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File No. 70-9381
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
* * *
AMENDMENT NO. 3
TO
FORM U-1
APPLICATION OR DECLARATION
under the
PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
* * *
AMERICAN ELECTRIC POWER COMPANY, INC.
1 Riverside Plaza, Columbus, Ohio 43215
---------------------------
and
CENTRAL AND SOUTH WEST CORPORATION
1616 Woodall Rodgers Freeway, Dallas, Texas 75202
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(Name of companies and top registered holding company
parents filing this statement and address
of principal executive offices)
* * *
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Armando A. Pena Wendy G. Hargus
Treasurer Treasurer
American Electric Power Company, Inc. Central and South West Corporation
1 Riverside Plaza 1616 Woodall Rodgers Freeway
Columbus, OH 43215 Dallas, TX 75202
Susan Tomasky Jeffrey D. Cross
Senior Vice President and General Counsel Vice President and General Counsel
American Electric Power Company, Inc. AEP Resources, Inc.
1 Riverside Plaza 1 Riverside Plaza
Columbus, OH 43215 Columbus, OH 43215
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Marianne K. Smythe Joris M. Hogan
Wilmer, Cutler & Pickering Milbank, Tweed, Hadley & McCloy LLP
2445 M Street, N.W. 1 Chase Manhattan Plaza
Washington, DC 20037-1420 New York, NY 10005
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(Names and addresses of agents for service)
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TABLE OF CONTENTS
Page
ITEM 1. DESCRIPTION OF MERGER 1
A. INTRODUCTION 1
B. DESCRIPTION OF THE 3
PARTIES TO THE MERGER
1. General Description 3
2. Description of 12
Energy Sales and Facilities
3. Electric Coordination 22
C. DESCRIPTION OF MERGER AND
STATEMENT AS TO CONSIDERATION 25
1. Background of the Merger 25
2. Merger Agreement 26
3. Reasons for the Merger 27
4. AEP Management 28
Following the Merger
ITEM 2. FEES, COMMISSIONS AND EXPENSES 28
ITEM 3. APPLICABLE STATUTORY PROVISIONS 29
A. SECTION 10(b) 31
1. Section 10(b)(1) 31
2. Section 10(b)(2) 40
3. Section 10(b)(3) 47
B. SECTION 10(c) 50
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1. Section 10(c)(1) 50
2. Section 10(c)(2) 71
C. SECTION 10(f) 73
D. INTRA-SYSTEM FINANCING
AND OTHER COMMISSION
AUTHORIZATIONS 73
E. SERVICE AGREEMENT;
APPROVAL OF METHODOLOGY
FOR ALLOCATING COSTS
UNDER THE SERVICE AGREEMENT 74
F. ACQUISITION OF
NON-UTILITY BUSINESSES 75
G. ORGANIZATION OF MERGER
SUB; ACQUISITION OF
MERGER SUB COMMON STOCK 76
ITEM 4. REGULATORY APPROVAL 76
A. ANTITRUST CONSIDERATIONS 77
B. ATOMIC ENERGY ACT 77
C. FEDERAL POWER ACT 78
D. COMMUNICATIONS ACT 78
E. ARKANSAS COMMISSION 78
F. LOUISIANA COMMISSION 78
G. OKLAHOMA COMMISSION 79
H. TEXAS COMMISSION 79
I. INDIANA COMMISSION
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J. KENTUCKY COMMISSION
K. MISSOURI COMMISSION
L. AFFILIATE CONTRACTS 80
ITEM 5. PROCEDURE 80
ITEM 6. EXHIBITS AND FINANCIAL STATEMENTS 80
ITEM 7. INFORMATION AS TO ENVIRONMENTAL 82
EFFECTS
GLOSSARY OF TERMS
The following abbreviations or acronyms used in this Application-Declaration are
defined below:
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250 MW 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
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
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AEP System American Electric Power System, an integrated
electric utility system owned and operated by AEP's
U.S. electric utility subsidiaries
Alliance RTO Application Application of Alliance RTO for Approval of
Transaction under Section 203 of the Federal Power
Act, FERC Docket No. EC99-80 (filed June 3, 1999)
Ameren Ameren Corporation, a public utility holding company
registered under the 1935 Act
Antitrust Division Antitrust Division of U.S. Department of Justice
APCo Appalachian Power Company
Applicants AEP and CSW
Arkansas Commission Arkansas Public Service Commission
Atomic Energy Act Atomic Energy Act of 1954, as amended
C3 Communications C3 Communications, Inc.
