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10.1.4.6 loss of project (to protect the physical damage to R&D
property, as well as additional costs to recreate, restore and
reproduce the damaged property);
10.1.4.7 delayed introduction of product (to protect loss from
delays in bringing the Services to AEPSC); and
10.1.4.8 extended period of indemnity (to extend business income
period of indemnity for whatever reasonable time needed to
restore/resume operations after a loss).
10.2 SPP shall submit two copies of certificates of insurance for the
insurance provided in Sections 10.1.1 through 10.1.4. Such certificates shall
state that the insurance carrier has issued the policies providing for the
insurance specified herein, that such policies are in force and that the
insurance carrier will give AEPSC 30 (thirty) calendar days prior written notice
of any material change in or cancellation of such policies. If Such insurance
policies are subject to any exceptions to the terms specified herein, such
exceptions shall be explained in full in such certificates. AEPSC may, at its
discretion, require SPP to obtain insurance policies that are not subject to any
exceptions.
10.3 Insurance policies written on a "claims-made" basis shall be
maintained by SPP or its Sub-contractors for a minimum of 5 (five) years after
completion of the Services under this Agreement.
10.4 SPP and its Sub-contractors shall obtain waivers of subrogation on
all their insurance whether required by this Agreement or in excess of the
Agreement requirements such waivers shall be for the benefit of AEPSC and its
affiliated companies. Notwithstanding the foregoing, AEPSC shall not require
waiver of subrogation on commercial general liability, professional liability
and workers compensation. Furthermore, AEPSC shall not require waiver of
subrogation on SPP and its Sub-contractors business auto policy provided that it
follows the industry standard definition of "insured" which includes AEPSC's
usage with permission. SPP and its Sub-contractors shall obtain a waiver of
subrogation on such policies as property, inland marine and crime.
SECTION 11 - CONFIDENTIALITY.
11.1 Both Parties hereby agree that:
11.1.1 "Confidential Information" means all information designated as
such by either Party in writing together with all other information
which relates to the business, affairs, products, developments, trade
secrets, know-how, personnel, customers and suppliers of either Party
or information which may reasonably be regarded as the confidential
information of the disclosing Party.
11.1.2 any person employed or engaged by the Parties (in connection
with this Agreement in the course of such employment or engagement)
shall only use Confidential Information for the purposes of this
Agreement;
<PAGE> 16
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11.1.2.1 any person employed or engaged by either SPP or AEPSC
(in connection with this Agreement in the course of such
employment or engagement) shall not disclose any Confidential
Information to any third party without the prior written
consent of the other.
11.1.3 both Parties shall take all necessary precautions to ensure that
all Confidential Information is treated as confidential and not
disclosed (save as aforesaid) or used other than for the purposes of
this Agreement by their employees, servants, agents or sub-contractors.
11.2 The provisions of above Clause shall not apply to any information
which:
11.2.1 is required by the OATT or FERC regulation to be made publicly
available;
11.2.2 is or becomes public knowledge other than by breach of this
Clause;
11.2.3 is in the possession of the receiving Party without restriction
in relation to disclosure before the date of receipt from the
disclosing Party;
11.2.4 is received from a third party who lawfully acquired it and who
is under no obligation restricting its disclosure;
11.2.5 is independently developed without access to the Confidential
Information, provided that such independent development can be
evidenced; or
11.2.6 is required to be disclosed by law, regulatory authority or
stock exchange.
11.3 AEPSC's Data shall be regarded as Confidential Information and
SPP's rights with respect to the use, sale, reproduction, modification and
distribution of the same shall be limited to the extent necessary so as to
enable SPP to fulfill its obligations under this Agreement.
11.4 Nothing in this Clause shall prevent SPP or AEPSC from using data
processing techniques, ideas and know-how gained during the performance of this
Agreement in the furtherance of its normal business, to the extent that this
does not relate to a disclosure of AEPSC's Data, any data generated from AEPSC's
Data, a disclosure of any Confidential Information, or an infringement by AEPSC
or SPP of any Intellectual Properly Right.
SECTION 12 - FORCE MAJEURE.
12.1 For the purposes of this Agreement the expression "Force Majeure"
shall mean any cause affecting the performance by a Party of its obligations
arising from acts, events, omissions, or happening which are beyond its
reasonable control including (but without limiting the generality thereof)
governmental regulations, fire, flood, or any disaster or a labor dispute.
12.2 Neither Party shall in any circumstances be liable to the other
for any loss of any kind whatsoever including but not limited to any damages
whether directly or indirectly caused to or incurred by the other Party by
reason of any failure or delay in the performance of its obligations hereunder
which is due to Force Majeure. If SPP fails to perform or is delayed in
<PAGE> 17
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performing due to an act of Force Majeure, AEPSC shall be entitled to a refund
of any advance payments made up to the date such Force Majeure event occurs and
shall not be required to make further payments until such time as SPP resumes
its full performance. Notwithstanding the foregoing, each Party shall use all
reasonable endeavors to continue to perform, or resume performance of, such
obligations hereunder for the duration of such Force Majeure event. If SPP fails
to perform or is delayed in performing its obligations due to Force Majeure,
AEPSC may during the period of Force Majeure, utilize a third party to perform
SPP's obligations. SPP shall use reasonable efforts to cooperate with AEPSC in
effecting a transition to such alternative services.
12.3 If either of the Parties shall become aware of circumstances of
Force Majeure which give rise to or which are likely to give rise to any such
failure or delay on its part it shall forthwith notify the other by the most
expeditious method then available and shall inform the other of the period which
it is estimated that such failure or delay shall continue.
12.4 It is expressly agreed that any failure by SPP to perform or any
delay by SPP in performing its obligations under this Agreement which results
from any failure or delay in the performance of its obligations by any person,
firm or company with which SPP shall have entered into any such contract, supply
arrangement or sub-contract or otherwise, shall be regarded as a failure or
delay due to Force Majeure only in the event that (a) such person, firm or
company shall itself be prevented from or delayed in complying with its
obligations under such contract, supply arrangement or sub-contract or otherwise
as a result of circumstances of Force Majeure (b) the contract, supply
arrangement or subcontract is essential to SPP's performance and (c) SPP has
exercised its best efforts to find substituted goods or services on terms
generally equivalent to those agreed under such contract, supply arrangement or
sub-contract.
12.5 If the event of Force Majeure prevents either Party from
performing all or a substantial part of its obligations for a consecutive period
of 90 (ninety) calendar days then the other Party may terminate this Agreement
upon written notice, provided always that SPP shall be reimbursed for all direct
costs incurred under this Agreement up to the effective date of such
termination, provided always that such costs take account of:
12.5.1 any recoveries made by SPP pursuant to its insurance policies;
and
12.5.2 all charges paid by AEPSC hereunder.
SECTION 13 - AMENDMENTS TO AGREEMENT.
13.1 This Agreement shall not be varied or amended unless such
variation or amendment is agreed in writing by a duly authorized representative
of AEPSC on behalf of AEPSC and by a duly authorized representative of SPP on
behalf of SPP.
SECTION 14 - NOTICES.
14.1 Notices. Any notice, demand or request required or authorized by
this Agreement to be given by one Party to the other Party shall be in writing.
It shall either be personally delivered, transmitted by telecopy or facsimile
equipment (with receipt verbally and electronically confirmed), sent by
overnight courier or mailed, postage prepaid, to the other Party
<PAGE> 18
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at the address designated in this Article 14. Any such notice, demand or request
so delivered or mailed shall be deemed to be given when so delivered or three
(3) days after mailed.
14.2 Addresses of the Parties. Notices and other communications shall
be addressed to:
AEPSC
J. Craig Baker
American Electric Power Service Corporation
1 Riverside Plaza
Columbus, Ohio 43215
SPP
Nicholas A. Brown
Southwest Power Pool, Inc.
415 North McKinley Street
#700 Plaza West
Little Rock, AR 72205-3020
SECTION 15 - MISCELLANEOUS PROVISIONS.
15.1 Governing Law. This Agreement shall be interpreted, construed, and
governed by the laws of the State of Ohio, except to the extent preempted by the
law and/or unless a court with jurisdiction rules otherwise, provided, however,
that all matters relating to real property or any interest in realty shall be
governed by the laws of the State wherein such real property or interest in
realty is physically located.
15.2 Successors and Assigns. This Agreement shall inure to the benefit
of, and be binding upon the Parties, their respective successors and assigns
permitted hereunder, but shall not be assignable by a Party, by operation of law
or otherwise, without the approval of the other Party which approval shall not
be unreasonably withheld, except that no such approval is required as to a
successor in the operation of the AEP System's East Zone Transmission Facilities
by reason of a merger, consolidation, reorganization, sale, spin-off, or
foreclosure, as a result of which substantially all such transmission facilities
are acquired by such successor.
15.3 No Implied Waivers. The failure of a Party to insist upon or
enforce strict performance of any of the specific provisions of this Agreement
at any time shall not be construed as a waiver or relinquishment to any extent
of such Party's right to assert or rely upon any such provisions, rights, or
remedies in that or any other instance, or as a waiver to any extent of any
specific provision of this Agreement; rather the same shall be and remain in
full force and effect.
15.4 Severability. Each provision of this Agreement shall be considered
severable, and if for any reason any provision of this Agreement, or the
application thereof to any person, entity, or circumstance, is determined by a
court or regulatory authority of competent jurisdiction to be invalid, void, or
unenforceable, then the remaining provisions of this Agreement shall continue in
full force and effect and shall in no way be affected, impaired, or invalidated,
and
<PAGE> 19
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such invalid, void, or unenforceable provision shall be replaced with a suitable
and equitable provision in order to carry out, so far as may be valid and
enforceable, the intent and purpose of such invalid, void, or unenforceable
provision.
15.5 Renegotiation. If any provision of this Agreement, or the
application thereof to any person, entity or circumstance, is held by a court or
regulatory authority of competent jurisdiction to be invalid, void, or
unenforceable, or if a modification or condition to this Agreement is imposed by
a regulatory authority exercising jurisdiction over this Agreement, then the
Parties shall endeavor in good faith to negotiate such amendment or amendments
to this Agreement as will restore the relative benefits and obligations of the
signatories under this Agreement immediately prior to such holding,
modification, or condition. If after sixty days such negotiations are
unsuccessful, then either Party may terminate this Agreement upon three month's
notice.
15.6 Representations and Warranties. Each Party represents and warrants
to other signatories that as of the date it executes this Agreement:
15.6.1 It is duly organized, validly existing, and in good standing
under the laws of the Jurisdiction where organized.
15.6.2 Subject to any necessary approvals by federal or state
regulatory authorities, the execution and delivery by each Party, and
the performance of its obligations hereunder have been duly and validly
authorized by all requisite action on the part of the signatories. This
Agreement has been duly executed and delivered by the Parties, and,
subject to the conditions set forth in this Agreement, constitutes the
legal, valid, and binding obligation on the part of each Party,
enforceable against it in accordance with its terms except insofar as
the enforceability thereof may be limited by applicable bankruptcy,
insolvency, reorganization, fraudulent conveyance, moratorium, or other
similar laws affecting the enforcement of creditor's rights generally,
and by general principles of equity regardless of whether such
principles are considered in a proceeding at law or in equity.
15.6.3 There are no actions at law, suits in equity, proceedings, or
claims pending or, to the knowledge of each Party, threatened against
such Party before or by any federal, state, foreign or local court,
tribunal, or governmental agency or authority that might materially
delay, prevent, or hinder the performance by such entity of its
obligations hereunder.
15.7 Further Assurances. Each Party agrees that it shall hereafter
execute and deliver such further instruments, provide all information, and take
or forbear such further acts and things as may be reasonably required or useful
to carry out the intent and purpose of this Agreement and as are not
inconsistent with the provisions of this Agreement.
15.8 Entire Agreement. This Agreement, including applicable appendices
and their duly approved replacements, constitute the entire agreement among the
Parties with respect to the subject matter of this Agreement, and no previous
oral or written representations,
<PAGE> 20
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agreements, or understandings made by any officers, agent, or employee of any
Party shall be binding on any such Party unless contained in this Agreement or
applicable appendices.
15.9 Good Faith Efforts. Each Party agrees that it shall in good faith
take all reasonable actions necessary to permit it and other signatories to
fulfill their obligations under this Agreement. Where the consent, agreement, or
approval of any Party must be obtained hereunder, such consent, agreement, or
approval shall not be unreasonable withheld, conditioned, or delayed. Where any
Party is required or permitted to act, or omit to act, based on its opinion or
judgment, such opinion or judgment shall not be unreasonably exercised. To the
extent that the jurisdiction of any federal or state regulatory authority
applies to any part of this Agreement and/or the transactions or actions covered
by this Agreement, each Party shall cooperate with all other signatories to
secure any necessary or desirable approval or acceptance of such regulatory
authorities of such part of this Agreement and/or such transactions or actions.
15.10 Counterparts. This Agreement may be executed in any number of
counterparts, each of which shall be deemed to be an original, but all of which
together shall constitute one and the same instrument, binding upon AEPSC and
SPP, notwithstanding that AEPSC, and SPP may not have executed the same
counterpart.
IN WITNESS WHEREOF, the Parties have caused their duly authorized
representatives to execute and attest this Agreement, on their respective
behalves.
AMERICAN ELECTRIC POWER SERVICE CORPORATION
Henry W. Fayne
- -----------------------------------------------
Name of Authorized Representative
Executive Vice President - Financial Services
- -----------------------------------------------
Title of Authorized Representative
- -----------------------------------------------
Signature of Authorized Representative
- -----------------------------------------------
Date of Execution
<PAGE> 21
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SOUTHWEST POWER POOL, INC.
Nicholas A. Brown
- -----------------------------------------------
Name of Authorized Representative
Senior Vice President and Corporate Secretary
- -----------------------------------------------
Title of Authorized Representative
- -----------------------------------------------
Signature of Authorized Representative
- -----------------------------------------------
Date of Execution
<PAGE> 22
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
American Electric Power Company )
and ) Docket Nos. EC98-40-000,
Central and South West Corporation ) ER98-2770-000, and
ER98-2786-000
AFFIDAVIT OF
DOUGLAS R. BOHI
I. BACKGROUND
1. My name is Douglas R. Bohi. I am a Vice President of
Charles River Associates ("CRA"), an economics consulting firm. My
business address is Charles River Associates Incorporated, 600 13th
Street, N.W., Suite 700, Washington, DC 20005.
2. At CRA, I have served as an expert witness before state and
federal regulatory agencies on matters involving market power and
competition issues, transmission pricing and access, electric utility
mergers, and transportation, energy, and environmental policy.
Previously, I served as Chief Economist and Director of the Office of
Economic Policy at the Federal Energy Regulatory Commission, where I
was responsible for developing market-based approaches to electric
regulation, and establishing policies for granting utilities authority
for charging market-determined prices. Prior to joining CRA, I directed
the Energy and Natural Resources Division of Resources for the Future,
Washington, D.C. I also have served as a Senior Research Scientist for
Economic Policy for the Energy Division of Oak Ridge National
Laboratory, and Chairman of the Department of Economics at Southern
Illinois University. I have been an active member of the National
Research Council Committee on the National
<PAGE> 23
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Energy Modeling System, and I also serve on the editorial board of
Resource and Energy Economics. I have written eight books and numerous
articles on energy issues. I received my Ph.D. in Economics from
Washington State University.
3. Under FERC's March 15, 2000 order addressing the proposed
merger between American Electric Power Company ("AEP") and Central and
South West Corporation ("CSW"), AEP is required to put in place
independent monitoring to monitor the effects of the dispatch of AEP
generation facilities on constrained transmission facilities and the
effects of the redispatch of generation on energy pricing and volume of
transactions. The purpose of this Affidavit is to explain the plan that
I have developed for American Electric Power Service Corporation
("AEPSC") to perform the monitoring functions required under the merger
order (the "Monitoring Plan").
4. At the outset I should note that CRA has no corporate or
business affiliation with AEP or CSW or any their respective
subsidiaries and affiliates. Neither I nor any of my colleagues at CRA
has provided advice to the Applicants concerning their proposed merger.
Nor have we represented or provided consulting service to any other
market participant or competitor or customer of AEP or CSW. For the
duration of our service to AEPSC under the Monitoring Plan, we will not
undertake additional consulting services for AEP or any affiliate
thereof.
5. In order to implement the Monitoring Plan, I will be
assisted by other senior CRA consultants with extensive industry
experience in electric power markets, and power system planning,
design, implementation and operations. Indeed, certain of the
<PAGE> 24
-3-
team members have extensive experience in this area working for large
electric utility companies.
II. THE MONITORING PROPOSAL
6. Consistent with the Commission's order, I will implement a
monitoring plan to identify strategic actions by AEP to create binding
transmission constraints resulting in substantial increases in
wholesale prices. Such actions could be accomplished through
transmission operations and/or through generation operations.
Transmission actions would include unjustifiably derating transmission
facilities, strategically taking facilities out of service, and calling
for unjustified line loading relief (TLRs). On the generation side, the
strategic action that needs to be monitored is the operation of
generating resources out of economic merit or in a manner inconsistent
with good utility practice in order to create or exacerbate binding
transmission constraints, thereby driving up wholesale prices on the
constrained side of the facilities.
7. In order to determine whether such strategic actions were
taken by AEPSC, it will be necessary to routinely receive and review
information relating to AEP's recent operations. The type of
information that I contemplate that our monitoring team will review is:
(i) hourly output of the AEP generating resources; (ii) transmission
limits and deratings for monitored flowgates or other facilities that,
during the prior two years, have limited transmission capability; (iii)
the hourly flow over such limiting facilities; (iv) generation
redispatch and other actions taken by AEPSC to manage transmission
congestion; (v) generation and transmission outage data; and (vi)
information concerning the level of transactions and prices charged by
AEP (and its affiliates) and in the marketplace as a whole before and
after AEPSC implements TLRs
<PAGE> 25
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or other congestion management actions. We will work with AEPSC to
develop and implement data transfer protocols and procedures.
8. Our monitoring team also will develop and utilize various
screens and indices for reviewing, correlating and interpreting the
various information that is gathered. We intend to seek the input of
AEPSC, AEP customers, market participants and other interested persons
to develop such screens and indices. Should our review and analyses
indicate that further investigation is warranted, we will gather
additional information and seek explanations from AEPSC representatives
regarding the matters under investigation.
9. In addition to the information that we expect routinely to
gather from AEPSC, any interested party (including members of the
Commission's staff) may submit requests that we investigate specific
incidents or activities. In this regard, we will develop a
communications procedure to facilitate input from market participants.
The team will review any such requests and conduct further
investigations as it deems appropriate.
10. It will also be necessary to put in place procedures to
protect the confidentiality of information obtained through the
monitoring process. It would be any expectation that, except as
required by subpoena or formal process, all the information that is
gathered by our monitoring team that otherwise is not publicly
available will be treated as strictly confidential and not shared with
third parties (other than the Commission and its staff) absent the
consent of the entity that produced or prepared the material.
<PAGE> 26
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11. The monitoring team will submit to the Commission
semi-annually a report detailing the results of our findings. The
report will summarize the data that we reviewed and analyzed, evaluate
the performance of the AEP transmission system and the conduct of the
AEPSC transmission and generation functions, and comment on the overall
impact of AEPSC's transmission and generation activities on the
competitive performance of the wholesale market within AEP's control
area and immediately adjacent areas. In addition, to the extent
requested by the Commission, we would provide additional reports or
address individual inquiries and conduct briefings with the
Commission's staff.
Further Affiant sayeth not.
<PAGE> 27
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
American Electric Power Company ) Docket Nos. EC98-40-000,
and ) ER98-2770-000, and
Central and South West Corporation ) ER98-2786-000
State of _________________ )
)
County of _______________ )
AFFIDAVIT OF
I, ____________________, having first been duly sworn, do hereby depose and
state that the foregoing Affidavit of _______________ was prepared by me or
under my supervision and that the testimony given therein is true and correct to
the best of my information and belief as of the date of this Affidavit.
------------------------------
Subscribed and sworn before me, a Notary
Public in and for said State and County,
this _____ day of March 2000.
- ------------------------------------
Notary Public
<PAGE> 28
March 31, 2000
The Honorable David P. Boergers
Secretary
Federal Energy Regulatory Commission
888 First Street, N.E.
Washington, D.C. 20426
Re: American Electric Power Company and
Central and South West Corporation
Docket Nos. EC98-40-000, et al.
Dear David P. Boergers:
By separate filing of even date the Applicants in the above-referenced
proceeding reported to the Commission regarding the manner in which they propose
to implement certain of the interim mitigation measures required by the
Commission's March 15, 2000 Order. Attached to this letter, please find a
description of the means by which the Applicants will implement the interim
energy sales discussed at pages 27-28 of the Order.
Copies of this filing are being served on all parties to the restricted
service list.
Very truly yours,
Clark Evans Downs
<PAGE> 29
INTERIM ENERGY SALES
The Commission found that the Applicants' proposal to sell 250 MW of
energy and related capacity from the Frontera unit and 300 MW of system energy
in the Southwest Power Pool ("SPP") would offer reasonable and effective
mitigation of any merger-related increase in Applicants' market power prior to
the divestiture of the Frontera and the Northeastern generating facilities.
Order at 27. The Commission directed the Applicants to file, prior to
consummation of the merger, the terms and conditions under which the Applicants
would propose to make the interim sales, including "substantive information
about the 'market indicia' that will be used to determine replacement cost when
the interim purchaser is unable to purchase replacement energy during a recall
event." Order at 28. Only the 300 MW sale in the SPP is subject to recall by
Applicants. Term sheets for the SPP and Frontera interim sales, respectively,
are attached.
SPP INTERIM SALE
The Applicants will offer to sell 300 MW of capacity and associated
energy in the SPP on a financially firm basis. The minimum and maximum amounts
of capacity the Applicants will sell to any one buyer are 50 MW and 150 MW,
respectively. The energy price will be $14.00 for all hours. The successful
bidders will be expected to pay a negotiated monthly charge for the right to
take the energy to be sold. The initial sales will begin on May 15, 2000 and
will continue for a term of 24 months.
The Applicants may recall all or a portion of the energy to be sold
when necessitated by the declaration of a generation emergency. Any such recall
will be made only if necessary to maintain adequate power supply for the native
load retail and firm power wholesale customers of the CSW operating companies
and only after all alternatives to recall, such as cutting interruptible load,
discontinuing non-firm energy sales and making purchases from third parties,
have been exhausted. If the energy is recalled, the Applicants will compensate
the purchaser for
<PAGE> 30
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the purchaser's replacement cost. The replacement price shall be the actual
prices the buyers pay to purchase substitute energy. If the buyers are unable to
purchase substitute energy, the market price shall be equal to the published day
ahead price for the Into Entergy market or as otherwise mutually agreed.
The Applicants plan to issue the first solicitation for bids on the 300
MW interim energy sale on or before April 20, 2000 with the goal of executing
final contracts no later than May 15, 2000. Applicants will contract only with
those purchasers whose control of the energy to be sold will not cause HHI
levels to violate the Commission's Appendix A screening criteria.
ERCOT INTERIM SALE
The Applicants will carry out their commitment to make interim energy
sales out of the Frontera station by the already committed sale of 100 MW to the
Lower Colorado River Authority ("LCRA") and the sale of 190 MW to one or more
other counter-parties. When, in testimony filed in January 1999, the Applicants
committed to sell 250 MW from the Frontera unit as a mitigation measure, the
Frontera station was under construction. Frontera has a net summer rated
capacity of 470 MW and consists of two nominal 165 MW gas turbine generators and
a steam turbine generator. The gas turbines were placed in commercial operation
in July 1999. The gas turbines were taken off line last fall to permit the
construction of the steam turbine and are expected to be returned to service in
April 2000.
In ERCOT, load serving entities obtain transmission service ("planned
capacity transmission service") for a calendar year by designating planned
capacity resources to the ERCOT ISO by October 1 of the preceding calendar year.
In the summer of 1999, CSW Energy (through its power marketing affiliate) began
marketing Frontera capacity for use during the year 2000. These sales efforts
were addressed to ERCOT load serving entities that were known to have year 2000
planned capacity needs and who planned to meet those needs through purchased
<PAGE> 31
-3-
power arrangements. CSW Energy canvassed the ERCOT market including
investor-owned utilities, power marketers and those municipal and cooperative
utilities known to have year 2000 planned capacity needs. The potential buyers
that CSW Energy approached included the following:
- - Alfa/PEGI - Energy Transfer Group
- - Aquila - Garland Power and Light
- - Austin Energy - Lower Colorado River Authority
- - Brownsville (PUB) - LG&E Energy Marketing
- - Bryan Utilities - PECO
- - CFE - PG&E
- - City of Denton - Reliant Energy (Unregulated)
- - City Public Service (San Antonio) - Reliant HL&P (Regulated)
- - Constellation - Sharyland
- - Coral Energy - Southern Energy Marketing
- - Duke - South Texas Electric Cooperative
- - Dynegy - Tenaska
- - Enron - Texas-New Mexico Power Company
- - Entergy - TXU
In addition, CSW Energy listed the Frontera capacity on the "New Generation
Projects Under Development in ERCOT" section of the ERCOT ISO website. This list
is intended to facilitate communication between generators, load serving
entities and transmission providers. Several of the entities listed above
contacted CSW Energy after viewing this website.
As the result of this marketing effort, Frontera entered into a
contract to sell 180 MW to Tenaska Power Services Co. through December 31, 2000
and a contract to sell 100 MW to LCRA for a term from March 16, 2000 to February
15, 2001. Under the LCRA contract, LCRA pays a price for energy that reflects
the marginal operating cost of the Frontera station. The energy pricing is
similar to the energy pricing specified in the term sheet for the 190 MW sale.
LCRA also pays negotiated capacity charges for the night to take such energy and
in the event that the Frontera plant is not available LCRA's capacity payment
obligations are reduced. The energy is delivered to LCRA at the plant busbar.
<PAGE> 32
-4-
Applicants will offer to potential bidders an additional 190 MW of
Frontera unit contingent capacity and the right to take all the energy
associated with such capacity amount under arrangements that will leave Frontera
no residual right to energy not scheduled for delivery. Energy will be sold to
the purchaser at an energy price equal to the product of a heat rate of 7700
MMBTU/MWh times the Gas Daily Houston Ship Channel Midpoint price for the day of
delivery plus $0.07/mmbtu plus a variable O&M charge of $2.25/MWh. In addition,
the third-party purchaser will pay a start charge and a negotiated monthly
capacity charge.
The Applicants anticipate they will begin to solicit bids for the 190
MW contract by April 20, 2000 and execute the agreement by May 15, 2000. The
initial sales will begin on May 15, 2000 and continue to December 31, 2000. If
by December 31, 2000 the Frontera Plant will not have been sold to meet the
permanent mitigation provisions of the Commission's order, Frontera will enter
into an additional sale consistent with the order of at least 190 MW for a
period that will extend at least until the date of Frontera divestiture.
Applicants will sell the 190 MW only to those purchasers whose control of the
energy to be sold will not cause HHI levels to violate the Commission's Appendix
A screening criteria.
<PAGE> 33
SPP ENERGY SALE
OFFERED BY
AMERICAN ELECTRIC POWER
SERVICE CORPORATION, AS AGENT FOR
PUBLIC SERVICE COMPANY OF OKLAHOMA AND
SOUTHWESTERN ELECTRIC POWER COMPANY
DESCRIPTION This is a sale for resale of 300 MW of energy by Public
Service Company of Oklahoma ("PSO") and Southwestern
Electric Power Company ("SWEPCO") (PSO and SWEPCO are
referred to below collectively as "Seller") to ("Buyer").
Such sale will be made from the output of Seller's system
generation resources. The minimum amount of capacity that
will be sold to any one buyer shall be 50 MW. No buyer may
purchase more than 150 MW of capacity and associated energy.
BUYER MAY NOT RELY ON THE CAPACITY TO BE SOLD HEREUNDER TO
MEET THE PLANNING RESERVE RESPONSIBILITY OF AN ENTITY
SERVING LOAD IN THE SOUTHWEST POWER POOL ("SPP") AS PSO AND
SWEPCO WILL CONTINUE TO COUNT ON SUCH CAPACITY TO MEET THEIR
SPP PLANNING RESERVE OBLIGATIONS.
TERM The sale will begin on May 15, 2000. The contract will have
a term of 24 months.
CAPACITY PRICING Respondents to this Offer shall bid Capacity Prices stated
in $_______/KW-month for the right to take energy associated
with the capacity to be purchased. Buyer bids
$____________/KW-month for _____ MW.
ENERGY PRICING All energy scheduled for delivery hereunder shall be priced
at $14.00 for all hours.
RATE CHANGES The rates for capacity and energy shall be fixed rates that
are not subject to change by Seller through a unilateral
rate change filing with the Federal Energy Regulatory
Commission ("FERC") pursuant to the Federal Power Act.
Further, Buyer may not file a complaint with the FERC
seeking a reduction in rates or any change in the other
terms and conditions of sale pursuant to the Federal Power
Act.
ENERGY SCHEDULE Energy will be available 7x24 and Buyer sale shall be
obligated in each hour during the term of the sale to take
the amount of energy purchased. Schedules will be in
accordance with the scheduling rules of the Southwest Power
Pool, or its successor as the OASIS operator for the region.
LIMITED RECALL Seller may recall all or a portion of the energy to be sold
RIGHTS when necessitated by the declaration of a generation
emergency pursuant to SPP operating guides or the system
operating agreement among PSO,
<PAGE> 34
-2-
SWEPCO and the other CSW operating companies, or similar
agreement among the CSW operating companies or their
successors in interest. Any such recall will be made only
after cutting interruptible load, discontinuing non-firm
energy sales and making energy purchases from third parties.
If, as the result of such recall, the amount Seller
scheduled or delivers in any hour is less than the Contract
Quantity, then Seller shall pay Buyer an amount equal to:
(i) the product of the amount (whether positive or
negative), by which the "Replacement Purchase Price" differs
from the Contract Price (Replacement Purchase Price minus
Contract Price) and the amount by which the quantity
delivered by the Seller is less than the hourly Contract
Quantity; plus (ii) the amount of Transmission Charges, if
any, for transmission service downstream of the delivery
point, which the Buyer incurs to achieve the Replacement
Purchase Price, less the reduction, if any, in Transmission
Charges achieved as a result of the reduction in Seller's
Schedule or delivery (based upon Buyer's reasonable
commercial effort to achieve such reduction); plus (iii)
costs, limited to Transmission Charges and broker fees
caused by the Non-Performing Party's failure to perform. The
Replacement Purchase Price is the actual price. In the event
that Buyer is unable to purchase replacement energy, the
replacement price shall be equal to the day ahead price
published for the Into Entergy market or as otherwise
mutually agreed by the parties. If the total amount
calculated under this provision is less than zero, then
neither Party shall pay damages to the other Party. Such
damages shall not apply, however, if the failure to deliver
is the result of a force majeure event. For the purposes of
this provision, a force majeure event shall be an event that
is beyond Seller's control that renders Seller unable to
deliver the capacity and energy to the delivery point. Such
force majeure events shall not include a recall.
DELIVERY POINT(S) Energy will be delivered at PSO's Northeastern station.
Buyer and Seller may agree to an alternate delivery point
or a book-out of the transaction.
TRANSMISSION Buyer shall obtain transmission service and any ancillary
services required for transmission of the energy associated
with the capacity purchased hereunder on the Seller's
transmission system in accordance with the Southwest Power
Pool Open Access Transmission Tariff (the "SPP OATT") .
Buyer will be responsible for any transmission arrangements
for delivery of such energy beyond the Seller's control
area.
CONDITIONS Acceptance of any proposals pursuant to this offer is
PRECEDENT subject to review of and acceptance of such proposals by
AEPSC. AEPSC shall select such proposals from creditworthy
counter-parties as, in its judgment, provide maximum value
to Seller from the sale of capacity that is offered
hereunder. AEPSC must accept proposals for the purchase of
<PAGE> 35
-3-
all capacity and energy offered hereunder. Any transaction
that may result from this offer is contingent upon a
favorable credit review of the prospective purchaser by
AEPSC. Any such transaction is also contingent upon: (1)
negotiation of a definitive agreement that is acceptable to
AEPSC and to filing with and acceptance of that agreement by
the FERC; and (2) a determination by AEPSC that the sale to
the prospective purchaser will not result in a violation of
the FERC's Appendix A screening criteria relating to market
concentration.
<PAGE> 36
CAPACITY AND ENERGY
OFFERED BY
FRONTERA GENERATION LIMITED PARTNERSHIP
DESCRIPTION This is a sale for resale of 190 MW of
capacity and associated energy by Frontera
Generation Limited Partnership ("Seller") to
("Buyer"). Such sale will be made from the
output of Seller's 470 MW combined cycle
generating plant located near Mission, Texas
("Frontera Plant"). BUYER SHALL NOT RESELL
SUCH CAPACITY AND ENERGY FOR DELIVERY OUTSIDE
OF THE ELECTRIC RELIABILITY COUNCIL OF TEXAS
("ERCOT").
TERM The initial sale will begin on May 15, 2000
and end December 31, 2000.
CAPACITY PRICING Respondents to this Offer shall bid Capacity
Prices stated in $/kW-month for the right to
take energy associated with the capacity to be
purchased. Buyer bids $_____________/kW-month
for ____ MW.
ENERGY TYPE ERCOT Interchange Energy Classification
Type D-Unit Contingent
ENERGY PRICING All energy scheduled for delivery hereunder
shall be priced as follows:
1. Buyer shall pay to Seller monthly for
energy delivered to the Point(s) of Delivery,
an amount equal to the sum over every day of
the month of the following daily amount: the
product obtained by multiplying the sum of
Fuel Cost ($/MWh) plus O&M Cost ($/MWh), all
as defined below, times the quantity of energy
(in MWh) delivered on that day. In addition,
Buyer shall pay a start charge, as applicable.
2. Definitions.
"Fuel Cost" shall mean, for any Day, the
product of (i) the Fuel Price ($/MMBtu) for
such Day and (ii) Heat Rate (MMBtu/MWh)
"Fuel Price," unless otherwise agreed to by
the Parties, means the Midpoint, expressed in
$/MMBtu, reported in Gas Daily under the
heading "Houston Ship Channel," for the day
the energy is delivered, plus $0.07/MMBtu. If
a Midpoint is not reported for any day energy
was to be
<PAGE> 37
delivered, the index used to determine the
Fuel Price shall be the Midpoint, expressed in
$/MMBtu, reported in Gas Daily under the
heading "Houston Ship Channel," for delivery
on the first day following the day the energy
was delivered, plus $0.07/MMBtu.
"Heat Rate" shall be 7700 MMBtu/MWh
"O&M Cost" shall be $2.25/MWh
"Start Charge" shall be 562 mmbtu times Fuel
Price
RATE CHANGES Buyer may not file a complaint with the FERC
seeking a reduction in rates or any change in
the other terms and conditions of sale
pursuant to the Federal Power Act or the
Public Utility Commission of Texas pursuant to
the Public Utility Regulatory Act of Texas.
ENERGY SCHEDULE Buyer will each day provide to Seller by 8:00
a.m. Central Prevailing Time the schedule for
delivery of the contract quantity during each
hour of the following day. Schedules will be,
in accordance with the scheduling parameters
of the AEP System Open Access Transmission
Tariff (the "AEP OATT") and the scheduling
rules of the ERCOT ISO.
REMEDY FOR FAILURE TO DELIVER If Seller fails to deliver all or any part of
the energy sold hereunder, Seller shall pay
Buyer an amount equal to the sum of (a) the
positive difference, if any, between the
contract price of energy to be supplied by
Seller and the market price for a
corresponding amount of capacity and energy if
purchased in a commercially reasonable manner,
(b) any additional transmission costs incurred
by Buyer in obtaining substitute energy, and
(c) costs reasonably incurred by Buyer to
purchase energy from an alternative source.
Such damages shall not apply, however, if the
failure to deliver is the result of a force
majeure event. For the purposes of this
provision, a force majeure event shall be an
event that is beyond Seller's control that
renders Seller unable to deliver the capacity
and energy to the Delivery Point.
DELIVERY POINT Capacity and energy sold hereunder shall be
delivered at the Frontera Plant busbar.
TRANSMISSION Buyer shall obtain transmission service and
any ancillary services required for
transmission of the energy associated with the
capacity purchased hereunder on the AEP West
<PAGE> 38
system in accordance with the AEP OATT. Buyer
will be responsible for any transmission
arrangements for delivery of such energy
beyond the control area of Central Power and
Light Company and West Texas Utilities
Company.
CONDITIONS PRECEDENT Acceptance of any proposals pursuant to this
offer is subject to Seller's review of such
proposals. Seller shall select such proposal
or proposals from creditworthy counter-parties
as, in its judgment, provide maximum value to
Seller from the sale of capacity that is
offered hereunder. Seller must accept
proposals for the purchase of all capacity and
energy offered hereunder. Any transaction that
may result from this offer is contingent upon
a favorable credit review of the prospective
purchaser by Seller. Any such transaction is
also contingent upon: (1) negotiation of a
definitive agreement that is acceptable to the
Seller; and (2) a determination by Seller that
the sale to the prospective purchaser will not
result in violation of the FERC's Appendix A
screening criteria relating to market
concentration.
<PAGE> 39
J. A. BOUKNIGHT JR.
202.429.6222
[email protected]
March 31, 2000
The Honorable David P. Boergers
Secretary
Federal Energy Regulatory Commission
888 First Street, N.E.
Washington, D.C. 20426
Re: American Electric Power Company and
Central and South West Corporation
Docket Nos. EC98-40-000, et al.
Dear Mr. Boergers:
In accordance with Ordering Paragraph (B) of the Commission's March 15,
2000 order in the referenced proceeding ("Merger Order"), American Electric
Power Company ("AEP") and Central and South West Corporation ("CSW")
(collectively, the "Applicants") hereby submit their compliance filing
describing their plan to implement certain of the interim mitigation measures
required by the Merger Order. The Commission required that these interim
mitigation measures be submitted prior to the consummation of the merger.
<PAGE> 40
Among other things, the Merger Order required the Applicants to
implement two interim mitigation measures that would be in place from the date
that the merger is consummated through the date that the AEP transmission system
("AEP East") is subject to the operational control of a Commission-approved RTO.
First, the Merger Order required that AEP implement independent calculation and
posting of Available Transmission Capability ("ATC"). Consistent with these
directives, American Electric Power Service Corporation ("AEPSC")(3) has engaged
Southwest Power Pool, Inc.
- --------
(3) AEPSC is a service company that provides various services for the AEP
utility operating companies.
<PAGE> 41
("SPP") to make independent ATC calcultions and postings.(4) In addition, SPP
will have the additional responsibility for performing the OASIS function of
disposing of transmission service requests for customers (including marketers
affiliated with AEP) seeking service over the AEP East zone. The Merger Order
also required the Applicants to put in place an independent monitor that would
review the effects of AEP's generation dispatch on the loading of the AEP East
zone's constrained transmission facilities. For the monitoring requirement,
AEPSC has entered into an agreement with Dr. Douglas R. Bohi, who will be
responsible for overseeing the implementation of the attached Monitoring Plan
under which Dr. Bohi's team will review data of transmission constraints, the
effectiveness of redispatch to alleviate such constraints, and the impacts of
redispatch on the volume and price of energy before and after redispatch.
Each aspect of the compliance plan is discussed below. Submitted with
this compliance filing are (i) the Affidavit of Nicholas A. Brown, Senior Vice
President and Corporate Secretary of Southwest Power Pool, Inc. ("Brown
Affidavit"), and (ii) the Affidavit of Dr. Douglas R. Bohi, Vice President at
Charles River Associates ("Bohi Affidavit").
A. The SPP Agreement
The SPP Agreement sets out the scope of the services that SPP will
undertake for AEPSC in connection with the administration of AEPSC's open access
transmission tariff ("OATT") for services in the AEP East zone. The scope of
SPP's responsibilities and a description of the SPP and how it satisfies the
Commission's independence requirement are more fully described in the Brown
Affidavit. Mr. Brown, who is a Senior Vice President and Corporate Secretary of
SPP, will have overall management responsibility for overseeing the
administration of the SPP Agreement and will directly supervise those SPP
managers that will have day-to-day implementation responsibilities.
The SPP is an independent regional reliability council, security
coordinator, and tariff administrator for the interconnected electric systems in
the Southwest part of the United States. SPP currently administers the SPP
regional tariff that provides for all the services required under FERC's pro
forma tariff. In addition, SPP is responsible for performing calculations of
Total Transmission Capability ("TTC") and ATC, posting TTC and ATC and other
required information on the SPP OASIS, processing all requests for transmission
service under the tariff, and serving as the security coordinator for the
region. As the Commission is aware, on December 30, 1999, SPP filed in Docket
No. EL00-39 a petition seeking recognition as an Independent System Operator
consistent with Order 888, and as a Regional Transmission Organization fully
compliant with the requirements of Order 2000. As described in that filing and
in Mr. Brown's affidavit, while CSW has one member on the twenty-one member SPP
board, under the governance structure, no single company or sector (such as
transmission owners) can band together to force or veto any board action.
- ----------
(4) For informational purposes, the Applicants have attached a copy of the
agreement between AEPSC and SPP (the "SPP Agreement").
<PAGE> 42
The AEP East zone is not within the SPP, but two of the CSW operating
utilities (Southwestern Electric Power Company and Public Service Company of
Oklahoma) do operate within the SPP. As such, the SPP tariff provides for
service over the systems of those two CSW utilities. However, as Mr. Brown
explains, SPP's employees have completely severed any prior relationships with
member utilities. Thus, no SPP employees have any affiliation with the CSW
utilities and no CSW employees have any role in administering the SPP regional
tariff or in calculating or posting ATCs. Moreover, CSW and SPP employees
perform pursuant to the Standards of Conduct which, consistent with Order 889,
are on file with the Commission.
Under the SPP Agreement, SPP has agreed to calculate and post on the
AEP OASIS short-term and long-term ATC, and to process requests for transmission
service under the AEP OATT. SPP will perform these functions until AEPSC
transfers operational control of the AEP transmission system to a FERC-approved
RTO. Upon termination of the Agreement, SPP will work with AEPSC on the
transition to the RTO. The SPP Agreement provides that SPP will perform the
agreed-upon functions in accordance with Good Utility Practice, and to conform
to the applicable NERC and East Central Area Reliability Coordination Agreement
("ECAR") rules and regulations as well as to AEPSC's specific reliability
requirements and guidelines. Mr. Brown explains that the SPP personnel that will
perform the functions under the SPP Agreement will be experienced transmission
operators that are familiar with the AEP transmission system and the ECAR region
in general. This is extremely important in order to preserve reliability and
limit disruption to the greatest extent possible, especially considering that
AEPSC will be transferring important and integral functions for a large and
comprehensive transmission system such as that in the AEP East zone on the eve
of the summer peak system.
Prior to the actual time that SPP begins performing these functions,
SPP will establish operating protocols and practices, and will begin installing
equipment and establishing communication links necessary for SPP to perform the
required functions without interruption. The SPP Agreement further provides for
AEPSC to supply SPP all data that SPP deems necessary to perform the functions,
and enables SPP to enter into various hardware and software leases or licensing
agreements with AEPSC as SPP determines necessary.
In addition, the SPP Agreement requires that the required functions be
performed only by SPP employees. However, in order to ensure that SPP has access
to persons with broad knowledge of the AEP transmission system and expertise in
the ECAR rules and protocols, it is imperative that SPP have the ability and
discretion to seek to hire AEPSC employees to carry out the various functions
under the SPP Agreement. It should be stressed, however, that any former AEPSC
employees hired by SPP immediately will sever their employment with AEPSC
(although they will have six months to divest securities in any affiliate of
AEPSC.) Mr. Brown further explains that no employees that work for SPP and are
tasked to implement the SPP Agreement will have any financial interest in AEP
(including any affiliates) or in any "market participant" as that term is
defined in the new Order 2000 regulations. Likewise, no employees of SPP that
are performing any of the functions under the Agreement will share office space
with any transmission or marketing employees of AEPSC or any of its affiliates.
The Applicants submit that the SPP Agreement fully complies with the
Commission's requirements as to the TTC/ATC calculations and disposition of
transmission requests. SPP is an existing reliability council that already is
performing these functions for the transmission-
<PAGE> 43
owning utilities in its region. Indeed, SPP has sought recognition as an Order
2000-compliant RTO. SPP is staffed with skilled and highly-skilled personnel who
obviously have relevant experience and training in the functions to be provided
under the SPP Agreement. Moreover, AEPSC will make available to SPP employees
familiar with the AEP system, as well as the data, hardware, and software that
SPP deems necessary.
As to independence, SPP's employees have no financial interest in the
CSW utilities and likewise will have none in the AEP utility companies. While
SPP employees naturally will need access to AEPSC facilities, such as the
control center, the SPP Agreement provides explicitly that those SPP employees
that work at the AEPSC facilities will be subject to oversight by SPP managers,
will not share office space with AEPSC persons that perform merchant or
transmission reliability functions for AEPSC (or any of its affiliates).
Finally, all employees of SPP that perform the various functions under the SPP
Agreement will be treated as "transmission function employees" under FERC's
Order No. 889 Standards of Conduct and, therefore, will be restricted from
relating transmission reliability information to merchant employees of AEPSC (or
any marketing affiliates). And, all SPP employees are required to abide by the
Standards of Conduct which are on file with the Commission.
B. The Monitoring Plan
To address the Merger Order's requirements, AEPSC has engaged Dr.
Douglas R. Bohi to perform a monitoring function. Dr. Bohi will head a team from
Charles River Associates that will develop a plan to monitor to protect against
anticompetitive effects in electricity markets until a fully functional RTO is
available, and will submit to the Commission reports of its findings,
accompanied by supporting data. Dr. Bohi is an expert in the area of
competition, market power analysis and energy policy, having formerly served,
among other things, as the Chief Economist and Director of the Commission's
Office of Economic Policy.
Consistent with the Merger Order, Dr. Bohi will monitor whether AEP has
attempted to create binding transmission constraints with the idea of
substantially increasing prices in the wholesale marketplace. (A copy of Dr.
Bohi's Monitoring Plan is attached for informational purposes). As explained in
the Bohi Affidavit, such actions potentially could be accomplished through
transmission operations and/or through generation operations. Transmission
actions, for example, could include unjustifiable deration of transmission
facilities, strategically taking facilities out of service, or calling for
unjustified line loading relief (TLRs). On the generation side, the strategic
action that Dr. Bohi will monitor includes the operation of generating resources
out of economic merit or in a manner inconsistent with good utility practice in
an effort to create or exacerbate binding transmission constraints, which has
the effect of driving up wholesale prices on the constrained side of the
facilities.
In order to determine whether such strategic actions were taken, Dr.
Bohi's team routinely will receive and review information relating to AEP's
recent operations. Dr. Bohi explains that he contemplates that the monitoring
team will review: (i) the hourly output of the AEP generating resources; (ii)
transmission limits and deratings for monitored flowgates or other facilities
that, during the prior two years, have limited transmission capability; (iii)
the hourly
<PAGE> 44
flow over such limiting facilities; (iv) generation redispatch and other actions
taken by AEPSC to manage transmission congestion; (v) generation and
transmission outage data; (vi) information concerning wholesale transactions of
AEP (and affiliated) marketers before and after the implementation of TLRs or
other congestion management actions, and (vii) information concerning the level
of transactions and prices in the market place as a whole before and after AEPSC
implements TLRs or other congestion management actions.
The monitoring team also will develop and utilize various screens and
indices for reviewing, correlating and interpreting the various information that
is gathered. Dr. Bohi states the monitoring team intends to seek the input of
AEPSC, AEP customers, market participants and other interested persons to
develop such screens and indices. Should this review and analyses indicate that
further investigation is warranted, the monitoring team will gather additional
information and, perhaps, seek explanations from AEPSC representatives regarding
the matters under investigation. In addition to the information routinely
gathered from AEPSC, any interested party (including members of the Commission's
staff) may submit requests that the monitoring team investigate specific
incidents or activities. The team will review any such requests and conduct
further investigations as it deems appropriate.
The monitoring team will submit to the Commission semi-annually a
report detailing the results of its findings. The report will summarize the data
that was reviewed and analyzed, evaluate the performance of the AEP transmission
system and the conduct of the AEPSC transmission and generation functions, and
comment on the overall impact of AEPSC's transmission and generation activities
on the competitive performance of the wholesale market within AEPSC's control
area and immediately adjacent areas. In addition, to the extent requested by the
Commission, the monitoring team would provide additional reports or address
individual inquiries and conduct briefings with the Commission's staff. The
reports submitted to the Commission will contain all the findings and will
include workpapers and other relevant data necessary to support those findings.
Applicants submit that the Monitoring Plan meets the criteria specified
in the Merger Order and provides the Commission complete assurance that actions
taken by AEP that affect constrained transmission facilities will be thoroughly
reviewed by an independent and highly qualified monitoring team. Dr. Bohi is a
highly respected economist who has assembled a very strong team, none of the
members of which has any business affiliation with the Applicants. The
Commission will be provided, on a semi-annual basis, a comprehensive report of
Dr. Bohi's findings, complete with workpapers and relevant supporting data.
The Applicants also have attached to this compliance a Notice of Filing
for publication in the Federal Register with an accompanying electronic version.
This
<PAGE> 45
compliance filing has been served on all parties to this proceeding. If you have
any questions concerning this filing, please do not hesitate to contact any of
the undersigned.
Respectfully submitted,
-----------------------
Clark Evans Downs J.A. Bouknight, Jr.
Martin V. Kirkwood Douglas G. Green
Shelby Provencher Steven J. Ross
Jones, Day, Reavis & Pogue Steptoe & Johnson LLP
51 Louisiana Avenue, N.W. 1330 Connecticut Ave., N.W.
Washington, D.C. 20001 Washington, D.C. 20036
(202) 879-3939 (202) 429-6222
Attorneys for Central and South Carmen L. Gentile
West Corporation Thomas L. Blackburn
Bruder, Gentile & Marcoux, LLP
1100 New York Ave., N.W.
Suite 510 East
Washington D.C. 20005
(202) 783-1350
Attorneys for American Electric
Power Company, Inc.
cc: Restricted Service List
<PAGE> 46
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
American Electric Power Company ) Docket Nos. EC98-40-000,
and ) ER98-277-000, and
Central and South West Corporation ) ER98-2786-000
AFFIDAVIT OF
DOUGLAS R. BOHI
I. BACKGROUND
1. My name is Douglas R. Bohi. I am a Vice President of
Charles River Associates ("CRA"), an economics consulting firm. My
business address is Charles River Associates Incorporated, 600 13th
Street, N.W., Suite 700, Washington, DC 20005.
2. At CRA, I have served as an expert witness before state and
federal regulatory agencies on matters involving market power and
competition issues, transmission pricing and access, electric utility
mergers, and transportation,
14
<PAGE> 47
energy, and environmental policy. Previously, I served as Chief
Economist and Director of the Office of Economic Policy at the Federal
Energy Regulatory Commission, where I was responsible for developing
market-based approaches to electric regulation, and establishing
policies for granting utilities authority for charging
market-determined prices. Prior to joining CRA, I directed the Energy
and Natural Resources Division of Resources for the Future, Washington,
D.C. I also have served as a Senior Research Scientist for Economic
Policy for the Energy Division of Oak Ridge National Laboratory, and
Chairman of the Department of Economics at Southern Illinois
University. I have been an active member of the National Research
Council Committee on the National Energy Modeling System, and I also
serve on the editorial board of Resource and Energy Economics. I have
written eight books and numerous articles on energy issues. I received
my Ph.D. in Economics from Washington State University.
3. Under FERC's March 15, 2000 order addressing the proposed
merger between American Electric Power Company ("AEP") and Central and
South West Corporation ("CSW"), AEP is required to put in place
independent monitoring to monitor the effects of the dispatch of AEP
generation facilities on constrained transmission facilities and the
effects of the redispatch of generation on energy pricing and volume of
transactions. The purpose of this Affidavit is to explain the plan that
I have developed for American Electric Power Service Corporation
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("AEPSC") to perform the monitoring functions required under the merger
order (the "Monitoring Plan").
4. At the outset I should note that CRA has no corporate or
business affiliation with AEP or CSW or any their respective
subsidiaries and affiliates. Neither I nor any of my colleagues at CRA
have provided advice to the Applicants concerning their proposed
merger. Nor have we represented or provided consulting service to any
other market participant or competitor or customer of AEP or CSW. For
the duration of our service to AEPSC under the Monitoring Plan, we will
not undertake additional consulting services for AEP or any affiliate
thereof.
5. In order to implement the Monitoring Plan, I will be
assisted by other senior CRA consultants with extensive industry
experience in electric power markets, and power system planning,
design, implementation and operations. Indeed, certain of the team
members have extensive experience in this area working for large
electric utility companies.
II. THE MONITORING PROPOSAL
6. Consistent with the Commission's order, I will implement a
monitoring plan to identify strategic actions by AEP to create binding
transmission constraints resulting in substantial increases in
wholesale prices. Such actions could be accomplished through
transmission operations and/or through generation operations.
Transmission actions would include unjustifiably derating
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transmission facilities, strategically taking facilities out of
service, and calling for unjustified line loading relief (TLRs). On the
generation side, the strategic action that needs to be monitored is the
operation of generating resources out of economic merit or in a manner
inconsistent with good utility practice in order to create or
exacerbate binding transmission constraints, thereby driving up
wholesale prices on the constrained side of the facilities.
7. In order to determine whether such strategic actions were
taken by AEPSC, it will be necessary to routinely receive and review
information relating to AEP's recent operations. The type of
information that I contemplate that our monitoring team will review is:
(i) hourly output of the AEP generating resources; (ii) transmission
limits and deratings for monitored flowgates or other facilities that,
during the prior two years, have limited transmission capability; (iii)
the hourly flow over such limiting facilities; (iv) generation
redispatch and other actions taken by AEPSC to manage transmission
congestion; (v) generation and transmission outage data; and (vi)
information concerning the level of transactions and prices charged by
AEP (and its affiliates) and in the marketplace as a whole before and
after AEPSC implements TLRs or other congestion management actions. We
will work with AEPSC to develop and implement data transfer protocols
and procedures.
8. Our monitoring team also will develop and utilize various
screens and indices for reviewing, correlating and interpreting the
various information that is
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gathered. We intend to seek the input of AEPSC, AEP customers, market
participants and other interested persons to develop such screens and
indices. Should our review and analyses indicate that further
investigation is warranted, we will gather additional information and
seek explanations from AEPSC representatives regarding the matters
under investigation.
9. In addition to the information that we expect routinely to
gather from AEPSC, any interested party (including members of the
Commission's staff) may submit requests that we investigation specific
incidents or activities. In this regard, we will develop a
communications procedure to facilitate input from market participants.
The team will review any such requests and conduct further
investigations as it deems appropriate.
10. It will also be necessary to put in place procedures to
protect the confidentiality of information obtained through the
monitoring process. It would be my expectation that, except as required
by subpoena or formal process, all the information that is gathered by
our monitoring team that otherwise is not publicly available will be
treated as strictly confidential and not shared with third parties
(other than the Commisson and its staff) absent the consent of the
entity that produced or prepared the material.
11. The monitoring team will submit to the Commission
semi-annually a report detailing the results of our findings. The
report will summarize the data that
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we reviewed and analyzed, evaluate the performance of the AEP
transmission system and the conduct of the AEPSC transmission and
generation functions, and comment on the overall impact of AEPSC's
transmission and generation activities on the competitive performance
of the wholesale market within AEPS's control area and immediately
adjacent areas. In addition, to the extent requested by the Commission,
we would provide additional reports or address individual inquiries and
conduct briefings with the Commission's staff.
Further Affiant sayeth not.
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UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
American Electric Power Company ) Docket Nos. EC98-40-000,
and ) ER98-277-000, and
Central and South West Corporation ) ER98-2786-000
State of ________ )
)
County of _____ )
AFFIDAVIT OF
I, , having first been duly sworn, do hereby depose and state that the
foregoing Affidavit of was prepared by me or under my supervision and that the
testimony given therein is true and correct to the best of my information and
belief as of the date of this Affidavit.
------------------
<PAGE> 53
Subscribed and sworn before me, a Notary
Public in and for said State and County, this
__ day of March, 2000.
- ---------------------
Notary Public
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MARKET MONITORING PLAN
AMERICAN ELECTRIC POWER COMPANY
1. PURPOSE AND OBJECTIVES OF THE PLAN
1.1 PURPOSE OF THE PLAN
The purpose of the monitoring plan is to identify conduct that departs
substantially from rational behavior in a workably competitive market or from
good utility practice, and that results in a significant increase in wholesale
prices or the foreclosure of competition by rival suppliers.
The Market Monitor will provide independent and impartial monitoring and
reporting on: (1) generation dispatch of AEP East and loadings on constrained
transmission facilities in relevant areas; (2) details on binding transmission
constraints in the relevant areas, such as transmission refusals and TLR events,
or other information as called for; (3) operating guides and other procedures to
relieve transmission constraints in the relevant areas and the effectiveness of
these procedures in relieving constraints; and (4) other information required to
determine the effects of generation dispatch on transmission constraints and
associated effects on market prices.
The Market Monitor will provide semi-annual reports to the Federal Energy
Regulatory Commission ("FERC") that will provide the foregoing market data and
the results of analyses of that data undertaken by the Market Monitor. The
Market Monitor would also respond to requests from FERC for additional data and
analysis on an as-required basis, and to complaints by customers and competitors
of AEP.
1.2 ANTICOMPETITIVE CONDUCT TO BE IDENTIFIED
The anticompetitive conduct that the monitoring plan will be designed to
identify refers to strategic, unjustifiable actions the company may take to
cause transmission constraints to bind that result in a substantial increase in
wholesale electric prices. Such actions may relate to either the operation of
transmission or generation facilities:
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A) Transmission operations - taking actions in the operation the
transmission system that are not technically justified by its
obligation to maintain the reliability and stability of the
system. These actions include derating transmission facilities
unjustifiably, taking transmission facilities out of service
strategically or calling for unjustifiable line loading relief.
B) Generation operations - operating generation facilities in a
manner that departs substantially from economic dispatch or is
inconsistent with good utility practice, and shifts flows on the
network in order to create a binding transmission constraint.
1.3 IMPLEMENTATION OF THE PLAN
The market monitoring plan will be implemented by an independent expert that
shall report its findings to the FERC. The Market Monitor shall not be obligated
to review its findings or analysis with AEP prior to submission to FERC,
although the Market Monitor shall obtain AEP's comments before reaching final
conclusions.
The market monitoring plan will be implemented when the merger between AEP and
CSW is consummated, and will continue until the Commission-approved RTO is
established.
2. ACCESS TO DATA AND INFORMATION
2.1 ROUTINELY COLLECTED DATA AND INFORMATION
For purposes of carrying out this plan, the Market Monitor shall routinely
receive data and information generated by AEP in the course of its operations.
These data and information shall include:
- - Hourly output of each of AEP's generating units
- - Transmission limits (including temporary deratings) on each of the
monitored flowgates or other transmission facilities that have been
limiting over the previous two years
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- - Hourly flow over each of the monitored flowgates or other transmission
facilities that have been limiting over the previous two years
- - Redispatch of generation or other actions taken to manage transmission
congestion
- - Generation and transmission facility outage data
- - Records of complaints by customers and competitors of AEP regarding
transmission access
2.2 ADDITIONAL DATA AND INFORMATION
The Market Monitor shall also have reasonable access to additional information
that may be necessary to investigate issues identified in the course of
monitoring the data routinely provided by AEP, to investigate issues raised by
FERC, or to investigate complaints of customers and competitors of AEP.
AEP will designate individuals in the generation, transmission, and marketing
units of the Company that will serve as points of contact for providing
information to the Market Monitor.
2.3 Confidentiality of Data
The Market Monitor shall use all reasonable procedures necessary to protect and
preserve the confidentiality of all information obtained in connection with the
implementation of the Plan, provided that such information is not available from
public sources. Except as may be required by subpoena or other compulsory
process, the Market Monitor shall not disclose confidential information to any
person or entity without the prior written consent of AEP. Upon receipt of a
subpoena or other compulsory process for the disclosure of confidential
information, the Market Monitor shall promptly notify AEP and shall provide all
reasonable assistance requested by AEP to prevent disclosure.
3. PERFORMANCE INDICES AND SCREENS
3.1 Development of Indices and Screens
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The Market Monitor shall develop and utilize indices or other screens for
reviewing the data or other information collected in connection with the
implementation of this plan. All proposed or adopted indices and screens shall
be filed as an attachment to this plan.
3.2 Consultation with Market Participants
AEP, its customers, its competitors, or other interested parties may submit
comments or alternative proposed indices or screens for review of the data or
other information collected in connection with the implementation of this plan.
3.3 Use of Indices and Screens
As much as practicable, the Market Monitor shall review data or other
information collected in connection with implementation of this plan in
accordance with the indices or screens adopted as specified above. However, the
Market Monitor may conduct other reviews or evaluations of such data or
information as appropriate for the effective implementation of this plan. When
the screens and indices indicate that further investigation is warranted, the
Market Monitor shall gather additional data as specified in section 2.2 and
shall seek an explanation from AEP regarding the issue under investigation.
4. COMPLAINTS AND REQUESTS FOR INVESTIGATIONS
Any interested party or FERC may submit a reasonable request to the Market
Monitor to conduct an investigation. Such submissions or requests may be made on
a confidential basis. The Market Monitor may request additional relevant
information from the party as a condition of undertaking any further
investigation. The Market Monitor shall decline to take further action or shall
carry out such investigation as deemed appropriate. The results of
investigations shall be submitted to FERC as provided in section 5.2. The Market
Monitor shall include a summary of its actions, and decisions not to act, in its
semi-annual report to FERC.
5. REPORTS
5.1 SEMI-ANNUAL REPORT
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The Market Monitor shall prepare and submit to FERC a semi-annual report
summarizing the Market Monitor's analysis and evaluation of the operation of
AEP's transmission system, and the competitive performance of the wholesale
power markets within AEP's control area.
5.2 OTHER REPORTS OR FILINGS
The Market Monitor shall submit to FERC such other reports as may be requested
by the FERC or that, based on an investigation conducted by the Market Monitor,
raise significant competitive issues.
6. BUDGET
AEP will provide the Market Monitor a budget sufficient to maintain a database
of routinely collected information, to conduct screen analyses and follow-up
investigations, and to prepare semi-annual reports to FERC. If additional funds
are required to conduct investigations or produce additional reports, the Market
Monitor will notify AEP of the requirement and allow AEP the opportunity to
request that FERC determine that the additional costs are reasonably necessary
to accomplish the objectives of this plan.
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<PAGE> 59
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
American Electric Power Company ) Docket Nos. EC98-40-000,
and ) ER98-277-000, and
Central and South West Corporation ) ER98-2786-000
NOTICE OF FILING
(April __, 2000)
On March 31, 2000, American Electric Power Company and Central and
South West Corporation made their compliance filing as required under Ordering
Paragraph (B) of the Commission's March 15, 2000 order in the referenced
dockets. Copies of the filing were served on all parties to the proceeding.
Any person desiring to be heard or to protest this filing should file a
petition to intervene, comments, or protest with the Federal Energy Regulatory
Commission, 888 First Street, N.E., Washington, D.C. 20426, in accordance with
Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 CFR
Section 385.211 and 18 CFR Section 385.214). All petitions to intervene,
comments, or protests should be filed on or before _________. Comments and
protests will be considered by the Commission in determining the appropriate
action to be taken, but will not serve to make protestants parties to the
proceeding. Any person wishing to become a party must file a petition to
intervene. Copies of the filing are on file with the Commission and are
available for public inspection. This filing also may be viewed on the Internet
at http://www.ferc.fed.us/online/rims.htm (call 202-208-2222 for assistance).
______________________
David P. Boergers
Secretary
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B. AGREEMENT
This Agreement is entered into this ___ day of March, 2000, between
American Electric Power Service Corporation ("AEPSC"), a New York corporation
and Southwest Power Pool, Inc. ("SPP"), an Arkansas non-profit corporation,
which are sometimes individually referred to herein as a "Party" and
collectively as "Parties".
WHEREAS, AEPSC is a service company providing services for the
affiliated companies of the American Electric Power ("AEP") System, a multistate
public utility holding company system registered under the Public Utility
Holding Company Act of 1935; and
WHEREAS the operating companies of the AEP system own, among other
things, an integrated electric transmission system, which they use to provide
electric service to their customers, and to provide non-discriminatory open
access transmission service pursuant to an open access transmission Tariff
("OATT") filed with and subject to the jurisdiction of the Federal Energy
Regulatory Commission ("FERC"); and
WHEREAS, AEPSC as agent for the AEP operating companies, administers
the OATT, which administration includes the determination and public posting of
Total Transmission Capability ("TTC") and Available Transmission Capability
("ATC"); and the acceptance and approval or denial of reservations for
transmission service;
WHEREAS SPP is an independent Regional Reliability Council, security
coordinator, and tariff administrator for interconnected electric systems in the
Southwest part of the United States; and;
WHEREAS, in order to fulfill certain conditions specified by the FERC
in an Opinion and Order ("Opinion No. 442") conditionally approving a merger
between companies of the AEP System and Companies of the Central and South West
System ("AEP/CSW Merger"), AEPSC wishes to transfer control of certain functions
as described in this Agreement related to its administration of its OATT in the
East Zone of its transmission system to an independent party; and
WHEREAS, SPP is independent from AEPSC, possesses the necessary
competency and experience to perform the functions in question and is willing to
perform such functions under the terms and conditions of this Agreement;
NOW THEREFORE, in consideration of the mutual promises contained
herein, and other good and valuable consideration, the receipt of which is
hereby acknowledged, the Parties agree as follows:
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SECTION 1 - SCOPE OF SERVICES.
1.1 SPP shall perform the following functions on behalf of AEPSC,
associated with administration of the OATT in the AEP East Zone: (i) Long-term
ATC calculation and posting; (ii) Short-term ATC calculation and posting and
(iii) acceptance and approval or denial of reservations for transmission
service.
SECTION 2 - INDEPENDENCE.
2.1 All functions shall be performed by employees of SPP. No such
employees shall be employed by AEPSC or any affiliate of AEPSC, or have a
financial interest in any Market Participant as defined in 18 C.F.R.
Section 35.34 (a) (2). Any employee owning securities in any affiliate of AEPSC
or any Market Participant shall divest such securities within six months of his
or her employment by SPP. Nothing in this section shall be interpreted to
preclude any such SPP employee from indirectly owning securities issued by any
affiliate of AEPSC or any Market Participant through a mutual fund or similar
arrangement (other than a fund or arrangement specifically targeted toward the
electric industry or the electric utility industry or any segment thereof) under
which the employee does not control the purchase or sale of such securities.
Participation in a pension plan of AEPSC or any affiliate of AEPSC or any Market
Participant shall not be deemed to be a direct financial interest if the plan is
a defined-benefit plan that does not involve ownership of the securities.
2.2 No employees of SPP performing such functions shall share office
space with any transmission/reliability employee or merchant employee of AEPSC
or of any affiliate of AEPSC, or those of any Market Participant.
2.3 All employees of SPP performing functions on behalf of AEPSC under
this Agreement shall be treated, for purposes of the FERC's Standards of Conduct
set forth in 18 C.F.R. Section 37.4, as the equivalent of
transmission/reliability employees of AEPSC, and all restrictions relating to
information sharing and other relationships between merchant employees of AEPSC
or its affiliates and transmission/reliability employees of AEPSC or its
affiliates shall apply to such employees. Such employees shall also abide by the
SPP Standards of Conduct.
SECTION 3 - COMPENSATION, BILLING AND PAYMENT.
3.1 AEPSC shall reimburse SPP for all reasonable and necessary costs
incurred by SPP in performing functions on behalf of AEPSC pursuant to this
Agreement. Reimbursable expenses shall include employee salaries and benefits,
office space, supplies and equipment, computer hardware and software lease costs
and other information technology costs, reasonable travel and other business
expenses, legal, accounting and other necessary corporate services [others?].
Such expenses shall be directly assigned to SPP's performance of its
responsibilities under this agreement when possible, and shall be based upon
time billing or other reasonable allocation methods when such direct assignment
is not possible.
3.2 SPP shall render to AEPSC monthly statements by regular mail,
facsimile, electronic mail or other acceptable means. Such statement shall set
forth any reimbursable costs incurred
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during the month in question by SPP. AEPSC shall make payment of the amount
shown to be payable by AEPSC by wire transfer to an account specified by SPP not
later than the twentieth (20th) day after receipt of the statement, unless such
day is not a business day, in which case AEPSC shall make payment on the next
business day. All such payments shall be deemed to be made when said wire
transfer is received by SPP. Overdue payments shall accrue interest daily at the
then current prime interest rate (the base corporate loan interest rate)
published in the Money and Investing Section of the Wall Street Journal, or, if
no longer published, in any mutually agreeable publication, plus 2% per annum,
from the due date of such unpaid amount until the date paid.
3.3 Upon the occurrence of a default, SPP may terminate this Agreement.
In the event of a billing dispute between the Parties, SPP will proceed to
perform its responsibilities under this Agreement as long as AEPSC (i) continues
to make all payments not in dispute, and (ii) pays into an independent escrow
account the portion of the invoice in dispute, pending resolution of such
dispute.
3.4 SPP shall allow AEPSC access to SPP's books and records, at
reasonable times and under reasonable conditions, as necessary to verify
transactions and billings under this agreement. SPP's books and records related
to this agreement shall be subject to and part of the SPP's annual audit
performed under National Accounting Standards with results made available to
AEPSC. SPP shall maintain such books and records for one year after termination
of expiration of this Agreement or longer if necessary to resolve a pending
dispute.
SECTION 4 - TERM AND TERMINATION.
4.1 The initial term of this Agreement shall begin on the date that it
has been executed by both Parties and shall end on May 31, 2001. During the
initial term, the Agreement may be terminated upon three months' notice if AEPSC
reasonably determines that the AEP/CSW Merger will not be consummated. SPP shall
be compensated for reasonable costs incurred prior to such cancellation. After
the initial term, the Agreement shall continue in effect for periods of one
month until terminated by AEPSC by giving at least three months' written notice.
The Parties may mutually agree to allow a shorter notice period, so long as SPP
is compensated for any costs it may incur as a result of such earlier
termination.
4.2 SPP shall begin performing the functions required by Section 1.1 at
1200 hours on the earlier of June 1, 2000 or the date upon which the AEP/CSW
Merger is consummated ("Date of Transfer") and shall cease performing such
functions at 1200 hours on the date the Agreement expires or is terminated,
except as otherwise agreed pursuant to Section 4.4.
4.3 It is the intent of the Parties to allow the transfer of functions
from AEPSC to SPP to occur without any interruption in the normal administration
of the OATT. To this end, the Parties shall, prior to the Date of Transfer,
cooperate to establish the necessary practices, routines, installation of
equipment, establishment of communication links, and all other activities
necessary to allow SPP to begin perform its required functions without any such
interruption.
4.4 The Parties recognize that it is the intention of AEPSC to transfer
to the Alliance Regional Transmission Organization ("RTO") the functions being
performed by SPP for AEPSC
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pursuant to this Agreement, when the Alliance RTO becomes operational, which is
expected to occur in 2001. The notice and termination provisions in Section 4.1
are intended to facilitate such transfer. The Parties shall cooperate to
facilitate the intended transfer, including agreement upon an alternative time
at which SPP ceases to perform its required functions under this Agreement, if
necessary. AEP shall not give notice of termination except to transfer the
functions described in Section 1.1 to an RTO or other independent party.
4.5 If the FERC places additional conditions on the AEP/CSW merger, or
interprets existing conditions in a manner that causes this Agreement to be
burdensome to AEPSC, in AEPSC's sole judgment, then the Parties shall negotiate
in good faith to amend this Agreement so as to remove such burdens, and if
unable to agree on such amendments, AEPSC may terminate this Agreement during
the initial term upon three months' notice. SPP shall be compensated for
reasonable costs incurred prior to such cancellation.
SECTION 5 - STANDARD OF PERFORMANCE.
5.1 SPP shall perform the functions specified in this Agreement in
accordance with Good Utility Practice and shall conform to applicable
reliability criteria, policies, standards, rules regulations and other
requirements of SPP, NERC and the East Central Area Reliability Coordination
Agreement ("ECAR"), AEPSC's specific reliability requirements and operating
guidelines (to the extent these are not inconsistent with other requirements
specified in this paragraph) and all applicable requirements of federal and
state regulatory authorities.
SECTION 6 - DATA, SYSTEMS AND PERSONNEL.
6.1 AEPSC shall supply to SPP, both initially and throughout the term
of this Agreement, all data that SPP deems necessary to perform the functions
required to be performed under this Agreement. The Parties shall agree upon the
necessary data and the format and manner in which it shall be provided prior to
the Date of Transfer.
6.2 AEPSC shall reimburse SPP in accordance with Section 3 for computer
hardware and software and any incremental licensing costs necessary to allow SPP
to perform its responsibilities under this Agreement. Such arrangements may
involve hardware and/or software lease and/or maintenance agreements with AEPSC,
as determined by SPP.
6.3 The Parties recognize that to allow SPP to begin performing its
responsibilities on the Date of Transfer, in accordance with Section 4.3 and
4.4, it may be necessary for it to hire certain personnel who have previously
been employed by AEPSC. The Parties shall cooperate to assure, insofar as
possible, the availability of such personnel. All such former employees of AEPSC
shall comply with the independence requirements set forth in Section 2.
SECTION 7 - WAIVER OF LIABILITY AND INDEMNIFICATION.
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7.1 SPP, its directors, officers, agents and employees shall not be
liable to AEPSC for damages arising out of or related to performance of SPP's
obligations under this Agreement; provided, however, that this section shall not
apply to actions which are unlawful, undertaken in bad faith, or are the result
of gross negligence or willful misconduct.
7.2 AEPSC hereby agrees to indemnify and hold harmless SPP, its
directors, officers, agents and employees against and from any and all claims,
demands, causes of action, losses and liabilities (including any cost and
expense of litigation and reasonable attorneys fees incurred by SPP in defending
any action, suit or proceeding, provided that SPP affords AEPSC a reasonable
opportunity in such action, suit or proceeding to conduct SPP's defense and to
approve any settlement agreements) for or on account of (i) injury, bodily or
otherwise, to, or the death of, persons, or for damage to, or destruction that
arises from negligent acts of AEPSC associated with (a) facilities, property and
equipment owned or controlled by AEPSC or ifs affiliates, or AEPSC's operation
and maintenance thereof; (b) the transmission and delivery of electricity by
AEPSC; and (ii) damages arising out of or related to performance by SPP of its
obligations under this Agreement, except to the extent that such claims,
demands, causes of action, losses and liabilities are attributable to actions of
SPP or its directors, officers, agents or employees which are unlawful,
undertaken in bad faith, or are the result of gross negligence or willful
misconduct.
SECTION 8 - DISPUTE RESOLUTION.
8.1 Any dispute under this Agreement shall be resolved in accordance
with the dispute resolution procedures set forth in Section 3.13 of the SPP
Bylaws. For purposes of such disputes, AEPSC shall be regarded as a "consenting
non-member".
SECTION 9 - DATA MANAGEMENT.
9.1 "Data" means all information, text, drawings, diagrams, images or
sounds which are embodied in any electronic or tangible medium and which are
supplied or in respect of which access is granted to SPP by AEPSC under this
Agreement
9.2 "Processes" means software, base data models and operating
procedures for software or base data models.
9.3 SPP acknowledges that AEPSC's Data and Processes are the property
of AEPSC and AEPSC hereby reserves all Intellectual Property Rights which may
subsist in AEPSC's Data and Processes.
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SPP shall not delete or remove any copyright notices contained within or
relating to AEPSC's Data.
9.4 Having due regard for the nature of their respective obligations
under this Agreement:
9.4.1 SPP shall use its best efforts to preserve the integrity of
AEPSC's Data and Processes, to prevent any corruption or loss of
AEPSC's Data, and
9.4.2. AEPSC shall use its best efforts to preserve the integrity of
AEPSC's Data and Processes by, as a minimum, continuing to employ its
own established internal procedures in relation to the same.
9.5 Without limiting the foregoing obligations of either Party, AEPSC
shall reasonably assist SPP in establishing measures to preserve the integrity
and prevent any corruption or loss of AEPSC's Data, and shall reasonably assist
SPP in the recovery of any corrupted or lost data.
9.6 SPP shall retain and preserve AEPSC's Data until such data is
transferred as a result of AEP's membership in an RTO. At the end of the
retention period, SPP shall request AEPSC's approval before disposing of AEPSC's
Data. If AEPSC refuses to approve of the disposal, SPP may deliver AEPSC's Data
retained information to AEPSC at AEPSC's expense. III.
SECTION 10 - INSURANCE.
10.1 SPP shall furnish and require its Sub-contractors to furnish
insurance listed in sections 10.11 through 10.14. Insurance shall be placed with
insurance carriers acceptable to AEPSC, such acceptance not to be unreasonably
withheld. SPP shall maintain and
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cause its Sub-contractors to maintain this insurance at all times during the
performance of this Agreement:
10.1.1 coverage for the legal liability of SPP or its Sub-contractors
under the workers' compensation and occupational disease law of the
state in which the services are performed according to the following:
10.1.1.1 in the states of Ohio and West Virginia, SPP or its
Sub-contractors shall be contributors to the state workers'
compensation fund and shall furnish a certificate to that
effect.
10.1.1.2 in states other than Ohio or West Virginia, SPP or
its Sub-contractors shall maintain an insurance policy for
workers' compensation from an insurance carrier approved for
contracting workers' compensation business in the state in
which the services are to be performed.
10.1.1.3 if SPP or its Sub-contractor is a legally permitted
and qualified self-insurer in the state in which the Services
are to be performed, it may furnish proof that it is such a
self-insurer in lieu of submitting proof of insurance.
10.1.2 commercial general liability insurance with limits of not less
than $1,000,000 (one million dollars) each occurrence and aggregate.
10.1.3 professional liability insurance with a limit of not less than
$30,000,000 (thirty million dollars) each occurrence and aggregate,
providing coverage for claims arising out of the performance of
professional services under this Agreement and resulting from any
error, omission, or negligent act for which SPP is held liable. SPP
shall maintain this insurance for a minimum period of 5 (five) years
after the completion of the Agreement.
10.1.4 property insurance with a limit of liability necessary to
restore and replace all physical and intellectual assets necessary to
the Services under this Agreement including AEPSC Data. This insurance
shall include, but not be limited to the following coverages:
10.1.4.1 mechanical breakdown and artificially generated
electrical current;
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10.1.4.2 changes in temperature and humidity;
10.1.4.3 computer viruses;
10.1.4.4 off-premises services;
10.1.4.5 transportation of goods;
10.1.4.6 loss of project (to protect the physical damage to R&D
property, as well as, additional costs to recreate, restore and
reproduce the damaged property);
10.1.4.7 delayed introduction of product (to protect loss from delays
in bringing the Services to AEPSC); and
10.1.4.8 extended period of indemnity (to extend business income period
of indemnity for whatever reasonable time needed to restore/resume
operations after a loss.);
10.2 SPP shall submit two copies of certificates of insurance for the
insurance provided in Sections 10.1.1 through 10.1.4. Such certificates shall
state that the insurance carrier has issued the policies providing for the
insurance specified herein, that such policies are in force and that the
insurance carrier will give AEPSC 30 (thirty) calendar days prior written notice
of any material change in or cancellation of such policies. If such insurance
policies are subject to any exceptions to the terms specified herein, such
exceptions shall be explained in full in such certificates. AEPSC may, at its
discretion, require SPP to obtain insurance policies that are not subject to any
exceptions.
10.3 Insurance policies written on a "claims-made" basis shall be
maintained by SPP or its Sub-contractors for a minimum of 5 (five) years after
completion of the Services under this Agreement.
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10.4 SPP and its Sub-contractors shall obtain waivers of subrogation on
all their insurance whether required by this Agreement or in excess of the
Agreement requirements such waivers shall be for the benefit of AEPSC and its
affiliated companies. Notwithstanding the foregoing, AEPSC shall not require
waiver of subrogation on commercial general liability, professional liability
and workers compensation. Furthermore, AEPSC shall not require waiver of
subrogation on SPP and its Sub-contractors business auto policy provided that it
follows the industry standard definition of "insured" which includes AEPSC's
usage with permission. SPP and its Sub-contractors shall obtain a waiver of
subrogation on such policies as property, inland marine and crime.
SECTION 11 - CONFIDENTIALITY.
11.1 Both Parties hereby agree that:
11.1.1 "Confidential Information" means all information designated as
such by either Party in writing together with all other information
which relates to the business, affairs, products, developments, trade
secrets, know-how, personnel, customers and suppliers of either Party
or information which may reasonably be regarded as the confidential
information of the disclosing Party.
11.1.2 any person employed or engaged by the Parties (in connection
with this Agreement in the course of such employment or engagement)
shall only use Confidential Information for the purposes of this
Agreement;
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11.1.2.1 any person employed or engaged by either SPP or AEPSC
(in connection with this Agreement in the course of such
employment or engagement) shall not disclose any Confidential
Information to any third party without the prior written
consent of the other. 18.
11.1.3 both Parties shall take all necessary precautions to ensure that
all Confidential Information is treated as confidential and not
disclosed (save as aforesaid) or used other than for the purposes of
this Agreement by their employees, servants, agents or sub-contractors.
11.2 The provisions of above Clause shall not apply to any information
which:
11.2.1 is required by the OATT or FERC regulation to be made publically
available.
11.2.2 is or becomes public knowledge other than by breach of this
Clause;
11.2.3 is in the possession of the receiving Party without restriction
in relation to disclosure before the date of receipt from the
disclosing Party;
11.2.4 is received from a third party who lawfully acquired it and who
is under no obligation restricting its disclosure;
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11.2.5 is independently developed without access to the Confidential
Information, provided that such independent development can be
evidenced; or
11.2.6 is required to be disclosed by law, regulatory authority or
stock exchange.
11.3 AEPSC's Data shall be regarded as Confidential Information and
SPP's rights with respect to the use, sale, reproduction, modification and
distribution of the same shall be limited to the extent necessary so as to
enable SPP to fulfill its obligations under this Agreement.
11.4 Nothing in this Clause shall prevent SPP or AEPSC from using data
processing techniques, ideas and know-how gained during the performance of this
Agreement in the furtherance of its normal business, to the extent that this
does not relate to a disclosure of AEPSC's Data, any data generated from AEPSC's
Data, a disclosure of any Confidential Information, or an infringement by AEPSC
or SPP of any Intellectual Property Right.
SECTION 12 - FORCE MAJEURE.
12.1 For the purposes of this Agreement the expression "Force Majeure"
shall mean any cause affecting the performance by a Party of its obligations
arising from acts, events, omissions, or happening which are beyond its
reasonable control including (but without limiting the generality thereof)
governmental regulations, fire, flood, or any disaster or a labor dispute.
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12.2 Neither Party shall in any circumstances be liable to the other
for any loss of any kind whatsoever including but not limited to any damages
whether directly or indirectly caused to or incurred by the other Party by
reason of any failure or delay in the performance of its obligations hereunder
which is due to Force Majeure. If SPP fails to perform or is delayed in
performing due to an act of Force Majeure, AEPSC shall be entitled to a refund
of any advance payments made up to the date such Force Majeure event occurs and
shall not be required to make further payments until such time as SPP resumes
its full performance. Notwithstanding the foregoing, each Party shall use all
reasonable endeavors to continue to perform, or resume performance of, such
obligations hereunder for the duration of such Force Majeure event. If SPP fails
to perform or is delayed in performing its obligations due to Force Majeure,
AEPSC may during the period of Force Majeure, utilize a third party to perform
SPP's obligations. SPP shall use reasonable efforts to cooperate with AEPSC in
effecting a transition to such alternative services.