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
CPL Central Power and Light Company
CSPCo Columbus Southern Power Company
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CSW Central and South West Corporation before the
Merger, unless the context indicates otherwise
CSW Common Stock CSW common stock, $3.50 par value
CSW Credit CSW Credit, Inc.
CSW Energy CSW Energy, Inc.
CSW Energy Services CSW Energy Services, Inc.
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
Division Commission's Division of Investment Management
DOJ U.S. Department of Justice
Duke Duke Energy Corporation, an integrated energy and
energy services provider including an electric
public utility
ECAR East Central Area Reliability Council
Energy Act Energy Policy Act of 1992
EnerShop EnerShop Inc.
Entergy Entergy Corporation, a public utility holding
company registered under the 1935 Act
ERCOT Electric Reliability Council of Texas
EWG Exempt Wholesale Generator
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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)
FPA Federal Power Act
FTC Federal Trade Commission
FUCO Foreign Utility Company
HHI Herfindahl-Hirschman Index
HSR Act Hart-Scott-Rodino Antitrust Improvements Act of 1976
HVDC High Voltage Direct Current
I&M Indiana Michigan Power Company
Indiana Commission Indiana Utility Regulatory Commission
IPP Independent Power Producer
ISO Independent System Operator
Kentucky Commission Kentucky Public Service Commission
KPCo Kentucky Power Company
KgPCo Kingsport Power Company
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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
Merger Sub Augusta Acquisition Corporation, to become a wholly
owned subsidiary of AEP
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
1935 Act Public Utility Holding Company Act of 1935, as amended
1995 Report The Regulation of Public Utility Holding Companies
(report to Congress by the Division, June 1995)
NRC Nuclear Regulatory Commission
OASIS Open Access Same-Time Information System
OATT Open Access Transmission Tariff
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OG&E Oklahoma Gas & Electric Company
Ohio Commission Public Utilities Commission of Ohio
Oklahoma Commission Corporation Commission of the State of Oklahoma
OPCo Ohio Power Company
PG&E PG&E Corporation, a public utility holding company
PSNH Public Service Company of New Hampshire
PSO Public Service Company of Oklahoma
QF Qualifying Facility as defined in the Public Utility
Regulatory Policies Act of 1978
Registration Statement Joint Proxy Statement/Prospectus
dated April 16, 1998 of AEP and CSW
RTO Regional Transmission Organization
Salomon Salomon Smith Barney Inc., an investment banking
firm and AEP's financial adviser with respect to the
Merger
SEEBOARD SEEBOARD plc, one of the 12 regional electricity
companies formed due to the restructuring and
subsequent privatization of the United Kingdom
electricity industry in 1990
Southern The Southern Company, a public utility holding
company registered under the 1935 Act
SPP Southwest Power Pool
STP South Texas Project, a two-unit nuclear electricity
generating station in which CPL owns a 25.2%
interest
STP Operating STP Nuclear Operating Company
SWEPCO Southwestern Electric Power Company
Texas Commission Public Utility Commission of Texas
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UE Union Electric Company, a public utility and a
wholly owned subsidiary of Ameren
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.
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A. INTRODUCTION
This Application-Declaration seeks approvals relating to the proposed
Merger of AEP and CSW. Pursuant to the Merger Agreement, AEP will acquire all of
the issued and outstanding shares of CSW Common Stock. Both AEP and CSW are
registered with the Commission as holding companies under the 1935 Act.
(References to "AEP" or "CSW" refer to each Applicant and/or its subsidiaries,
jointly or separately.)
AEP owns all of the outstanding shares of common stock of seven U.S.
electric utility operating subsidiaries: APCo, CSPCo, I&M, KPCo, KgPCo, OPCo and
WPCo. The service area of AEP's electric utility subsidiaries covers portions of
Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia and West Virginia. AEP
also owns all of the common stock of AEGCo and AEPSC, among others. AEP
indirectly owns 50% of the outstanding share capital of Yorkshire Electricity.
CSW owns all of the outstanding shares of common stock of four U.S.
electric utility operating subsidiaries: CPL, PSO, SWEPCO and WTU. The service
area of CSW's electric utility subsidiaries covers portions of Arkansas,
Louisiana, Oklahoma and Texas. CSW also owns all of the common stock of CSWS,
among others, and indirectly owns all of the outstanding share capital of
SEEBOARD.
The Merger Agreement provides for a business combination of AEP and CSW
in which Merger Sub will be merged into CSW. CSW will be the surviving
corporation and will become a wholly owned subsidiary of AEP. Immediately
following the Merger, the Combined Company will be a holding company with
respect to CSW, which, in turn, will be a holding company with respect to the
electric utility subsidiaries and other subsidiaries it currently owns (with the
exception of CSWS, which will be merged into AEPSC, and CSW Credit, which will
be directly held by the Combined Company). AEP's utility and non-utility
subsidiaries will remain subsidiaries of AEP, and CSW's utility and non-utility
subsidiaries, which will continue to be owned by CSW, will become indirect
subsidiaries of AEP (except for CSWS and CSW Credit). The final ownership
structure has not yet been determined.
Upon consummation of the Merger, each share of issued and outstanding CSW
Common Stock (other than Excluded Shares) will be exchangeable for 0.60 shares
of AEP Common Stock. The former holders of CSW Common Stock will own
approximately 40% of the outstanding shares of AEP Common Stock after the
Merger. The only voting securities of AEP that will be publicly held will be AEP
Common Stock; the Merger is expected to have no effect on the issued and
outstanding public debt securities, preferred stock and/or preferred trust
securities of CSW and the respective subsidiaries of AEP and CSW.
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.
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The Merger will produce substantial benefits to the public, investors and
consumers and will meet all applicable standards of the 1935 Act. Applicants
believe that the Merger offers significant strategic and financial benefits to
them and to their respective shareholders, as well as to their employees,
customers and the communities in which they provide service. These benefits
include, among others:
(i) The Combined Company will operate more efficiently and be
better equipped to keep rates low in an increasingly competitive electric
utility industry;
(ii) The Combined Company will achieve savings through the
elimination of duplication in corporate and administrative programs,
greater efficiencies in operations and business processes, improved
purchasing power, and the combination of two workforces;
(iii) The Merger will result in a Combined Company with a stronger
financial base, improved position in the credit markets and greater
market diversity;
(iv) The Merger will diversify the service territory of the
Combined System, reducing exposure to local changes in economic and
competitive conditions; and
(v) The Merger will enhance the profitability of the Combined
Company through increased scale.
Applicants estimate the net non-fuel savings from the Merger to be nearly
$2 billion and the net fuel-related savings to be approximately $98 million over
the first ten years following the Merger. The projected Merger fuel and non-fuel
savings are discussed in greater detail in Item 3.B.2 below. A copy of the
Merger Agreement is incorporated by reference and attached as Exhibit B-1.
At their Annual Meeting on May 27, 1998, holders of AEP Common Stock
overwhelmingly approved the shareholder actions necessary to effect the Merger.
The following day, holders of CSW Common Stock overwhelmingly approved the
Merger at their Annual Meeting. Various aspects of the Merger are subject to the
approval of this Commission as well as the: (i) FERC; (ii) NRC; (iii) FCC; (iv)
Louisiana Commission; (v) Oklahoma Commission; and (vi) Arkansas Commission. In
addition, the Applicants must obtain pre-Merger clearance from the DOJ 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. 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. In July 1999, Applicants filed with the DOJ
under the HSR Act. 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. Orders approving the Merger have been
received from the Arkansas Commission, the Louisiana Commission, the Oklahoma
Commission, the Kentucky Commission, and the Indiana Commission, copies of which
are filed as Exhibit D-2.2, Exhibit D-3.2, Exhibit D-4.2, Exhibit D-7.1, and
Exhibit D-8.1, respectively, and incorporated by reference. At FERC, a
procedural schedule has been adopted which directs the Administrative Law Judge
to issue an Initial Decision no later than November 24, 1999. This schedule will
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allow FERC to issue a decision no later than March 2000. To realize the benefits
of the Merger promptly, Applicants ask that the Commission review this
Application-Declaration and issue an order approving the Merger and granting
authority for the attendant transactions set forth above as expeditiously as
practicable without a hearing.