12.3 If either of the Parties shall become aware of circumstances of
Force Majeure which give rise to or which are likely to give rise to any such
failure or delay on its part it shall forthwith notify the other by the most
expeditious method then available and shall inform the other of the period which
it is estimated that such failure or delay shall continue.
12.4 It is expressly agreed that any failure by SPP to perform or any
delay by SPP in performing its obligations under this Agreement which results
from any failure or delay in the performance of its obligations by any person,
firm or company with which SPP shall have entered into any such contract, supply
arrangement or sub-contract or otherwise, shall be regarded as a failure or
delay due to Force Majeure only in the event that (a) such person, firm or
company shall itself be prevented from or delayed in complying with its
obligations under such contract, supply arrangement or sub-contract or otherwise
as a result of circumstances of Force Majeure (b) the contract, supply
arrangement or subcontract is essential to SPP's performance and (c) SPP has
exercised its best efforts to find substituted goods or services on terms
generally equivalent to those agreed under such contract, supply arrangement or
sub-contract.
12.5 If the event of Force Majeure prevents either Party from
performing all or a substantial part of its obligations for a consecutive period
of 90 (ninety) calendar days then the other Party may terminate this Agreement
upon written notice, provided always that SPP shall be reimbursed for all direct
costs incurred under this Agreement up to the effective date of such
termination, provided always that such costs take account of:
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12.5.1 any recoveries made by SPP pursuant to its insurance policies;
12.5.2 all charges paid by AEPSC hereunder; and
SECTION 13 - AMENDMENTS TO AGREEMENT.
13.1 This Agreement shall not be varied or amended unless such
variation or amendment is agreed in writing by a duly authorized representative
of AEPSC on behalf of AEPSC and by a duly authorized representative of SPP on
behalf of SPP.
SECTION 14 - NOTICES.
14.1 Notices. Any notice, demand or request required or authorized by
this Agreement to be given by one Party to the other Party shall be in writing.
It shall either be personally delivered, transmitted by telecopy or facsimile
equipment (with receipt verbally and electronically confirmed), sent by
overnight courier or mailed, postage prepaid, to the other Party at the address
designated in this Article 14. Any such notice, demand or request so delivered
or mailed shall be deemed to be given when so delivered or three (3) days after
mailed.
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14.2 Addresses of the Parties. Notices and other communications shall
be addressed to:
AEPSC
J. Craig Baker
American Electric Power Service Corporation
1 Riverside Plaza
Columbus, Ohio 43215
SPP
Nicholas A. Brown
Southwest Power Pool, Inc.
415 North McKinley Street
#700 Plaza West
Little Rock, AR 72205-3020
SECTION 15 - MISCELLANEOUS PROVISIONS.
15.1 Governing Law. This Agreement shall be interpreted, construed, and
governed by the laws of the State of Ohio, except to the extent preempted by the
law and/or unless a court with jurisdiction rules otherwise, provided, however,
that all matters relating to real property or any interest in realty shall be
governed by the laws of the State wherein such real property or interest in
realty is physically located.
15.2 Successors and Assigns. This Agreement shall inure to the benefit
of, and be binding upon the Parties, their respective successors and assigns
permitted hereunder, but shall not be assignable by a Party, by operation of law
or otherwise, without the approval of the other Party which approval shall not
be unreasonably withheld, except that no such approval is required as to a
successor in the operation of the AEP System's East Zone Transmission Facilities
by reason of a merger, consolidation, reorganization, sale, spin-off, or
foreclosure, as a result of which substantially all such transmission facilities
are acquired by such successor.
15.3 No Implied Waivers. The failure of a Party to insist upon or
enforce strict performance of any of the specific provisions of this Agreement
at any time shall not be construed as a waiver or relinquishment to any extent
of such Party's right to assert or rely upon any such provisions, rights, or
remedies in that or any other instance, or as a waiver to any extent
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of any specific provision of this Agreement; rather the same shall be and remain
in full force and effect.
15.4 Severability. Each provision of this Agreement shall be considered
severable, and if for any reason any provision of this Agreement, or the
application thereof to any person, entity, or circumstance, is determined by a
court or regulatory authority of competent jurisdiction to be invalid, void, or
unenforceable, then the remaining provisions of this Agreement shall continue in
full force and effect and shall in no way be affected, impaired, or invalidated,
and such invalid, void, or unenforceable provision shall be replaced with a
suitable and equitable provision in order to carry out, so far as may be valid
and enforceable, the intent and purpose of such invalid, void, or unenforceable
provision.
15.5 Renegotiation. If any provision of this Agreement, or the
application thereof to any person, entity or circumstance, is held by a court or
regulatory authority of competent jurisdiction to be invalid, void, or
unenforceable, or if a modification or condition to this Agreement is imposed by
a regulatory authority exercising jurisdiction over this Agreement, then the
Parties shall endeavor in good faith to negotiate such amendment or amendments
to this Agreement as will restore the relative benefits and obligations of the
signatories under this Agreement immediately prior to such holding,
modification, or condition. If after sixty days such negotiations are
unsuccessful, then either Party may terminate this Agreement upon three month's
notice.
15.6. Representations and Warranties. Each Party represents and
warrants to other signatories that as of the date it executes this Agreement:
15.6.1 It is duly organized, validly existing, and in good standing
under the laws of the jurisdiction where organized.
15.6.2 Subject to any necessary approvals by federal or state
regulatory authorities, the execution and delivery by each Party, and the
performance of its obligations hereunder have been duly and validly authorized
by all requisite action on the part of the signatories. This Agreement has been
duly executed and delivered by the Parties, and, subject to the conditions set
forth in this Agreement, constitutes the legal, valid, and binding obligation on
the part of each Party, enforceable against it in accordance with its terms
except insofar as the enforceability thereof may be limited by applicable
bankruptcy, insolvency, reorganization, fraudulent conveyance, moratorium, or
other similar laws affecting the enforcement of creditor's rights generally, and
by general principles of equity regardless of whether such principles are
considered in a proceeding at law or in equity.
15.6.3 There are no actions at law, suits in equity, proceedings, or
claims pending or, to the knowledge of each Party, threatened against such Party
before or by any federal, state, foreign or local court, tribunal, or
governmental agency or authority that might materially delay, prevent, or hinder
the performance by such entity of its obligations hereunder.
15.7 Further Assurances. Each Party agrees that it shall hereafter
execute and deliver such further instruments, provide all information, and take
or forbear such further acts and things
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as may be reasonably required or useful to carry out the intent and purpose of
this Agreement and as are not inconsistent with the provisions of this
Agreement.
15.8 Entire Agreement. This Agreement, including applicable appendices
and their duly approved replacements, constitute the entire agreement among the
Parties with respect to the subject matter of this Agreement, and no previous
oral or written representations, agreements, or understandings made by any
officers, agent, or employee of any Party shall be binding on any such Party
unless contained in this Agreement or applicable appendices.
15.9 Good Faith Efforts. Each Party agrees that it shall in good faith
take all reasonable actions necessary to permit it and other signatories to
fulfill their obligations under this Agreement. Where the consent, agreement, or
approval of any Party must be obtained hereunder, such consent, agreement, or
approval shall not be unreasonable withheld, conditioned, or delayed. Where any
Party is required or permitted to act, or omit to act, based on its opinion or
judgment, such opinion or judgment shall not be unreasonably exercised. To the
extent that the jurisdiction of any federal or state regulatory authority
applies to any part of this Agreement and/or the transactions or actions covered
by this Agreement, each Party shall cooperate with all other signatories to
secure any necessary or desirable approval or acceptance of such regulatory
authorities of such part of this Agreement and/or such transactions or actions.
15.10 Counterparts. This Agreement may be executed in any number of
counterparts, each of which shall be deemed to be an original, but all of which
together shall constitute one and the same instrument, binding upon AEPSC and
SPP, notwithstanding that AEPSC, and SPP may not have executed the same
counterpart.
IN WITNESS WHEREOF, the Parties have caused their duly authorized
representatives to execute and attest this Agreement, on their respective
behalves.
AMERICAN ELECTRIC POWER SERVICE CORPORATION
- -------------------------------------------
Henry W. Fayne
- ---------------------------------------------
Name of Authorized Representative
Executive Vice President - Financial Services
- ---------------------------------------------
Title of Authorized Representative
- ---------------------------------------------
Signature of Authorized Representative
- ---------------------------------------------
Date of Execution
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SOUTHWEST POWER POOL, INC.
- --------------------------
Nicholas A. Brown
- ---------------------------------------------
Name of Authorized Representative
Senior Vice President and Corporate Secretary
- ---------------------------------------------
Title of Authorized Representative
- ---------------------------------------------
Signature of Authorized Representative
- ---------------------------------------------
Date of Execution
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UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
American Electric Power Company ) Docket Nos. EC98-40-000,
and ) ER98-277-000, and
Central and South West Corporation ) ER98-2786-000
AFFIDAVIT OF
NICHOLAS A. BROWN
V. BACKGROUND
30. My name is Nicholas A. Brown. I am a Senior Vice President
and Corporate Secretary of Southwest Power Pool, Inc. ("SPP"). My
business address is 415 North McKinley Street, #700 Plaza West, Little
Rock, AR 72205-3020. I am responsible for conception, research,
development, soliciting approval and compliance monitoring of SPP
policy, legal, regulatory and governmental affairs, and corporate
communications.
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31. Prior to my current position, I served as SPP's Director,
Engineering & Operations from 1993-96; Manager, Engineering Services
from 1989-93; and in several engineering positions since joining the
SPP Staff in 1985. Prior to joining the SPP Staff, I worked as a
planning engineer in the System Planning Section at Southwestern
Electric Power Co. I received bachelor of science degrees in physics
and math from Ouachita Baptist University in 1981 and in electrical
engineering from Louisiana Tech University in 1982. I am a member of
Tau Beta Pi and Eta Kappa Nu engineering honor societies, and IEEE and
NSPE technical and professional societies, and a registered
Professional Engineer in the state of Arkansas.
32. As I understand FERC's March 15, 2000 order addressing the
proposed merger between American Electric Power Company ("AEP") and
Central and South West Corporation ("CSW"), AEP is required to contract
out to an independent entity the responsibility for certain
transmission-related functions for transmission service over the
current AEP system ("AEP East Zone"). The purpose of my Affidavit is to
explain the Agreement that the SPP has entered into with American
Electric Power Service Corporation ("AEPSC") under which SPP will
perform for AEPSC certain functions in connection with the
administration of AEPSC's open access transmission tariff ("OATT") for
service in the AEP East Zone. The Agreement provides for SPP to
undertake (i) long-term ATC calculation and posting, (ii) short-term
ATC calculation and posting, and (iii)
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approval of reservations for AEP transmission service from transmission
customers including marketers affiliated with AEPSC.
33. The SPP is an independent regional reliability council,
security coordinator, and tariff administrator for the interconnected
electric systems in the Southwest part of the United States. The AEP
East Zone is not within the SPP, but two of the CSW operating utilities
(Southwestern Electric Power Company and Public Service Company of
Oklahoma) do operate within the SPP. In June 1998, when the SPP began
administering a regional transmission tariff, SPP began functioning
independently of its member utilities, and SPP now operates separately
and apart from any utilities or market participants. SPP's employees
have completely severed any prior relationships with member utilities.
Thus, while the SPP tariff provides for service over the systems of the
CSW utilities within the SPP, no SPP employees have any affiliation
with those utilities and no CSW employees have any role in
administering the regional tariff or in calculating or posting ATCs.
Moreover, SPP employees perform pursuant to the Standards of Conduct
which, consistent with Order No. 889, are on file with the Commission.
34. In July of 1999, SPP approved a new board structure
consisting of transmission owners (investor-owned, municipals, and
cooperatives), transmission users, and non-stakeholders. The current
president of the board is the President and CEO of Arkansas Electric
Power Cooperative Corporation. CSW does have a single member on the
21-member board, but board action requires a two-thirds
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majority. Thus, not only is CSW unable to control any decisions of the
board, but under the governance structure adopted, no single sector,
such as transmission owners, will have a sufficient number of votes to
block or veto action. In addition, the independent members of the board
of directors will be free of any financial interest of any market
participant or transmission owner.
35. SPP administers a regional tariff that provides for all
the services required under FERC's pro forma tariff. SPP is responsible
for performing calculations of total transmission capability ("TTC")
and available transmission capability ("ATC"), posting TTC and ATC and
other required information on the SPP OASIS, processing all requests
for transmission service under the tariff, and serving as the security
coordinator for the region. On December 30, 1999, SPP filed with FERC a
petition seeking recognition as an Independent System Operator
consistent with Order 888, and as a Regional Transmission Organization
fully compliant with the requirements of Order 2000.
VI. THE AEPSC AGREEMENT
36. On March 31, SPP and AEPSC entered into an Agreement under
which SPP agreed to calculate and post on the AEP OASIS short-term and
long-term ATC, and to process requests for transmission service under
the AEP OATT. SPP will perform these functions until AEPSC transfers
operational control of the AEP transmission system to a FERC-approved
RTO. Upon termination of the Agreement, SPP will work with AEPSC on the
transition to the RTO. I will have
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overall management responsibility for overseeing administration of the
Agreement, and I will directly supervise certain of the SPP managers
that will have day-to-day responsibility for implementing the
Agreement.
37. The Agreement obligates SPP to perform the agreed-upon
functions in accordance with Good Utility Practice, and to conform to
the applicable NERC and East Central Area Reliability Coordination
Agreement ("ECAR") rules and regulations as well as to AEPSC's specific
reliability requirements and guidelines in much the same manner as it
performs these functions for the SPP members. The SPP personnel that
will perform the functions under the Agreement will be experienced
transmission operators that are familiar with the AEP transmission
system and the ECAR region in general. Prior to the actual time that
SPP begins performing these functions ("Date of Transfer"), SPP will
establish operating protocols and practices, and will begin installing
equipment and establishing communication links necessary for SPP to
perform the required functions without interruption.
38. The Agreement requires AEPSC to supply SPP, throughout the
term of the Agreement, all data that SPP deems necessary to perform the
functions. The data and the format and manner in which such data will
be provided to SPP will be determined before the Date of Transfer. SPP
also may enter into various hardware and software leases or licensing
agreements with AEPSC as technically necessary to perform services in
an effective and efficient manner.
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39. The Agreement requires that the required functions be
performed only by SPP employees. (Thus, any former AEPSC employees
hired by SPP immediately will sever their employment with AEPSC,
although they will have six months to divest securities in any
affiliate of AEPSC.) No employees that work for SPP and are tasked to
implement the Agreement will have any financial interest in AEP
(including any affiliates) or in any "market participant" as that term
is defined in the new Order 2000 regulations. Likewise, no employees of
SPP that are performing any of the functions under the Agreement will
share office space with any transmission or marketing employees of
AEPSC or any of its affiliates.
40. All employees of SPP that perform the various functions
under the Agreement will be treated as "transmission function
employees" under FERC's Order No. 889 Standards of Conduct and,
therefore, will be restricted from relating transmission reliability
information to merchant employees of AEPSC (or any marketing
affiliates). Indeed, as I mentioned above, all SPP employees are
required to abide by the Standards of Conduct which are on file with
the Commission.
Further Affiant sayeth not.
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UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
American Electric Power Company ) Docket Nos. EC98-40-000,
and ) ER98-277-000, and
Central and South West Corporation ) ER98-2786-000
State of ________ )
)
County of _____ )
AFFIDAVIT OF
NICHOLAS A. BROWN
I, NICHOLAS A. BROWN, having first been duly sworn, do hereby depose and state
that the foregoing Affidavit of Nicholas A. Brown was prepared by me or under my
supervision and that the testimony given therein is true and correct to the best
of my information and belief as of the date of this Affidavit.
------------------
Nicholas A. Brown
Subscribed and sworn before me, a Notary
Public in and for said State and County, this
__ day of March, 2000.
- ---------------------
Notary Public
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CERTIFICATE OF SERVICE
I hereby certify that I have this day served the foregoing
document on each person designated on the official service list compiled by the
Secretary in this proceeding.
Dated at Washington, D.C. this 31st day of March, 2000.
----------------------------------
Steven J. Ross
Steptoe & Johnson LLP
1330 Connecticut Ave., N.W.
Washington, D.C. 20036
(202) 429-6279
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INTERIM ENERGY SALES
The Commission found that the Applicants' proposal to sell 250 MW of
energy and related capacity from the Frontera unit and 300 MW of system energy
in the Southwest Power Pool ("SPP") would offer reasonable and effective
mitigation of any merger-related increase in Applicants' market power prior to
the divestiture of the Frontera and the Northeastern generating facilities.
Order at 27. The Commission directed the Applicants to file, prior to
consummation of the merger, the terms and conditions under which the Applicants
would propose to make the interim sales, including "substantive information
about the 'market indicia' that will be used to determine replacement cost when
the interim purchaser is unable to purchase replacement energy during a recall
event." Order at 28. Only the 300 MW sale in the SPP is subject to recall by
Applicants. Term sheets for the the SPP and Frontera interim sales,
respectively, are attached.
SPP INTERIM SALE
The Applicants will offer to sell 300 MW of capacity and associated
energy in the SPP on a financially firm basis. The minimum and maximum amounts
of capacity the Applicants will sell to any one buyer are 50 MW and 150 MW,
respectively. The energy price will be $14.00 for all hours. The successful
bidders will be expected to pay a negotiated monthly charge for the right to
take the energy to be sold. The initial sales will begin on May 15, 2000 and
will continue for a term of 24 months.
The Applicants may recall all or a portion of the energy to be sold
when necessitated by the declaration of a generation emergency. Any such recall
will be made only if necessary to
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maintain adequate power supply for the native load retail and firm power
wholesale customers of the CSW operating companies and only after all
alternatives to recall, such as cutting interruptible load, discontinuing
non-firm energy sales and making purchases from third parties, have been
exhausted. If the energy is recalled, the Applicants will compensate the
purchaser for the purchaser's replacement cost. The replacement price shall be
the actual prices the buyers pay to purchase substitute energy. If the buyers
are unable to purchase substitute energy, the market price shall be equal to the
published day ahead price for the Into Entergy market or as otherwise mutually
agreed.
The Applicants plan to issue the first solicitation for bids on the 300
MW interim energy sale on or before April 20, 2000 with the goal of executing
final contracts no later than May 15, 2000. Applicants will contract only with
those purchasers whose control of the energy to be sold will not cause HHI
levels to violate the Commission's Appendix A screening criteria.
ERCOT INTERIM SALE
The Applicants will carry out their commitment to make interim energy
sales out of the Frontera station by the already committed sale of 100 MW to the
Lower Colorado River Authority ("LCRA") and the sale of 190 MW to one or more
other counter-parties. When, in testimony filed in January 1999, the Applicants
committed to sell 250 MW from the Frontera unit as a mitigation measure, the
Frontera station was under construction. Frontera has a net summer rated
capacity of 470 MW and consists of two nominal 165 MW gas turbine generators and
a steam turbine generator. The gas turbines were placed in commercial operation
in July
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1999. The gas turbines were taken off line last fall to permit the construction
of the steam turbine and are expected to be returned to service in April 2000.
In ERCOT, load serving entities obtain transmission service ("planned
capacity transmission service") for a calendar year by designating planned
capacity resources to the ERCOT ISO by October 1 of the preceding calendar year.
In the summer of 1999, CSW Energy (through its power marketing affiliate) began
marketing Frontera capacity for use during the year 2000. These sales efforts
were addressed to ERCOT load serving entities that were known to have year 2000
planned capacity needs and who planned to meet those needs through purchased
power arrangements. CSW Energy canvassed the ERCOT market including
investor-owned utilities, power marketers and those municipal and cooperative
utilities known to have year 2000 planned capacity needs. The potential buyers
that CSW Energy approached included the following:
- Alfa/PEGI - Energy Transfer Group
- Aquila - Garland Power and Light
- Austin Energy - Lower Colorado River Authority
- Brownsville (PUB) - LG&E Energy Marketing
- Bryan Utilities - PECO
- CFE - PG&E
- City of Denton - Reliant Energy (Unregulated)
- City Public Service (San Antonio) - Reliant HL&P (Regulated)
- Constellation - Sharyland
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- Coral Energy - Southern Energy Marketing
- Duke - South Texas Electric Cooperative
- Dynegy - Tenaska
- Enron - Texas-New Mexico Power Company
- Entergy - TXU
In addition, CSW Energy listed the Frontera capacity on the "New Generation
Projects Under Development in ERCOT" section of the ERCOT ISO website. This list
is intended to facilitate communication between generators, load serving
entities and transmission providers. Several of the entities listed above
contacted CSW Energy after viewing this website.
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As the result of this marketing effort, Frontera entered into a
contract to sell 180 MW to Tenaska Power Services Co. through December 31, 2000
and a contract to sell 100 MW to LCRA for a term from March 16, 2000 to February
15, 2001. Under the LCRA contract, LCRA pays a price for energy that reflects
the marginal operating cost of the Frontera station. The energy pricing is
similar to the energy pricing specified in the term sheet for the 190 MW sale.
LCRA also pays negotiated capacity charges for the right to take such energy and
in the event that the Frontera plant is not available LCRA's capacity payment
obligations are reduced. The energy is delivered to LCRA at the plant busbar.
Applicants will offer to potential bidders an additional 190 MW of
Frontera unit contigent capacity and the right to take all the energy associated
with such capacity amount under arrangements that will leave Frontera no
residual right to energy not scheduled for delivery. Energy will be sold to the
purchaser at an energy price equal to the product of a heat rate of 7700
MMBTU/MWh times the Gas Daily Houston Ship Channel Midpoint price for the day of
delivery plus $0.07/mmbtu plus a variable O&M charge of $2.25/MWH. In addition,
the third party purchaser will pay a start charge and a negotiated monthly
capacity charge.
The Applicants anticipate they will begin to solicit bids for the 190
MW contract by April 20, 2000 and execute the agreement by May 15, 2000. The
initial sales will begin on May 15, 2000 and continue to December 31, 2000. If
by December 31, 2000 the Frontera Plant will not have been sold to meet the
permanent mitigation provisions of the Commission's order, Frontera will enter
into an additional sale consistent with the order of at least 190 MW for a
period that will extend at least until the date of Frontera divestiture.
Applicants will sell the 190 MW only to those purchasers whose control of the
energy to be sold will not cause HHI levels to violate the Commission's Appendix
A screening criteria.
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SPP ENERGY SALE
OFFERED BY
AMERICAN ELECTRIC POWER
SERVICE CORPORATION, AS AGENT FOR
PUBLIC SERVICE COMPANY OF OKLAHOMA AND
SOUTHWESTERN ELECTRIC POWER COMPANY
DESCRIPTION This is a sale for resale of 300 MW of energy
by Public Service Company of Oklahoma ("PSO")
and Southwestern Electric Power Company
("SWEPCO") (PSO and SWEPCO are referred to
below collectively as "Seller") to ___________
("Buyer"). Such sale will be made from the
output of Seller's system generation
resources. The minimum amount of capacity that
will be sold to any one buyer shall be 50 MW.
No buyer may purchase more than 150 MW of
capacity and associated energy. BUYER MAY NOT
RELY ON THE CAPACITY TO BE SOLD HEREUNDER TO
MEET THE PLANNING RESERVE RESPONSIBILITY OF AN
ENTITY SERVING LOAD IN THE SOUTHWEST POWER
POOL ("SPP") AS PSO AND SWEPCO WILL CONTINUE
TO COUNT ON SUCH CAPACITY TO MEET THEIR SPP
PLANNING RESERVE OBLIGATIONS.
TERM The sale will begin on May 15, 2000. The
contract will have a term of 24 months.
CAPACITY PRICING Respondents to this Offer shall bid Capacity
Prices stated in $/KW-month for the right to
take energy associated with the capacity to be
purchased. Buyer bids $__________/KW-month for
____MW.
ENERGY PRICING All energy scheduled for delivery hereunder
shall be priced at $14.00 for all hours.
RATE CHANGES The rates for capacity and energy shall be
fixed rates that are not subject to change by
Seller through a unilateral rate change filing
with the Federal Energy Regulatory Commission
("FERC") pursuant to the Federal Power Act.
Further, Buyer may not file a complaint with
the FERC seeking a reduction in rates or any
change in the other terms and conditions of
sale pursuant to the Federal Power Act.
ENERGY SCHEDULE Energy will be available 7x24 and Buyer sale
shall be obligated in each hour during the
term of the sale to take the amount of energy
purchased. Schedules will be in accordance
with the scheduling rules of the Southwest
Power Pool, or its successor as the OASIS
operator for the region.
<PAGE> 91
-2-
LIMITED RECALL RIGHTS Seller may recall all or a portion of the
energy to be sold when necessitated by the
declaration of a generation emergency pursuant
to SPP operating guides or the system
operating agreement among PSO, SWEPCO and the
other CSW operating companies, or similar
agreement among the CSW operating companies or
their successors in interest. Any such recall
will be made only after cutting interruptible
load, discontinuing non-firm energy sales and
making energy purchases from third parties.
If, as the result of such recall, the amount
Seller scheduled or delivers in any hour is
less than the Contract Quantity, then Seller
shall pay Buyer an amount equal to: (i) the
product of the amount (whether positive or
negative), by which the "Replacement Purchase
Price" differs from the Contract Price
(Replacement Purchase Price minus Contract
Price) and the amount by which the quantity
delivered by the Seller is less than the
hourly Contract Quantity; plus (ii) the amount
of Transmission Charges, if any, for
transmission service downstream of the
delivery point, which the Buyer incurs to
achieve the Replacement Purchase Price, less
the reduction, if any, in Transmission Charges
achieved as a result of the reduction in
Seller's Schedule or delivery (based upon
Buyer's reasonable commercial effort to
achieve such reduction); plus (iii) costs,
limited to Transmission Charges and broker
fees caused by the Non-Performing Party's
failure to perform. The Replacement Purchase
Price is the actual price. In the event that
Buyer is unable to purchase replacement
energy, the replacement price shall be equal
to the day ahead price published for the Into
Entergy market or as otherwise mutually agreed
by the parties. If the total amount calculated
under this provision is less than zero, then
neither Party shall pay damages to the other
Party. Such damages shall not apply, however,
if the failure to deliver is the result of a
force majeure event. For the purposes of this
provision, a force majeure event shall be an
event that is beyond Seller's control that
renders Seller unable to deliver the capacity
and energy to the delivery point. Such force
majeure events shall not include a recall.
DELIVERY POINT(S) Energy will be delivered at PSO's Northeastern
station. Buyer and Seller may agree to an
alternate delivery point or a bookout of the
transaction.
TRANSMISSION Buyer shall obtain transmission service and
any ancillary services required for
transmission of the energy associated with the
capacity purchased hereunder on the Seller's
transmission system in accordance with the
Southwest Power Pool Open Access Transmission
Tariff (the "SPP OATT") . Buyer will be
responsible for any transmission arrangements
for delivery of such energy beyond the
Seller's control area.
CONDITIONS
PRECEDENT Acceptance of any proposals pursuant to this
offer is subject to review of and acceptance
of such proposals by AEPSC. AEPSC shall select
such
<PAGE> 92
-3-
proposals from creditworthy counter-parties
as, in its judgment, provide maximum value to
Seller from the sale of capacity that is
offered hereunder. AEPSC must accept proposals
for the purchase of all capacity and energy
offered hereunder. Any transaction that may
result from this offer is contingent upon a
favorable credit review of the prospective
purchaser by AEPSC. Any such transaction is
also contingent upon: (1) negotiation of a
definitive agreement that is acceptable to
AEPSC and to filing with and acceptance of
that agreement by the FERC; and (2) a
determination by AEPSC that the sale to the
prospective purchaser will not result in a
violation of the FERC's Appendix A screening
criteria relating to market concentration.
<PAGE> 93
-4-
CAPACITY AND ENERGY
OFFERED BY
FRONTERA GENERATION LIMITED PARTNERSHIP
DESCRIPTION This is a sale for resale of 190 MW of
capacity and associated energy by Frontera
Generation Limited Partnership ("Seller") to
___________ ("Buyer"). Such sale will be made
from the output of Seller's 470 MW combined
cycle generating plant located near Mission,
Texas ("Frontera Plant"). BUYER SHALL NOT
RESELL SUCH CAPACITY AND ENERGY FOR DELIVERY
OUTSIDE OF THE ELECTRIC RELIABILITY COUNCIL OF
TEXAS ("ERCOT").
TERM The initial sale will begin on May 15, 2000
and end December 31, 2000.
CAPACITY PRICING Respondents to this Offer shall bid Capacity
Prices stated in $/kW-month for the right to
take energy associated with the capacity to be
purchased. Buyer bids $_________/kW-month for
____MW.
ENERGY TYPE ERCOT Interchange Energy Classification Type
D-Unit Contingent
ENERGY PRICING All energy scheduled for delivery hereunder
shall be priced as follows:
1. Buyer shall pay to Seller monthly for
energy delivered to the Point(s) of Delivery,
an amount equal to the sum over every day of
the month of the following daily amount: the
product obtained by multiplying the sum of
Fuel Cost ($/MWh) plus O&M Cost ($/MWh), all
as defined below, times the quantity of energy
(in MWh) delivered on that day. In addition,
Buyer shall pay a start charge, as applicable.
2. Definitions.
"Fuel Cost," shall mean, for any Day, the
product of (i) the Fuel Price ($/MMBtu) for
such Day and (ii) Heat Rate (MMBtu/MWh)
"Fuel Price," unless otherwise agreed to by
the Parties, means the Midpoint, expressed in
$/MMBtu, reported in Gas Daily under the
heading "Houston Ship Channel," for the day
the energy is delivered, plus $0.07/MMBtu. If
a Midpoint is not reported for any day energy
was to be delivered, the index used to
determine the Fuel Price shall be the
Midpoint, expressed in $/MMBtu, reported in
Gas Daily under the heading "Houston Ship
Channel," for delivery on the first day
following the day the energy was delivered,
plus $0.07/MMBtu.
<PAGE> 94
-5-
"Heat Rate" shall be 7700 MMBtu/MWh
"O&M Cost" shall be $2.25/MWh
"Start Charge" shall be 562 mmbtu times Fuel
Price
RATE CHANGES Buyer may not file a complaint with the FERC
seeking a reduction in rates or any change in
the other terms and conditions of sale
pursuant to the Federal Power Act or the
Public Utility Commission of Texas pursuant to
the Public Utility Regulatory Act of Texas.
ENERGY SCHEDULE Buyer will each day provide to Seller by 8:00
AM Central Prevailing Time the schedule for
delivery of the contract quantity during each
hour of the following day. Schedules will be
in accordance with the scheduling parameters
of the AEP System Open Access Transmission
Tariff (the "AEP OATT") and the scheduling
rules of the ERCOT ISO.
REMEDY FOR
FAILURE TO DELIVER If Seller fails to deliver all or any part of
the energy sold hereunder, Seller shall pay
Buyer an amount equal to the sum of (a) the
positive difference, if any between the
contract price of energy to be supplied by
Seller and the market price for a
corresponding amount of capacity and energy if
purchased in a commercially reasonable manner,
(b) any additional transmission costs incurred
by Buyer in obtaining substitute energy, and
(c) costs reasonably incurred by Buyer to
purchase energy from an alternative source.
Such damages shall not apply, however, if the
failure to deliver is the result of a force
majeure event. For the purposes of this
provision, a force majeure event shall be an
event that is beyond Seller's control that
renders Seller unable to deliver the capacity
and energy to the Delivery Point.
DELIVERY POINT Capacity and energy sold hereunder shall be
delivered at the Frontera Plant busbar.
TRANSMISSION Buyer shall obtain transmission service and
any ancillary services required for
transmission of the energy associated with the
capacity purchased hereunder on the AEP West
system in accordance with the AEP OATT. Buyer
will be responsible for any transmission
arrangements for delivery of such energy
beyond the control area of Central Power and
Light Company and West Texas Utilities
Company.
CONDITIONS
PRECEDENT Acceptance of any proposals pursuant to this
offer is subject to Seller's review of such
proposals. Seller shall select such proposal
or proposals from creditworthy counter-parties
as, in its judgment, provide maximum value to
Seller from the sale of capacity that is
offered hereunder. Seller must accept
proposals for the purchase of all capacity and
energy offered
<PAGE> 95
-6-
hereunder. Any transaction that may result
from this offer is contingent upon a favorable
credit review of the prospective purchaser by
Seller. Any such transaction is also
contingent upon: (1) negotiation of a
definitive agreement that is acceptable to the
Seller; and (2) a determination by Seller that
the sale to the prospective purchaser will not
result in violation of the FERC's Appendix A
screening criteria relating to market
concentration.
<PAGE> 1
EXHIBIT D-1.11
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Before Commissioners: James J. Hoecker, Chairman
William L. Massey, Linda Breathirt,
and Curt Hebert, Jr.
American Electric Power Company
Docket Nos. EC98-40-005,
and ER98-2770-005 and ER98-2786-006
Central and Southwest Corporation
OPINION NO. 442-A
OPINION AND ORDER DISMISSING IN PART, DENYING IN PART, AND
GRANTING IN PART REHEARING
(Issued May 15, 2000)
This Opinion dismisses in part, denies in part, and grants in part
rehearing of Opinion No. 442(1) in which the Commission conditionally approved
the proposed merger of American Electric Power Company (AEP) and Central and
South West Corporation (CSW) (jointly, Applicants). Applicants request rehearing
of two determinations in Opinion No. 442. In addition, Wabash Valley Power
Association, Inc. (Wabash) and Lafayette Utilities System (Lafayette) filed a
joint request for rehearing of other determinations in Opinion No. 442.(2)
BACKGROUND
In Opinion. No. 442, the Commission concluded that the Applicants had
not carried their burden of establishing that the proposed merger will not
adversely affect competition. The Commission therefore conditioned its approval
of the merger upon the adoption of certain long-term and interim remedies and
mitigation measures. For example, the commission accepted Applicants' proposal
to divest 550 MW of generating capacity, but modified it to require divestiture
of Applicants' entire ownership interest in the generating facilities to be
divested, explaining that "divestiture of Applicants' entire ownership interest
provides the maximum assurance that control has been transferred to a third
party."(3) As another example, the Commission also accepted Applicants' proposal
to join a Commission-approved Regional
- --------------
(1) American Electric Power Co. and Central and South West Corp., Opinion No.
442, 90 FERCP Paragraph 61,242 (2000).
(2) Dayton Power & Light Company (Dayton) withdrew its request for rehearing.
(3) Opinion No. 442 at 61,792. Another merger approval condition was that
Applicants complete the divestiture within a certain time frame.
<PAGE> 2
EXHIBIT D-1.11
Transmission Organization (RTO) and transfer operational control of their
transmission facilities to the RTO, but required that the RTO be fully
functional and required Applicants to transfer control by December 15, 2001,(4)
the date specified in the RTO Final Rule for RTO formation.(5)
Pending the implementation of these long-term remedies, the Commission
also required certain interim mitigation measures,(6) and directed Applicants to
notify the Commission within 15 days of the issuance of Opinion No. 442 whether
they accept the merger approval conditions. On March 27, 2000, Applicants
notified the Commission that they accept the conditions, and on March 31, 2000,
Applicants submitted two compliance filings to implement the interim mitigation
measures.
REHEARING REQUESTS
Applicants state in their rehearing request that they "support the
Commission's determination that, subject to certain mitigation measures, the
merger will be consistent with the public interest."(7) They also state that
they have accepted the merger approval conditions of Opinion No. 442 and are
"committed to comply with them. Applicants will abide by their commitments
regardless of the disposition of this request for rehearing."(8) In addition,
Applicants state that they do not "expect the Commission to rule on the issues
raised in the request for rehearing before consummation"9 of the merger.
Applicants then go on, however, to request rehearing of the Commission's finding
that Applicants' "analysis provides an incomplete and inadequate evaluation of
the potential vertical effect of the proposed merger. . . . Consequently we
conclude that Applicants failed to show that the proposed merger will not
adversely affect competition as a result of combining their generation and
transmission."(10) Applicants claim that concerns about vertical market power
were raised by their competitors to delay the merger and pursue their own
economic agenda. They also request rehearing of the modification that the
Commission required to the pricing methodology for system energy exchanges
between the AEP and CSW zones after the merger is consummated.
Wabash and Lafayette request rehearing of the Commission's
determination that the proposed merger, as conditioned in Opinion No. 442, is in
the public interest. They argue that the Commission should have rejected the
merger, and that the conditions imposed are ineffective to resolve market power
concerns. Wabash and Lafayette reiterate arguments previously made (in Briefs On
Exceptions to the Initial Decision) that Applicants should have been required to
join the Midwest ISO before consummating the merger. In addition, they
- --------------------
(4) Id. at 20.
(5) Regional Transmission Organizations, Order No. 2000, FERC Stats. & Regs.
Paragraph 31,089 (2000), order on reh'g, Order No. 2000-A, FERC Stats. & Regs.
Paragraph 31,092 (2000) appeal pending.
(6) Opinion No. 442 at 61,788-794 and Ordering Paragraph (B) at 61,799-80.
(7) Applicants' Rehearing Request at 1.
(8) Id. at 6.
(9) Id. at 2.
(10) Id. at 22 quoting from Opinion No. 442 at 61,786.
<PAGE> 3
EXHIBIT D-1.11
reiterate the arguments that the ratepayer protection measures are
"worthless,"(11) and that Wabash should be given the opportunity to terminate
its contract without being exposed to stranded costs.
DISCUSSION
1. Applicants' Rehearing Request
Applicants' rehearing request contains the unequivocal statement that
they will comply with the merger approval conditions regardless of the
disposition of rehearing request.(12) Applicants in effect support our
determination to impose certain conditions on the merger.(13) Moreover,
Applicants state that they do not expect the Commission to rule on the
rehearing request prior to consummation of the merger.(14) The Commission also
observes that Applicants' notice accepting the merger approval conditions is
unconditional. It does not even mention that Applicants will seek rehearing of
the findings on which the conditions are predicated.
The result of these statements and actions is that Applicants seek no
relief from the Commission as a result of the finding in Option No. 442 that "in
order to find that the proposed merger will not adversely affect competition as
a result of combining transmission and generation, we find it necessary to
impose certain remedies and conditions...."(15) The Commission therefore
concludes that Applicants are not aggrieved by the Commission's determination on
this issue.(16) Any further analysis of this determination would be pointless,
since Applicants are not challenging the conditions we imposed on the basis of
this determination. Accordingly, we will not address the merits of Applicants'
request for rehearing as to our finding on this issue, and hereby dismiss it as
moot.
We shall grant rehearing with respect to our rejection of Applicants'
original pricing proposal, because as Applicants have explained on rehearing,
the formula will always operate so as not to result in an above-market price for
the buying company. Applicants correctly point out that their formula defines
the buyer's decremental cost as the lower of its decremental generation or its
zonal purchase opportunity. Therefore, as noted by Applicants, the buyer can
never pay more than the market price available in its own zonal market which was
the Commission's main concern in modifying the pricing formula. Based upon our
further review, we conclude that Applicants' original pricing formula produces a
reasonable result and an equitable sharing of the benefits of the economic
energy transfers between merged companies. Accordingly, we will
- --------------------
(11) Wabash and Lafayette's Rehearing Request at 21.
(12) Applicants' Rehearing Request at 6.
(13) Id. at 1.
(14) Id. at 2.
(15) Opinion No. 442 at 61,786
(16) Section 313(a) of the Federal Power Act, 16 U.S.C. Section 8251, permits
only those persons that are aggrieved by a Commission order to request rehearing
of that order. See, e.g., City of Summersville, 84 FERC Paragraph 61,073 (1998)
and Arizona Public Service Co., 26 FERC Paragraph 61,357 (1984).
<PAGE> 4
EXHIBIT D-1.11
grant rehearing, reverse our modification to Applicants' proposed pricing
formula, and accept Applicants' proposal.
2. Wabash and Lafayette's Joint Request For Rehearing
Wabash and Lafayette raise four issues in their joint rehearing
request: (1) the Commission failed to assess the impact of the defective HHI
analysis and the inadequacy of the Competitive Analysis Screening Model (CASm)
associated with CASm's failure to include the AEP/Ameren transmission path as a
component of the analysis and Applicants' failure to test CASm against a
benchmark;(17) (2) the conditions imposed by the Commission were limited,
ineffective, and failed to address intervenor arguments (e.g., strategic
manipulation of generation);(18) (3) the Commission failed to insist upon
implementation of RTO commitments before consummation;(19) and (4) the
Commission failed to address how the proposed merger would adversely affect
transmission availability.(20) We do not find Wabash and Lafayette's arguments
compelling, as discussed below.
In regard to concerns about CASm and benchmarking, we stated in the
Merger Policy Statement that:
It would be expected that there be some correlation between the
suppliers included in the market by the delivered price test and
those actually trading in the market. As a check, actual trade
data should be used to compare actual trade patterns with the
delivered price test.(21)
In fact, Applicants provided such checks in their Application and in
testimony filed during the hearing.(22) We also note that Wabash and Lafayette's
argument regarding the failure of CASm to include the AEP/Ameren transmission
path is unsupported. The data on the AEP/Ameren link is included in CASm.
However, because CASm accounts for simultaneous transfer capability constraints,
the AEP/Ameren link may not be used in all time periods. Thus we disagree that
the AEP/Ameren link is not included in CASm.
Wabash and Lafayette argue that the Commission failed to implement a
remedy to resolve the harm of strategic manipulation of generation, loop flows,
and transmission availability. We disagree. We note that Wabash and Lafayette do
not explain how the Commission's remedies fail to address these problems. In
fact, the Commission considered the
- ----------------------
(17) Wabash and Lafayette's Rehearing Request at 6, 8.
(18) Id. at 5.
(19) Id. at 14.
(20) Id. at 17.