B. DESCRIPTION OF THE PARTIES TO THE MERGER
1. General Description
a. AEP
AEP, a New York corporation, has its principal executive offices at 1
Riverside Plaza, Columbus, Ohio. AEP was incorporated under the laws of the
State of New York in 1906 and reorganized in 1925. AEP is a registered public
utility holding company that owns all of the outstanding shares of common stock
of seven U.S. electric utility operating subsidiaries: APCo, CSPCo, I&M, KPCo,
KgPCo, OPCo and WPCo. Most of the operating revenues of AEP and its subsidiaries
are derived from sales of electricity. AEP also owns, either directly or
indirectly, all of the common stock of four material non-utility businesses --
AEP Resources, AEPRESCO, AEPC, and AEPES -- and all of the common stock of two
other businesses -- AEGCo and AEPSC. AEP indirectly owns 50% of the outstanding
share capital of Yorkshire Electricity.
AEP and its subsidiaries are subject to the broad regulatory provisions
of the 1935 Act administered by the Commission. Various of its subsidiaries are
also subject to regulation by the FERC under the FPA with respect to rates for
interstate sale at wholesale and transmission of electric power, accounting and
other matters and construction and operation of hydroelectric projects.
AEP's electric utility operating subsidiaries serve approximately 3
million customers in Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia and
West Virginia. The generating and transmission facilities of these subsidiaries
are physically interconnected, and their operations are coordinated, as a single
integrated electric utility system. Transmission networks are interconnected
with extensive distribution facilities in the territories served.
At December 31, 1997, the U.S. subsidiaries of AEP had a total of 17,844
employees. AEP, as such, has no employees. The electric utility operating
subsidiaries of AEP are each described below:
APCo (organized in Virginia in 1926) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 877,000 customers in the southwestern portion of Virginia
and southern West Virginia, and in supplying electric power at wholesale
to other electric utility companies and municipalities in those states
and in Tennessee. At December 31, 1997, APCo had 3,877 employees. Among
the principal industries served by APCo are coal mining, primary metals,
chemicals and textile mill products. A comparatively small part of the
properties and business of APCo is located in the northeastern end of
Tennessee. APCo's retail rates and certain other matters are subject to
regulation by the West Virginia Commission and the State Corporation
Commission of Virginia.
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CSPCo (organized in Ohio in 1937, the earliest direct predecessor
company having been organized in 1883) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 621,000 customers in central and southern Ohio, and in
supplying electric power at wholesale to other electric utilities and to
municipally owned distribution systems within its service area. At
December 31, 1997, CSPCo had 1,802 employees. Among the principal
industries served by CSPCo are food processing, chemicals, primary
metals, electronic machinery and paper products. CSPCo's retail rates and
certain other matters are subject to regulation by the Ohio Commission.
I&M (organized in Indiana in 1925) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 549,000 customers in northern and eastern Indiana and
southwestern Michigan, and in supplying electric power at wholesale to
other electric utility companies, rural electric cooperatives and
municipalities. At December 31, 1997, I&M had 3,306 employees. Among the
principal industries served by I&M are primary metals, transportation
equipment, electrical and electronic machinery, fabricated metal
products, rubber and miscellaneous plastic products and chemicals and
allied products. I&M's retail rates and certain other matters are subject
to regulation by the Indiana Commission and the Michigan Public Service
Commission. I&M also is subject to regulation by the NRC under the Atomic
Energy Act with respect to the operation of its nuclear generation plant.
KPCo (organized in Kentucky in 1919) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 168,000 customers in eastern Kentucky, and in supplying
electric power at wholesale to other utilities and municipalities in
Kentucky. At December 31, 1997, KPCo had 731 employees. The principal
industries served by KPCo include coal mining, petroleum refining,
primary metals and chemicals. KPCo's retail rates and certain other
matters are subject to regulation by the Kentucky Commission.
KgPCo (organized in Virginia in 1917) provides electric service to
approximately 43,000 customers in Kingsport and eight neighboring
communities in northeastern Tennessee. KgPCo has no generating facilities
of its own. It purchases electric power distributed to its customers from
APCo. At December 31, 1997, KgPCo had 85 employees. The principal
industries served by KgPCo include chemicals and allied products, paper
products, stone, clay, glass and concrete products, textiles and printing
products. KgPCo's retail rates and certain other matters are subject to
regulation by the Tennessee Regulatory Authority.
OPCo (organized in Ohio in 1907 and reincorporated in 1924) is
engaged in the generation, sale, purchase, transmission and distribution
of electric power to approximately 679,000 customers in the northwestern,
east central, eastern and southern sections of Ohio, and in supplying
electric power at wholesale to other electric utility companies and
municipalities. At December 31, 1997, OPCo and its wholly owned
subsidiaries had 4,376 employees. Among the principal industries served
by OPCo are primary metals, rubber and plastic products, stone, clay,
glass and concrete products,
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petroleum refining and chemicals. OPCo's retail rates and certain other
matters are subject to regulation by the Ohio Commission.
WPCo (organized in West Virginia in 1883 and reincorporated in
1911) provides electric service to approximately 42,000 customers in
northern West Virginia. WPCo has no generating facilities of its own. It
purchases electric power distributed to its customers from OPCo. At
December 31, 1997, WPCo had 94 employees. The principal industries served
by WPCo include chemicals, coal mining and primary metal products. WPCo's
retail rates and certain other matters are subject to regulation by the
West Virginia Commission.
AEGCo was organized in Ohio in 1982 as an electric generating company.
AEGCo sells power at wholesale to I&M, KPCo and Virginia Electric and Power
Company, an unaffiliated public utility. AEGCo has no employees.
AEPSC provides, at cost, accounting, administrative, information systems,
engineering, financial, legal, maintenance and other services to the AEP
companies. The executive officers of AEP and its public utility subsidiaries are
all employees of AEPSC.
AEP, primarily through AEP Resources, AEPRESCO, AEPC, and AEPES, pursues
new non-utility business opportunities, particularly those which allow use of
its expertise. These subsidiaries are described below:
AEP Resources' primary business is development of, and investment
in, EWGs, FUCOs, 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 2.1 million customers in
its authorized service territory which is comprised of 3,860 square miles
and located centrally on the east coast of England.
AEP Resources' indirect subsidiary, AEP Pushan Power, LDC, has a
70% interest in Nanyang Electric, a joint venture organized to develop
and build two 125 MW coal-fired generating units near Nanyang City in the
Henan Province of The Peoples' Republic of China. Funding for the
construction of the generating units has commenced and will continue
through completion thereof, which is expected to occur sometime before
the end of 1999.
A subsidiary of AEP Resources also has an equity interest, which,
subject to certain conditions, could reach 20%, in Pacific Hydro Limited,
an Australian company that develops and operates hydroelectric
facilities.
In December 1998, AEP Resources, through wholly-owned
subsidiaries, acquired CitiPower Pty., an electric distribution and
retail sales company in Victoria, Australia. CitiPower Pty. serves
approximately 240,000 customers in a service area that covers
approximately 100 square miles in the city of Melbourne.
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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 $1,645,000,000 at June 30, 1998) for
investment in EWGs and FUCOs through AEP Resources. American Elec. Power
Co., HCAR No. 26864 (Apr. 27, 1998).
AEPRESCO offers engineering, construction, project management and
other consulting services for projects involving transmission,
distribution or generation of electric power both domestically and
internationally.
AEPC, an "exempt telecommunications company" under the 1935 Act,
was formed in 1997 to pursue opportunities in the telecommunications
field. AEPC operates a fiber optic line that runs through Kentucky, Ohio,
Virginia and West Virginia. This fiber optic line is capable of providing
high speed telecommunications capacity to other telecommunications
companies. In addition to establishing and providing fiber optic
services, AEPC also made investments in two companies engaged in
providing digital personal communications services, the West Virginia PCS
Alliance, LLC and the Virginia PCS Alliance, LLC.