(21) See Inquiry Concerning the Commission's Merger Policy Under the Federal
Power Act: Policy Statement, Order No. 592, FERC Stats. & Regs. 68,595 at 30,133
(1996), order on reconsideration, Order No. 592-A, 79 FERC 61,321 (1997) (Merger
Policy Statement).
(22) Direct Testimony of William H. Hieronymus, Exhibit no. AC-500 at 42:9-12.
<PAGE> 5
EXHIBIT D-1.11
arguments made by intervenors regarding the adverse competitive effects of the
proposed merger and fashioned remedies accordingly.
Wabash and Lafayette argue that the Commission erred by failing to
require Applicants to implement their RTO commitments before merger
consummation. As explained in Opinion No. 442, in cases where it will take time
to implement a long-term remedy, such as here, interim mitigation is warranted.
As we stated in Opinion No. 442, the interim mitigation will be fully effective
in remedying the identified market power problems.(23)
All the other arguments raised by Wabash and Lafayette are arguments
that we have considered and either addressed or rejected as not material to our
determination of the issues in this case.(24)
The Commission orders
(A) The Applicants' rehearing request on the finding on the effect of
combining transmission and generation is hereby dismissed as moot, as discussed
in the body of this Opinion. Applicants' rehearing request on the energy
exchange pricing methodology is hereby granted as discussed in the body of this
Opinion.
(B) The joint rehearing request of Wabash and Lafayette is hereby
denied as discussed in the body of this Opinion.
By the Commission
(SEAL)
S/ David P. Boergers
David P. Boergers,
Secretary
- ---------------------
(23) Opinion No. 442 at 61,789 and 61,794.
(24) See, e.g., Opinion No. 442 at 61,794-97 for a discussion of arguments
raised by Wabash and Lafayette on ratepayer protection and contract termination.
<PAGE> 1
EXHIBIT D-3.2
SOUTHWESTERN ELECTRIC POWER COMPANY "SWEPCO", CENTRAL AND
SOUTH WEST CORPORATION "CSW" AND AMERICAN ELECTRIC POWER
COMPANY, INC. "AEP"
EX PARTE
ORDER NO. U-23327
Louisiana Public Service Commission
1999 La. PUC LEXIS 141
July 28, 1999, Decided; September 16, 1999, Ordered
SYLLABUS: [*1] In re: The applicants jointly request a letter of non-opposition
to a proposed Business Combination and Merger.
PANEL: C. Dale Sittig, District IV Chairman; Jack "Jay" A. Blossman, Jr.,
District I Vice Chairman; Don Owen, District V Commissioner; Irma Muse Dixon,
District III Commissioner; James M. Field, District II Commissioner
OPINION:
I. INTRODUCTION
On May 15, 1998, Central and Southwest Corporation ("CSW"), Southwestern
Electric Power Company ("SWEPCO"), and American Electric Power Company, Inc.
("AEP") (collectively, the "Applicants") filed an application with this
Commission seeking approval of a merger between Central and Southwest
Corporation and American Electric Power Company. The merger is proposed to be
accomplished through the exchange of CSW common stock for AEP common stock at a
ratio of 0.60 AEP share to one CSW share. Based upon the share price at closing
on the last trading day before announcing the merger, the total value of the 127
million shares to be issued by AEP is $6.6 billion. If completed, the combined
holding company will be the largest holding company in the United States in
terms of total customers, generating capacity, and MW sold, and the fourth
largest [*2] in terms of revenues. The Applicants believe that the merger is in
the public interest, will provide savings to ratepayers by maintaining and
improving efficiencies, and will result in a company with an improved financial
position. In response to the filing, the Commission opened Docket No. U-23327,
appointed an Administrative Law Judge who established a procedural schedule, and
directed its expert consultants and Special Counsel to analyze the proposed
combination.
This merger required the analysis of numerous complex technical and policy
issues. Our consideration of proposed mergers is guided by the standards set
forth in Commission General Order In Re: Commission Approval Required of Sales,
Leases, Mergers, Consolidations, Stock Transfers, and All Other Changes of
Ownership or Control of Public Utilities Subject to Commission Jurisdiction
(March 18, 1994). This General Order enumerates eighteen standards that must be
satisfied before the Commission will approve a merger. The planned asset
transfer must also comply with Commission General Order In Re: Commission
Approval of Security Issues and Assumptions of Liability (November 13, 1996).
Often conditions to the merger must [*3] be adopted to satisfy the standards
in the Commission's General Orders and to ensure both that the merger is in the
public interest and that Louisiana ratepayers are protected from any potential
adverse consequences stemming from the merger. Of particular importance in this
proceeding are the standards relating to whether the merger is in the public
interest; whether the merger provides net benefits to ratepayers and a
ratemaking method to ensure that these benefits are actually enjoyed by
ratepayers; the ability of the acquiring utility to provide safe and reliable
service; the financial condition of the resulting company; whether the transfer
adversely affects competition; whether the transfer will improve the quality of
management of the resulting public utility; whether the transfer is fair to the
affected public utility employees; whether the transfer preserves the
Commission's jurisdiction and ability to regulate effectively; and, whether it
is necessary to attach conditions to prevent adverse consequences that may
result from the merger.
<PAGE> 2
After careful consideration of these issues, the Commission has determined
that it will approve the merger but only subject to certain conditions [*4]
required to protect ratepayers. These conditions are designed to (1) capture for
ratepayers the actual savings resulting from the merger; (2) protect ratepayers
from any adverse effect on rates or quality and reliability of service; and (3)
ensure that transactions among the AEP affiliate companies do not result in cost
increases to Louisiana customers. The specific conditions are set forth in the
appendix to this Order, entitled "Stipulation and Settlement," and are discussed
in more detail below. Subject to these conditions, the Commission approves the
proposed merger.
A. The Applicants
1. American Electric Power Company, Inc.
AEP is a public utility holding company registered under the Public Utility
Holding Company Act of 1935, with utility operating subsidiaries engaged
primarily in the generation, transmission, distribution, and sale of electric
energy to over 3 million customers in 7 states. AEP also owns non-utility
subsidiaries. AEP is a New York corporation with its principal executive offices
located in Columbus, Ohio. AEP owns all of the outstanding shares of common
stock of seven domestic electric utility operating subsidiaries, Appalachian
Power Company, [*5] Columbus Southern Power Company, Indiana Michigan Power
Company, Kentucky Power Company, Ohio Power Company, and Wheeling Power Company.
The AEP operating companies serve nearly three million people in portions of
Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia, and West Virginia. The
generation and transmission facilities of AEP's subsidiaries are physically
interconnected, and their operations are coordinated as a single integrated
electric utility system. The transmission networks are interconnected with
extensive distribution facilities in the areas served by AEP's utility operating
subsidiaries.
AEP also owns AEP Service Corporation ("AEPSC"), which primarily provides
services to the regulated operating companies, and AEP Generating Company, which
sells power and energy at wholesale to certain AEP operating companies and to
unaffiliated purchasers. The AEP operating subsidiaries own several coal
companies, including Conesville Coal Preparation Co., Southern Ohio Coal
Company, Central Ohio Coal Company, Windsor Coal Company, and Cardinal Operating
Co. (which is jointly owned with Buckeye Power, Inc.). AEP also owns interests
in unregulated enterprises.
AEP owns 38 power [*6] plants with an aggregate generating capacity of 23,759
MW. This capacity is made up of the following generating sources:
- --------------------------------------------------------------------------------
Coal/Lignite 20,670 MW (87%)
Nuclear 2,138 MW (9%)
Hydro/Oil 950 MW (4%)
- --------------------------------------------------------------------------------
AEP owns roughly 22,000 miles of transmission lines and 119,000 miles of
distribution lines.
The retail operations of the AEP operating companies are subject to the
jurisdiction of the public service (or utilities) commissions of Indiana,
Kentucky, Michigan, Ohio, Tennessee, Virginia, and West Virginia. The Federal
Energy Regulatory Commission ("FERC") regulates the wholesale purchases and
sales of the operating companies and other AEP subsidiaries as well as the rates
and service offerings of AEP's bulk transmission facilities. The Nuclear
Regulatory Commission ("NRC") exercises regulatory authority over the operation
of the nuclear unit owned by Indiana Michigan Power Company, one of the AEP
operating subsidiaries. The AEP System is also subject to regulation by the
Security and Exchange Commission ("SEC") under the Public Utility Holding
Company Act of 1935.
2. Central and Southwest Corporation
<PAGE> 3
CSW is also a registered public utility holding company that owns all of [*7]
the common stock of four electric utility operating subsidiaries: SWEPCO,
Central Power and Light Company ("CPL"), Public Service Company of Oklahoma
("PSO"), and West Texas Utilities Company ("WTU"). CSW indirectly owns all of
the outstanding stock of Seeboard, a regulated regional electricity company in
England and Wales. CSW also owns Central and South West Services, Inc. ("CSWS"),
which provides administrative and general and other services to the four
operating companies. CSW owns a number of other subsidiaries that are engaged in
a variety of ventures. The basic structure of CSW parallels that of AEP,
although some differences exist in the business functions of the non-operating
company subsidiaries.
The CSW operating companies provide electric service to approximately 1.7
million customers in a widely diversified area covering 152,000 square miles.
The CSW operating companies serve portions of the states of Louisiana, Texas,
Oklahoma, and Arkansas. A majority of CSW's Texas operations take place within
the Electric Reliability Council of Texas ("ERCOT") while the remainder of CSW's
operations are within the Southwest Power Pool ("SPP"). On a combined basis, the
CSW operating [*8] companies serve approximately 1,470,000 residential customers
(sales of 17.9 billion kwh); approximately 214,000 commercial customers (sales
of 14.5 billion kwh); over 22,000 industrial customers (sales of 21.0 billion
kwh); and, over 14,000 customers in other categories such as municipal service
and sales for resale (sales of 1.7 billion kwh). The CSW operating companies own
13,739 MW of installed generating capacity, fired by the following fuel sources:
- --------------------------------------------------------------------------------
Coal 5,358 MW (39%)
Gas and Oil 7,282 MW (53%)
Nuclear 1,099 MW (8%)
- --------------------------------------------------------------------------------
As previously mentioned, SWEPCO is one of the CSW operating companies. SWEPCO
provides electric service in a 25,000 square mile territory covering the
northwest portion of Louisiana, as well as in northwestern Texas and western
Arkansas. SWEPCO serves nearly 414,000 customers in these three states, many of
whom are located in the cities of Shreveport, Bossier City, Texarkana,
Fayatteville, and Longview. SWEPCO provides service to approximately 169,000
customers in Louisiana.
The retail operations of SWEPCO-Louisiana ("SWEPCO-La.") are subject to the
jurisdiction of the Louisiana Public Service Commission. SWEPCO's retail
operations are also regulated [*9] by the Public Utility Commission of Texas and
the Arkansas Public Service Commission. The retail operations of the other three
CSW operating companies are regulated by the public service commissions of Texas
and Oklahoma. The FERC regulates the wholesale transactions of SWEPCO and the
other CSW operating companies and CSW subsidiaries as well as their bulk
transmission rates and services. The NRC exercises jurisdiction over the CSW
nuclear operations. The CSW System also is subject to regulation by the SEC
under the Public Utility Holding Company Act of 1935.
B. The Application
AEP and CSW filed a joint application with this Commission seeking approval
of the proposed merger of their two systems. CSW seeks permission to exchange
all of the common stock for shares in AEP. If approved, all of CSW's accounts
will be transferred to AEP, and the CSW electric utility operating companies
will become operating subsidiaries of AEP. AEP and CSW also sought approval of a
regulatory plan that contained the following elements:
1. Merger Savings -- Applicants proposed a 50/50 sharing between shareholders
and ratepayers of an estimated amount of non-fuel savings to be realized [*10]
through the merger. The amount to be shared would be calculated after all merger
costs and costs to achieve the savings were deducted from the savings.
Applicants sought to include in SWEPCO-La.'s cost of service the shareholders'
portion of the estimated savings. Applicants also sought to capture in cost of
service the ratepayers' share of savings by accelerating the depreciation rate
of SWEPCO-La.'s distribution plant and accelerating recovery of the unamortized
portion of certain debt and regulatory assets.
2. Fuel Savings -- Applicants proposed to pass all fuel savings to ratepayers
through the fuel adjustment clause.
<PAGE> 4
3. Rate Cap -- SWEPCO-La. offered to cap its rates at current levels through
January 1, 2002, subject to certain exceptions designed principally to capture
large cost increases.
4. Merger Costs -- Applicants sought to recover all of the merger and
transition costs through deferral and amortization over 5 years.
5. Off-System Sales -- Applicants sought a sharing between customers and
shareholders on a 50/50 basis of all off-system sales margins above recent
historical levels.
Contemplating a June, 1999 closing date for the merger, the Applicants [*11]
initially requested a decision from the Commission by the end of April, 1999.
However, after the application was filed, the FERC denied the Applicants'
request for summary approval of the merger and set the case for full, contested
hearings, noting that the proposed merger raised serious concerns regarding the
potential adverse effect on competition of the combined companies. [In re:
American Electric Power Co., 85 FERC P 61, 201, pp. 21-22. (Nov. 10, 1998).] As
a result, the Applicants filed a revised plan with the FERC, including proposed
mitigation, addressing the FERC's market power concerns. The plan calls for the
divestiture of certain generation assets that are part of the CSW System.
Generation is to be divested in both the ERCOT and SPP areas of CSW. n1 This
plan may be revised further by the FERC and could include the divestiture of
additional generating assets.
- - - - - - - - - - - - - - - - - -FOOTNOTES- - - - - - - - - - - - - - - - - -
n1 In connection with a non-unanimous settlement with the Texas Commission and
certain Texas intervenors, CSW has committed to divest additional CP&L
generation assets in ERCOT.
- - - - - - - - - - - - - - - - -END FOOTNOTES- - - - - - - - - - - - - - [*12]
The proposed plans for asset divestiture, along with the other issues being
addressed at the FERC, are complex and have important potential ramifications
for Louisiana ratepayers. As a result, the Commission believed it advisable to
postpone the targeted decision date to allow these and other issues to be
analyzed fully. This brief postponement also provided the parties with an
opportunity to negotiate a settlement of the issues in our Docket. The
Commission notes further that the proceedings in Texas are still pending, as are
proceedings before state public service commissions in some of the AEP
jurisdictions.
C. Necessary Regulatory Approvals
In addition to the Louisiana Commission, the merger requires approval from at
least 8 regulatory agencies and one federal government department: the FERC, the
Securities and Exchange Commission ("SEC"), the NRC, the Federal Communications
Commission, the Federal Trade Commission, the state public service commissions
of Arkansas, Texas, and Oklahoma, as well as the United States Department of
Justice. AEP and CSW have made the required filings with each of the regulators
and agencies, but final approval has not been obtained from any [*13] regulator
other than the Arkansas Public Service Commission. Additionally, the Dockets
pending in jurisdictions served by the AEP electric utility operating companies
will have to be completed.
The status of the major proceedings before the federal and state regulatory
agencies is discussed below.
1. Federal Approvals
a. FERC
On April 30, 1998, Applicants filed for approval of the merger with the FERC.
Applicants contemporaneously requested approval of three related filings: (1) a
System Integration Agreement, pursuant to which the combined system will operate
on a coordinated basis after the merger; (2) a System Transmission Integration
Agreement governing transmission system coordination; and (3) a Transmission
Reassignment Tariff providing for the sale and reassignment of unused
transmission capacity. Applicants requested approval of the merger and related
filings without an evidentiary hearing. Numerous parties intervened in the FERC
Dockets, including this Commission. The FERC consolidated the Dockets addressing
the merger and related filings.
<PAGE> 5
The FERC has jurisdiction to determine whether a merger is consistent with
the public interest. 16 U.S.C. Section 824b(a) (1994). [*14] To make this
determination, the FERC examines the effect of the merger on competition, rates,
and regulation. [See Inquiry Concerning the Commission's Merger Policy under the
Federal Power Act: Policy Statement, Order No. 592, 61 Fed. Reg. 68, 595 (1996),
FERC Stats. and Regs. P31,044 (1996), order on reconsideration, Order No. 592-A,
62 Fed. Reg. P 33,341 (1997), 79 FERC P 61,321 (1997) ("Merger Policy
Statement)."] In this case, the screening analysis revealed an excessive
concentration in the region served by CSW. According to Applicants, this
concentration resulted from the need to purchase a 250 MW firm transmission
contract path in order to link the AEP and CSW systems. These systems are not
otherwise integrated, which is required under PUHCA before holding companies may
merge.
Applicants proposed to mitigate their enhanced market power by dedicating
into the market 250 MW of capacity for two, two-year periods. Applicants
subsequently revised this proposal to require the divestiture of certain
generating units located in Oklahoma on the CSW system. This mitigation plan may
be amended further to include additional divestiture.
On November 10, 1998, the FERC denied Applicants' [*15] request to
approve the merger and related filings without an evidentiary hearing. [In re:
American Electric Power Co., 85 FERC P 61, 201 (Nov. 10, 1998).] The FERC found
that the proposed merger failed the screening analysis. [65 FERC P 61,201 at p.
21.] The FERC also rejected the Applicants' market power mitigation plan. [Id.]
The FERC set these issues for a full evidentiary hearing. The FERC also set for
hearing the effect of the merger on retail competition and rates and the need
for ratepayer protection provisions. [ Id. at pp. 23-29.] The System Integration
Agreement and System Transmission Integration Agreement were also made subject
to a full evidentiary hearing. [Id. at p. 32.]
The issues being addressed by the FERC, particularly those relating to the
proposed mitigation plan, may have significant impact on Louisiana customers. As
noted previously, Applicants have filed a revised mitigation plan that calls for
divestiture of certain generating assets located in the SPP portion of the CSW
System. The divestiture of generating units in the SPP portion of the CSW system
may diminish the capacity available to satisfy the native load requirements of
Louisiana customers [*16] and could cause significant increases in SWEPCO's
purchased power costs. Because SWEPCO is projected to experience a capacity
shortage by (or before) the 2001 summer cooling season, any generation divesture
may have a material adverse impact on SWEPCO's costs and, therefore, the rates
charged to Louisiana customers. This is an area of obvious concern to the
Commission. The Commission is also concerned that the proposed system agreements
not result in cost shifting from AEP to SWEPCO or be otherwise unjust or
unreasonable.
Hearings on the merger approval application and the related Dockets commenced
before a FERC administrative law judge on June 29, 1999 and concluded on July
19, 1999. The Louisiana Commission was an active participant in the proceedings
and sponsored the testimony of Mr. Steve Baron of J. Kennedy and Associates,
Inc. The Commission's testimony responded to proposals made by various
intervenors to require CSW immediately to divest in excess of one thousand MW of
generation in the CSW-SPP area. This is precisely the type of proposal that
would cause SWEPCO to be short of capacity to serve its Louisiana native load
customers and, at the very least, raise Louisiana ratepayer [*17] costs. The
issues are currently being briefed and by order of the full FERC, the presiding
Administrative Law Judge is required to issue his initial decision no later than
November, 24, 1999.
b. SEC
On April 1, 1998, the SEC approved Applicants' Joint Proxy Statement, which
requested authority to solicit proxies for shareholder approval of the proposed
merger.
On October 1, 1998, Applicants filed for SEC approval of the merger.
Applicants expect that the SEC will approve the merger thirty to sixty days
after the FERC issues its decision. The October 1, 1999 filing also included
cost allocation factors for the combined company. The SEC has not yet responded
to this filing, and there is no determined date when action is expected.
Applicants also plan to file a proposed new service company agreement, which
includes changes to the allocation methodologies for affiliate transactions.
Applicants have agreed to provide this filing to the Commission, which will
review the filing and determine whether to intervene and take action before the
SEC. The allocation methodologies for
<PAGE> 6
affiliate transactions affect the level of costs charged by AEP to the electric
utility operating companies, [*18] including SWEPCO. It is the Commission's
position that these allocation factors do not determine the ratemaking treatment
of the AEPSC or any other affiliate transaction costs. Applicants disagree with
this position, although they have agreed that the Commission may disallow such
costs if it finds the costs imprudent, unreasonable, or excessive.
c. NRC
Applicants filed a request with the Nuclear Regulatory Commission to obtain
approval to transfer control of the South Texas Project nuclear facilities to
AEP, Central Power & Light Co., which owns a portion of the unit is a subsidiary
of CSW. These proceedings are still pending before the NRC, and no definitive
date has been set for action.
d. Other Approvals
In addition to these regulatory approvals, both AEP and CSW were required to
obtain shareholder approval for the merger. On May 28, 1998, CSW shareholders
gave their approval. On May 27, 1998, AEP shareholders approved the issuance of
the additional shares of AEP stock needed to consummate the merger.
2. State Commission Approvals
CSW serves retail customers in Louisiana, Arkansas, Texas, and Oklahoma, and
the state public service commission of each of these [*19] states must approve
the merger. AEP and CSW have therefore applied to each state commission for
merger approval. The Arkansas Public Service Commission has approved the merger,
subject to certain conditions. The proceedings in Texas are still pending.
a. Arkansas
In a series of orders, the Arkansas Public Service Commission approved the
proposed merger, subject to a number of conditions. In its initial order, the
Arkansas Commission found "no persuasive evidence that the proposed merger would
adversely affect SWEPCO's Arkansas customers or the overall public interest if
consummated subject to the express conditions set forth hereinafter." [In the
Matter of the Joint Application of American Electric Power Co., Inc., Docket No.
98-172-U, Order No. 5 at p. 7 (Aug. 13, 1998).] However, its approval is
conditioned upon satisfactory resolution of the FERC proceedings. The Arkansas
Commission remains an active participant in the FERC proceedings involving the
Applicants' market power mitigation plan and proposed divestiture of generation
assets.
The Arkansas Commission imposed conditions on the merger concerning quality
and reliability of service, cost of capital protection, [*20] stranded cost
recovery, Ohio Power issues, notice and filing requirements, and most favored
nations protection. It also adopted a regulatory plan governing the treatment of
and the manner in which the costs and benefits of the merger would be reflected
in SWEPCO's Arkansas retail rates. [In the matter of the Joint Application of
American Electric Power Co., Docket No. 98-172-U, Order No. 9 (December 17,
1998).] The regulatory plan provides for a rate cap through 2002, the reflection
of merger savings and costs in retail rates over 5 years; the flow through of
fuel savings through the fuel adjustment clause; and, a hold harmless provision
regarding the effects of any market power mitigation plan approved by the FERC.
The Arkansas Commission also required most favored nations protection; notice
requirements for certain filings; and, a waiver of any requirement under the
Ohio Power decision that the Arkansas Commission lacks authority to determine
the reasonableness of non-power affiliate costs for retail ratemaking purposes.
b. Oklahoma
The Oklahoma Public Service Commission regulates the retail rates and service
of Public Service Company of Oklahoma. In July, 1999, [*21] the Oklahoma Public
Service Commission approved the proposed merger. The Order includes conditions
similar to those imposed by the Arkansas Commission. The Order has been appealed
by one customer group. However, in testimony before the Commission, AEP stated
that it was prepared to proceed with the merger regardless of the pendency of
the appeal. [07/07/99 Test., R. Munczinski.]
c. Texas
<PAGE> 7
The Public Utility Commission of Texas ("PUCT") also regulates the retail
operations of SWEPCO as well as those of West Texas Utilities Company and
Central Power and Light Company, which are also CSW operating companies. On
April 30, 1998, AEP and CSW filed an application with the PUCT requesting
approval of the merger. Numerous parties intervened in the proceeding, including
customers, competitors, and other regulatory authorities.
The parties have engaged in settlement negotiations and reached a settlement
with the Staff of the Texas PUCT as well as the majority of the parties involved
in the PUCT merger proceeding. Applicants filed a non-unanimous "Stipulation and
Agreement," reflecting the terms of the proposed settlement. A number of parties
objected to this agreement.
The non-unanimous [*22] Stipulation and Agreement contains provisions similar
to those approved by the Arkansas Commission. The agreement also includes
additional elements to the regulatory plan and provisions addressing off-system
sales margins, affiliate transactions, and other issues. The Applicants have
reached agreement with the Staff of the Texas Commission in which they have
committed to divest additional generation assets (over and above those they
committed to divest in the FERC proceeds) within ERCOT.
Hearings on the Applicants' petition in Texas were conducted before an
administrative law judge appointed by the PUCT. Those hearings were concluded in
August, 1999, and the parties are awaiting the ALJ's initial decision.
II. PROCEDURAL HISTORY BEFORE THIS COMMISSION
After receiving the merger application, the Commission docketed this matter
and assigned the Honorable Valerie Meiners, Chief Administrative Law Judge, as
the Presiding Administrative Law Judge. The Commission engaged J. Kennedy and
Associates, Inc. and Stone, Pigman, Walther, Wittmann & Hutchinson, L.L.P. to
assist the Commission's in-house Economics and Rate Analysis Division and
in-house Staff legal counsel in representing [*23] the Commission in this
matter. Interventions were filed on behalf of Entergy Gulf States, Inc., Entergy
Louisiana, Inc., the Louisiana Energy Users Group ("LEUG"), Koch Refining
Company, L.P., the Association of Louisiana Electric Cooperatives, Inc., Dixie
Electric Membership Corporation, Beauregard Electric Cooperative, Inc.,
Claiborne Electric Cooperative, Inc., Valley Electric Cooperative, Inc., and the
International Brotherhood of Electrical Workers ("IBEW").
On July 30, 1998, a status conference was conducted by Judge Meiners. A
procedural schedule was established which included deadlines for discovery, the
filing of testimony and exhibits, as well as hearing dates.
The Commission Staff engaged in extensive discovery from the Applicants,
including multiple rounds of data requests and depositions of numerous Applicant
witnesses who submitted pre-filed testimony. The IBEW also issued data requests
to the Applicants. On November 20, 1998, the Commission Staff and IBEW submitted
prefiled testimony in response to the direct testimony previously filed by the
Applicants. The Applicants propounded discovery to the Staff and deposed the
Commission's expert witnesses, Rick Baudino and [*24] Lane Kollen. On January
19, 1999, the Applicants filed rebuttal testimony to respond to the issues
raised by the Staff and the IBEW.
During the course of discovery, the Applicants and the Commission Staff
engaged in lengthy negotiations in an attempt to resolve the outstanding issues
related to the merger. Ultimately, the Commission Staff and the Applicants
reached agreement on a proposal to present to the Commission to resolve the
matters in this Docket. A hearing was held before Chief Administrative Law Judge
Meiners on July 7, 1999. The Commission Staff offered into evidence the
"Proposed Stipulation and Settlement" that had been negotiated between the
Applicants and the Staff. Commission Staff witnesses Richard A. Baudino and Lane
Kollen offered testimony in support of the Proposed Stipulation and Settlement
and were made available for cross-examination by all parties. The Applicants,
SWEPCO, CSW, and AEP presented two witnesses, Richard E. Munczinski and David G.
Carpenter, who also testified in support of the proposed settlement. Messrs.
Munczinski and Carpenter were made available for cross-examination by all
parties and were in fact cross-examined by the Commission Staff.
Counsel [*25] for several of the Intervenors, namely, the Association of
Louisiana Electric Cooperatives, the Louisiana Energy Users Group, Dixie
Electric Membership Corporation, Beauregard Electric Cooperative, Inc.,
Claiborne Electric Cooperative, Inc. and Valley Electric Cooperative, Inc.,
entered appearances at the hearing. However, none of the Intervenors presented
evidence or testimony at the hearing. Following the testimony of the
<PAGE> 8
Commission Staff's and Applicants' witnesses, an opportunity was provided for
other parties to state objections to the proposed settlement. There were no
objections. n2
- - - - - - - - - - - - - - - - - -FOOTNOTES- - - - - - - - - - - - - - - - - -
n2 Prior to the hearing, two of the Intervenors, Koch Industries, Inc. and the
International Brotherhood of Electrical Workers, had filed into the record
statements of no opposition to the proposed merger of AEP and CSW.
- - - - - - - - - - - - - - - - -END FOOTNOTES- - - - - - - - - - - - - - - - -
Following the July 7, 1999 hearing, Chief Judge Meiners issued a Report of
Proceedings. After outlining the history of the Docket and the participation of
the parties at the hearing, the Report stated:
In light [*26] of the proposed settlement, there are no disputed issues to be
considered and addressed by the administrative law judge in the form of a
Recommendation. Instead, the administrative law judge herewith submits a copy of
the Proposed Stipulation and Settlement, together with a copy of a cover letter
from Staff Counsel to all counsel of record, providing an overview of the terms
of the Proposed Stipulation and Settlement.
All parties are advised that the Proposed Stipulation and Settlement will be
considered and voted on by the Commissioners at an upcoming monthly Commission
meeting.
Report of Proceedings, Docket No. U-23327 (July 13, 1999) at p. 3).
III DISCUSSION OF THE ISSUES
A. Overview
In recent years, this Commission has considered a number of mergers involving
electric utilities, including the Entergy/Gulf States Utilities merger (Order
No. U-19904), the BREMCO/SWEPCO merger (Order No. U-20315) and the TECHE/CLECO
merger (Order No. U-21128). Our experience with the earliest of these mergers
influenced the Commission to adopt its March 18, 1994 General Order codifying
the standards that all mergers must meet. In addition, however, the post-merger
experience with [*27] these combinations has demonstrated some of the problems
mergers may cause.
Many of the conditions that we impose on this merger are designed to avoid
past mistakes in other transactions. The plan for capturing merger-related
savings coupled with the conditions we require, as set forth in the Stipulation
and Settlement attached hereto as Appendix A, will result in a merger that
satisfies the eighteen standards contained in our March 18, 1994 General Order
while ensuring that ratepayers will not be harmed, either financially or
regarding service quality and reliability, as a result of the merger. In
addition, this Commission will retain its jurisdiction and authority over SWEPCO
and the transactions in which it engages.
B. General Order Standards
Our March 18, 1994 General Order, In re: Commission Approval Required of
Sales, Leases, Mergers, Consolidations, Stock Transfers, and All Other Changes
of Ownership or Control of Public Utilities Subject to Commission Jurisdiction,
sets forth the eighteen factors to be considered by the Commission in analyzing
proposed mergers:
1 Whether the transfer is in the public interest.
2 Whether the purchaser is ready, willing and [*28] able to continue providing
safe, reliable and adequate service to the utility's ratepayers.
3 Whether the transfer will maintain or improve the financial condition of the
resulting public utility.
4 Whether the proposed transfer will maintain or improve the quality of service
to public utility ratepayers.
<PAGE> 9
5 Whether the transfer will provide net benefits to ratepayers in both the
short term and the long term and provide a ratemaking method that will ensure,
to the fullest extent possible, that ratepayers will receive the forecasted
short and long term benefit.
6 Whether the transfer will adversely affect competition.
7 Whether the transfer will maintain or improve the quality of management of
the resulting public utility doing business in the State.
8 Whether the transfer will be fair and reasonable to the affected public
utility employees.
9 Whether the transfer will be fair and reasonable to the majority of all
affected public utility shareholders.
10 Whether the transfer will be beneficial on an overall basis to State and
local economies and to the communities in the area served by the public utility.
11 Whether the transfer will preserve the jurisdiction of the [*29] Commission
and the ability of the Commission to regulate and audit effectively the
resulting public utility's operations in the State.
12 Whether conditions are necessary to prevent adverse consequences which may
result from the transfer.
13 The history of compliance or noncompliance of the proposed acquiring entity
or principals or affiliates have had with regulatory authorities in this State
or other jurisdictions.
14 Whether the acquiring entity, persons, or corporations have the financial
ability to operate the system and maintain or upgrade the quality of the
physical system.
15 Whether any repairs and/or improvements are required and the ability of the
acquiring entity to make those repairs and/or improvements.
16 The ability of the acquiring entity to obtain all necessary health, safety
and other permits.
17 The manner of financing the transfer and any impact that may have on
encumbering the assets of the entity and the potential impact on rates.
18 Whether there are any conditions which should be attached to the proposed
acquisition.
Witnesses Dr. E. Linn Draper, Chairman, President, and CEO of AEP, and Mark
D. Roberson, Vice President Regulatory Affairs [*30] of CSW, presented the
Applicants' view regarding how the terms and conditions of the merger satisfy
the criteria set forth in our General Order. Commission Staff witness Rick
Baudino specifically addressed the criteria set forth in the General Order, and
Commission Staff witness Lane Kollen discussed the issue when proposing certain
conditions to the proposed merger. Both Mr. Baudino and Mr. Kollen concluded
that the proposed combination could satisfy our merger criteria if changes were
made to the proposed regulatory plan to ensure that ratepayers enjoy the actual
savings produced by the merger and a series of conditions and ratepayer
protection mechanisms were attached to the merger. For the reasons more fully
explained below, we believe that this merger should be approved, but only
subject to the conditions contained in the Stipulation and Settlement. The
Applicants have agreed to abide by all of these conditions. [07/07/99 Test., R.
Munczinski and D.
Carpenter.]
C. Terms of the Merger
This merger presents several unique problems for the Commission. In previous
mergers considered by the Commission, there existed a likely prospect of
significant ratepayer savings, [*31] making these mergers inherently attractive
for ratepayers. Others mergers involved the takeover of a utility with major
service problems by a more reliable company. The prospect of a significant
upgrade in service quality is also desirable for ratepayers. This merger is
somewhat different.
<PAGE> 10
For the past several years, SWEPCO has been, on average, the lowest cost
investor-owned electric utility providing service to retail ratepayers in
Louisiana. Additionally, while the Company suffered some significant service
quality problems in recent years, SWEPCO has generally been a relatively
well-run, low cost provider of utility service. As such, we were concerned that
the proposed merger not result in any increase in rates or degradation in
service quality or reliability. Finally, the Commission is concerned that the
proceedings at the FERC not result either in the absence of sufficient capacity
to serve SWEPCO customers or increased costs resulting from the need to purchase
power on the open market rather than obtaining it through native generation.
The need to ensure that rates do not rise and service does not deteriorate is
reinforced by the apparent absence of significant merger savings [*32] as
estimated by the Applicants. The non-fuel savings for SWEPCO's Louisiana
operations are projected by the Applicants to be $50 million, over 10 years.
These savings are in nominal dollars. The projected fuel savings over 10 years
for SWEPCO-Louisiana are only $2.6 million, once again, in nominal dollars. (For
comparison purposes, SWEPCO Louisiana's 1998 non-fuel revenues were $179
million, and fuel revenues for the same year were $96 million.) Because of the
relatively modest non-fuel savings, the virtual absence of fuel savings, the
planned divestiture of capacity, and the enhanced level of affiliate
transactions, the Commission must adopt a variety of merger conditions,
affiliate transaction conditions, and ratepayer protection mechanisms ("hold
harmless" provisions) to ensure that SWEPCO's Louisiana ratepayers are no worse
off as a result of the merger than they would have been had no merger occurred.
These conditions and the ratepayer protection mechanisms are described below.
1 Merger Conditions
a. The Costs Of The Merger To Be Borne By Shareholders
The Applicants initially proposed to have ratepayers bear 100% of the costs
to accomplish the [*33] merger. (This was to be accomplished through a sharing
of merger savings after the costs of the merger and the costs to achieve the
savings were netted out of the merger savings). However, we believe that AEP and
CSW have agreed to merge, first and foremost, because those two companies
believe that the merger is in the best interest of their shareholders.
Consequently, the owners of the Company, not their customers, should bear the
cost to achieve the merger. As the Staff recommended, the Applicants may not
seek recovery of merger-related costs from ratepayers. Even if the FERC permits
the costs of the merger to be assigned to the books of operating companies for
accounting purposes, SWEPCO commits that it will not seek recovery of those
costs from retail ratepayers, whether in traditional rate case proceedings or
through any rider or automatic adjustment clause mechanism. The Applicants
agreed to this condition. The Applicants shall be allowed to defer merger costs
associated with transaction costs and other costs to achieve net of associated
savings prior to the operation of the SSM. Ratemaking recovery of the deferred
costs will not be permitted other than through SWEPCO's retained [*34] savings
computed through the SSM. We find this treatment appropriate, and it will be
adopted.
b. The Costs To Achieve The Projected Merger Savings Should be Borne By
Shareholders
The Applicants proposed that ratepayers bear 100% of the costs to achieve the
projected merger savings before sharing any of those savings with customers. The
Staff recommended that these costs be treated in the same manner as the costs to
achieve the merger, that is, they should be borne by shareholders, and any
recovery will be out of the Company's retained savings computed pursuant to the
SSM. The Applicants have agreed not to seek recovery of these costs from
Louisiana retail ratepayers. This treatment is fair and consistent with our
treatment of the costs of the merger and will be adopted.
c. All Fuel Savings Will Be Flowed Through Directly To SWEPCO's Louisiana
Ratepayers
The Applicants have offered to flow through to Louisiana ratepayers all fuel
savings generated by the merger. We agree that 100% of the fuel savings produced
by the merger should be enjoyed by SWEPCO customers. This treatment is
consistent with the Commission's directives in Order No. U-19904 requiring all
fuel [*35] savings resulting from the merger of Entergy, Inc. ("Entergy") and
Gulf States Utilities Company ("Gulf States") be flowed through to ratepayers.
d. Actual Non-Fuel Savings Will Be Flowed Through To SWEPCO's Louisiana
Ratepayers
<PAGE> 11
As previously discussed, the Applicants assert that non-fuel savings will
result from cost reductions and other efficiencies associated with the merger.
The Applicants offered to provide to Louisiana ratepayers, as merger savings, a
predetermined dollar amount for a period of five years regardless of the level
of actual savings. This pre-determined amount is obviously an estimate. The
offered savings represented approximately one-half of the projected savings
calculated after all merger related costs and all costs to achieve the savings
were deducted. Stated otherwise, the Applicants proposed to split projected
savings, with about 50% of savings benefitting ratepayers and 50% being retained
by shareholders. This sharing would take place, however, only after ratepayers
paid all merger-related costs and all costs to achieve the merger. If
merger-related savings exceeded those projected by the Applicants, shareholders
would enjoy 100% [*36] of those excess savings. Moreover, the Company sought to
use the ratepayers' portion of the projected savings to fund accelerated
depreciation of SWEPCO's distribution plant and the accelerated recovery of
certain regulatory assets.
The Commission has previously addressed the appropriate treatment of merger
savings. In the Entergy/Gulf States merger, the Commission required that actual,
not projected, savings be refunded to ratepayers. In that case, we adopted a
tracking mechanism designed to capture the actual savings resulting from the
merger and required the ratepayer portion of those savings to be flowed through
directly to consumers.
We find that the pass through of actual rather than projected savings is both
fair and consistent with prior Commission precedent. To accomplish this pass
through, the Applicants will implement a mechanism similar to that utilized in
the Entergy merger to capture actual savings. The mechanism is known as the
Savings Sharing Mechanism ("SSM"). The SSM will track the actual savings
generated by the merger as well as any other cost of service reductions
generated by productivity improvements implemented by SWEPCO. Fifty percent of
all actual savings [*37] will be flowed through directly to Louisiana ratepayers
via annual filings by SWEPCO. Unlike the Applicants' proposal, however, savings
to be enjoyed by ratepayers will be calculated before any deduction of merger
costs or costs to achieve the savings. Additionally, also unlike the Applicants'
proposal, the savings will not be offset by any accelerated cost recovery but
rather will be credited to ratepayer bills. The Company will be authorized to
defer its merger costs, costs to achieve, transaction costs and change in
control payments and to utilize its retained share of the SSM savings to
amortize these costs. The SSM will be implemented 15 months after the merger is
consummated.
In connection with the operation of the SSM, SWEPCO shall submit to and pay
for an audit by the Commission which shall include an examination of affiliate
transactions. The cost of the audit shall be reflected in SWEPCO's
cost-of-service in the appropriate test year. The audit shall be conducted no
less than six months and no more than eighteen months after the merger is
consummated.
e. SWEPCO Ratepayers Shall Benefit From Any Increased Off-System Sales
Margins
From time to time, CSW engages [*38] in off-system sales when it does not
need its full capacity to serve its native load customers. Currently, 100% of
the SWEPCO portion of the margins (profit) from the off-systems sales are
credited to Louisiana ratepayers through the fuel adjustment clause. AEP also
engages in off-system sales on behalf of its operating companies, but on a far
more extensive basis. AEP has committed to increase significantly the off-system
sales and margins for the former CSW operating companies.
To provide the Applicants with an incentive to pursue off-system sales (when
profitable), while at the same time ensuring that Louisiana ratepayers continue
to benefit from such sales, we will adopt to a tiered approach to sharing the
benefit of the off-system sales margins. The proposal is as follows: (1) 100% of
Louisiana jurisdictional off-system sales margins up to $874,000 shall be
credited to customers. This figure is approximately 130% of current off-system
sales margins. (2) 85% of off-system sales margins between $874,000 and
$1,314,000 shall be flowed through to customers, with the remaining 15% to be
retained by shareholders. (3) SWEPCO off-system sales margins above $1,314,000
shall be shared [*39] equally between ratepayers and shareholders. As a result,
only if sales margins increase by over 30% of current levels will shareholders
receive any benefit, and the 50/50 sharing mechanism is triggered only if
off-system sales margins approximately double. Ratepayers thus continue to
receive the principal benefit of any off-system sales while the Applicants have
a significant incentive to increase margins. The Staff recommends that
off-system sales margins shall continue to be flowed back to ratepayers through
the fuel adjustment clause.
f. Any Stranded Costs That SWEPCO Seeks To Recover Must Be On A Stand Alone
Basis
<PAGE> 12
In comments filed in the Commission's Generic Restructuring Docket (Docket
No. U-21453), SWEPCO indicated that it could not identify any generation-related
stranded costs that would result if the Commission implemented retail
competition. However, it is possible that some of the AEP operating companies
may have stranded costs in the event of competition. In addition, at least one
of SWEPCO's sister CSW operating companies has nuclear exposure and may have
stranded costs. To ensure that Louisiana ratepayers are not allocated stranded
costs incurred by the [*40] AEP (or other CSW) operating companies, the Staff
has proposed, and we will require, that any stranded costs SWEPCO seeks to
recover must be on a stand-alone basis and will be limited to ownership and
contractual interests of SWEPCO in its own assets and obligations. Applicants
have agreed to this requirement and further that they will not seek to recover
from Louisiana customers any stranded costs associated with the existing AEP
system.
g. SWEPCO Shall Submit To A Full Cost Of Service Ratemaking Examination By
The Commission
To ensure that the AEP Savings Sharing Mechanism is working properly and that
SWEPCO's ratepayers are only bearing their fair share of system costs, the
Company agrees that twenty-eight months after the consummation of the merger, it
shall submit to the Commission a full cost of service/revenue requirement
filing. The Commission will then conduct a full rate examination of SWEPCO to
recalibrate rates for the future operation of the Savings Sharing Mechanism.