AEPES is authorized to engage in energy-related activities,
including marketing electricity, gas and other energy commodities. 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 August 31, 1998, there were 190,915,648 shares of
AEP Common Stock outstanding. All shares of the common stock of APCo, CSPCo,
I&M, KPCo, KgPCo, OPCo and WPCo are held by AEP.
APCo has four series of cumulative preferred stock issued and
outstanding, one of which is listed on a public securities exchange. As of June
30, 1998, there were 194,902 shares of its 4-1/2% Cumulative Preferred Stock
outstanding (listed on the Philadelphia Stock Exchange); 77,100 shares of its
5.90% Series Cumulative Preferred Stock outstanding; 61,500 shares of its 5.92%
Cumulative Preferred Stock outstanding; and 84,500 shares of its 6.85%
Cumulative Preferred Stock outstanding.
CSPCo has one series of cumulative preferred stock outstanding that is
not listed on a public securities exchange. As of June 30, 1998, there were
250,000 shares of its 7% Cumulative Preferred Stock outstanding.
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I&M has seven series of cumulative preferred stock outstanding, none of
which is listed on any public securities exchange. As of June 30, 1998, there
were 59,767 shares of its 4-1/8% Cumulative Preferred Stock outstanding; 14,912
shares of its 4.56% Cumulative Preferred Stock outstanding; 19,131 shares of its
4.12% Cumulative Preferred Stock outstanding; 167,000 shares of its 5.90%
Cumulative Preferred Stock outstanding; 202,500 shares of its 6-1/4% Cumulative
Preferred Stock outstanding; 182,500 shares of its 6-7/8% Cumulative Preferred
Stock outstanding; and 132,450 shares of its 6.30% Cumulative Preferred Stock
outstanding.
OPCo has seven series of cumulative preferred stock outstanding, none of
which is listed on a public securities exchange. As of June 30, 1998, there were
15,393 shares of its 4.08% Cumulative Preferred Stock outstanding; 103,821
shares of its 4-1/2% Cumulative Preferred Stock outstanding; 23,100 shares of
its 4.20% Cumulative Preferred Stock outstanding; 32,474 shares of its 4.40%
Cumulative Preferred Stock outstanding; 82,500 shares of its 5.90% Cumulative
Preferred Stock outstanding; 31,000 shares of its 6.02% Cumulative Preferred
Stock outstanding; and 5,000 shares of its 6.35% Cumulative Preferred Stock
outstanding.
AEP's consolidated operating revenues for the twelve months ended June
30, 1998, after eliminating intercompany transactions, were $8,195,575,000.
Consolidated assets of AEP and its subsidiaries as of June 30, 1998, were
approximately $17.8 billion, consisting of $11.6 billion in net electric utility
property, plant and equipment and $6.2 billion in other corporate assets. More
detailed information concerning AEP and its subsidiaries is contained in AEP's
Annual Report on Form 10-K for the year ended December 31, 1998, and the
Quarterly Report on Form 10-Q for the quarter ended March 31, 1999, each of
which is attached and incorporated by reference as Exhibits G-15 and G-16,
respectively.
b. CSW
CSW, incorporated under the laws of Delaware in 1925, has its principal
executive offices at 1616 Woodall Rodgers Freeway, Dallas, Texas. CSW is a
public utility holding company registered under the 1935 Act that owns all of
the common stock of four U.S. electric utility operating subsidiaries: CPL, PSO,
SWEPCO, and WTU. CSW also owns all of the common stock of CSWS, CSW Energy, CSW
International, C3 Communications, EnerShop, CSW Energy Services, and CSW Credit,
and indirectly owns all of the outstanding share capital of SEEBOARD. In
addition, CSW owns 80% of the outstanding shares of common stock of CSW Leasing.
CSW's electric utility subsidiaries are public utility companies engaged
in generating, purchasing, transmitting, distributing and selling electricity.