2 Affiliate Transaction Conditions
As previously discussed, post-merger, AEP will own eleven operating company
subsidiaries. In addition, AEP is the parent company of numerous unregulated
[*41] subsidiaries and is also the parent of American Electric Power Service
Company, which provides goods and services to the operating companies. The
Applicants have testified that one of the principal methods of obtaining merger
savings will be through consolidation and centralization of operations for
various functions. As a consequence, post-merger, as compared to today, a higher
level of costs will be assigned or allocated to SWEPCO rather than being
incurred by SWEPCO itself. The types and magnitude of costs being assigned and
allocated will become increasingly difficult to track when SWEPCO is one of
eleven regulated operating subsidiaries with numerous other unregulated AEP
companies.
In the Entergy/Gulf States merger, we established, as a condition of the
merger, a series of affiliate interest conditions governing the types, levels
and appropriate regulatory treatment of costs that could be assigned and
allocated to the Entergy operating companies subject to this Commission's
jurisdiction. In addition, the conditions guaranteed the Commission full access
to relevant data as well as audit rights. The Staff is recommending that a
similar set of conditions be adopted in this [*42] case.
This Commission will adopt a set of affiliate transaction conditions
applicable to SWEPCO and the AEP system. The need for these guidelines is even
greater today than it was when we approved the Entergy Gulf States merger some 6
years ago. An increasing number of transactions are being billed to operating
companies, the number of non-operating company subsidiaries is growing
exponentially and these affiliate transactions are increasingly difficult to
track. These requirements will help to ensure that costs associated with
unregulated activities are not assigned to the regulated customer; that SWEPCO
only bears its fair share of the costs of the regulated subsidiaries; and, that
the Commission will continue to have access to all documents associated with
affiliate transactions, as it would if SWEPCO had procured all of those goods
and services on its own. The Applicants have agreed to these conditions, which
are outlined below. A full set of the conditions is contained in the Stipulation
and Settlement attached hereto.
. CSW's operating companies, including SWEPCO, will continue to be core
businesses for the post-merger AEP. Applicants commit to continue to meet the
needs [*43] of its domestic regulated customers, including all appropriate
capital requirements.
. AEP and SWEPCO will provide the Commission access to their books and records
and to any records of their subsidiaries and affiliates that reasonably relate
to regulatory concerns and that affect SWEPCO's cost of service and/or revenue
requirement.
<PAGE> 13
. AEP will cooperate with audits ordered by the Commission of affiliate
transactions between SWEPCO and other AEP affiliates, including timely access to
books and records and persons knowledgeable regarding those affiliate
transactions.
. Assets with a net book value in excess of $1 million per transaction,
purchased by SWEPCO from an unregulated affiliate, will be included in rate base
at the lesser of the cost to the affiliate or its fair market value.
. For goods and services purchased by SWEPCO from unregulated affiliates,
SWEPCO will reflect the lower of cost or fair market value in operating expenses
for ratemaking purposes.
. Assets with a net book value in excess of $1 million per transaction sold by
SWEPCO to an unregulated affiliate, will be valued for purposes of Louisiana
retail rate base at the greater of the cost to SWEPCO [*44] or the fair market
value.
. For goods and services sold by SWEPCO to unregulated affiliates, for
ratemaking purposes, SWEPCO will reflect the higher of the cost or fair market
value in operating income.
. The Company shall comply with all requirements contained in the Commission's
March, 1994 General Order (and any superseding General Order) regarding mergers,
acquisitions and transfers of ownership and control regarding regulated
utilities and their assets.
. SWEPCO shall notify the Commission in writing at least 90 days in advance of
any proposed purchase, sale or transfer of assets with a net book value in
excess of $1 million. With this notice, the Company shall identify the assets to
be transferred, the proposed transferor and transferee, the value at which the
assets will be transferred, the net book value of the assets, and the
anticipated affect on Louisiana retail customers.
. SWEPCO shall have the burden of proof in any subsequent ratemaking proceeding
to demonstrate that such purchase, sale or transfer of assets satisfies the
requirements of applicable Commission and legal precedent and Commission General
Orders, and will not harm ratepayers.
. The Commission [*45] reserves the right, in accordance with Commission and
legal precedent and Commission General Orders, to determine the ratemaking
treatment of any gains or losses from the sale or transfer of assets to
affiliates.
. For ratemaking and regulatory reporting purposes, SWEPCO shall reflect the
costs assigned or allocated from affiliate service companies on the same basis
as if SWEPCO had incurred the costs directly.
. At least 30 days prior to the filing, and 90 days prior to the proposed
effective date of any changes contained in those filings, the Company shall
submit to the Commission any changes it proposes to the System Agreement, the
System Integration Agreement (or successor agreements) and any other affiliate
cost allocation agreements or methodologies that affect the allocation or
assignment of costs to SWEPCO. The filing with the Commission shall include a
description of the changes, the reason for the changes, and an estimate of the
impact, on an annual basis, of such changes on SWEPCO's regulated costs.
. SWEPCO, or any entity on behalf of SWEPCO, may not make any non-emergency or
scheduled maintenance procurement other than from American Electric Power
Service Company [*46] in excess of $1 million from a non-regulated affiliate
except through a competitive bidding process or as otherwise authorized by the
Commission.
. To the extent that SWEPCO develops or pays for any product or service, all
profits from the sale of the product or service shall be shared between SWEPCO
and the non-regulated entity responsible for marketing and selling the product
or service.
. Because of a decision of the United States Court of Appeals for the District
of Columbia Circuit, Ohio Power Co. v. FERC, 954 F.2d 779 (D.C. Cir.) cert.
denied, 498 U.S. 73 (1992), an issue has arisen as to whether authority of the
Securities and Exchange Commission impairs the ability of state public service
commissions to examine and determine the prudence, reasonableness and necessity
of non-power affiliate transaction costs of public utilities subject to the
state commissions' jurisdiction. A second issue is whether state public service
commissions can challenge Securities and
<PAGE> 14
Exchange Commission-approved cost allocations. As to the first issue, the
Applicants have agreed not to assert that the authority of the SEC impairs the
ability of the Louisiana Commission to examine and determine [*47] the prudence,
reasonableness and necessity of non-power affiliate transaction costs of SWEPCO.
Regarding the second issue concerning cost allocations, the parties have simply
agreed to disagree and litigate that issue if and when it arises.
3 Hold Harmless/Ratepayer Protection Mechanisms
In addition to the specific provisions described above, and because of the
possibility that significant savings may not materialize as a result of the
merger, we will adopt several provisions that are in the nature of "hold
harmless" or ratepayer protection mechanisms. Fundamentally, these are designed
to ensure that ratepayers will not be worse off after the merger than they would
have been had CSW not been acquired by AEP. The specific hold harmless
conditions that we require, which have already been agreed to by the Applicants
are as follows:
a. SWEPCO's Rates Shall Be Capped For 5 Years After The Merger
SWEPCO shall function under a base rate ceiling, set at the level of current
rates, for a period of 5 years after the merger closes. This ceiling will
protect ratepayers from base rate increases resulting from the merger or other
causes. The level of the proposed cap is the [*48] level of current rates. This
is a rate cap and not a rate freeze. Rates can be reduced below current levels,
but they cannot rise. The rate cap is subject to certain limited force majeure
type provisions described in the Stipulation and Settlement (Appendix A).
b. SWEPCO's Fuel Charges Shall Not Rise As A Result Of The Merger
As with base rates, it is important to ensure that SWEPCO's fuel charges are
no higher after the merger than they would have been absent the merger. This is
particularly important because as we previously discussed, SWEPCO is projecting
only $2.5 million in merger-related fuel savings, over 10 years, in nominal
dollars for its Louisiana jurisdictional operations. This indicates that fuel
savings may not materialize and that fuel costs may increase as a result of the
merger. Absent some action by the Commission, these increased fuel costs would
be flowed through to ratepayers via the fuel adjustment clause.
To protect SWEPCO customers, we will require that ratepayers be held harmless
from any increases in fuel costs resulting from the merger for a period of 10
years. This 10-year commitment captures the effective period of the Shared
Savings [*49] Mechanism and is similar to the 10-year fuel protection mechanism
we required in the Entergy/Gulf States merger. To ensure that fuel costs do not
increase as a result of the merger, the Applicants have agreed to continue in
place the current CSW System Operating Agreement and to make only economic
exchanges of power between the AEP and CSW systems (that is, power will be
exchanged only when the exchange will lower fuel or purchased power costs for
the entire system). The Applicants have agreed to provide detailed data and
calculations to verify compliance with the hold harmless commitment for fuel
costs.
c. Cost Of Capital Protection Mechanism
In many respects, the cost of capital of a regulated operating subsidiary is
determined (and viewed by the financial community) by the risk of the parent
company. It is possible that AEP's risk would be greater than either CSW or
SWEPCO as a stand-alone company. Any increased risk could translate into a
higher cost of capital (or lower debt rating) for SWEPCO. The Commission seeks
to ensure that the merger would not adversely affect SWEPCO's cost of capital,
thereby causing higher rates to Louisiana customers. The Applicants are [*50] in
agreement and have committed that the cost of capital as reflected in SWEPCO's
rates shall not be adversely affected as a result of AEP's acquisition of CSW.
We adopt that proposition and will require that subsequent to the completion of
the merger, the cost of capital for SWEPCO will be set commensurate with the
risk of SWEPCO, and the determination of the cost of capital will be based on
the risk attendant to the regulated operations of SWEPCO and not to AEP's total
operations.
d. SWEPCO's Ratepayers Shall Be Held Harmless From Any Increases Resulting
From The Applicants Mitigation Plan
In connection with the application filed with the FERC seeking approval of
the merger, the Applicants proposed (and subsequently amended) a mitigation plan
to allay any market power concerns that might result from the merger. Under
<PAGE> 15
the current mitigation plan, a portion of a Public Service Company of Oklahoma
coal-fired generating unit will be sold to third parties, along with the
divestiture of additional CSW generating assets located within ERCOT. The sale
of PSO generating capacity could cause SWEPCO's fuel and/or purchased power
costs to increase. Therefore, we will require, and the [*51] Applicants have
agreed to, a commitment that Louisiana ratepayers shall be held harmless from
any net cost increases resulting from the Applicants' mitigation plan, measured
on a calendar year basis. The specific formula for this hold harmless
requirement will be developed after the final mitigation plan is ordered by the
FERC. The Commission Staff and the Applicants are directed to work together to
develop the hold harmless formula.
4 Additional Conditions
a. Commission Approval Of The Merger Will Not Be Final Until FERC Action Is
Reviewed And Approved
If the Commission accepts the Staff's recommendation to approve the AEP/CSW
merger subject to the conditions outlined in this letter, that approval will
occur prior to the time that the proceedings are complete at the FERC. It is
possible that the FERC may include certain conditions (particularly by way of
mitigation) that would be unacceptable to the Louisiana Public Service
Commission. For that reason, the Louisiana Commission's approval shall not
become final until after we have had an opportunity to review any action by the
Federal Energy Regulatory Commission and determined that such action will not be
harmful [*52] to Louisiana ratepayers.
b. The Louisiana Commission Has Most Favored Nations Status
Consistent with the Entergy/Gulf States merger, the Commission will require a
most favored nations provision as a condition to the merger. Thus, if any other
regulator is able to negotiate an overall "better deal" for its ratepayers,
Louisiana consumers will get the benefit of that better deal. The most favored
nations clause is as follows:
Applicants and the merged Company commit and agree that upon issuance of any
final and non-appealable order from the FERC, SEC, or any state or federal
commission addressing the merger, through stipulation or otherwise, providing
any benefits to ratepayers of any jurisdiction or imposing any conditions on
Applicants or the merged Company that would benefit the ratepayers of any
jurisdiction, such benefits and conditions will be extended to Louisiana retail
customers to the extent necessary to achieve equivalent net benefits and
conditions to Louisiana retail customers, provided the proposed merger is
ultimately consummated.
IV CONCLUSION
Upon the unanimous vote of the Commission taken at its July 28, 1998 Open
Session,
IT IS HEREBY [*53] DETERMINED AND ORDERED that the merger between AEP and CSW
is in the public interest and complies with all of the provisions of the
Commission's General Orders regarding transfers of ownership and control,
subject to the conditions set forth in the Stipulation and Settlement attached
as Appendix A to this Order, which are incorporated herein by reference, and
subject to the Commission's approval of the capacity mitigation plan and the
development of an appropriate methodology to hold SWEPCO's ratepayers harmless
from any increased costs relating to the mitigation plan.
This Order will be effective upon its issuance.
BY ORDER OF THE COMMISSION
BATON ROUGE, LOUISIANA
September 16, 1999
DISTRICT IV
CHAIRMAN C. DALE SITTIG
DISTRICT I
VICE CHAIRMAN JACK "JAY" A. BLOSSMAN, JR.
<PAGE> 16
DISTRICT V
COMMISSIONER DON OWEN
DISTRICT III
COMMISSIONER IRMA MUSE DIXON
DISTRICT II
COMMISSIONER JAMES M. FIELD
APPENDIX -A
PROPOSED STIPULATION AND SETTLEMENT
MERGER CONDITIONS/REGULATORY PLAN
1. SWEPCO shall function under a base rate ceiling set at the level of current
rates for a period of 5 years after the merger closes. This base rate ceiling is
not applicable solely [*54] under the following conditions:
a. Changes in statutory federal income tax provisions that result in more than
a $16,000,000 net impact on the earnings (income) of SWEPCO;
b. A catastrophic "act of God" that has an extreme and long-term impact on the
earnings and operations of SWEPCO-La.;
c. An increase in the Consumer Price Index - Urban of 10% or more for 2
consecutive years;
d. Applicants may file a request with the Commission for changes to the base
rates of SWEPCO-La. upon the mandated restructuring or unbundling of electric
utility services;
e. This condition does not preclude the implementation of a surcharge
authorized by statute, Commission decision or as a result of any remand to the
Commission from a court proceeding.
f. If the purchased power costs incurred by SWEPCO-La. to serve its native load
customers during or after the 2001 summer cooling season would, absent this
ceiling, cause SWEPCO-La. to seek an increase in its base rates, then the
Company may seek relief from this rate ceiling. The Commission's analysis of
such a request shall include consideration of all offsets to the requested rate
increase, whether such offsets are in the form of lower revenue [*55]
requirements or cost of capital needs, and these offsets may be used to reduce
the need for rate relief.
2. SWEPCO shall implement a nonfuel savings sharing mechanism ("SSM") that
assures ratepayers will receive timely rate reduction benefits from
merger-related cost reductions. See attached, Exhibit A.
3. In connection with the operation of the SSM, SWEPCO shall submit to and pay
for an audit by the Commission which shall include an examination of affiliate
transactions. The cost of the audit shall be reflected in SWEPCO's cost of
service in the appropriate test year. The audit shall be conducted no less than
6 months and no more than 18 months after the merger is consummated.
4. The Applicants shall be allowed to defer merger costs associated with
transaction costs and other costs to achieve net of associated savings prior to
the operation of the SSM. Ratemaking recovery of the deferred costs will not be
allowed other than through SWEPCO's retained savings computed through the SSM.
5. SWEPCO shall flow through all Louisiana jurisdictional fuel savings from the
combined operation of the AEP/CSW systems.
6. SWEPCO ratepayers shall be held harmless from any increases [*56] in fuel
costs that result from the merger for a period of 10 years. To ensure that fuel
and purchase power costs shall not increase as a result of the merger, the
<PAGE> 17
Applicants commit that the current CSW System Operating Agreement shall be
continued by the Applicants, subject to the right to seek FERC-approved
modification and subject to the provisions of paragraph 12 of the Affiliate
Transaction Conditions. The West Zone (CSW) shall be economically dispatched,
and the Applicant's proposed System Integration Agreement shall operate to allow
for economic exchanges between the East and West Zones to lower fuel and
purchased power costs for the West Zone. Applicants agree that they will not
dispatch their system in a manner that will cause increased fuel costs to SWEPCO
retail ratepayers as a result of the merger.
This provision shall function in connection with the hold harmless provision
related to any mitigation sale as described in Paragraph 9 of the Merger
Conditions/Regulatory Plan of this Stipulation and Settlement. If AEP changes
its System Integration Agreement, the notice provisions contained in Paragraph
12 of the Affiliate Transaction Conditions of this Stipulation and Settlement
[*57] shall apply.
To allow the Commission to monitor the fuel costs of SWEPCO-La. to ensure that
ratepayers do not pay higher fuel costs as a result of the merger and/or any
mitigation measures undertaken by the Applicants, the Applicants agree that for
a period of 10 years following consummation of the merger, SWEPCO shall file
yearly fuel and purchase power cost reports with the Commission. These reports
shall provide the following information:
a. Calendar year fuel and purchase power cost for SWEPCO and SWEPCO-La.
b. A detailed explanation (including detailed workpapers) of how the annual
fuel and purchase power costs were derived.
c. A detailed explanation with supporting calculations showing how the
Applicants incorporated the two hold-harmless merger conditions relating to any
mitigation sale. The hold-harmless conditions include (1) the effect of any
call-back provision; and (2) the effect on fuel and purchased power costs from
any change in system dispatch from the operation of the mitigation sale.
d. The annual savings attributable to power interchanges with the East Zone,
including detailed workpapers supporting the savings calculation. If fuel and
purchase power [*58] costs increased due to power interchanges with the East
Zone, this calculation shall be shown along with detailed supporting workpapers.
e. A sworn statement, consistent with current Commission requirements, with a
supporting explanation, by a qualified representative of AEP stating that the
fuel and purchase power costs of SWEPCO-La. did not increase as a result of the
merger during the calendar year being reported.
7. SWEPCO shall continue to flow through the Louisiana jurisdictional portion
of off-system sales margins to ratepayers in accordance with the following terms
and conditions:
a. 100% of Louisiana-jurisdictional off-system sales margins up to $874,000
shall be credited to customers. 85% of off-system sales margins between $874,000
and $1,314,000 shall be flowed through to customers, with the remaining 15% to
be retained by shareholders. The off-system sales margins of SWEPCO-La. above
$1,314,000 shall be shared equally between ratepayers and shareholders. These
dollar figures shall apply on a calendar-year basis and shall include margins
associated with mitigation sales.
b. All off-system sales margins to be credited to the ratepayers of SWEPCO-La.
under [*59] this subsection shall be made in the form of credits to the fuel
adjustment clause of SWEPCO-La.
c. AEP shall report annually to the Commission the capital and operating costs
allocable or assigned (directly or indirectly) to SWEPCO-La. of the AEP energy
trading organization or operations, based upon the most recent composite
allocation factor calculated. This report shall include, without limitation, the
total AEP operating and capital costs for the energy trading organization and
operations, allocation factors, and all supporting documentation and workpapers.
To the extent that the Applicants deem any of this information to be
confidential and/or proprietary, they shall so mark the information and those
documents shall be treated as such in accordance with the Commission's General
Orders, and Rules of Practice and Procedure. The Commission reserves the right
to disallow for ratemaking purposes the costs associated with AEP's energy
trading function, if the Commission finds these costs excessive in relation to
the benefit received by ratepayers.
<PAGE> 18
8. The Applicants commit and agree that the cost of capital as reflected in
SWEPCO's rates shall not be adversely affected as a result [*60] of AEP's
acquisition of CSW. The Applicants also agree that subsequent to the completion
of the merger, the cost of capital for SWEPCO should be set commensurate with
the risk of SWEPCO and should not be affected by the merger. Applicants agree
that they will not oppose, in either a regulatory proceeding or an appeal of a
decision by the LPSC, the application of the principle that the determination of
the cost of capital can be based on the risk attendant to the regulated
operations of SWEPCO.
9. SWEPCO's Louisiana ratepayers shall be held harmless from any net cost
increases resulting from the Applicants' mitigation plan (as approved or ordered
by the FERC) as measured on a calendar year basis.
10. SWEPCO and AEP shall commit to maintaining and improving service quality in
the Louisiana jurisdiction in accordance with the Commission's April 30, 1998
General Order In re: Ensuring Reliable Electric Service Quality and as required
by the Commission in the Service Quality Improvement Program resulting from the
Commission's previously established investigation into SWEPCO's service quality.
11. SWEPCO and the merged company commit and agree that any stranded cost that
SWEPCO [*61] may seek to recover will be on a stand-alone basis, and will be
limited to ownership and contractual interests of SWEPCO in its respective
assets and obligations. The Applicants and merged company agree not to seek or
recover any stranded costs associated with the existing AEP system from
Louisiana customers. The Commission will not propose the allocation of any
stranded costs associated with the CSW system to customers of the existing AEP
operating companies.
12. Applicants agree not to assert in proceedings before the LPSC or in appeals
of LPSC orders, that the authority of the SEC, as interpreted in Ohio Power Co.
v. FERC, 954 F.2d 779 (D.C. Cir. 1992) cert. denied, 498 U.S. 73 (1992) impairs
the ability of the LPSC to examine and determine the prudence, reasonableness
and necessity of non-power affiliate transaction costs of SWEPCO. The parties
agree that this Agreement does not include a waiver of any arguments that
Applicants may have with respect to the reasonableness of SEC approved cost
allocations, as opposed to the reasonableness of the costs themselves.
13. Commission merger approval shall be final, unless the Commission rules,
within 45 days of the receipt [*62] by the Commission of an order of the FERC
approving the merger, that Commission approval of the merger is rescinded,
modified or will be reconsidered. If the Commission does not have a B&E meeting
within 45 days of receipt of the FERC order approving the merger, then the 45
day time period will begin to run on the day following the first B&E meeting
after the Commission receives the FERC's merger order. The applicable time
periods for seeking rehearing and/or review of the Commission order will begin
to run upon the earlier of the expiration of the 45 day time period or the
issuance of a final Commission order.
14. The Applicants and the merged company commit and agree that upon issuance
of any final and non-appealable order from the FERC, SEC, or any state or
federal commission addressing the merger, through stipulation or otherwise,
providing any benefits to ratepayers of any jurisdiction or imposing any
conditions on Applicants or the merged Company that would benefit the ratepayers
of any jurisdiction, such net benefits and conditions will be extended to
Louisiana retail customers to the extent necessary to achieve equivalent net
benefits and conditions to Louisiana retail customers, [*63] provided the
proposed merger is ultimately consummated.
AFFILIATE TRANSACTION CONDITIONS
CONFIDENTIAL DATA: When the following obligations require the Company to
produce competitively sensitive information, upon request of the Company, that
information shall be maintained as confidential in accordance with the
Commission's Rules of Practice and Procedure and applicable General Orders.
1. CSW's domestic electric companies, including SWEPCO, will be core businesses
for AEP. The Applicants commit, as part of their obligation to serve, to
continue to meet the needs of SWEPCO's domestic regulated customers, including
capital requirements, as long as SWEPCO is provided an opportunity to earn a
fair return on its regulated investment in assets to provide service to
customers, in accordance with regulatory precedent and applicable law.
<PAGE> 19
2. AEP and SWEPCO will provide the Louisiana Commission access to their books
and records, and to any records of their subsidiaries and affiliates that
reasonably relate to regulatory concerns and that affect SWEPCO's cost of
service and/or revenue requirement.
3. AEP will cooperate with audits ordered by the Louisiana Commission of [*64]
affiliate transactions between SWEPCO and other AEP affiliates, including timely
access to books and records and to persons knowledgeable regarding affiliate
transactions, and will authorize and utilize its best efforts to obtain
cooperation from its external auditor to make available the audit workpapers
covering areas that affect the costs and pricing of affiliate transactions.
4. a. Assets with a net book value in excess of $1 million per transaction,
purchased by or transferred to the regulated electric utility (SWEPCO) from an
unregulated affiliate either directly or indirectly (through another affiliate),
must be valued for purposes of the Louisiana retail rate base (but not
necessarily for book accounting purposes) at the lesser of the cost to the
originating entity and the affiliated group (CSW or AEP) or the fair market
value, unless otherwise authorized by applicable Commission rules, Orders, or
other Commission requirements.
b. Assets with a net book value in excess of $1 million per transaction, sold
by or transferred from the regulated electric utility (SWEPCO) to an unregulated
affiliate either directly or indirectly (through another affiliate), with the
exception [*65] of accounts receivable sold by SWEPCO to CSW Credit, must be
valued for purposes of the Louisiana retail rate base (but not necessarily for
book accounting purposes) at the greater of the cost to SWEPCO or the fair
market value, unless otherwise authorized by applicable Commission rules,
Orders, or other Commission requirements.
5. The Company shall comply with all requirements contained in the Commission's
March, 1994 General Order (and any superseding General Order) regarding mergers,
acquisitions and transfers of ownership and control regarding regulated
utilities and their assets.
6. The Company shall notify the Commission in writing at least 90 days in
advance of a proposed purchase, sale or transfer of assets with a net book value
in excess of $1 million if such proposed purchase, sale or transfer is expected
at least 90 days before the anticipated effective date of the transaction. With
the notice, the Company shall provide such information as may be necessary to
enable the Commission Staff to review the proposed transaction, including,
without limitation, the identity of the asset to be transferred, the proposed
transferor and transferee, the value at which the asset [*66] will be
transferred, the net book value of the asset, and the anticipated effect on
Louisiana retail customers. When such a transaction requires approval of a
federal agency, under no circumstances shall such notification be less than 60
days in advance or such longer advance period as the applicable federal agency
may from time to time prescribe. If not provided with the initial notice, the
Company will provide the Commission with a copy of its federal filing at the
same time it is submitted to the federal agency.
7. Consistent with applicable Commission and legal precedents and Commission
General Orders, the Company shall have the burden of proof in any subsequent
ratemaking proceeding to demonstrate that such purchase, sale or transfer of
assets satisfies the requirements of applicable Commission and legal precedent
and Commission General Orders, and will not harm retail ratepayers.
8. The Commission reserves the right, in accordance with Commission and legal
precedents and Commission General Orders, to determine the ratemaking treatment
of any gains or losses from the sale or transfer of assets to affiliates.
9. For goods and services, including lease costs, sold by SWEPCO [*67] to
unregulated affiliates either directly or indirectly (through another
affiliate), SWEPCO agrees that it will reflect the higher of cost or fair market
value in operating income (or as an offset to operating expenses) for ratemaking
purposes, unless otherwise authorized by applicable Commission rules, Orders, or
other Commission requirements (e.g., Commission-approved tariffed rates).
10. With the exception of transactions between SWEPCO and CSW Credit, Inc. and
AEPSC, for goods and services, including lease costs, purchased by SWEPCO from
unregulated affiliates either directly or indirectly (through another
affiliate), SWEPCO agrees that it will reflect the lower of cost or fair market
value in operating expenses for ratemaking purposes, unless otherwise authorized
by applicable Commission rules, Orders, or other Commission requirements.
<PAGE> 20
11. For ratemaking and regulatory reporting purposes, SWEPCO shall reflect the
costs assigned or allocated from affiliate service companies on the same basis
as if SWEPCO had incurred the costs directly. This condition shall not apply to
book accounting for affiliate transactions.
12. The Company shall submit in writing to the Commission [*68] any changes it
proposes to the System Agreement, the System Integration Agreement and any other
affiliate cost allocation agreements or methodologies that affect the allocation
or assignment of costs to SWEPCO. The written submission to the Commission shall
include a description of the changes, the reasons for such changes, and an
estimate of the impact, on an annual basis, of such changes on SWEPCO's
regulated costs. To the extent any such changes are filed with the SEC or FERC,
the Company agrees to utilize its best efforts to notify the Commission at least
30 days prior to those filings, and at least 90 days prior to the proposed
effective date of those changes or as early as reasonably practicable, to allow
the Commission a timely opportunity to respond to such filings. If the documents
to be filed with the SEC or the FERC are not finalized 30 days prior to the
filing, the information required above may be provided by letter to the
Commission with a copy of the SEC or FERC filing to be provided as soon as it is
prepared. The filing by the Company of this information with the Commission
shall not constitute acceptance of the proposed changes, the allocation or
assignment methodologies, [*69] or the quantifications for ratemaking purposes.
13. SWEPCO or AEPSC on behalf of SWEPCO may not make any non-emergency
procurement in excess of $1 million per transaction from an unregulated
affiliate other than from AEPSC except through a competitive bidding process or
as otherwise authorized by this Commission. Transactions involving the Company
and CSW Credit, Inc. (or its successor) for the financing of accounts
receivables are exempt from this condition. Records of all such affiliate
transactions must be maintained until the Company's next comprehensive retail
rate review. In addition, at the time of the next comprehensive rate review, all
such affiliate transactions that were not competitively bid shall be separately
identified for the Commission by the Company. This identification shall include
all transactions between the Company and AEPSC in which AEPSC acquired the goods
or services from another unregulated affiliate.
14. If an unregulated business markets a product or service that was developed
by SWEPCO or paid for by SWEPCO directly or through an affiliate, and the
product or service is actually used by SWEPCO, all profits on the sale of such
product or service (based [*70] on Louisiana retail jurisdiction) shall be split
evenly between SWEPCO, which was responsible for or shared the cost of
developing the product, and the unregulated business responsible for marketing
the product or service to third parties, after deducting all incremental costs
associated with making such product or service available for sale, including the
direct cost of marketing such product or service. However, in the event that
such a product or service developed by SWEPCO to be used in its utility business
is not actually so used, and subsequently is marketed by the unregulated
business to third parties, SWEPCO shall be entitled to recover all of its costs
to develop such product or service before any such net profits derived from its
marketing shall be so divided. If SWEPCO jointly develops such product or
service and shares the development with other entities, then the profits to be
so divided shall be SWEPCO's pro rata share of such net profits based on
SWEPCO's contribution to the development costs.
15. Subject to the provisions of Paragraph 6 of the Merger Conditions (fuel
hold harmless), SWEPCO shall continue to purchase, treat, and allocate its fuel
costs consistently [*71] with the Commission General Order dated November 6,
1997, In re: Development of Standards Governing the Treatment and Allocation of
Fuel Costs by Electric Utility Companies, including any future amendments to
this Order.
16. In the event of the implementation of electric generation open access for
Commission-jurisdictional electric utilities, any rules, regulations or orders
of general applicability adopted by the Commission regarding generation assets
in an open access environment will apply to the company and, to the extent
inconsistent with provisions of this Order, will govern. No later than six
months prior to the mandated open access date, the company shall file with the
Commission any proposed modifications to this Order to address any such
inconsistencies.
17. If retail access for SWEPCO-La. is mandated by the Commission, or through
action by the Federal Energy Regulatory Commission or federal legislation, then
SWEPCO-La. shall have the right to petition the Commission for modifications to
the terms of this settlement, including the affiliate transaction conditions,
that are made necessary by the mandating of retail access and its likely impact
on the retail rates [*72] at SWEPCO-La. Any such petition must establish the
necessity of the proposed modifications and provide appropriate protections to
ensure that the benefits of this merger are preserved for SWEPCO-La. regulated
customers, including merger savings and the hold harmless provisions set forth
herein. The Commission will act upon the petition in accordance with its normal
rules and
<PAGE> 21
procedures. This paragraph is not intended to limit SWEPCO's right to petition
the Commission in the event that electric utility unbundling or retail access is
ordered by a state commission regulating SWEPCO's retail rates, provided that
SWEPCO must comply with the requirements set forth above in any such petition.
SAVINGS SHARING MECHANISM (SSM)
The savings in nonfuel operation and maintenance (O&M) expense resulting from
the merger between CSW and AEP will be quantified in accordance with a formula
based methodology, the SSM, and shared equally between customers and
shareholders. The Louisiana retail jurisdictional share of nonfuel O&M savings
quantified in accordance with the SSM will be flowed through to customers
through an annual surcredit effective initially and for the period beginning on
the [*73] first day of the fifteenth month after the consummation of the merger.
The nonfuel savings quantification through the SSM and the surcredit will be
updated for current information on each twelve month anniversary for a total of
eight filings. The surcredit in effect after the eighth filing will remain in
effect unless and until the Commission issues an order in a base rate
proceeding. The annual surcredit will be computed and applied as a uniform
percentage of base revenues.
After the base rate cap expires, the Company will be allowed to file a claim
for a base rate revenue deficiency as an offset to the SSM savings surcredit,
which will be subject to an expedited six month review by the Commission.
However, the surcredit may only be reduced prospectively after the Commission
determines and approves a revenue requirement offset. After the Company's base
rate cap expires, but only through the effective dates of the Company's last
required SSM filing, or in a base rate proceeding initiated by this Commission
after the effective date of the merger, the Company may include its retained
savings, computed pursuant to the SSM, as a cost of service expense in its
revenue requirement filed [*74] in conjunction with a comprehensive base rate
proceeding. The Company may not include its retained share of savings, computed
pursuant to the SSM, as a cost of service item in any revenue requirement filing
to offset the SSM. In any base revenue requirement filing through the effective
date of the Company's last required SSM filing, the Company will exclude the
test year amount of the SSM surcredit from its per books and pro forma revenues.
I. Merger Costs To Achieve, Transaction Costs, And Change In Control Payments.
The Company is authorized to defer its merger costs to achieve, transaction
costs, and change in control payments as these terms have been defined in the
testimony of the Applicants' witnesses in this proceeding. The Commission will
allow the Company to retain its share of the SSM savings in order to amortize
its deferred costs.
During the first fourteen months following the consummation of the merger, the
Company will retain 100% of the merger savings and may utilize these savings to
reduce the deferrals of its merger costs. Commencing in the fifteenth month
following the consummation of the merger, the Company will retain 50% of the
merger savings, computed [*75] pursuant to the SSM, and may utilize these
savings or any portion of these savings to reduce the deferrals of its merger
costs.
II. Savings Sharing Mechanism Formula.
The SSM surcredit and the Company's retained share of merger savings will be
computed in accordance with the SSM formula. The SSM formula compares the
Company's future year normalized O&M expense (FYNE) to the 1998 base year
normalized O&M expense (BYNE) escalated for inflation and reduced for
productivity improvements. The 1998 base year normalized O&M expense, prior to
the inflation and productivity adjustments, is based upon the actual pre-merger
level of the Company's nonfuel O&M expense adjusted to reflect certain
ratemaking adjustments, to remove operating lease costs, and to remove certain
nonrecurring expenses (specifically identifiable and in excess of $1 million
during the twelve-month period), including all merger costs. The derivation of
the 1998 base year normalized O&M expense is detailed on Attachment A.
For each year subsequent to 1998, the base year normalized O&M will be
escalated by an inflation factor reflecting the annual increase in the Consumer
Price Index - Urban (CPI-U) less a [*76] 1.1% annual productivity adjustment.
For each subsequent year, the CYCPI-U will be for the month representing the
mid-point of the twelve month future year period as published on the Consumer
Price Indexes home page (http://stats.bls.gov/cpihome.htm).
<PAGE> 22
The future year normalized O&M expense will be based upon the actual post
merger level of the Company's nonfuel O&M expenses adjusted to reflect certain
ratemaking adjustments, to remove operating lease costs, and to remove certain
nonrecurring expenses (specifically identifiable and in excess of $1 million
during the twelve-month period), including all merger related costs and
amortizations, in a manner similar to that of the base year normalized O&M. The
formula for the future year normalized O&M is detailed on Attachment B.
Merger savings will be computed as the difference between the future year
normalized O&M and the base year normalized O&M, adjusted for inflation and
productivity improvements as previously described. The merger savings then will
be allocated to the Louisiana retail jurisdiction (LJA).
The merger savings for the Louisiana retail jurisdiction under the SSM will be
computed in accordance with the following [*77] formula, consistent with the
preceding description.
Merger Savings = (FYNE - BYNE) * LJA where:
FYNE = Future Year Normalized O&M, Computed According to Attachment B
BYNE = Base Year Normalized O&M, Computed According to Attachment A, escalated
for inflation and reduced for productivity improvement in accordance with the
following formula:
BYNE = 1998 BYNE O&M * (CYCPI-U/BYCPI-U) - ((1 + .011)n - 1)
where:
CYCPI-U = Current Year CPI-U (as of the month representing the mid-point of
12-month future year period)
BYCPI-U = 1998 Base Year CPI-U (as of June 1998)
n = number of years (stated as a decimal to reflect partial years) computed as
mid-point of current year less the mid-point of 1998
LJA = Louisiana retail jurisdiction allocation percentage based upon the most
recent calendar year cost of service
Savings computed pursuant to the SSM formula beginning with the fifteenth month
after the effective date of the merger will be allocated 50% to customers
through the SSM surcredit mechanism and retained 50% by the Company.
Attachment C provides an example of the calculation of the SSM and the
allocation of savings to customers through the surcredit and the savings [*78]
retained by the Company.
III. Timing of SSM Surcredit Reductions to Customers and Commission Review.
The first twelve month (year) period for the computation of SSM savings will
begin on the first day of the first calendar month after the consummation of the
merger. Subsequent periods for the computation of SSM savings will follow the
same twelve month cycle as the first period. SWEPCO will make the first SSM
filing within the Merger Docket U-23327 and pursuant to the Merger Order in
Docket U-23327 within 60 days after the completion of the first twelve month
period (within fourteen months of the consummation of the merger). The first
surcredit rate reductions will commence on the first day of the fifteenth month
following the consummation of the merger, subject to the Commission's subsequent
review and approval. Likewise, the subsequent surcredit rate reductions will
commence on the twelve month anniversaries of the first surcredit rate
reductions, subject to the Commission's subsequent review and approval. To
implement the surcredit rate reductions, the Company's annual filings will
include a tariff that will go into effect with no further action by the
Commission, subject [*79] to the Commission's subsequent review and approval.
Copies of the SSM filings will be provided to the Commission and, if directed,
its consultants and Special Counsel for review, analysis, and recommendations to
the Commission. In the event that the Commission ultimately determines that a
larger surcredit rate reduction than the one filed by the Company is required,
that additional reduction shall be
<PAGE> 23
effective as of the date the original filing became effective. The Company shall
make such additional refunds or credit customer bills to reflect this effective
date.
In conjunction with the second SSM filing, but within 120 days of the end of
the second SSM period, the Company also will file detailed financial information
typically utilized in a revenue requirement filing, including a jurisdictional
cost of service study. The filing of this detailed financial information also
will be within the Merger Docket U-23327 and pursuant to the Merger Order in
Docket U-23327. The detailed financial information will be for the most recent
twelve months ending concurrent with the second SSM savings period. The detailed
financial information will be provided in the format specified in Attachment
[*80] D. However, the Company and other parties agree that the schedules filed
pursuant to this provision will not be determinative for ratemaking purposes.
Copies of the detailed financial information will be provided to the
Commission's consultants and Special Counsel for review, analysis, and
recommendations to the Commission. The Company agrees to cooperate with the
Commission's Staff and/or its consultants and Special Counsel and to provide
timely, accurate, and comprehensive responses to discovery.
Attachment A
- --------------------------------------------------------------------------------
BASE YEAR NORMALIZED (BYNE)
OPERATION AND MAINTENANCE EXPENSE
SWEPCO SAVINGS SHARING MECHANISM
(000)
<TABLE>
<CAPTION>
Twelve Months
Ended
December 31, 1998
<S> <C>
I. Total Actual 1998 Non-Fuel O&M Expense
(Excluding Account Nos. 501, 518, 536, 547 and 555) $ 191,833
II. Less:
A. Transmission Fees (Account 565) (7,292)
B. Merger Costs (Costs to Achieve,
Transaction Costs, Separation Payments) 0
C. Costs of Early Retirement or
Other Cost Reductions 0
D. Operating Lease Expense *** (1,770)
III. Other: Add/(Subtract)
A. SFAS 106 Expense
in Excess of Cash Pay-As-You-Go (194)
B. Other Non-Recurring Adjustments (13,870)
IV. Total Base Year Normalized $ 168,707
</TABLE>
- --------------------------------------------------------------------------------
[*81]
- - - - - - - - - - - - - - - - - -FOOTNOTES- - - - - - - - - - - - - - - - - -
*** FERC Accounts 507, 525, 540, 550, 567, 589, and 931.
- - - - - - - - - - - - - - - - -END FOOTNOTES- - - - - - - - - - - - - - - - -
<PAGE> 24
FUTURE YEAR NORMALIZED (FYNE)
OPERATION & MAINTENANCE EXPENSE
SWEPCO SAVINGS SHARING MECHANISM
(000)
Attachment B
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Twelve Months
Ended
MM, DD, YY
<S> <C>
I. Total Actual Future Year Non-Fuel O&M Expense
(Excluding Account Nos. 501, 518, 536, 546 and 555) $II. Less:
A. Transmission Fees (Account 565)
B. Merger Costs (Costs to Achieve, Transaction Costs,
Separation Payments) and Amortizations
C. Costs of Early Retirement or
Other Cost Reductions
D. Operating Lease Expense ****
III. Other: (Add/(Subtract)
A. SFAS No. 106 Expense in Excess of Cash Pay-As-You-Go
B. Other Non-Recurring Adjustments
IV. Total Future Year Normalized $
</TABLE>
- --------------------------------------------------------------------------------
- - - - - - - - - - - - - - - - - -FOOTNOTES- - - - - - - - - - - - - - - - - -
* FERC Accounts 501, 525, 540, 550, 567, 589, and 931
- - - - - - - - - - - - - - - - -END FOOTNOTES- - - - - - - - - - - - - - - - -
Attachment C
- --------------------------------------------------------------------------------
ILLUSTRATION OF OPERATION OF SWEPCO MERGER SAVINGS SHARING MECHANISM
<TABLE>
<CAPTION>
Year 1 Year 2 Year 3 Year 4
<S> <C> <C> <C> <C>
Description
Base Year O&M Expenses $ 100,000 $ 100,000 $ 100,000 $ 100,000
Future Year CPI-U 103,000 106,090 109,273 112,551
Base Year CPI-U 100,000 100,000 100,000 100,000
Future Year CPI-U/Base Year CPI- 1.030 1.061 1.093 1.126
U
Productivity Factor Offset -0.011 -0.022 -0.033 -0.045
SSM Base Year Escalation Factor 1.019 1.039 1.059 1.081
Base Year Normalized Expense, $ 101,900 $ 103,878 $ 105,938 $ 108,078
Esc & Prod Offset
Future Year Normalized Expenses $ 101,000 $ 102,010 $ 103,080 $ 104,060
Total Company Savings (FYNE- ($ 900) ($ 1,868) ($ 2,906) ($ 4,017)
BYNE)
Louisiana Jurisdictional Factor 40.00% 40.00% 40.00% 40.00%
Louisiana Jurisdictional Merger ($ 360) ($ 747) ($ 1,162) ($ 1,607)
Savings
Customers Allocation of Savings ($ 180) ($ 374) ($ 581) ($ 803)
(pound sterling)50%
</TABLE>
NOTE: Years in the column headings refers to the twelve month imple-
mentation periods commencing on the first day of the fifteenth month
following consummation of the merger.
- --------------------------------------------------------------------------------
[*82]
- --------------------------------------------------------------------------------
<PAGE> 25
ILLUSTRATION OF OPERATION OF SWEPCO MERGER SAVINGS SHARING MECHANISM
<TABLE>
<CAPTION>
Year 5 Year 6 Year 7 Year 8
<S> <C> <C> <C> <C>
Description
Base Year O&M Expenses $ 100,000 $ 100,000 $ 100,000 $ 100,000
Future Year CPI-U 115,927 119,405 122,987 126,677
Base Year CPI-U 100,000 100,000 100,000 100,000
Future Year CPI-U/Base Year CPI- 1.159 1.194 1.230 1.267
U
Productivity Factor Offset -0.056 -0.068 -0.080 -0.091
SSM Base Year Escalation Factor 1.103 1.126 1.150 1.175
$ 115,029
Base Year Normalized Expense, $ 110,305 $ 112,621 $ 117,531
Esc & Prod Offset
Future Year Normalized Expenses $ 105,101 $ 106,152 $ 107,214 $ 108,286
Total Company Savings (FYNE- ($ 5,204) ($ 6,469) ($ 7,815) ($ 9,245)
BYNE)
Louisiana Jurisdictional Factor 40.00% 40.00% 40.00% 40.00%
Louisiana Jurisdictional Merger ($ 2,082) ($ 2,588) ($ 3,126) ($ 3,698)
Savings
Customers Allocation of Savings ($ 1,041) ($ 1,294) ($ 1,563) ($ 1,849)
(pound sterling)50%
</TABLE>
NOTE: Years in the column headings refers to the twelve month imple-
mentation periods commencing on the first day of the fifteenth month
following consummation of the merger.
- --------------------------------------------------------------------------------
<PAGE> 1
EXHIBIT D-5.4
PUC DOCKET NO. 19265
SOAH DOCKET NO. 473-98-0839
APPLICATION OF CENTRAL AND # PUBLIC UTILITY COMMISSION
SOUTH WEST CORPORATION AND #
AMERICAN ELECTRIC POWER #
COMPANY, INC. REGARDING #
PROPOSED BUSINESS COMBINATION # OF TEXAS
ORDER
This Order finds that the proposed business combination involving
Central and South West Corporation (CSW) and American Electric Power Company,
Inc. (AEP) (collectively applicants) is consistent with the public interest,
pursuant to PURA(1) Section 14.101, under the terms and conditions specified in
thiS Order. This conclusion rated the comprehensive public interest standard
articulated in Application of Southwestern Public Service Company Regarding
Proposed Business Combination with Public Service Company of Colorado.(2)
Furthermore, this Order and approves the requested regulatory treatments
detailed in Section X of the application to the extent specified in this Order.
This Order is consistent with the non-unanimous stipulation (ISA)(3)
entered into by several parties in this proceeding. Nevertheless, this Order
addresses two areas, allocation of certain savings to regulated rates and
reliability standards, to ensure compatability of the ISA and this Order with
electric restructuring legislation passed by the 76th Legislature.(4) The State
Office of Administrative Hearings' Proposal for Decision,(5) including findings
of fact and conclusions of law, is adopted and
- ----------
(1) Public Utility Regulatory Act, TEX. UTIL. CODE ANN.
Sections 11.001-64.158 (Vernon 1999) (PURA).
(2) Application of Southwestern Public Service Company Regarding
Proposed Business Combination with Public Service Company of Colorado, Docket
No. 14980 (Feb. 14, 1997).
(3) Integrated Stipulation and Agreement (May 4, 1999) (ISA).
(4) Act of May 27, 1999, 76th Leg., R.S., ch. 405 (S.B. 7), 1999 Tex.
Sess. Law Serv. 2543 (Vernon) (to be codified primarily as Chapters 39, 40, and
41 of the Texas Utilities Code).
(5) Proposal for Decision (Sept. 30, 1999).
<PAGE> 2
PUC DOCKET NO. 19265 ORDER PAGE 2 OF 28
SOAH DOCKET NO. 473-98-0839
incorporated by reference into this Order, except where inconsistent with this
Order.
I. DISCUSSION
DISTRIBUTION RATES
The ISA provides that the Texas operating companies(6) will apply the
savings detailed in Attachments A and H of the ISA to the "regulated rates of
their customers"(7) and that all rate reduction riders will be credited to
customers in accordance with Attachment I.(8) Paragraph 9 of Attachment I
provides:
In the event of industry restructuring legislation, the base rate
revenue credits will be maintained by individual rate class, to the
extent possible, although it is impossible to formulate a specific plan
at this time. If and when restructuring legislation is enacted, the
Applicants will submit a plan for [Commission] approval to allocate the
credits set forth in Attachments A and H consistent with Sections 3.C,
3.F(8) and Attachment H, Section 6.(9)
Subsequent to the filing of the ISA, electric restructuring legislation was
enacted into law.(10)
The Commission concludes that customers of the Texas operating
companies will not receive the full benefit of the savings specified in the ISA
after January 1, 2002, unless the savings are allocated to the distribution
rates of the successor transmission and distribution utilities.(11) A
representative of AEP has assured the Commission that the proposed savings in
the ISA can, as a practical matter, be applied against distribution rates.(12)
The Commission's decision in this matter
- ----------
(6) Central Power and Light, Southwestern Electric Power Company, and
West Texas Utilities and their respective successors in interest. See ISA
Section 1.
(7) ISA Section 3.C and Attachment H, P. 6.
(8) Id. Attachment H, P. 1.
(9) Id. Attachment I, P. 9.
(10) Act of May 27, 1999, 76th Leg., R.S., ch. 405 (S.B. 7), 1999 Tex.
Sess. Law Serv. 2543 (Vernon) (to be codified primarily as Chapters 39, 40, and
41 of the Texas Utilities Code).
(11) Under PURA Section 39.051, all electric utilities, including the
Texas operating companies, will be required to unbundle their business
activities into several entities, one of which will be a transmission and
distribution utility.
(12) Open Meeting Tr. at 284-88 (Nov. 4, 1999).
<PAGE> 3
PUC DOCKET NO. 19265 ORDER PAGE 3 OF 28
SOAH DOCKET NO. 473-98-0839
rests, in part, on this assurance.
Therefore, the unbundling proceedings in 2000, in which the Commission
will approve the transmission and distribution tariffs(13) are the appropriate
forums to reflect these post-2002 savings in distribution rates. The savings are
not effective, however, until the first month after the effective date of the
merger,(14) and the merger may not be effective until after the April 1, 2000
deadline for filing tariffs initiating the unbundling proceedings.(15) In that
event, after the merger is effective, the Texas operating companies' filings
shall be amended to reflect the regulated-rate savings in the distribution rates
of their successor transmission and distribution utilities. Ordering Paragraph 9
is modified and new Ordering Paragraph 9A is added to reflect this decision.
RELIABILITY STANDARDS
Section 7.B of the ISA specifies reliability standards that are based
upon P.U.C. SUBST. R. 25.53 and 25.81, and guarantees related to those
standards. The Commission is, however, presently considering amendments to these
rules(16) to conform to newly enacted statutory requirements.(17) Anticipating
such changes, Section 7.D(2) of the ISA provides that:
In the event the Commission's service reliability rule (Substantive
Rule 25.52) is amended, such amendments shall automatically be
incorporated in this agreement. Additionally, the signatories agree
that they will revisit these standards and penalties in the future in
the context of any performance-based ratemaking plans or rules for CSW
and /or the electric industry.(18)
To effectuate this provision, the Commission adds new Ordering
Paragraph 9B directing the
- --------
(13) See PURA Section 39.201.
(14) ISA Section 3A.
(15) Open Meeting Tr. at 301-02 (Nov. 4, 1999).
(16) Electric Reliability Standards, Project No. 21076 (pending).
(17) See PURA Section 38.005.
(18) ISA Section 7.D(2).
<PAGE> 4
PUC DOCKET NO. 19265 ORDER PAGE 4 OF 28
SOAH DOCKET NO. 473-98-0839
Office of Regulatory Affairs, after any amendments to the Commission's service
reliability rules, to establish a project to address any inconsistencies between
the ISA and those amendments.
V. FINDINGS OF FACT AND CONCLUSIONS OF LAW
A. FINDINGS OF FACT
DESCRIPTION OF THE APPLICANTS
1. This case involves the potential merger of American Electric Power
Company, Inc. (AEP) with Central and South West Corporation (CSW)
(collectively called the Applicants).
2. AEP is a utility holding company based in Columbus, Ohio. It owns all
the common shares of seven domestic electric utility operating
companies: Appalachian Power Company, Columbus Southern Power Company,
Indiana Michigan Power Company, Kentucky Power Company, Kingsport Power
Company, Ohio Power Company, and Wheeling Power Company. The AEP
operating companies serve almost three million customers in parts of
Ohio, Michigan, Indiana, Kentucky, West Virginia, Virginia, and
Tennessee.
3. CSW is a utility holding company based in Dallas, Texas. It owns four
domestic utility operating companies: Central Power and Light Company
(CPL), Public Service Company of Oklahoma (PSO), Southwestern Electric
Power Company (SWEPCO), and West Texas Utilities Company (WTU). CPL and
WTU operate within Texas, SWEPCO serves customers in Texas, Arkansas
and Louisiana, and PSO serves customers within Oklahoma. The CSW
operating companies provide electric service to approximately 1.7
million customers in a widely diversified area covering 152,000 square
miles. The three utility companies serving Texas are referred to as the
"Texas operating companies."
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DESCRIPTION OF THE MERGER
4. Under the proposed transaction, CSW will in effect be merged into AEP,
and CSW shares will be converted into AEP shares using an exchange
ratio of .6 AEP shares per CSW share. Any fractional shares of AEP
stock resulting from the exchange will be paid in cash. The merger will
be accounted for by the "pooling of interests" method of accounting.
5. The only corporate effect of the merger on the operating companies of
CSW is a change in the ownership of the holding company. AEP will be
the surviving corporation, which will be headquartered in Columbus,
Ohio.
6. The eleven domestic utility operating companies of CSW and AEP retain
their separate corporate identities, assets and liabilities,
franchises, and certificates of convenience and necessity.
7. The merger will require the approval of the Oklahoma Corporation
Commission, the Arkansas Public Service Commission, and the Louisiana
Public Service Commission. Each of those bodies has issued an order
approving the merger with various conditions. On the federal level,
approvals are being requested from the Federal Energy Regulatory
Commission (FERC), the Securities and Exchange Commission under the
Public Utility Holding Company Act of 1935, the Federal Trade
Commission under the Hart-Scott-Rodino Antitrust Improvement Act, the
Nuclear Regulatory Commission, and the Federal Communications
Commission.
PROCEDURAL HISTORY
8. On April 30, 1998, the Applicants submitted an application to the
Public Utility Commission of Texas (PUC or Commission) for a public
interest finding. On May 1, 1998, the Commission referred this docket
to the State Office of Administrative Hearings (SOAH).
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9. On May 27, 1998, the Administrative Law Judge (ALJ) held a pre-hearing
conference and set December 2, 1998 as the date for the hearing on the
merits. On June 1, 1998, the PUC Office of Policy Development (OPD)
issued an order requesting briefing on threshold issues. On June 5,
1998, OPD requested additional briefing on the issue of federal
authority vis-a-vis the Commission's regulatory authority. After
consideration of the briefs of the parties, the Commission issued its
first Preliminary Order in this docket on July 1, 1998. That
Preliminary Order identified statutory issues, issues arising from
Commission precedent, and twelve case-specific questions. On July 14,
1998, the Commission issued its Supplemental Preliminary Order, adding
a thirteenth question. On July 14, 1998, the Applicants submitted
supplemental testimony that addressed each of the issues identified in
the Commission's Preliminary Orders.
10. On July 24, 1998, the ALJ directed parties to engage in settlement
meetings, and specified dates on which the Applicants would report to
the ALJ on those settlement discussions. No comprehensive settlement
was reached as a result of those discussions, but the Applicants did
reach a settlement with the Office of Public Utility Counsel (OPC) and
intervenor Cities.(19) That settlement was filed November 9, 1998. As a
result, the Applicants filed additional testimony in support of that
stipulation on November 25, 1998. On December 8, 1998, the ALJ issued
an order setting a new date for the hearing on the merits of April 27,
1999. The ALJ also ordered the Applicants to file supplemental
testimony on market power on January 15, 1999.
11. Several parties contended that the non-unanimous stipulation required
additional notice. In Order No. 32, issued on December 14, 1998, the
ALJ denied the motion. On appeal, in an order dated January 27, 1999,
the Commission reversed the ALJ's ruling and ordered bill insert
notices be given to affected customers and affected municipalities.
- ----------
(19) Cities include Abilene, Corpus Christi, McAllen, Victoria, Big
Lake, Vernon, and Paducah.
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12. On March 23, 1999, the ALJ suspended the procedural schedule and
rescheduled the hearing on the merits to May 4, 1999. On April 1, 1999,
the ALJ moved the hearing on the merits to May 25, 1999. On April 23,
1999, the ALJ granted a motion to suspend the procedural schedule in
light of a pending settlement. On May 4, 1998, numerous parties (the
Signatories) submitted an Integrated Stipulation and Agreement (ISA).
In addition to the OPC and the Cities, the Signatories included the
Commission Office of Regulatory Affairs (ORA), the State of Texas, the
Texas Industrial Energy Consumers, and Low Income Intervenors. On May
11, 1999, the ALJ issued Order No. 52, requiring the filing of
additional testimony in support of the ISA and setting August 9, 1999
as the date for the hearing on the merits.
13. In accordance with Order No. 52, the Signatories filed supplemental
testimony on May 21, 1999. Several non-signatory parties filed
testimony regarding the merger on July 16, 1999. The Signatories filed
rebuttal testimony on July 30, 1999.
14. The hearing on the merits commenced on August 9, 1999. At the start of
the hearing, counsel for Applicants announced additional settlements
had been reached with all but one of the active non-signatories. As a
result, the hearing consisted exclusively of the cross-examination by
Power Choice, Inc.'s (Power Choice) counsel, with limited redirect by
the Signatories and inquiry by the ALJ. Upon receipt of a letter from
the counsel for the Public Utility Board of Brownsville, the ALJ closed
the hearing on August 11.
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THE ISA
15. The ISA resolves all the merger-related issues among the Signatories
and also resolves some regulatory proceedings of the Texas operating
companies as well. The ISA contains merger-related rate reductions, as
well as rate reductions arising from the settlement of other cases. It
provides for additional amortization of Excess Cost Over Market (ECOM)
of CPL. It contains a market power mitigation plan and provides
affiliate standards. It sets detailed customer service standards. It
includes a rate moratorium for the Texas Operating companies that will
last until January 1, 2003, subject to certain force majeure
provisions. It contains provisions regarding jurisdictional issues
between the PUC and federal agencies. It provides for Applicants to
implement a Customer Education Plan and an expanded Low-Income program.
It includes a sharing of off-system sales margins and other provisions
relating to the operations of the merged companies.
16. The ISA represents a compromise among all the Signatories. If the PUC
does not accept the ISA or issues an interim or final order that is
materially inconsistent with the ISA, any Signatory adversely impacted
by that material modification or inconsistency may withdraw its consent
and proceed to a hearing on all issues.
REASONABLE VALUE
17. This merger is accomplished through a stock transaction. The price of
CSW's and AEP's stock is set through the daily trading activity of the
New York Stock Exchange. The merger was analyzed by the Board of
Directors of both CSW and AEP and included the consideration of
fairness opinions produced for both Boards. The transaction was the
product of a willing buyer and a willing seller establishing a
reasonable value after consideration of a number of factors. The Boards
of both companies utilized fairness opinions prepared by investment
bankers. Those opinions considered discounted cash flows, comparable
companies, selected other mergers and acquisitions, historic trading
ratios, and a pro forma analysis of the merger.
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18. AEP will convert CSW stock to AEP stock using a conversion ratio of .60
of AEP shares for each share of CSW stock.
HEALTH AND SAFETY
19. AEP has an excellent safety record. AEP has employee training regarding
safety, programs for the health and well being of its employees, and an
active safety outreach program for the general public. After the
merger, the similar health and safety programs of CSW will eventually
be combined into a unified health and safety program. The proposed
merger will not adversely affect the health or safety of customers or
employees.
EMPLOYMENT IMPACTS
20. The merger could result in some jobs being transferred out of the state
of Texas. Most of the potential job losses will be in the middle and
upper ranks of management in the service companies. The geographic
diversity of the merger ensures that many functions remain local.
21. Paragraph 9.C. of the ISA commits the Merged Company(20) not to reduce
operating company field positions and customer service jobs for
eighteen months beginning April 1, 1999. "Field positions" includes all
employees on the front-line of providing service to the customer. This
term would include all linemen, servicemen, and meter readers.
"Customer service jobs" would include all the jobs having day-to-day
contact with customers, such as telephone service representatives in
the companies' call centers.
22. The merger will not result in the material transfer of jobs of citizens
of this state to workers domiciled outside this state.
- ----------
(20) Merged company is defined in the ISA as the post-merger AEP and
its successors in interest. See ISA Section 1.
<PAGE> 10
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NO DECLINE IN SERVICE
23. The ISA contains numerous standards for service quality, with monetary
penalties if they are not met. The merger will not result in a decline
of service quality or reliability.
MERGER DOES "MORE THAN PROMISE" COST SAVINGS
24. The ISA provides for the sharing of net merger savings with Texas
customers through a "net merger savings rate reduction rider." A total
of $84.4 million of merger savings will be shared with customers of CPL
($52.7 million), SWEPCO ($16 million), and WTU ($15.6 million). After
the sixth year, the net merger savings rider will continue at the same
level as the year six rider. In the first base rate proceeding for an
operating company after the six-year net merger sharing savings period,
all merger savings will be reflected in rates and the net merger
savings rate reduction rider will be terminated. The amount of the net
merger savings rate reduction rider is based on the estimates of net
Texas retail merger savings. Even if net merger savings fall short of
the estimates, the Applicants are guaranteeing a fixed level of
benefits to customers and will bear the risk of any failure to actually
achieve the full amount of net savings.
25. The ISA also contains rate reduction riders in Attachment H. In the
context of the overall ISA, the total amount of the rate reductions
(merger-related and Attachment H) is just and reasonable. Attachment H
also provides that CPL will extend the terms of the Docket No.
12820(21) Stipulation to include a pre-tax ECOM amortization of
$20,000,000 per year in 2000 and 2001 and a pre-tax ECOM amortization
of $5,000,000 per year in the years 2002 through 2005. The provisions
of the ISA dealing with rate reduction riders and reductions of ECOM
are reasonable and in the public interest.
- ----------
(21) Inquiry of General Counsel for an Inquiry Into the Reasonableness
of the Rates and Services of Central Power and Light Company (CPL), Docket No.
12820, Order on Rehearing (Oct. 11, 1995).
<PAGE> 11
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26. The ISA requires that all reconcilable fuel and purchased power savings
be passed through to customers in accordance with PUC rules and
proceedings for fuel factor adjustments and fuel reconciliation. The
Applicants estimate that there will be fuel savings as a result of the
merger.
27. The ISA does more than "just promise" savings to the Texas retail
customers of the Texas Operating companies.
IMPROVEMENT IN SERVICE
28. AEP made the commitment to meet current levels of service and strive to
exceed those levels. AEP may improve CSW service through the
introduction of a real-time customer service data system, developments
in the AEP transmission and distribution system which may be useful to
CSW in the proper circumstances, and software programs which may be
useful to CSW service.
29. The ISA contains eight pages of detailed standards relating to quality
of service. The ISA specifies standards for service turn on and
upgrades, light replacements, telephone response, and reporting
requirements. Each of the customer standards has an accompanying
penalty for failure to meet the standard. The ISA similarly establishes
standards for distribution feeders and system standards, with detailed
monetary penalties for failure to meet each standard. The ISA
authorizes an independent audit of the standards by the Office of
Customer Protection twenty-four months after the standards are
implemented by the Merged Company, and every twenty-four months
thereafter.
30. The quality of service provisions provide additional assurances that
the merger will result in improvements in service to CSW's Texas
customers because of the financial incentives contained in the
standards. The customer service reporting standards are new
requirements
<PAGE> 12
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that do not exist under current Commission rules. The ISA establishes
numerous reporting, surveying, and independent auditing requirements,
which enhance the Commission's and customers' monitoring and evaluation
of the customer service provided by the Merged Company.
31. The ISA contains an expanded Low-Income program which will improve the
quality of service for the customers served by that program. The
Low-Income program is reasonable and in the public interest.
32. The ISA includes a Customer Education plan in the event of retail
competition. Now that Senate Bill No. 7 has been signed, this provision
of the ISA will mean more information for Texas consumers. The Customer
Education plan is reasonable and in the public interest.
33. The customer service standards and reliability standards contained in
the ISA are appropriate. Based on Findings of Fact Nos. 28 through 32,
the quality of service for Texas customers will improve as a result of
the merger.
MERGER COSTS AND MERGER BENEFITS
34. Over a ten-year period, the Applicants estimate they would have a total
savings of $2.407 billion, less merger costs-to-achieve of $248,080
million and pre-merger initiatives of $193,327 billion for a net
savings level of $1.965 billion.
35. The total amount of merger savings was allocated to each company by
creating a synergy savings work order based on the analysis of services
provided by the functional group. They utilized appropriate allocation
factors for those functions to determine savings allocated to each
operating company. The merger costs and pre-merger initiatives were
allocated to all companies on a pro rata basis following gross savings.
The individual company estimates of costs savings and costs were
divided among regulatory jurisdictions using allocation
<PAGE> 13
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SOAH DOCKET NO. 473-98-0839
factors that were generally consistent with the practices used for cost
assignments in past CSW rate proceedings. These efforts resulted in the
level of merger savings shown in the ISA.
36. The ISA authorizes a "net merger savings" expense item (as shown in ISA
Attachment B) to be reflected as a reasonable and necessary operating
expense, if there is a proceeding to change base rates of a Texas
Operating Company to become effective prior to the end of a six-year
period after the effective date of the merger.
37. The ISA authorizes the Merged Company and Texas Operating companies to
defer and amortize their merger-related costs-to-achieve over a
six-year period following the effective date of the merger. If there is
a proceeding to change base rates of a Texas Operating Company within
six years after the effective date of the merger, the ISA states that
the amortization of costs to achieve the merger included in Attachment
C to the ISA will be reflected as a reasonable and necessary expense
included in the cost of service. The ISA also reduces the amount that
will be considered reasonable and necessary as included in Attachment E
if a Texas operating company requests an increase to overall base
revenues to be effective prior to the end of the six-year period.
38. Both the provisions of the ISA relating to the "net merger savings"
expense item and the deferral and amortization of costs to achieve the
merger, including change in control payments, are reasonable and should
be approved.
39. The merger will not cause Texas customers to bear merger costs
unrelated to corresponding benefits to Texas customers.
<PAGE> 14
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MERGER FACILITATES REGULATORY OVERSIGHT
40. This merger does not cause any change in the jurisdiction of any
regulatory body.
41. The Merged Company will propose a substantially expanded set of
allocation factors over those presented by CSW in the last CPL rate
case. Those factors will correlate to the volume of activity that is
generated in performing certain services and thereby emphasize cost
causation factors.
42. The ISA contains numerous provisions that relate to the regulatory
jurisdiction of the PUC. They are primarily contained within ISA
Section 4, but other provisions will assist the PUC in its regulatory
oversight over the Merged Company.
43. The books and records of the Texas operating companies might be kept
outside the state. The Merged Company will return such records for
inspection pursuant to P.U.C. Subst. R. 25.71.
44. The merger is not a means of evading regulation and will facilitate
regulatory oversight of the Merged Company.
MARKET POWER AND COMPETITION
45. Under the Applicants' market power study, there were instances in the
Southwest Power Pool (SPP) and the Electric Reliability Council of
Texas (ERCOT) in which the merger might cause failures of the FERC
merger guidelines screen. The mitigation proposed by the ISA will
address the apparent problems.
46. Under the ISA, the Merged Company agrees to divest 1604 megawatts (MW)
of generation capacity in ERCOT. The ISA specifies that the divestiture
shall consist of Lon Hill Units 1-4 (546 MW), Nueces Bay Plant (559
MW), Joslin Unit 1 (249 MW), and Frontera Plant (250 MW). The ISA also
specifies that the Merged Company agrees to divest 300 MW in the SPP,
or more if it is required to do so by FERC.
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47. The ISA protects the accounting of the merger by timing the ERCOT
divestiture so as to not violate the criteria of pooling of interests
accounting. Paragraph 6.C of the ISA contains the procedures that the
Applicants and ORA will follow in order to determine the appropriate
timing for the divestiture.
48. CPL may recall up to 1354 MW of the divested capacity under certain
circumstances. The ISA contains numerous details regarding when and
under what circumstances CPL may recall the capacity.
49. Gains from the sale of the CPL plants will be used to reduce ECOM of
the South Texas Nuclear Project (STP). Pursuant to the ISA, CPL is
required to submit the terms of the divestiture of its plants to the
Commission for approval.
50. The ISA also addresses a Regional Transmission Organization (RTO) in
SPP. Under paragraph 6 M of the ISA, the Applicants set a date certain
to place CSW's SPP transmission facilities within an RTO.
51. The market power mitigation plan contained in the ISA is consistent
with the public interest.
CONSISTENCY WITH CPL RATE CASE
52. The ISA regulatory plan does not change the accounting treatments
ordered in Docket No. 14965,(22) or the rate reductions associated with
the "glide path." The ISA reduces rates as reflected in the rate
reduction riders contained in the ISA. The final order in Docket No.
14965 does not restrict CPL's ability to file for rate increases, but
the ISA imposes a rate moratorium, with certain force majeure
conditions, until January 1, 2003.
- ----------
(22) Application of Central Power and Light Company for Authority to
Change Rates, Docket No. 14965 (Oct. 16, 1997).
<PAGE> 16
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53. Under the ISA, within 30 days of the effective date of the merger, CPL
will withdraw from its pending appeal of Docket No. 14965 all issues
which relate to the mandated glide path rate reductions. Paragraph 4.L
of the ISA also provides that the Merged Company will abide by the
ultimate resolution of affiliate allocation issues in the Docket No.
14965 appeal.
54. The ISA is consistent with and furthers the final decision in Docket
No. 14965.
CONSISTENCY WITH WTU RATE CASE
55. Docket No. 13369(23) limited WTU-initiated rate increases, which has
now been extended by the ISA to January 1, 2003. The ISA does not
impact the amortization of the deferred Oklaunion costs, but does
reduce rates as provided in the ISA's rate reduction riders.
56. With regard to sharing margins for off-system sales, the CPL final
order requires that 100 percent of the off-system sales be passed
through to CPL customers, while the WTU settlement allows 15 percent of
the margins to be shared with shareholders. The ISA contains sharing
mechanisms that allow for 100 percent of off-system margins to go to
customers if the margins are below a certain level, 85 percent to
customers if the margins exceed that level, and 50 percent of margins
to customers if the margins exceed a significantly greater level.
57. There is good cause to authorize the treatment for off-system sales
contained in the ISA. The current high credit percentages diminish the
incentive to the Texas operating companies to commit additional
resources to pursue additional sales and/or trading activities. The
levels proposed in the ISA for sharing of 15 percent with shareholders
is approximately 30 percent
- ----------
(23) Petition & Statement of Intent of West Texas Utilities for Rate
Review, Request for Good Cause Exceptions for Filing & Procedural Requests,
Docket No. 13369 (Nov. 10, 1995).
<PAGE> 17
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SOAH DOCKET NO. 473-98-0839
higher than the previous maximum margins in the last three years. In
order to justify 50/50 sharing, the margins must increase by almost 100
percent from historical maximum levels. The ISA's provisions with
regard to off-system sales are reasonable and in the public interest.
58. While the ISA contains off-system sales margins that differ from those
contained in the CPL or WTU rate cases, they are "consistent with" or
"further the rate treatments incorporated in" those two cases, and
should, therefore, be adopted as part of the overall ISA. Similar
treatment should be given to SWEPCO.
59. The ISA's provisions as a whole are consistent with or further the rate
treatments incorporated in the WTU rate case.
CONSISTENCY WITH IRP
60. While the merger with AEP will potentially result in an additional
source of firm capacity for the CSW Texas Companies after closing the
merger, because planning for the sources of supply in the current IRP
must occur today and given the limited amount of available firm
transmission capacity, the CSW Texas Companies will continue the
resource solicitation approved in Docket No.
16995.(24)
61. The ISA contains an agreement by the Applicants not to seek any new
resource surcharge or Power Cost Recovery Factor or increase in any
existing resource surcharge or PCRF, subject to certain conditions.
Those conditions include if the requested surcharge or PCRF (1) was
- ----------
(24) Joint Application of Central Power and Light Company, West Texas
Utilities Company and Southwestern Electric Power Company for Approval of
Preliminary Integrated Resource Plans (IRP) and Related Good Cause Exceptions,
Docket No. 16995 (July 30, 1997 and April 13, 1998)(Interim Order on Preliminary
Plan and Interim Order on Interruptible Phase, respectively).
<PAGE> 18
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SOAH DOCKET NO. 473-98-0839
authorized in Docket Nos. 18041 or 18845,(25) or (2) is to provide for
recovery of fuel and purchased power energy savings resulting from
demand-side management (DSM) as required by the preliminary integrated
resource plan in Docket No. 16995. Docket Nos. 18041 and 18845 provide
for certification of contracts and recovery of costs associated with
low-income DSM programs and renewable-energy resources, which were
acquired in compliance with the Commission's interim order in Docket
No. 16995.
62. Neither the merger nor the provisions of the ISA affect the decisions
in the interim orders issued in Docket No. 16995.
TRANSMISSION RIGHTS
63. The rights of Texas transmission users (and all other parties) are
potentially affected by the merger only to the extent that available
transmission capacity through Ameren and into PSO and SWEPCO is reduced
by the reservation of 250 MW of transmission capacity. AEP will
continue to offer open-access transmission service between its East
region (the current AEP) and the West region (the current CSW). The
Applicants have filed a tariff at FERC that follows FERC Order No.
888 and ERCOT rules.
64. The Applicants have agreed to waive certain transmission priorities at
FERC. They will agree to waive the SPP operating companies' priority to
the use of their interfaces with other transmission systems to import
centrally dispatched energy from the existing AEP East Zone in excess
of 250 MW. The Merged Company will also waive PSO's and SWEPCO's
priority to the use of those interfaces to import non-firm energy from
non-affiliates. Finally, the
- ----------
(25) Petition of Central Power and Light Company, West Texas Utilities
Company, and Southwestern Electric Power Company for Approval of Contracts for
Low-Income DSM Programs and for Authority to Implement a Power Cost Recovery
Factor Associated Therewith, Docket No. 18041, Final Order (May 11, 1998) or
Petition of Central Power and Light Company, West Texas Utilities Company and
Southwestern Electric Power Company for Approval of Photovoltaic Contract and
Renewable Energy Technologies Trailer Program and Associated Cost Recovery
Mechanisms, PUC Docket No. 18845, Final Order (Nov. 24, 1998).
<PAGE> 19
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Merged Company will schedule its use of the HVDC ties between SPP and
ERCOT on a first-in-time basis for certain transactions.
65. The acquisition and use of transmission rights by AEP for the merger
will not impair the access, rights or priorities of other transmission
owners or customers in Texas.
TANGIBLE BENEFITS ON A TIMELY BASIS
66. Based on Findings of Fact Nos. 19 through 65, the ISA contains tangible
benefits for Texas customers.
67. The ISA will produce timely benefits for Texas customers in the areas
of rate reductions, ECOM amortization, market power mitigation,
affiliate standards, customer service standards, rate moratorium,
jurisdictional issues, customer education, low-income programs,
off-system sales margins, and other ISA provisions.
68. Based on Findings of Fact Nos. 66 and 67, the merger will result in
tangible benefits to Texas customers on a timely basis.
IMPACT OF RETAIL COMPETITION
69. The net merger savings rate reduction rider will continue to apply to
regulated rates in the event of legislatively-mandated unbundling. The
rate reductions apply even if there is a legislatively-mandated rate
freeze. The net merger savings rate reduction rider will continue if
there are legislatively-mandated rate reductions, and the net merger
savings rate reduction rider will not be considered an offset to the
legislative reduction.
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FORM OF MERGER SAVINGS SHARING
70. The nature of the merger savings sharing plan has changed since the
Commission issued its Preliminary Order. The Applicants' current
regulatory plan is contained in the ISA, and is an appropriate means to
implement sharing with customers. Preliminary Order question No. 6, as
posed, is moot or should be modified to ask if the ISA's provisions are
reasonable.
SERVICE QUALITY GUARANTEES
71. The ISA contains several guarantees for service quality, including
penalties if the standards are not met. The ISA also requires several
reports (including statistically valid customer service surveys) and
bi-annual audits by the Office of Customer Protection. The ISA contains
appropriate guarantees to ensure that service quality in Texas does not
suffer after the merger.
GUARANTEED MINIMUM AMOUNT
72. The ISA's net merger savings rate reduction rider is based on the
estimated net Texas retail merger savings. Use of a fixed amount of
savings allows for guaranteed benefits for customers while providing
flexibility to accommodate a transition to competition. The Applicants
bear the risk of any failure to actually achieve the full amount of net
savings.
73. Using a fixed value for merger costs is reasonable. The ISA provides
for a guaranteed minimum amount for the customers' share of merger
savings. No true-up mechanism should be adopted.
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AFFILIATE STANDARDS
74. The ISA contains affiliate standards that will apply in the absence of
PUC rules or legislation. The PUC is also devising rules for affiliate
relations, including unbundling rules and code of conduct rules. Senate
Bill No. 7 also contains several provisions concerning the ability of
electric utilities to engage in cost shifting, cross subsidies, and/or
discriminatory behavior. The Applicants have provided sufficient
guarantees that will prevent unjustified cost shifting, cross
subsidies, or discriminatory behavior.
CONTESTED ISSUE
75. Section 4.E. of the ISA states that stranded costs will be recovered on
a stand-alone basis among the Texas operating companies. This section
of the ISA is intended to ensure a clear separation between the three
Texas companies and the AEP companies or PSO in Oklahoma in the
allocation and recovery of stranded costs. It guarantees that customers
of the CSW operating companies will not be at risk for stranded costs
incurred by AEP.
76. Central Power & Light Company is likely to have stranded costs related
to its ownership interest in the STP. WTU and SWEPCO do not currently
have stranded costs related to generation plant. The language of
Section 4.E. does not address whether CPL stranded costs should be
netted against the value of WTU and SWEPCO plants among the CSW
operating companies. Furthermore, treatment of CSW stranded costs
through netting among its Texas operating companies is not relevant to
issues in this merger case.
77. The ISA does provide for ECOM mitigation in two instances: Attachment
H, paragraph 3.d. of the ISA pledges a $60 million stranded cost
reduction for CPL customers as an extension of the Docket No. 12820
Stipulation, and Section 6.J. provides that the gains on the sale of
CPL's power plants will be applied to reduce the company's stranded
costs. The ISA does not bind the Commission to any particular treatment
of stranded costs or ECOM in future proceedings.
<PAGE> 22
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GENERAL EVALUATION
78. The ISA, taken as a whole, is a reasonable resolution of contested
issues in this docket, is supported by the record, and is in the public
interest. Therefore, the ISA should be adopted as the basis for the
Commission's decision in this case.
79. The Applicants have presented substantial evidence that demonstrates
that this merger meets each of the statutory standards, the Docket No.
14860(26) (SPS/PSCo) standards and the questions posed by the PUC in
the Preliminary Orders. This evidence supports an independent finding
that the ISA is just and reasonable.
80. Under the provisions and conditions of the ISA, the merger of AEP with
CSW is consistent with the public interest.
B. CONCLUSIONS OF LAW
81. CPL, SWEPCO and WTU are electric utilities as defined by Section 31.002
of the Public Utility Regulatory Act (PURA), TEX. UTIL. CODE ANN.
(Vernon 1999). The Commission has jurisdiction over those utilities
under PURA Section 14.001, et seq.;Section 31.001 et seq.;Section
33.001, et seq.; Section 36.001, et seq.; and Section 38.001 et seq.
82. The Applicants seek a public interest determination pursuant to PURA
Section 14.101.
83. SOAH has jurisdiction over all matters relating to the conduct of a
hearing of this proceeding including the preparation of a proposal for
decision with findings of fact and conclusions of law pursuant to PURA
Section 14.053 and TEX. GOV. CODE ANN. Section 2003.049 (Vernon 1999).
- ----------
(26) Application of Southwestern Public Service Company Regarding
Proposed Business Combination With Public Service Company of Colorado, Docket
No. 14980, Final Order (Feb. 14, 1997).
<PAGE> 23
PUC DOCKET NO. 19265 ORDER PAGE 23 OF 28
SOAH DOCKET NO. 473-98-0839
84. The Applicants have complied with the notice requirements as set by the
PUC.
85. Because the Applicants, along with numerous other parties, presented a
non-unanimous stipulation for approval, the procedure for considering
such stipulations is proscribed by PURA Section 14.054 and PUC
Procedural Rule Section 22.206. The hearing on the merits to consider
the ISA was conducted in accordance with these provisions.
86. Cities of Abilene, et al. v. Public Utility Comm'n, 854 S.W.2d 932,
937-38 (Tex. App. - - Austin 1993), aff'd in part and rev'd in part,
909 S.W. 2d 493 (Tex. 1995) determined that a non-unanimous stipulation
could be considered as a basis for a final order so long as
"nonstipulating parties had an opportunity to be heard on the merits of
the stipulation and the Commission made an independent finding on the
merits, supported by substantial evidence in the record, that the
stipulation set just and reasonable rates." The procedure followed in
this case conforms with the Cities of Abilene procedural requirements.
87. The ISA is a reasonable resolution of the contested issues in this
docket, is consistent with PURA, is supported by the record, and is in
the public interest.
88. The Applicants will comply with P.U.C. Subst. R. 25.71 by returning
records to the PUC for inspection.
89. The Applicants have demonstrated good cause for the ISA's provisions
regarding sharing of the margin for off-system sales in a manner
different than that contained within P.U.C. Subst. R.
25.236(a)(8).
90. The Applicants have met their burden of proof with regard to the
statutory standards; the SPS/PSCo standards found in Docket No. 14980,
which specified other issues that need to
<PAGE> 24
PUC DOCKET NO. 19265 ORDER PAGE 24 OF 28
SOAH DOCKET NO. 473-98-0839
be examined prior to the determination of the public interest; and the
questions posed by the PUC in its Preliminary Orders in this case.
91. The rates resulting from the net merger savings rate reduction rider
and the rate reduction riders in ISA Attachment H are just, reasonable,
in the public interest and are not unreasonably preferential,
prejudicial, or discriminatory pursuant to PURA Section 36.003.
92. Under the provisions and conditions of the ISA, the merger of AEP with
CSW is consistent with the public interest under PURA Section 14.101.
VI. ORDERING LANGUAGE
In accordance with the foregoing findings of fact and conclusions of
law, the Commission issues the following orders:
1. The application of CSW and AEP to combine their two businesses, as amended by
the Integrated Stipulation and Agreement, is approved.
2. CPL, SWEPCO and WTU shall implement the net merger savings rate reductions
riders and the ISA Attachment H rate reductions riders through filings with
appropriate regulatory authorities to be effective for bills rendered in the
first revenue month after the closing of the merger as specified in this Order.
3. CPL shall reduce stranded costs related to its generating plants consistent
with the agreements contained in ISA.
<PAGE> 25
PUC DOCKET NO. 19265 ORDER PAGE 25 OF 28
SOAH DOCKET NO. 473-98-0839
4. The Merged Company shall comply with the jurisdictional resolutions contained
in Section 4 of the ISA.
5. The Merged Company shall adopt the Low-Income program, customer service, and
reliability standards established in the ISA and shall implement the customer
education program to provide information concerning electric industry
restructuring and retail competition.
6. The Applicants shall provide for the sharing of off-system sales margins as
specified in the ISA and for the treatment of fuel savings arising from the
integrated operations of the Merged Company.
7. Applicants shall defer and amortize over a six-year period the estimated
costs to achieve the merger, including change in control payments as specified
in the ISA.
8. If the Merged Company maintains CSW's Texas operating companies' business
records outside the State of Texas, it shall do so in accordance with the
requirements of P.U.C. Subst. R. 25.71(c).
9. The Merged Company or the Texas operating companies shall file tariff sheets
consistent with this Order upon closing of the merger. Only savings applied to
regulated rates that will be recognized prior to January 1, 2002 shall be
included in this filing; additional tariffs to recognize post-2002 savings to
regulated rates shall be filed pursuant to Paragraph 9A. This tariff, and all
filings related to it, shall be filed in Tariff Control Number 21429, and shall
be styled: COMPLIANCE TARIFF Pursuant to Final Order in PUC Docket No. 19265,
SOAH Docket No. 473-98 - 0839, Application of Central and South West Corporation
and American Electric Power Company, Inc. Regarding Proposed Business
Combination. The filing shall include a transmittal letter stating that the
tariffs attached are in compliance with the order, giving the docket number,
date
<PAGE> 26
PUC DOCKET NO. 19265 ORDER PAGE 26 OF 28
SOAH DOCKET NO. 473-98-0839
of the order, a list of tariff sheets filed, and any other necessary
information. The timetable for review of the compliance tariff shall be
established by the PUC ALJ assigned to the tariff. In the event any sheets are
modified or rejected, the Applicants shall file proposed revisions to those
sheets in accordance with the PUC ALJ's notice. The effective date of the tariff
shall be as determined in the written notice of approval by the PUC ALJ. All
subsequent filings in connection with the compliance tariff (i.e., requests for
extensions, textual corrections, revisions) shall be filed in the same Tariff
Control No. provided above, and styled as set forth above. After issuance of the
final order in this docket, no further filings other than those pertaining to a
Motion for Rehearing shall be made in this docket.
9A. The Merged Company or Texas operating companies shall file, or shall amend
the filings made prior to the merger by the Texas operating companies relating
to, tariffs and supporting information to reflect the savings provided in the
ISA in the distribution rates of the Texas operating companies' successor
transmission and distribution utilities. The filings or amendments shall be made
in the unbundling proceedings established by the Commission to approve proposed
transmission and distribution tariffs under PURA Section 39.201 and shall comply
with any applicable Commission rules related to that proceeding.
9B. The Office of Regulatory Affairs shall, after adoption of any amendments to
the Commission's service reliability rules, establish a project to address any
inconsistencies between the ISA and those amendments.
10. Entry of the Order does not indicate the Commission's endorsement or
approval of any principle or methodology that may underlie the ISA. Neither
shall entry of the Order be regarded as binding precedent as to the
appropriateness of any principle underlying the ISA.
11. All motions, applications, requests for entry of specific findings of fact
and conclusions of
<PAGE> 27
PUC DOCKET NO. 19265 ORDER PAGE 27 OF 28
SOAH DOCKET NO. 473-98-0839
law, and other requests for relief, general or specific not expressly granted
herein, are denied for want of merit.
<PAGE> 28
PUC DOCKET NO. 19265 ORDER PAGE 28 OF 28
SOAH DOCKET NO. 473-98-0839
SIGNED AT AUSTIN, TEXAS THE ______DAY OF NOVEMBER, 1999.
PUBLIC UTILITY COMMISSION OF TEXAS
_____________________________________
PAT WOOD, III, CHAIRMAN
_____________________________________
JUDY WALSH, COMMISSIONER
_____________________________________
BRETT A. PERLMAN, COMMISSIONER
<PAGE> 1
EXHIBIT D-10.1
In the matter of the joint application of INDIANA
MICHIGAN POWER COMPANY and the MICHIGAN PUBLIC SERVICE COMMISSION
STAFF for ex parte approval of a rate reduction and
accounting authority related to the merger of American
Electric Power Company, Inc., and Central and South West
Corporation
Case No. U-12204
MICHIGAN PUBLIC SERVICE COMMISSION
1999 Mich. PSC LEXIS 394
December 16, 1999
PANEL: [*1] PRESENT: Hon. John G. Strand, Chairman; Hon. David A. Svanda,
Commissioner; Hon. Robert B. Nelson, Commissioner
OPINION:
At the December 16, 1999 meeting of the Michigan Public Service Commission in
Lansing, Michigan.
ORDER APPROVING SETTLEMENT AGREEMENT
On November 16, 1999, Indiana Michigan Power Company (I&M) and the Commission
Staff (Staff) filed a joint application for ex parte approval of a settlement
agreement related to the proposed merger of American Electric Power Company,
Inc., (AEP), I&M's parent company, and Central and South West Corporation, which
is at issue in a matter pending before the Federal Energy Regulatory Commission
(FERC) in Docket No. EC98-40-000. The Commission and the State of Michigan are
intervenors in the FERC merger docket. The purpose of the settlement signed by
I&M, AEP, and the Staff is to ensure that I&M's Michigan retail customers are
held harmless from certain potential effects of the proposed merger.
Under the settlement, the Commission agrees not to oppose the merger in the
FERC proceedings nor AEP's previous submissions to the Securities and Exchange
Commission (together with any nonmaterial changes and supplements) in connection
with the merger. [*2] AEP and I&M agree to file tariff sheets implementing rate
reductions representing the net merger savings allocable to I&M's Michigan
jurisdictional customers. The settlement authorizes I&M to use deferred cost
accounting to record certain costs incurred to achieve the merger. It specifies
how I&M will give rate recognition to merger-related fuel savings. In addition,
the settlement provides, among other things, for the maintenance and enhancement
of reliable retail electric service by I&M in Michigan, AEP's participation in a
regional transmission organization, and standards of conduct governing
relationships between regulated AEP operating utilities and affiliates.
The settlement contains various provisions that coordinate its rate effects
with another settlement agreement that imposes a conditional ceiling on I&M's
rates in Cases Nos. U-11181-R, U-11531-R, and U-11792, which is being approved
today in a separate order. The Commission wishes to make plain its understanding
that the parties drafted both settlements to make the rate reductions in each
cumulative to those in the other and that ratepayers will receive the full
benefit of both sets of rate reductions. The Commission also [*3] wants to
emphasize that the settlement provides that the rate reductions will be
accomplished notwithstanding any future restructuring or unbundling of rates.
After reviewing the settlement agreement, the Commission finds that it is
reasonable and in the public interest, and should be approved.
The Commission FINDS that:
<PAGE> 2
EXHIBIT D-10.1
a. Jurisdiction is pursuant to 1909 PA 106, as amended, MCL 460.551 et seq.;
MSA 22.151 et seq.; 1919 PA 419, as amended, MCL 460.51 et seq.; MSA 22.1 et
seq.; 1939 PA 3, as amended, MCL 460.1 et seq.; MSA 22.13(1) et seq.; 1969 PA
306, as amended, MCL 24.201 et seq.; MSA 3.560(101) et seq.; and the
Commission's Rules of Practice and Procedure, as amended, 1992 AACS, R 460.17101
et seq.
b. The settlement agreement is reasonable and in the public interest, and
should be approved.
c. Ex parte approval is appropriate.
THEREFORE, IT IS ORDERED that:
A. The settlement agreement, a copy of which is attached to this order as
Exhibit A, n1 is approved.
- - - - - - - - - - - - - - - - - -Footnotes- - - - - - - - - - - - - - - - -
n1 Attachment D to the settlement agreement, a proposed order, is not
attached to copies of this order. The Commission is not adopting the proposed
order as submitted.
- - - - - - - - - - - - - - - - -End Footnotes- - - - - - - - - - - - - - [*4]
B. Upon consummation of the merger, Indiana Michigan Power Company is
authorized to implement the rate reductions required by the settlement agreement
and the deferred cost accounting provisions in the settlement agreement.
C. Within 30 days of consummation of the merger, Indiana Michigan Power
Company shall file tariff sheets implementing the settlement agreement.
The Commission reserves jurisdiction and may issue further orders as
necessary.
Any party desiring to appeal this order must do so in the appropriate court
within 30 days after issuance and notice of this order, pursuant to MCL 462.26;
MSA 22.45.
MICHIGAN PUBLIC SERVICE COMMISSION
By its action of December 16, 1999.
EXHIBIT A
SETTLEMENT AGREEMENT
On June 30, 1998, the Michigan Public Service Commission ("MPSC" or
"Commission") intervened in Docket EC98-40-000, the proceeding initiated before
the Federal Energy Regulatory Commission ("FERC") regarding the proposed merger
of American Electric Power Company, Inc. ("AEP"), the parent company of Indiana
Michigan Power Company ("I&M"), and Central and South West Corporation ("CSW")
to ensure that the Michigan retail customers of I&M were protected from any
potential [*5] adverse effects of the merger. During the course of the FERC
proceeding, the Commission Staff, acting on behalf of the Commission, reviewed
numerous filings and participated in numerous discussions regarding the proposed
merger. In addition, the Commission Staff negotiated with representatives of AEP
and I&M to achieve a resolution of issues of concern to Michigan customers and
regulators.
Solely for the purposes of compromise and settlement, Indiana Michigan Power
Company, which does business in Michigan as American Electric Power, AEP and the
Commission Staff (collectively referred to as the "Parties") have met and
reached a settlement agreement ("Agreement") which they hereby submit and
recommend for approval to the Commission. If the Commission does not approve the
settlement
<PAGE> 3
EXHIBIT D-10.1
agreement in its entirety and incorporate it in the Final Order, the proposed
Agreement shall be null and void and deemed withdrawn, unless such change is
agreed to by the Parties.
SETTLEMENT AGREEMENT
WHEREAS AEP and CSW have filed various applications before federal and state
agencies seeking approvals necessary to consummate a proposed merger of the two
companies, and
WHEREAS AEP, I&M and the Commission [*6] Staff have met and explored over a
period of months various issues related to the proposed merger and their
agreements and differences regarding the effects of the proposed merger on
competition between electricity providers and on the terms and conditions under
which retail electric utility service is provided, and
WHEREAS AEP, I&M and the Commission Staff recognize the costs and uncertainty
of litigation and the desirability of consensual voluntary resolution of their
differences and the legitimate interests and good faith of each of the parties
in achieving the objectives each desires to achieve.
The Parties agree as follows:
The Commission Staff will recommend to the MPSC that the following Agreement be
adopted by the Commission in an order or other appropriate formal action that
references this Agreement or incorporates all of the provisions thereof. Where
appropriate, the Commission action may address or reserve other matters
ancillary or incidental to the matters addressed in this Agreement, for
immediate or future disposition, in a manner not inconsistent with the
Agreement.
All appropriate terms are defined in the "Definitions" section of the
Agreement.
THE MPSC:
[*7]
1. Will not oppose the proposed merger pending before the Federal Energy
Regulatory Commission.
2. Will not oppose AEP's filings previously made at the United States
Securities and Exchange Commission ("SEC") in connection with the proposed
merger, together with any non-material changes or supplements thereto.
AEP or I&M, AEP's Michigan jurisdictional AEP operating company, conditional on
merger consummation will:
1. REGULATORY PLAN. The net merger savings allocable to the Michigan
jurisdictional customers will be used to reduce customers' bills. I&M will
implement net merger savings reduction riders that will reduce bills to
customers by the annual amounts shown in Attachment A beginning with the first
revenue month after the consummation of the merger. The annual customer net
savings reduction amounts shown in column 3 of Attachment A ("customer net
savings") will be allocated to rate classes based upon the ratio of each class's
jurisdictional tariff revenue to total jurisdictional tariff revenue, excluding
fuel cost adjustment, and credited to customers' bills through the application
of a per kilowatt hour factor specific to each rate class. Each individual
year's customer [*8] net savings reduction will apply for a twelve month period
except for an adjustment during each third quarter to reconcile actual kWh sales
and projected kWh sales for the prior year. The last reduction will continue to
apply in years following the end of year eight until base rates for the
operating company are changed.
The merger savings and costs are based on estimated values included in AEP's
filing with FERC in Docket No. EC98-40-000.
Notwithstanding any base rate proceeding during the eight year period after the
consummation of the merger, the annual amounts shown in Attachment A will remain
in effect.
<PAGE> 4
EXHIBIT D-10.1
I&M must implement the customer net savings reductions in the manner and
amounts described above notwithstanding any changes to the current regulatory
structure in Michigan and notwithstanding the rate filing limitations contained
in paragraphs 3, 4 and 5 of the settlement agreement pending before the
Commission in Case Nos. U-11181-R, U-11531-R, and U-11792 ("PSCR cases"). When
retail electric deregulation is implemented in Michigan, or if there is any
unbundling or restructuring of rates, I&M shall continue to apply the regulatory
plan's provisions to regulated rates of [*9] its Michigan customers. The
allocation to rate classes after any unbundling or restructuring will be
determined as described above in the next annual customer net savings reduction
submittal.
Any legislatively or administratively mandated adjustments to rates, of any
kind, that are part of any retail electric deregulation legislation implemented
in Michigan shall not diminish or offset, but shall be in addition to, the
customer net savings reductions established in this proceeding.
Subject to this Agreement, AEP and I&M will defer and amortize their Michigan
jurisdictional share of estimated merger costs-to-achieve over an 8-year
recovery period. Costs to achieve the merger are those costs incurred to
consummate the merger and combine the operations of AEP and CSW. These costs
include, but are not limited to, investment banking fees; consulting and legal
services incurred in connection with obtaining regulatory and shareholder
approvals; transition planning and development costs; employee separation costs
including severance costs, change-in-control payments and retraining costs; and
facilities consolidation costs. Costs to achieve shall be recorded in Account
182.3. Actual amounts [*10] in excess of the estimated costs to achieve shall be
expensed as incurred by AEP. The MPSC will issue accounting orders or other
orders necessary to authorize the deferral and amortization of merger costs.
In any proceeding to change base rates for I&M to become effective after the
consummation of the merger, the following rate treatment will be reflected:
A. Estimated non-fuel merger savings, net of costs to achieve, will be included
in cost of service as an allowable expense in order to avoid duplication and to
continue to provide shareholders with their share of the net savings. The amount
to be included in the cost of service shall be based upon the test year period.
(See Attachment B)
B. Amortization of estimated costs to achieve will be included in cost of
service as an allowable expense. The amount to be included in the cost of
service shall be based upon the test year period. (See Attachment B)
The parties note that the settlement agreement pending before the Commission in
the PSCR cases contains a conditional moratorium on general increases in basic
rates and charges. The exact language, which is found on page 6, paragraph 5 of
the June 1, 1999 PSCR settlement [*11] document says, "Subject to paragraphs 6
and 8, AEP shall not file an application, which, if approved, would have the
effect either directly or indirectly, of authorizing a general increase in basic
rates and charges that would be effective prior to January 1, 2004." In the
event the PSCR settlement is approved by the Commission without modification,
the moratorium on general increases in basic rates and charges will be extended
by one year to January 1, 2005, subject to the same conditions contained in the
PSCR settlement agreement.
2. FUEL MERGER SAVINGS. All savings of fuel and purchased power expenses
resulting from the merger shall benefit retail customers through existing fuel
clause recovery mechanisms applied by State Commissions. In circumstances when
one or more AEP operating companies in one AEP zone are supplying power to the
other AEP zone, and as a result, the supplying zone needs to purchase
replacement power to serve its native load, AEP shall hold harmless the native
load customers of the supplying zone from any price differential between the
replacement power and the system power supplied to the other zone. Similarly, if
one or more AEP operating companies in one [*12] AEP zone are supplying power to
the other AEP zone, and as a result, the supplying zone loses the opportunity to
sell power at a price higher than received from the zone being supplied, AEP
shall credit the supplying zone for the foregone revenues.
<PAGE> 5
EXHIBIT D-10.1
The parties note that paragraphs 3 and 4 of the settlement agreement pending
before the Commission in the PSCR cases set forth a conditional suspension of
the PSCR process. In the event that the settlement agreement in the PSCR cases
is approved without modification, I&M will accrue the Michigan jurisdictional
amount of merger fuel savings achieved during the fixed PSCR factor period and
credit customers with those accrued savings, either through the PSCR factor in
effect at that time or through base rates, as soon as possible after the end of
the fixed PSCR factor period, but no later than July 1, 2004. After the fixed
PSCR factor period, I&M will continue to pass through the merger fuel savings
consistent with Michigan regulation.
3. STRANDED COSTS. AEP and its operating companies agree not to seek or recover
any stranded costs associated with the operating companies of one AEP zone from
the retail customers of the other AEP zone.
[*13]
4. PROCEEDS OF FACILITY SALES. Any proceeds from the sale of facilities shall
go to the AEP operating company in whose rate base the facilities are included,
for further disposition in accordance with the rules and orders of the
regulatory authorities whose jurisdiction encompasses the ultimate disposition
of such proceeds.
5. SYSTEM INTEGRATION AGREEMENTS. To mitigate any perceived impacts of the
merger on AEP's ability to exercise market power, AEP proposed in its FERC
merger application a mitigation plan. To protect retail customers, AEP agrees to
hold harmless the retail customers from any mitigation plan included in any FERC
order approving the merger of AEP-CSW. To implement this Agreement in any
general retail electric rate proceeding commenced by the filing of a petition on
or after the date of this Agreement, in which an AEP operating company requests
a change in its basic rates and charges, or in any other proceeding where so
ordered by the Commission, AEP shall have the burden therein to prove that such
requested rate relief does not reflect mitigation-related costs.
AEP commits to file any allocation of the cost of new, modified or upgraded
generation or transmission [*14] facilities whose costs will be subject to the
System Integration Agreement or the System Transmission Agreement with the FERC
and to notify the Commission of any such filing at the time it is made.
Notification to the Commission will include an estimate of the cost of
construction, an explanation of the reasons for constructing the facilities,
studies supporting the construction of the facilities, and a proposed allocation
of the facilities' costs. If AEP plans to purchase an in-service facility or
already constructed and soon-to-be-in-service facility, AEP will follow the
above described procedures and will include as part of the notification to the
Commission an explanation of the circumstances causing the AEP operating company
to make the purchase in question.
6. REGULATORY AUTHORITY. AEP agrees not to seek to overturn, reverse, set
aside, change or enjoin, whether through appeal or the initiation or maintenance
of any action in any forum, a decision or order of the Commission based on the
assertion that the authority of the SEC as interpreted in Ohio Power Co. v.
FERC, 954 F.2d 779 (D.C. Cir. 1992) cert. denied, 506 U.S. 981 (1992) impairs
the Commission's ability to examine [*15] and determine the reasonableness of
non-power affiliate transaction costs to be passed to retail customers. The
parties agree that the Ohio Power waiver does not include waiver of any
arguments that AEP may have with respect to the reasonableness of SEC approved
cost allocations. AEP will provide the Commission with notice at least 30 days
prior to any filings that propose new allocation factors with the SEC. The
notice need not be in the precise form of the final filing but shall include, to
the extent information is available, a description of the proposed factors and
the reasons supporting such factors. AEP and the Commission Staff will make a
good faith attempt to resolve their differences, if any, in advance of a filing
being made at the SEC.
7. REGIONAL TRANSMISSION ORGANIZATION.
A. Prior to December 31, 2000, AEP will file with the FERC an unconditional
application, consistent with the RTO agreement and tariff, to transfer the
operation and control of its bulk transmission facilities in Indiana, Michigan,
Kentucky, Ohio, Tennessee, Virginia and West Virginia owned, controlled and/or
operated by AEP to the Midwest Independent Transmission System Operator, Inc. or
another [*16] FERC-approved Regional Transmission Organization directly
interconnected with AEP transmission
<PAGE> 6
EXHIBIT D-10.1
facilities. Provided that, if, by June 30, 2000, there is pending before the
FERC for approval an RTO to which AEP is a signatory that includes two or more
directly interconnected control areas, at least one of which is not affiliated
with AEP, the December 31, 2000 date shall be extended to the date that is 75
days after the date on which the FERC issues an order either approving or
disapproving the RTO.
B. AEP shall endeavor to eliminate "pancaking" of transmission rates and to
incorporate equitable reciprocal pricing arrangements with contiguous RTOs in
the Alliance RTO or any other filing to which AEP is a signatory seeking FERC
approval of the formation of a new RTO.
C. AEP will provide generation dispatch information necessary for RTOs to
monitor the effect of such dispatch on the loading of that RTO's constrained
transmission facilities. This information must be provided to any RTO of which
AEP is a member, and to RTOs providing service over any transmission facilities
directly interconnected with the AEP east zone transmission facilities. Each of
these RTOs shall determine the [*17] format, quantity, and timing of these data
as necessary to perform this monitoring function. The information provided by
AEP shall be equivalent to that provided by all parties who control the dispatch
of generation facilities taking transmission service from these RTO(s) and shall
be subject to appropriate confidentiality provisions.
D. Nothing in this Agreement precludes the Commission, or its staff from
actively participating in any proceedings at the FERC arising from any RTO
filings made by AEP. However the Commission and its staff commits that it will
not offer such participation as a reason to delay the consummation of the merger
or to advocate a position before FERC inconsistent with Paragraph A above.
8. AFFILIATE STANDARDS. The following affiliate standards shall apply from the
date of closing of the merger until new affiliate standards imposed by state
legislation or Commission action become effective.
A. The financial policies and guidelines for transactions between an AEP
operating company and its affiliates shall reflect the following principles:
1. An AEP operating company's retail customers shall not subsidize the
activities of the operating company's [*18] non-utility affiliates or its
utility affiliates.
2. An AEP operating company's costs for jurisdictional rate purposes shall
reflect only those costs attributable to its jurisdictional customers.
3. An objective of these principles shall be to avoid costs found to be just
and reasonable for ratemaking purposes by the Commission being left unallocated
or stranded between various regulatory jurisdictions, resulting in the failure
of the opportunity for timely recovery of such costs by the operating company
and/or its utility affiliates; provided, however, that no more than one hundred
percent of such costs shall be allocated on an aggregate basis to the various
regulatory jurisdictions.
4. An AEP operating company shall maintain and utilize accounting systems and
records that identify and appropriately allocate costs between the operating
company and its affiliates, consistent with these cross-subsidization principles
and such financial policies and guidelines.
B. The Commission shall have access to the employees, officers, books and
records of any affiliate of its jurisdictional AEP operating company to the same
extent and in like manner that the Commission has over a public [*19] utility
operating within the state if the affiliate had engaged in direct or indirect
transactions with the jurisdictional AEP operating company. If such employees,
officers, books and records can not be reasonably made available to the
Commission, then upon request of the Commission, the AEP operating company
shall, in accordance with state reimbursement rules, reimburse the Commission
for appropriate out-of-state travel expenses incurred in accessing the
employees, officers, books and records. Each AEP operating company shall
maintain, in accordance with generally accepted accounting principles, books,
records, and accounts that are separate from the books, records, and accounts of
its affiliates, consistent with Part 101 -- Uniform System of Accounts
Prescribed for Public Utilities and Licensees Subject to the Provisions of the
Federal Power Act. Any objections to providing all books and records must
<PAGE> 7
EXHIBIT D-10.1
be raised before the Commission and the burden of showing that the request is
unreasonable or unrelated to the proceeding is on the AEP operating company. The
confidentiality of competitively sensitive information shall be maintained in
accordance with the Commission's rules and regulations [*20] and relevant state
law.
C. In accordance with generally accepted accounting principles and consistent
with state and federal guidelines, an AEP operating company shall record all
transactions with its affiliates, whether direct or indirect. An AEP operating
company and its affiliates shall maintain sufficient records to allow for an
audit of the transactions involving the operating company and its affiliates.
D. An AEP operating company shall not allow a non-utility affiliate to obtain
credit under any arrangement that would permit a creditor, upon default, to have
recourse to the operating company's assets. The financial arrangements of an AEP
operating company's affiliates are subject to the following restrictions unless
otherwise approved by the Commission:
1. Any indebtedness incurred by a non-utility affiliate will be without
recourse to the operating company.
2. An AEP operating company shall not enter into any agreements under terms of
which the operating company is obligated to commit funds in order to maintain
the financial viability of a non-utility affiliate.
3. An AEP operating company shall not make any investment in a non-utility
affiliate under circumstances [*21] in which the operating company would be
liable for the debts and/or liabilities of the non-utility affiliate incurred as
a result of acts or omissions of a non-utility affiliate.
4. An AEP operating company shall not issue any security for the purpose of
financing the acquisition, ownership, or operation of a non-utility affiliate.
5. An AEP operating company shall not assume any obligation or liability as
guarantor, endorser, surety, or otherwise in respect of any security of a
non-utility affiliate.
6. An AEP operating company shall not pledge, mortgage or otherwise use as
collateral any assets of the operating company for the benefit of a non-utility
affiliate.
7. AEP shall hold harmless the retail customers of an AEP operating company
from any adverse effects of credit rating declines caused by the actions of
non-utility affiliates.
Transactions between AEP operating companies and affiliates involving a money
pool for the financing of short-term funding requirements are exempt from the
requirements of this paragraph. Further, the provisions of this paragraph would
not preclude AEP operating companies from issuing securities or assuming
obligations related to their [*22] existing coal subsidiaries.
E. Any untariffed, non-utility service provided by an AEP operating company or
affiliated service company to any affiliate shall be itemized in a billing
statement pursuant to a written contract or written arrangement. The AEP
operating company and any affiliated service company shall maintain and keep
available for inspection by the Commission copies of each billing statement,
contract and arrangement between the AEP operating company or affiliated service
company and its affiliates that relate to the provision of such untariffed
non-utility services.
F. Any good or service provided by a non-utility affiliate to an AEP operating
company shall be by itemized billing statement pursuant to a written contract or
written arrangement. The operating company and non-utility affiliate shall
maintain and keep available for inspection by the Commission copies of each
billing statement, contract and arrangement between the operating company and
its non-utility affiliates that relate to the provision of such goods and
services in accordance with applicable Commission retention requirements.
<PAGE> 8
EXHIBIT D-10.1
G. Employees responsible for the day to day operations of the AEP operating
[*23] companies and those of affiliated exempt wholesale generators or
affiliated power marketers shall operate independently of one another. AEP shall
document all employee movement between and among all affiliates. Such
information shall be made available to the Commission upon request.
H. An AEP operating company may not own property in common with an affiliated
exempt wholesale generator or affiliated power marketer.
I. No market information obtained in the conduct of utility business may be
shared with an affiliated exempt wholesale generator or affiliated power
marketer, except where such information has been publicly disseminated or
simultaneously shared with and made available to all non-affiliated entities who
have requested such information. Customer specific information shall not be made
available to an affiliated exempt wholesale generator or affiliated power
marketer except under the same terms as such information would be made available
to a non-affiliated company, and only with the written consent of the customer
specifying the information to be released.
J. A non-utility affiliate may use an AEP operating company's name or logo only
if, in connection with such use, [*24] the affiliate makes adequate disclosures
to the effect that (i) the two entities are separate; (ii) it is not necessary
to purchase the non-regulated product or service to obtain service from the
operating company; and (iii) the customer will gain no advantage from the
operating company by buying from the affiliate.
K. An AEP operating company shall not condition or tie the provision of any
product, service, pricing benefit, or waiver of associated terms or conditions,
to the purchase of any good or service from its affiliated exempt wholesale
generator or power marketer.
L. Except as provided in paragraph M, an affiliated exempt wholesale generator
or affiliated power marketer shall not share office space, office equipment,
computer systems or information systems with an AEP operating company.
M. Computer systems and information systems may be shared between an AEP
operating company and non-utility affiliates only to the extent necessary for
the provision of corporate support services; however, the operating company
shall ensure that the proper security access and other safeguards are in place
to ensure full compliance with these affiliate rules.
N. An AEP operating company [*25] may engage in transactions directly related
to the provision of corporate support services with its affiliates in accordance
with requirements relating to service agreements. As a general principle, such
provision of corporate support services shall not allow or provide a means for
the transfer of confidential information from the operating company to the
affiliate, create the opportunity for preferential treatment or unfair
competitive advantage, create opportunities for cross-subsidization of
affiliates, or otherwise provide any means to circumvent these affiliate rules.
O. Except as provided in paragraph N, an AEP operating company may only make a
product or service available to an affiliated exempt wholesale generator or an
affiliated power marketer if the product or service is equally available to all
non-affiliated exempt wholesale generators and power marketers on the same
terms, conditions and prices, and at the same time. An AEP operating company
shall process all requests for a product or service from affiliated and
non-affiliated exempt wholesale generators and power marketers on a
non-discriminatory basis.
P. An AEP operating company which provides both regulated and [*26]
non-regulated services or products, or an affiliate which provides services or
products to an AEP operating company, shall maintain documentation in the form
of written agreements, an organization chart of AEP (depicting all affiliates
and AEP operating companies), accounting bulletins, procedure and work order
manuals, or other related documents, which describe how costs are allocated
between regulated and non-regulated services or products. Such documentation
shall be available, subject to requests for confidential treatment, for review
by the Commission in accordance with Paragraph B above.
<PAGE> 9
EXHIBIT D-10.1
Q. AEP shall designate an employee who will act as a contact for the Commission
seeking data and information regarding affiliate transactions and personnel
transfers. Such employee shall be responsible for providing data and information
requested by the Commission for any and all transactions between the
jurisdictional operating company and its affiliates, regardless of which
affiliate(s), subsidiary(ies) or associate(s) of an AEP operating company from
which the information is sought.
R. AEP shall designate an employee or agent within Michigan who will act as a
contact for retail consumers [*27] regarding service and reliability concerns
and to allow a contact for retail consumers for information, questions and
assistance. Such AEP representative shall be able to deal with billing,
maintenance and service reliability issues.
S. AEP shall provide the Commission a current list of employees or agents that
are designated to work with the Commission concerning state regulatory matters,
including, but not limited to, rate cases, consumer complaints, billing and
retail competition issues.
T. Thirty (30) days prior to filing any affiliate contract (including service
agreements) with the SEC or the FERC an AEP operating company shall submit to
the Commission Staff a copy of the proposed filing.
U. Any violation of the provisions of these affiliate standards is subject to
the enforcement powers and penalties of the Commission.
V. AEP shall contract with an independent auditor who shall conduct biennial
audits for eight years after merger consummation of affiliated transactions to
determine compliance with these affiliate standards. The results of such audits
shall be filed with the Commission. Prior to the initial audit, AEP will conduct
an informational meeting with the Commission [*28] regarding how its affiliates
and affiliate transactions will or have changed as a result of the proposed
merger.
W. If the Public Utility Holding Company Act of 1935 is repealed or materially
amended during the time this Agreement is in effect and equivalent jurisdiction
is not given to another federal agency, AEP will work with the Commissions to
ensure that AEP continues to furnish the Commission with the appropriate
information to regulate its jurisdictional AEP operating company. The Commission
may establish its reporting requirements regarding the nature of intercompany
transactions concerning the operating company and a description of the basis
upon which cost allocations and transfer pricing have been established in these
transactions.
9. ADEQUACY AND RELIABILITY OF RETAIL ELECTRIC SERVICE. AEP agrees to maintain
or enhance the adequacy and reliability of retail electric service provided by
each of the AEP operating companies. Service reports will be submitted to the
Commission in the format described in Attachment C to this Agreement. The
substance or format of reporting may be changed by mutual agreement of the
parties.
10. STATUTORY AND OTHER ISSUES. Provided the [*29] proposed merger is
ultimately consummated, AEP commits that upon issuance of any final and
non-appealable order from any state or federal commission addressing the merger
that provides benefits or imposes conditions on AEP that would benefit the
ratepayers of any jurisdiction, such net benefits and conditions will be
extended to all other retail customers to the extent necessary to achieve
equivalent net benefits and conditions to all retail customers of AEP.
11. CONTINUED PARTICIPATION. Upon execution of this Agreement, AEP may notify
the FERC in FERC Docket No. EC98-40-000 that a settlement agreement has been
executed by AEP, I&M and the Commission Staff and is being submitted to the
Commission for its review and approval. No press releases related to this
Agreement may be issued by either party until the Commission has acted on it.
Upon the approval of this Agreement, the Commission will immediately notify the
FERC that it is has reached a settlement agreement with AEP and will not
continue to pursue its argument before the FERC.
<PAGE> 10
EXHIBIT D-10.1
12. ENFORCEABILITY. AEP and I&M will not assert in any action to enforce an
order approving this Agreement that the Commission lacks the authority [*30] to
have the provisions of this Agreement enforced under Michigan law. Disputes
regarding the interpretation of this Agreement shall be brought to a state court
of competent jurisdiction.
DEFINITIONS
1. "AEP zone" means either the area comprising the AEP operating companies
providing service in Michigan, Michigan, Kentucky, Ohio, Tennessee, Virginia and
West Virginia ("East") or the area comprising the former CSW operating companies
providing service in Arkansas, Texas, Oklahoma and Louisiana ("West").
2. "AEP operating company" means an AEP affiliate that is a public utility
subject to rate regulation by the FERC and/or a state utility regulatory agency.
3. "Affiliate" means an entity that is an operating company's holding company,
a subsidiary of the operating company or a subsidiary of the holding company.
4. "Entity" means a corporation or a natural person.
5. "Exempt wholesale generator" means an entity which is engaged directly or
indirectly through one or more affiliates exclusively in the business of owning
or operating all or part of a facility for generating electric energy and
selling electric energy at wholesale and who:
a. does not own a facility for the [*31] transmission of electricity, other
than an essential interconnecting transmission facility necessary to affect a
sale of electric energy at wholesale; and
b. has applied to the FERC for a determination under 15 U.S.C. Section 79z-5a.
6. "FERC" means the Federal Energy Regulatory Commission, or any successor
governmental agency.
7. "Non-Utility Affiliate" means an Affiliate which is not a domestic public
utility. Non-utility affiliate includes a foreign affiliate.
8. "Holding Company" means AEP, or its successor in interest, or any Entity
that owns directly or indirectly 10 percent or more of the voting capital stock
of a utility operating company, or its successor in interest.
9. "Power Marketer" means an entity which:
a. becomes an owner or broker of electric energy in a state for the purpose of
selling the electric energy at wholesale;
b. does not own transmission or distribution facilities in a state;
c. does not have a certified service area; and
d. has been granted authority by the FERC to sell electric energy at
market-based rates.
10. "Regional Transmission Organization" (RTO) means an organization that
operates electric transmission equipment and facilities [*32] on a regional
basis.
11. "SEC" means the United States Securities and Exchange Commission, or any
successor governmental agency.
<PAGE> 11
EXHIBIT D-10.1
12. "Service Agreement" means the agreement entered into between American
Electric Power Service Corp. and AEP's operating companies, under which services
are provided by American Electric Power Service Corp. to the operating
companies.
13. "Service Company" means an Affiliate whose primary business purpose is to
provide, among other functions, administrative and general or operating services
to AEP utility operating companies.
14. "Services" means the performance of activities having value to one party
including, but not limited to, managerial, financial, accounting, legal,
engineering, construction, purchasing, marketing, auditing, statistical,
advertising, publicity, tax, research, and other similar services.
15. "Subsidiary" means any corporation 10 percent or more of whose voting
capital stock is controlled by another Entity.
16. "Utility Affiliate" means an affiliate of a utility operating company that
is also a public utility.
Presentation of Agreement to the Commission
1. I&M shall, contemporaneously with the execution of this [*33] Agreement,
petition the Commission for ex parte approval of the net merger savings
reductions and accounting authority set forth in the Agreement, conditioned on
the Commission's approval of the Agreement without modification. As part of the
proceeding on the petition for ex parte approval, the Parties will submit this
Agreement to the Commission for review and approval.
2. The Parties stipulate and agree to the issuance by the Commission of the
Proposed Order in the form attached hereto as Attachment D. All of the terms and
agreements contained in the Proposed Order are to be interpreted consistent with
the provisions of this Agreement, which is to be attached to and incorporated by
reference in the Final Order issued by the Commission.
Effect and Use of Agreement
1. This Agreement shall not constitute nor be cited as precedent or deemed an
admission by any Party in any other proceeding except as necessary to enforce
its terms before the Commission, or any State Court of competent jurisdiction.
This Agreement is solely the result of compromise in the settlement process,
shall not constitute a concession of subject matter jurisdiction, and except as
expressly provided herein, [*34] is without prejudice to and shall not
constitute a waiver of any position that any of the Parties may take with
respect to any or all of the items resolved herein in any future regulatory or
other proceedings and, failing approval by this Commission, shall not be
admissible or discussed in any subsequent proceedings.
2. The undersigned have represented and agreed that they are fully authorized
to execute this Agreement.
3. The Parties to this Agreement shall not appeal the agreed Final Order or any
other Commission order approving this Agreement to the extent such orders are
specifically implementing the provisions of this Agreement and shall support
this Agreement in the event of any appeal by a person not a Party. This
provision shall be enforceable by any Party, in any state court of competent
jurisdiction.
4. The communications and discussions during the negotiations and conferences
that produced the Agreement have been conducted on the explicit understanding
that they are or relate to offers of settlement and shall therefore be
privileged and not admissible in any proceeding.
ACCEPTED and AGREED this 16th day of November, 1999.
Indiana Michigan Power Company
By:
Marc [*35] E. Lewis
<PAGE> 12
EXHIBIT D-10.1
Senior Attorney
American Electric Power
By:
Richard E. Munczinski
Senior Vice President
American Electric Power Service Corporation
Michigan Public Service Commission Staff
By:
Steven D. Hughey (P-32203)
Assistant Attorney General
Attachment A
- --------------------------------------------------------------------------------
AEP/CSW MERGER
NET ANNUAL MERGER SAVINGS
AND MICHIGAN CUSTOMER RATE REDUCTIONS
($ 000)
<TABLE>
<CAPTION>
(1) (2) (3) (4)
Net Customer Net Shareholder
Period Merger Savings Savings Savings
<S> <C> <C> <C>
Year 1 1,157 685 472
Year 2 2,230 1,243 987
Year 3 2,840 1,560 1,280
Year 4 3,330 1,815 1,515
Year 5 3,651 1,982 1,669
Year 6 3,896 2,109 1,787
Year 7 4,086 2,208 1,878
Year 8 4,195 2,265 1,930
Total 25,385 13,866 11,519
</TABLE>
ATTACHMENT B
- --------------------------------------------------------------------------------
<TABLE>
<S> <C> <C> <C>
AEP/CSW MERGER
EXAMPLE OF BASE RATE CASE TREATMENT
BASED ON YEAR 3 ($ 000)
CREDIT PER RIDER CONTINUES (1,560)
INCLUDED IN TEST YEAR:
GROSS MERGER SAVINGS (3,575)
CHANGE IN CONTROL AMORTIZATION 160
OTHER CTA AMORTIZATION 575
TOTAL CTA/CIC AMORTIZATION 735
NET MERGER SAVINGS IN TEST YEAR (2,840)
ADD BACK TO TEST YEAR COST OF SERVICE:
CUSTOMER SHARE 1,560
SHAREHOLDER PORTION 1,280
2,840
</TABLE>
<PAGE> 13
EXHIBIT D-10.1
<TABLE>
<S> <C>
NET BASE RATE REDUCTION 0
MICHIGAN CUSTOMER RATE REDUCTION (1,560)
</TABLE>
[*36]
AEP/CSW MERGER
BASE RATE CASE TREATMENT
FOR INCLUSION IN COST OF
SERVICE ($ 000)
Add Back to Test Year
Cost of
Service
<TABLE>
<CAPTION>
RATE CUSTOMER SHAREHOLDER
YEAR NET SAVINGS NET SAVINGS
<S> <C> <C>
Year 1 685 472
Year 2 1,243 987
Year 3 1,560 1,280
Year 4 1,815 1,515
Year 5 1,982 1,670
Year 6 2,109 1,787
Year 7 2,208 1,878
Year 8 2,265 1,930
13,867 11,519
</TABLE>
AEP/CSW MERGER
AMORTIZATION OF
ESTIMATED
COSTS TO
ACHIEVE(*)
<TABLE>
<CAPTION>
RATE
YEAR AMOUNT
<S> <C>
Year 1 735,465
Year 2 735,465
Year 3 735,465
Year 4 735,465
Year 5 735,465
Year 6 735,465
Year 7 735,465
Year 8 735,465
TOTAL (**)5,883,722
</TABLE>
(*) Includes change control payments.
(**)May not add due to roundings.
<PAGE> 14
EXHIBIT D-10.1
Attachment C
Quality of Service Reporting
Indiana Michigan Power will maintain the overall quality and reliability of its
electric service at levels no less than it has achieved in the past decade.
Indiana Michigan Power will provide service reliability reports annually
indicating its calendar year Michigan Customer Average Interruption Duration
Index (CAIDI) and Michigan System Average Interruption Frequency Index (SAIFI).
These indices shall be determined [*37] and reported, including all storms.
Definitions for these measures are included in this Attachment.
Indiana Michigan Power also will provide annual Call Center performance
measures for those centers which handle Michigan customer calls. These will
include the Call Center Average Speed of Answer (ASA), Abandonment Rate, and
Call Blockage. Definitions for these measures are included in this Attachment.
The performance information described above shall be provided by the end of May
of the year following the calendar year in question.
AEP Reliability Measures
1) System Average Interruption Frequency Index (SAIFI) is defined as the number
of customers interrupted divided by the number of customers served. It is
calculated by the equation:
SAIFI = number of customers interrupted/number of customers served
2) Customer Average Interruption Duration Index (CAIDI) is defined as the
number of customer hours of interruption divided by the number of customers
interrupted. It is calculated by the equation:
CAIDI = sum of all customer hours of interruption/number of customers
interrupted
AEP Call Center Measures
1) Average Speed of Answer (ASA) is defined as the average [*38] time that
elapses in seconds between the instant when a call is answered and the time it
is connected to a Call Center representative (CSR) or an interactive voice
recorder (IVR). It is calculated using the equation:
Average Speed of Answer (seconds) =time for all calls between call answer and
CSR/IVR connection/total number of calls made to the Call Center
2) Abandonment Rate is the percentage of callers who hang up before being
connected to a Call Center representative (CSR) or an interactive voice recorder
(IVR). It is calculated using the equation:
Abandonment Rate (percent) = [total number of callers who hang up]/[total
number of calls made to the Call Center] x 100
3) Call Blockage is the percentage of non-outage call attempts which do not get
connected to a Call Center (busy signal, etc.). It is calculated using the
equation:
Call Blockage (percent) = [total number of non-outage calls that do not get
connected]/[total number of non-outage calls made to the Call Center] x 100
<PAGE> 1
EXHIBIT F-1
614/223-1648
Securities and Exchange Commission
450 Fifth Street, N.W.
Washington, D.C. 20549
May , 2000
Re: American Electric Power Company, Inc.
Central and South West Corporation
SEC File No. 70-9381
Dear Sirs:
I refer to the Application-Declaration on Form U-1 in File No. 70-9381, as
amended (the "Application"), under the Public Utility Holding Company act of
1935, as amended (the "1935 Act"), filed by American Electric Power Company,
Inc. ("AEP"), a New York corporation and a registered holding company under the
1935 Act, and Central and South West Corporation ("CSW"), a Delaware corporation
and a registered holding company under the 1935 Act (collectively, the
"Applicants"), seeking authority for (a) the acquisition by AEP of all of the
issued and outstanding CSW common stock; (b) the acquisition by AEP of common
stock of Augusta Acquisition Corporation, to become a wholly owned subsidiary of
AEP; (c) the issuance of AEP common stock; (d) the amendment of AEP's existing
authority to authorize AEP, upon consummation of the proposed Transactions (as
defined below), to support the financing arrangements and to conduct the
business activities of CSW; (e) the adoption of a service agreement to permit,
under Section 13 of the 1935 Act and the rules of the Securities and Exchange
Commission thereunder, American Electric Power Service Corporation to render
services to AEP's utility and non-utility subsidiaries and an expansion of AEP's
allocation factors following the consummation of the proposed Transactions; and
(f) the acquisition by AEP of CSW's non-utility businesses (to the extent
jurisdictional) (collectively, the "Transactions"), as more fully described in
the Application.
I am an employee of American Electric Power Service Corporation, and have acted
as counsel to AEP in connection with the filing of the Application. All
capitalized terms used herein but not defined herein shall have the meaning
ascribed to them in the Application.
<PAGE> 2
Securities and Exchange Commission
May , 2000
Page 2
In connection with this opinion, I have examined the Application and the
exhibits thereto and the Merger Agreement, and I have examined originals, or
copies certified to my satisfaction, of such corporate records of the
Applicants, certificates of public officials, certificates of officers and
representatives of the Applicants and other documents as I have deemed it
necessary to require as a basis for the opinions hereinafter expressed. In such
examination I have assumed the genuineness of all signatures and the
authenticity of all documents submitted to us as originals and the conformity
with the originals of all documents submitted to us as copies. As to various
questions of fact material to such opinions I have, when relevant facts were not
independently established, relied upon certificates by officers of Applicants
and other appropriate persons and statements contained in the Application.
Based upon the foregoing, and having regard to legal considerations which I deem
relevant, I am of the opinion that, in the event that the proposed Transactions
are consummated in accordance with the Application, and subject to the
assumptions and conditions set forth below:
1. The laws of the States of Ohio, Indiana, Michigan, Tennessee and
West Virginia and the Commonwealths of Kentucky and Virginia applicable to the
proposed Transactions as described in the Application will have been complied
with.
2. The consummation of the proposed Transactions as described in the
Application will not violate the legal rights of the lawful holders of any
securities issued by AEP or any associate company of AEP.
3. AEP will legally acquire all of the outstanding shares of CSW common
stock.
The opinions expressed above in respect of the proposed Transactions as
described in the Application are subject to the following assumptions or
conditions:
a. The Transactions shall have been duly authorized and approved, to
the extent required by state law, by the Board of Directors and shareholders of
Applicants, and such authorization and approval shall remain in effect at the
closing thereof.
<PAGE> 3
Securities and Exchange Commission
May , 2000
Page 3
b. The Securities and Exchange Commission shall have duly entered an
appropriate order or orders granting and permitting the Application to become
effective with respect to the Transactions described therein.
c. The Transactions shall have been accomplished in accordance with
required approvals, authorizations, consents, certificates and orders of all
state commission or regulatory authorities with respect thereto, and all such
required approvals, authorizations, consents, certificates and orders shall have
been obtained and remain in effect at the closing thereof.
d. No opinions are expressed with respect to laws other than those of
the States of Ohio, Indiana, Michigan, Tennessee and West Virginia and the
Commonwealths of Kentucky and Virginia.
e. Registration statements with respect to the shares of AEP common
stock to be issued in connection with the Transactions shall have become
effective pursuant to the Securities Act of 1933, as amended; no stop order
shall have been entered with respect thereto; and the issuance of shares of AEP
common stock in connection with the Transactions shall have been consummated in
compliance with the Securities Act of 1933, as amended, and the rules and
regulations thereunder.
f. The solicitation of proxies from the stockholders of AEP and CSW
with respect to the Transactions shall have been made in accordance with the
Securities Exchange Act of 1934, as amended, and the rules and regulations
thereunder.
g. No act or event other than as described herein shall have occurred
subsequent to the date hereof which would change the opinions expressed above.
I hereby consent to the use of this opinion as an exhibit to the Application.
Very truly yours,
Thomas G. Berkemeyer
<PAGE> 1
EXHIBIT F-2
April __, 2000
Securities and Exchange Commission
450 Fifth Street, N.W.
Washington, D.C. 20549
Re: American Electric Power Company and Central and South West
Corporation Form U-1 Application-Declaration in File No.
70-9381
Dear Sirs:
We refer to the Form U-1 Application in File No. 70-9381, as
amended (the "Application"), under the Public Utility Holding Company Act of
1935, as amended (the "1935 Act"), filed by American Electric Power Company
("AEP"), a New York corporation and a registered holding company under the 1935
Act, and Central and South West Corporation ("CSW"), a Delaware corporation and
a registered holding company under the 1935 Act (collectively the "Applicants"),
seeking authority for (a) the acquisition by AEP of all of the issued and
outstanding CSW common stock; (b) the acquisition by AEP of common stock of
Augusta Acquisition Corporation, to become a wholly owned subsidiary of
subsidiary of AEP; (c) the issuance of AEP common stock; (d) the amendment of
AEP's existing authority to authorize AEP, upon consummation of the proposed
Transactions (as defined below), to support the financing arrangements and to
conduct the business activities of CSW; (e) the adoption of a service agreement
to permit, under Section 13 of the 1935 Act and the rules of the Securities and
Exchange Commission thereunder, AEP Service Company to render services to AEP's
utility and non-utility subsidiaries and an expansion of AEP's allocation
factors following the consummation of the proposed Transactions; and (f) the
acquisition by AEP of CSW's non-utility businesses (to the extent
jurisdictional) (collectively, the "Transactions"), as more fully described in
the Application. We have acted as special counsel for CSW in connection with the
filing of the Application. All capitalized terms used herein but not defined
herein shall have the meaning ascribed to them in the Application.
In connection with this opinion, we have examined the
Application and the exhibits thereto and the Merger Agreement, and we have
examined originals, or copies certified to our satisfaction, of such corporate
records of the Applicants, certificates of public officials, certificates of
officers and representatives of the Applicants and other documents as we have
deemed it necessary to require as a basis for the opinions hereinafter
expressed. In such examination we have assumed the genuineness of all signatures
and the authenticity of all documents submitted to us as originals and the
conformity with the originals of all documents submitted to us as copies. As to
various questions of fact material to such opinions we have,
<PAGE> 2
EXHIBIT F-2
when relevant facts were not independently established, relied upon certificates
by officers of Applicants and other appropriate persons and statements contained
in the Application.
Based upon the foregoing, and having regard to legal
considerations which we deem relevant, we are of the opinion that, in the event
that the proposed Transactions are consummated in accordance with the
Application, and subject to the assumptions and conditions set forth below:
1. The laws of the States of Texas, Louisiana, Arkansas, Oklahoma,
and Delaware applicable to the proposed Transactions as
described in the Application will have been complied with.
2. The consummation of the proposed Transactions as described in
the Application will not violate the legal rights of the lawful
holders of any securities issued by CSW or any associate
company of CSW.
3. AEP will legally acquire all of the outstanding shares of CSW
common stock.
The opinions expressed above in respect of the proposed
Transactions as described in the Application are subject to the following
assumptions or conditions:
a. The Transactions shall have been duly authorized and
approved, to the extent required by state law, by the Board
of Directors and shareholders of Applicants, and such
authorization and approval shall remain in effect at the
closing thereof.
b. The Securities and Exchange Commission shall have duly
entered an appropriate order or orders granting and
permitting the Application to become effective with respect
to the Transactions described therein.
c. The Transactions shall have been accomplished in accordance
with required approvals, authorizations, consents,
certificates and orders of all state commission or
regulatory authorities with respect thereto, and all such
required approvals, authorizations, consents, certificates
and orders shall have been obtained and remain in effect at
the closing thereof.
d. No opinions are expressed with respect to laws other than
those of the States of Texas, New York, Louisiana,
Arkansas, Oklahoma and Delaware.
e. Registration statements with respect to the shares of AEP
common stock to be issued in connection with the
Transactions shall have become effective pursuant to the
Securities Act of 1933, as amended; no stop order shall
have been entered with respect thereto; and the issuance of
shares of AEP common stock in connection with the
Transactions shall have been consummated in
<PAGE> 3
EXHIBIT F-2
compliance with the Securities Act of 1933, as amended,
and the rules and regulations thereunder.
f. The solicitation of proxies from the stockholders of AEP
and CSW with respect to the Transactions shall have been
made in accordance with the Securities Exchange Act of
1934, as amended, and the rules and regulations thereunder.
g. No act or event other than as described herein shall have
occurred subsequent to the date hereof which would change
the opinions expressed above.
We hereby consent to the use of this opinion as an exhibit
to the Application.
Very truly yours,
MILBANK, TWEED, HADLEY & McCLOY LLP
JMH/GWG
<PAGE> 1
EXHIBIT I-2
Short-Term Borrowing Program
Pursuant to Central and South West Corp., et al., HCAR No. 26697 (Mar.
28, 1997), this Commission granted an extension of authority for CSW, CPL, PSO,
SWEPCO, WTU and CSWS (the "Money Pool Participants") to continue their
short-term borrowing program through March 31, 2002, including the sale of
commercial paper by CSW to commercial paper dealers and financial institutions,
and the sale of short-term notes to banks and their trust departments, by the
Money Pool Participants.
Pursuant to Central and South West Corp., et al., HCAR No. 26854 (Apr.
3, 1998), this Commission authorized increased short-term borrowing limits for
CSW and the Money Pool Participants as follows:
<TABLE>
<S> <C>
CSW $ 2,500,000,000
CPL $ 600,000,000
PSO $ 300,000,000
SWEPCO $ 250,000,000
WTU $ 165,000,000
CSWS $ 210,000,000
</TABLE>
Pursuant to American Elec. Power Co., et al., HCAR No. 27049 (July 14,
1999), this Commission authorized the following short-term borrowing limits for
AEP and certain of its subsidiaries identified below (the "AEP Utility
Subsidiaries"):
<TABLE>
<S> <C>
AEP $ 500,000,000
AEGCo $ 125,000,000
APCo $ 325,000,000
CSPCo $ 350,000,000
I&M $ 500,000,000
KPCo $ 150,000,000
KgPCo $ 30,000,000
OPCo $ 450,000,000
WPCo $ 30,000,000
TOTAL: $2,460,000,000
</TABLE>
Applicants hereby request authority, effective upon consummation of the
Merger, for the Combined Company to continue the Money Pool and to manage and
fund it consistent with all the terms and conditions of Central and South West
Corp., et al., HCAR No. 26697 (Mar. 28, 1997); Central and South West Corp., et
al., HCAR No. 26854 (Apr. 3, 1998) and all previous orders of this Commission
relating to the Money Pool subject to the following: (1) CSW's $2,500,000,000
short-term borrowing authorization shall transfer to the Combined Company and
Combined Company's short-term borrowing limit shall be increased from
$500,000,000 to $5,000,000,000 (such limit consisting of (a) $2,500,000,000
authorized for CSW, (b) $2,460,000,000 authorized for AEP and AEP Utility
Subsidiaries, and (c) $40,000,000 for AEPSC); (2) the Combined Company and the
AEP Utility Subsidiaries shall be added as participants to the Money Pool and
permitted to issue short term debt up to the amounts specified in American Elec.
Power Co., et al., HCAR No. 27049 (July 14, 1999);
<PAGE> 2
EXHIBIT I-2
and (3) the Coal Subsidiaries and AEPSC shall be added as participants to the
Money Pool, although their borrowings would be exempt under Rule 52(b).
<PAGE> 1
EXHIBIT I-4
CSW Guarantee Authorizations
Pursuant to Central and South West Corp., et al., HCAR No. 26910 (Aug.
24, 1998), this Commission authorized, through December 31, 2003, CSW to fund
the management, operations and administrative costs of the electric vehicle
business of CSW Energy Services (the 'EV Business') by making loans to CSW
Energy Services and providing guarantees and other credit support on behalf of
CSW Energy Services, up to an aggregate amount outstanding at any time of
$25,000,000 and to finance the EV Business by making loans and providing
guarantees and other credit support to commercial and institutional customers of
CSW Energy Services. Applicants hereby request that, upon consummation of the
Merger, the authority of CSW as stated in Central and South West Corp., et al.,
HCAR No. 26910 (Aug. 24, 1998) be vested in both CSW and the Combined Company.
Pursuant to Central and South West Corp., et al., HCAR No. 26811 (Dec.
30, 1997), this Commission authorized, effective through December 31, 2002, (i)
external financing by CSW; (ii) CSW to acquire common stock from its
subsidiaries; (iii) the subsidiaries to repurchase their common stock from CSW;
(iv) credit enhancement for the CSW subsidiaries' securities, including
guarantees by CSW; (v) CSW to repurchase its securities by means of tender
offers; and (vi) the issuance by CSW of other types of securities not exempt
under Rules 45 and 52. Applicants hereby request that, upon consummation of the
Merger, the guarantee authority of CSW as stated in Central and South West
Corp., et al., HCAR No. 26811 (Dec. 30, 1997) be vested in both CSW and the
Combined Company and that all other authority of CSW as stated in Central and
South West Corp., et al., HCAR No. 26811 (Dec. 30, 1997) be vested in the
Combined Company.
Pursuant to Central and South West Corp., et al., HCAR No. 26767 (Oct.
21, 1997), this Commission confirmed certain previous authority and granted
additional authority such that CSW was authorized, through December 31, 2002, to
organize and invest in EWGs and FUCOs, either directly or indirectly, to provide
certain operational and management services to EWGs and FUCOs, to provide
guarantees or other forms of credit support for the securities or contractual
obligations of the investees in connection with permitted activities, and to
fund these investments and obligations under these guarantees in other forms of
credit support through issuances by CSW. Applicants hereby request that, upon
consummation of the Merger, the authority of CSW as stated in Central and South
West Corp., et al., HCAR No. 26767 (Oct. 21, 1997) be vested in both CSW and the
Combined Company.
Pursuant to Central and South West Corp., et al., HCAR No. 26766 (Oct.
21, 1997), this Commission authorized CSW, through December 31, 2002, to issue
guarantees in an aggregate amount up to $250,000,000 to support the debt and
other obligations of affiliated power marketers and Rule 58 companies.
Applicants hereby request that, upon consummation of the Merger, the authority
of CSW as stated in Central and South West Corp., et al., HCAR No. 26766 (Oct.
21, 1997) be vested in both CSW and the Combined Company. Pursuant to American
Elec. Power Co., HCAR No. 26998 (April 7, 1999) this Commission authorized AEP,
through December 31, 2002, to form one or more gas marketing subsidiaries and to
issue guarantees of up to $200,000,000 of indebtedness and up to $200,000,000 of
other obligations in support of its gas marketing subsidiaries.
<PAGE> 2
EXHIBIT I-4
Pursuant to Central and South West Corp., et al., HCAR No. 26762 (Sept.
30, 1997), this Commission authorized CSW to participate in the organization and
operation of STP Operating. Applicants hereby request that, upon consummation of
the Merger, the authority of CSW as stated in Central and South West Corp., et
al., HCAR No. 26762 (Sept. 30, 1997) be vested in both CSW and the Combined
Company.
Pursuant to Central and South West Corp., et al., HCAR No. 26522 (May
29, 1996), this Commission authorized CSW to provide up to $250,000,000 in
equity support to the Sweeny Project in the form of the equity support
agreement, guaranty or letter of credit to the project lender. Applicants hereby
request that, upon consummation of the Merger, the authority of CSW as stated in
Central and South West Corp., et al., HCAR No. 26522 (May 29, 1996) be vested in
both CSW and the Combined Company.
<PAGE> 1
EXHIBIT L-1
MARKET SHARES FOR ELECTRIC COMPANIES IN THE UNITED STATES
COMPANIES SORTED BY ELECTRIC REVENUES
<TABLE>
<CAPTION>
1998
ELECTRIC REVENUES
RANK COMPANY NAME ($000S) SHARE OF TOTAL
- ---- ------------ ------- --------------
<S> <C> <C> <C>
1 AEP AND C&SW COMBINED (PRO FORMA) $10,044,103 4.88%
--------------------------------- ---------- -----
2 Southern Company $9,762,569 4.75%
3 PG&E Corporation $8,924,000 4.34%
4 Edison International $8,847,000 4.30%
5 Unicorn Corporation $7,151,253 3.48%
6 AMERICAN ELECTRIC POWER COMPANY $7,132,722 3.47%
------------------------------- ---------- -----
7 Texas Utilities Company $6,556,103 3.19%
8 FPL Group, inc. $6,365,829 3.09%
9 Entergy Corporation $6,136,322 2.98%
10 Consolidated Edison, Inc. $5,674,446 2.76%
11 FirstEnergy Corp. $5,263,756 2.56%
12 PECO Energy Company $4,810,840 2.34%
13 CINergy Corp. $4,747,235 2.31%
14 Duke Energy Corporation $4,586,000 2.23%
15 Reliant Energy, Incorporated $4,350,275 2.11%
16 Dominion Resources, Inc. $4,284,600 2.08%
17 Northeast Utilities $4,257,069 2.07%
18 Public Service Enterprise Group Inc $4,031,000 1.96%
19 GPU, Inc. $4,028,339 1.96%
20 DTE Energy Company $3,860,517 1.88%
21 CENTRAL AND SOUTH WEST CORPORATION $3,488,000 1.70%
---------------------------------- ---------- -----
22 Niagara Mohawk Holdings, Inc. $3,390,501 1.65%
23 Carolina Power &Light Company $3,130,045 1.52%
24 Ameren Corporation $3,094,211 1.50%
25 CMS Energy Corporation $2,883,000 1.40%
26 New Century Energies, Inc. $2,697,486 1.31%
27 Florida Progress Corporation $2,648,200 1.29%
28 Northern States Power Company $2,641,193 1.28%
29 Allegheny Energy, Inc. $2,576,436 1.25%
30 MidAmerican Energy Hldgs-CalEnergy $2,555,206 1.24%
31 Energy East Corporation $2,499,418 1.21%
32 PPL Corporation $2,410,000 1.17%
33 NSTAR $2,341,823 1.14%
34 Constellation Energy Group, Inc. $2,219,200 1.08%
35 Conectiv $2,203,748 1.07%
36 Pinnacle West Capital Corporation $2,006,398 0.98%
37 Potomac Electric Power Company $1,886,100 0.92%
38 Sempra Energy $1,865,000 0.91%
39 lllinova Corporation $1,781,400 0.87%
40 Dynegy Inc. $1,781,388 0.87%
41 Wisconsin Energy Corporation $1,663,632 0.81%
42 Western Resources, Inc. $1,612,959 0.78%
43 Alliant Energy Corporation $1,567,442 0.76%
44 New England Electric System $1,490,417 0.72%
45 Puget Sound Energy, Inc. $1,475,208 0.72%
46 LG&E Energy Corp. $1,438,824 0.70%
47 NiSource Inc. $1,429,986 0.70%
48 TECO Energy, Inc. $1,327,814 0.65%
49 OGE Energy Corp. $1,312,078 0.64%
50 KeySpan Corporation $1,293,998 0.63%
</TABLE>
Prepared by Navigant Consulting, Inc.
<PAGE> 2
EXHIBIT L-1
MARKET SHARES FOR ELECTRIC COMPANIES IN THE UNITED STATES
COMPANIES SORTED BY ELECTRIC REVENUES
<TABLE>
<CAPTION>
1998
ELECTRIC REVENUES
RANK COMPANY NAME ($000S) SHARE OF TOTAL
- ---- ------------ ------- --------------
<S> <C> <C> <C>
51 SCANA Corporation $1,220,000 0.59%
52 DQE $1,126,789 0.55%
53 DPL Inc. $1,070,700 0.52%
54 Hawaiian Electric Industries, Inc. $1,016,283 0.49%
55 Kansas City Power &Light Company $938,941 0.46%
56 CMP Group, Inc. $938,739 0.46%
57 Sierra Pacific Resources $873,682 0.42%
58 Avista Corporation $856,074 0.42%
59 Public Service Company -New Mexico $835,204 0.41%
60 IPALCO Enterprises, Inc. $785,835 0.38%
61 Eastern Utilities Associates $773,943 0.38%
62 RGS Energy Group, Inc. $687,970 0.33%
63 United Illuminating Company $686,191 0.33%
64 UniSource Energy Corporation $625,407 0.30%
65 UtiliCorp United Inc. $616,526 0.30%
66 El Paso Electric Company $602,221 0.29%
67 TNP Enterprises, Inc. $586,445 0.29%
68 Minnesota Power, Inc. $559,900 0.27%
69 Montana Power Company $547,164 0.27%
70 WPS Resources Corporation $543,260 0.26%
71 Cleco Corporation $515,175 0.25%
72 IDACORP, Inc. $514,856 0.25%
73 CH Energy Group, Inc. $418,507 0.20%
74 CILCORP Inc. $360,009 0.17%
75 SIGCORP, Inc. $297,865 0.14%
76 Central Vermont Public Service Corp $297,662 0.14%
77 Empire District Electric Co. $238,801 0.12%
78 Otter Tail Power Company $227,477 0.11%
79 MDU Resources Group, Inc. $211,453 0.10%
80 Bangor Hydro-Electric Company $195,144 0.09%
81 Citizens Utilities Company $190,051 0.09%
82 Green Mountain Power Corporation $184,304 0.09%
83 Madison Gas and Electric Company $169,563 0.08%
84 Unitil Corporation $149,639 0.07%
85 Black Hills Corporation $129,236 0.06%
86 St. Joseph Light &Power Company $89,678 0.04%
87 Northwestern Corporation $78,415 0.04%
88 Maine Public Service Company $56,602 0.03%
===================================================================================
TOTAL I.O.U. ELECTRIC REVENUES $205,740,800 100.00%
</TABLE>
Prepared by Navigant Consulting, Inc.
<PAGE> 1
EXHIBIT L-2
MARKET SHARES FOR ELECTRIC COMPANIES IN THE UNITED STATES COMPANIES
SORTED BY ASSETS
<TABLE>
<CAPTION>
1998
RANK COMPANY NAME ASSETS ($000S) SHARE OF TOTAL
- ---- ------------ -------------- --------------
<S> <C> <C> <C>
1 Texas Utilities Company $39,514,000 5.91%
2 Southern Company $36,192,000 5.41%
3 PG&E Corporation $33,234,000 4.97%
4 AEP AND C&SW COMBINED (PRO FORMA) $33,227,202 4.97%
--------------------------------- ----------- -----
5 Duke Energy Corporation $26,806,000 4.01%
6 Unicorn Corporation $25,707,080 3.84%
7 Edison International $24,698,000 3.69%
8 Entergy Corporation $22,848,023 3.42%
9 AMERICAN ELECTRIC POWER COMPANY $19,483,202 2.91%
------------------------------- ----------- -----
10 FirstEnergy Corp. $18,063,507 2.70%
11 Public Service Enterprise Group Inc $17,997,000 2.69%
12 Dominion Resources, Inc. $17,517,000 2.62%
13 GPU, Inc. $16,288,109 2.43%
14 Consolidated Edison, Inc. $14,381,403 2.15%
15 Niagara Mohawk Holdings, Inc. $13,861,187 2.07%
16 CENTRAL AND SOUTH WEST CORPORATION $13,744,000 2.05%
---------------------------------- ----------- -----
17 DTE Energy Company $12,088,000 1.81%
18 PECO Energy Company $12,048,363 1.80%
19 FPL Group, Inc. $12,029,000 1.80%
20 CMS Energy Corporation $11,310,000 1.69%
21 Sempra Energy $10,456,000 1.56%
22 Northeast Utilities $10,387,381 1.55%
23 ClNergy Corp. $10,298,795 1.54%
24 PPL Corporation $9,607,000 1.44%
25 Constellation Energy Group, Inc. $9,195,000 1.37%
26 MidAmerican Energy Hldgs-CalEnergy $9,103,524 1.36%
27 Ameren Corporation $8,847,439 1.32%
28 Carolina Power &Light Company $8,347,406 1.25%
29 Hawaiian Electric Industries, Inc. $8,199,260 1.23%
30 Western Resources, Inc. $7,951,428 1.19%
31 New Century Energies, Inc. $7,671,964 1.15%
32 Northern States Power Company $7,396,297 1.11%
33 KeySpan Corporation $6,895,102 1.03%
34 Pinnacle West Capital Corporation $6,824,546 1.02%
35 lllinova Corporation $6,801,300 1.02%
36 Allegheny Energy, Inc. $6,747,793 1.01%
37 Potomac Electric Power Company $6,654,800 0.99%
38 Florida Progress Corporation $6,160,800 0.92%
39 Conectiv $6,087,674 0.91%
40 UtiliCorp United Inc. $5,991,500 0.90%
41 Wisconsin Energy Corporation $5,361,757 0.80%
42 Citizens Utilities Company $5,292,932 0.79%
43 SCANA Corporation $5,281,000 0.79%
44 Dynegy Inc. $5,264,237 0.79%
45 DQE $5,247,563 0.78%
46 New England Electric System $5,070,535 0.76%
47 NiSource Inc. $4,986,503 0.75%
48 Alliant Energy Corporation $4,959,337 0.74%
49 Energy East Corporation $4,883,337 0.73%
50 LG&E Energy Corp. $4,773,268 0.71%
</TABLE>
<PAGE> 2
EXHIBIT L-2
Prepared by Navigant Consulting, Inc.
<PAGE> 3
EXHIBIT L-2
MARKET SHARES FOR ELECTRIC COMPANIES IN THE UNITED STATES COMPANIES
SORTED BY ASSETS
<TABLE>
<CAPTION>
1998
RANK COMPANY NAME ASSETS ($000S) SHARE OF TOTAL
- ---- ------------ -------------- --------------
<S> <C> <C> <C>
51 Puget Sound Energy, Inc. $4,720,689 0.71%
52 TECO Energy, Inc. $4,179,300 0.62%
53 DPL Inc. $3,855,900 0.58%
54 Avista Corporation $3,253,636 0.49%
55 NSTAR $3,204,036 0.48%
56 Kansas City Power &Light Company $3,012,364 0.45%
57 OGE Energy Corp. $2,983,929 0.45%
58 Montana Power Company $2,928,095 0.44%
59 UniSource Energy Corporation $2,634,180 0.39%
60 Sierra Pacific Resources $2,607,824 0.39%
61 Public Service Company -New Mexico $2,576,788 0.39%
62 Reliant Energy, Incorporated $2,452,935 0.37%
63 RGS Energy Group, Inc. $2,452,935 0.37%
64 IDACORP, Inc. $2,451,620 0.37%
65 Minnesota Power, Inc. $2,317,100 0.35%
66 CMP Group, Inc. $2,262,884 0.34%
67 IPALCO Enterprises, Inc. $2,118,945 0.32%
68 United Illuminating Company $1,891,336 0.28%
69 El Paso Electric Company $1,891,219 0.28%
70 Northwestern Corporation $1,736,216 0.26%
71 WPS Resources Corporation $1,510,387 0.23%
72 MDU Resources Group, Inc. $1,452,775 0.22%
73 Cleco Corporation $1,429,000 0.21%
74 CH Energy Group, Inc. $1,316,038 0.20%
75 CILCORP Inc. $1,312,940 0.20%
76 Eastern Utilities Associates $1,302,638 0.19%
77 SIGCORP, Inc. $1,029,518 0.15%
78 TNP Enterprises, Inc. $993,765 0.15%
79 Otter Tail Power Company $655,612 0.10%
80 Empire District Electric Co. $653,294 0.10%
81 Bangor Hydro-Electric Company $605,689 0.09%
82 Black Hills Corporation $559,417 0.08%
83 Central Vermont Public Service Corp $530,282 0.08%
84 Madison Gas and Electric Company $466,265 0.07%
85 Unitil Corporation $376,835 0.06%
86 Green Mountain Power Corporation $309,824 0.05%
87 St. Joseph Light &Power Company $251,255 0.04%
88 Maine Public Service Company $164,296 0.02%
=========================================================================================================
TOTAL I. O. U. ASSETS $669,007,113 100.00%
</TABLE>
Prepared by Navigant Consulting, Inc.
<PAGE> 1
EXHIBIT L-3
MARKET SHARES FOR ELECTRIC COMPANIES IN THE UNITED STATES
COMPANIES SORTED BY ELECTRIC CUSTOMERS
<TABLE>
<CAPTION>
ELECTRIC CUSTOMERS
RANK COMPANY NAME (1998) SHARE OF TOTAL
=========================================================================================================
<S> <C> <C> <C>
1 AEP AND C&SW COMBINED (PRO FORMA] 4,734,648 5.27%
2 PG&E Corporation 4,536,341 5.05%
3 Edison International 4,284,029 4.77%
4 Southern Company 3,761,136 4.19%
5 FPL Group, Inc. 3,680,481 4.10%
6 Unicorn Corporation 3,444,714 3.83%
7 Consolidated Edison, Inc. 3,231,096 3.60%
8 AMERICAN ELECTRIC POWER COMPANY 2,999,397 3.34%
9 Texas Utilities Company 2,516,927 2.80%
10 Entergy Corporation 2,481,956 2.76%
11 FirstEnergy Corp. 2,161,424 2.41%
12 DTE Energy Company 2,061,679 2.30%
13 GPU, Inc. 2,031,194 2.26%
14 Dominion Resources, Inc. 2,009,391 2.24%
15 Duke Energy Corporation 1,968,249 2.19%
16 Public Service Enterprise Group Inc 1,910,971 2.13%
17 CENTRAL AND SOUTH WEST CORPORATION 1,735,251 1.93%
18 Northeast Utilities 1,729,346 1.93%
19 CMS Energy Corporation 1,627,808 1.81%
20 Reliant Energy, Incorporated 1,596,361 1.78%
21 Niagara Mohawk Holdings, Inc. 1,550,732 1.73%
22 Northern States Power Company 1,546,804 1.72%
23 New Century Energies, Inc. 1,545,469 1.72%
24 Ameren Corporation 1,506,500 1.68%
25 PECO Energy Company 1,487,794 1.66%
26 ClNergy Corp. 1,424,118 1.59%
27 Allegheny Energy, Inc. 1,409,753 1.57%
28 Florida Progress Corporation 1,340,853 1.49%
29 PPL Corporation 1,250,246 1.39%
30 Sempra Energy 1,189,555 1.32%
31 Carolina Power & Light Company 1,168,585 1.30%
32 Constellation Energy Group, Inc. 1,116,652 1.24%
33 NSTAR 1,039,987 1.16%
34 Wisconsin Energy Corporation 1,005,173 1.12%
35 New England Electric System 972,056 1.08%
36 Conectiv 938,659 1.04%
37 Alliant Energy Corporation 901,825 1 00%
38 Puget Sound Energy, Inc. 881,843 0.98%
39 LG&E Energy Corp. 831,841 0.93%
40 Sierra Pacific Resources 825,377 0.92%
41 Energy East Corporation 812,772 0.90%
42 Pinnacle West Capital Corporation 777,674 0.87%
43 OGE Energy Corp. 693,710 0.77%
44 Potomac Electric Power Company 690,160 0.77%
45 MidAmerican Energy Hldgs-CalEnergy 650,586 0.72%
46 Eastern Utilities Associates 640,633 0.71%
47 Western Resources, Inc. 620,306 0.69%
48 DQE 581,205 0.65%
</TABLE>
Prepared by Navigant Consulting, Inc.
<PAGE> 2
EXHIBIT L-3
MARKET SHARES FOR ELECTRIC COMPANIES IN THE UNITED STATES
COMPANIES SORTED BY ELECTRIC CUSTOMERS
<TABLE>
<CAPTION>
ELECTRIC CUSTOMERS
RANK COMPANY NAME (1998) SHARE OF TOTAL
=========================================================================================================
<S> <C> <C> <C>
49 Dynegy Inc. 567,760 0.63%
50 lllinova Corporation 567,676 0.63%
51 TECO Energy, Inc. 530,252 0.59%
52 CMP Group, Inc. 529,845 0.59%
53 SCANA Corporation 510,499 0.57%
54 DPL Inc. 487,603 0.54%
55 Kansas City Power & Light Company 447,934 0.50%
56 WPS Resources Corporation 439,957 0.49%
57 IPALCO Enterprises, Inc. 423,409 0.47%
58 NiSource Inc. 418,387 0.47%
59 UtiliCorp United Inc. 370,587 0.41%
60 IDACORP, Inc. 367,597 0.41%
61 Public Service Company - New Mexico 353,653 0.39%
62 RGS Energy Group, Inc. 344,367 0.38%
63 Hawaiian Electric Industries, Inc. 327,186 0.36%
64 UniSource Energy Corporation 320,776 0.36%
65 United Illuminating Company 313,991 0.35%
66 Avista Corporation 301,980 0.34%
67 El Paso Electric Company 287,918 0.32%
68 Montana Power Company 283,834 0.32%
69 CH Energy Group, Inc. 268,502 0.30%
70 Cleco Corporation 245,176 0.27%
71 TNP Enterprises, Inc. 226,302 0.25%
72 CILCORP Inc. 195,244 0.22%
73 Empire District Electric Co. 143,154 0.16%
74 Central Vermont Public Service Corp 140,293 0.16%
75 Minnesota Power, Inc. 138,920 0.15%
76 Otter Tail Power Company 125,462 0.14%
77 SIGCORP, Inc. 123,350 0.14%
78 Madison Gas and Electric Company 123,270 0.14%
79 Bangor Hydro-Electric Company 120,561 0.13%
80 MDU Resources Group, Inc. 114,111 0.13%
81 Citizens Utilities Company 112,885 0.13%
82 Unitil Corporation 95,552 0.11%
83 Green Mountain Power Corporation 83,564 0.09%
84 St. Joseph Light & Power Company 62,010 0.07%
85 Black Hills Corporation 56,671 0.06%
86 Northwestern Corporation 55,965 0.06%
87 Maine Public Service Company 35,381 0.04%
88 KeySpan Corporation 1 0.00%
- ---------------------------------------------------------------------------------------------------------
TOTAL I.O.U. ELECTRIC CUSTOMERS 89,830,204 100.00%
</TABLE>
Prepared by Navigant Consulting, Inc.
<PAGE> 1
EXHIBIT M
SUMMARY OF RATINGS ON SECURITIES OF AEP AND CSW
AEP
<TABLE>
<CAPTION>
1/98 1/2000
- -------------------------------------------------------------------------------------------------------------
S&P Moody's S&P Moody's
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
APCO FMBs A A3 A A3
- -------------------------------------------------------------------------------------------------------------
CSP FMBs A- A3 A- A3
- -------------------------------------------------------------------------------------------------------------
I&M FMBs A- Baa1 A- Baa1
- -------------------------------------------------------------------------------------------------------------
KPCO FMBs A Baa1 A Baa1
- -------------------------------------------------------------------------------------------------------------
OPCo FMBs A- A3 A- A3
- -------------------------------------------------------------------------------------------------------------
AEP CP P-2 P-2
- -------------------------------------------------------------------------------------------------------------
APCO CP P-2 P-2
- -------------------------------------------------------------------------------------------------------------
CSP CP P-2 P-2
- -------------------------------------------------------------------------------------------------------------
I&M CP P-2 P-2
- -------------------------------------------------------------------------------------------------------------
KPCO CP P-2 P-2
- -------------------------------------------------------------------------------------------------------------
OPCO CP P-2 P-2
- -------------------------------------------------------------------------------------------------------------
YPG CP A-2 A-2
- -------------------------------------------------------------------------------------------------------------
</TABLE>
CSW
<TABLE>
<CAPTION>
1/98 1/2000
- -------------------------------------------------------------------------------------------------------------
S&P Moody's S&P Moody's
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
CPL FMBs A A3 A A3
- -------------------------------------------------------------------------------------------------------------
PSO FMBs AA- Aa3 AA- A1
- -------------------------------------------------------------------------------------------------------------
SWEPCO FMBs AA- Aa3 AA- Aa3
- -------------------------------------------------------------------------------------------------------------
WTU FMBs A A2 A A2
- -------------------------------------------------------------------------------------------------------------
CSW CP A2 P2 A2 P2
- -------------------------------------------------------------------------------------------------------------
CSW Credit CP A-1+ P1 A-1+ P1
- -------------------------------------------------------------------------------------------------------------
SEEBOARD CP A2 P2 A2 P2
- -------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE> 1
EXHIBIT N
BEFORE
THE PUBLIC UTILITIES COMMISSION OF OHIO
In the Matter of the Commission's Review )
of the Merger of American Electric Power, ) Case No. 98-113-EL-MER
Inc. and Central and South West Corporation)
ENTRY
The Commission finds:
(1) On December 22, 1997, American Electric Power, Inc. (AEP) and
Central and South West Corporation announced a merger
agreement between the two companies.
(2) On February 5, 1998, the Commission issued an Entry in these
proceedings in which it stated it would undertake a review of
issues associated with the proposed merger-related activities
to ensure that the proposed merger-related activities to
ensure that the proposed merger will promote the public
interest and not adversely affect any class of customer of the
AEP companies subject to Commission jurisdiction. In order to
receive input to focus the issues for its consideration, the
Commission requested comment from interested persons with
regard to the various topics related to the proposed merger
contained in Appendix A to that Entry.
(3) Since we opened these proceedings, the Governor of Ohio has
signed Am. S. B. No. 3, legislation into law. This legislation
establishes the framework in which electric industry
restructuring issues will be resolved in this state.
(4) On October 19, 1999, Columbus Southern Power Company and Ohio
Power Company (Companies) filed a motion requesting the
Commission to terminate this docket.
(5) In support of their motion, the Companies state that the
recent enactment of Am. S. B. No. 3 presents a significant
change in the circumstances of the Commission's review of the
proposed merger and provides a compelling basis for
terminating this docket.
(6) The Companies note that, as part of the new legislative
requirements, the Companies are required to file transition
plans with the Commission within 90 days of the effective date
of the legislation. The Companies argue that the transmission
plan filing and approval process provides a better and
well-structured opportunity to consider the public interest
issues as well as the benefits to Ohio which it believes will
result from the proposed merger.
<PAGE> 2
EXHIBIT N
(7) The Commission agrees that, in light of the enactment of Am.
S. B. No. 3, the dockets in which the Companies file their
respective transition plans are the appropriate dockets in
which to consider issues related to the proposed merger.
(8) This case should be dismissed and closed as a matter of
record.
It is, therefore,
ORDERED, That the motion filed by Columbus Southern Power Company and
Ohio Power Company on October 18, 1999 requesting the Commission to terminate
this docket be granted. It is, further,
ORDERED, That this case be dismissed and closed as a matter of record.
It is, further,
ORDERED, That a copy of this Entry be served upon AEP, Columbus
Southern Power Company, Ohio Power Company, and upon each person who has
expressed an interest in this case.
THE PUBLIC UTILITIES COMMISSION OF OHIO
/S/ Alan R. Schriber
-------------------------------
Alan R. Schriber, Chairman
/S/ Ronda Hartman Fergus /S/ Craig A. Glazer
- --------------------------- -----------------------
Ronda Hartman Fergus Craig A. Glazer
/S/ Donald L. Mason
- --------------------------- -----------------------
Judith A. Jones Donald L. Mason
AJD/vrh
<PAGE> 3
EXHIBIT N
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
American Electric Power Company :
: Docket Nos: EC98-40-000,
And : ER98-2770,
: ER98-2786
Central and South West Corporation :
NOTICE OF WITHDRAWAL OF PROTEST
OF
THE PUBLIC UTILITIES COMMISSION OF OHIO
Pursuant to Rule 216, 18 C.F.R. Sec. 385.216 (1999), the Public Utilities
Commission of Ohio (PUCO) gives notice of its withdrawal of its Protest and its
support of the testimony of witness, Kim M. Wissman, co-sponsored by the PUCO,
with the State of Michigan and the Michigan Public Service Commission. By
withdrawing its Protest and its support for testimony, the PUCO is no longer
opposing the merger of American Electric Power Company, Inc., and Central and
South West Corporation in this proceeding nor seeking the imposition of
conditions by this Commission if the merger is approved. This withdrawal of
protest and of support for testimony reflects only the position of the Public
Utilities Commission of Ohio and should not be viewed as having any effect on
any position of either the State of Michigan or the Michigan Public Service
Commission. The PUCO seeks to continue as an intervenor in this proceeding for
the limited purpose of receiving copies of the pleadings in this documents.
<PAGE> 4
EXHIBIT N
Respectfully submitted,
Betty D. Montgomery
Attorney General
Duan W. Luckey, Chief
Public Utilities Section
/S/ Thomas W. McNamee
------------------------------
Thomas W. McNamee
Assistant Attorneys General
Public Utilities Section
180 E. Broad St., 7th Floor
Columbus, OH 43215
(614) 466-4396
Fax: (614) 644-8764
<PAGE> 5
EXHIBIT N
CERTIFICATE OF SERVICE
I hereby certify that a true copy of the foregoing NOTICE OF WITHDRAWAL OF
PROTEST submitted on behalf of the Public Utilities Commission of Ohio was
served by regular U.S. mail, postage prepaid, or hand-delivered, and by
facsimile to the restricted service list, upon the Parties of Record listed with
the Secretary on this 21st day of October, 1999.
/S/ THOMAS W. MCNAMEE
-------------------------------
THOMAS W. MCNAMEE
Assistant Attorney General