CSW's U.S. electric utility operating subsidiaries serve approximately 1.7
million customers in portions of Texas, Oklahoma, Louisiana and Arkansas. These
companies serve a mix of residential, commercial and diversified industrial
customers.
CSW and its subsidiaries are subject to the broad regulatory provisions
of the 1935 Act administered by the Commission. Various of the subsidiaries are
also subject to regulation by the FERC under the FPA with respect to rates for
interstate sale at wholesale and transmission of electric power, accounting and
other matters and construction and operation of hydroelectric projects.
18
<PAGE> 19
At December 31, 1997, the U.S. subsidiaries of CSW had 7,254 employees.
CSW, as such, has no employees. The electric utility operating subsidiaries of
CSW are described below:
CPL (organized in Texas in 1945) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 628,000 customers in portions of south Texas, and in
supplying electric power at wholesale to other electric utility companies
and municipalities. At December 31, 1997, CPL had 1,668 employees. The
principal industries served by CPL include manufacturing, mining,
agricultural, transportation and public utilities sectors. The Texas
Commission has original jurisdiction over retail rates in the
unincorporated areas and appellate jurisdiction over retail rates in the
incorporated areas served by CPL. CPL is also subject to regulation by
the NRC under the Atomic Energy Act with respect to the operation of its
ownership interest in a nuclear generating plant.
PSO (organized in Oklahoma in 1913) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 481,000 customers in portions of eastern and southwestern
Oklahoma, and in supplying electric power at wholesale to other electric
utility companies and municipalities. At December 31, 1997, PSO had 1,273
employees. The principal industries served by PSO include natural gas and
oil production, oil refining, steel processing, aircraft maintenance,
paper manufacturing and timber products, glass, chemicals, cement,
plastics, aerospace, telecommunications and rubber goods. PSO is subject
to the jurisdiction of the Oklahoma Commission with respect to retail
rates.
SWEPCO (organized in Delaware in 1912) is engaged in the
generation, sale, purchase, transmission and distribution of electric
power to approximately 416,000 customers in portions of northeastern
Texas, northwestern Louisiana and western Arkansas, and in supplying
electric power at wholesale to other electric utility companies and
municipalities. At December 31, 1997, SWEPCO had 1,529 employees. The
principal industries served by SWEPCO include mining, manufacturing,
chemical products, petroleum products, agriculture and tourism. SWEPCO is
subject to the jurisdiction of the Arkansas Commission and the Louisiana
Commission with respect to retail rates, as well as the Texas Commission
as set forth in the description of the regulation of CPL above.
WTU (organized in Texas in 1927) is engaged in the generation,
sale, purchase, transmission and distribution of electric power to
approximately 187,000 customers in portions of central west Texas, and in
supplying electric power at wholesale to other electric utility companies
and municipalities. At December 31, 1997, WTU had 907 employees. WTU
serves manufacturing and processing plants producing cotton seed
products, oil products, electronic equipment, precision and consumer
metal products, meat products, gypsum products and carbon fiber products.
The territory also has several military installations and state
correctional institutions. WTU is subject to the jurisdiction of the
Texas Commission as set forth in the description of the regulation of CPL
above.
CSWS performs, at cost, various accounting, engineering, tax, legal,
financial, electronic data processing, centralized economic dispatching of
electric power and other services for the
19
<PAGE> 20
CSW companies, primarily for CSW's U.S. electric utility subsidiaries. After the
Merger, services performed by CSWS will be performed by AEPSC.
CSW's material non-utility businesses are conducted through CSW Energy,
CSW International, CSW Energy Services, C3 Communications, CSW Credit, EnerShop
and CSW Leasing. These subsidiaries are described below:
CSW Energy develops, owns and operates independent power
production and cogeneration facilities within the U.S. Currently, CSW
Energy has ownership interests in seven projects, six in operation and
one in development.
CSW International engages in international activities, including
developing, acquiring, financing and owning EWGs and FUCOs, either alone
or with local or other partners. CSW International indirectly owns all of
the outstanding share capital of SEEBOARD. CSW acquired indirect control
of SEEBOARD in April 1996. SEEBOARD's principal regulated businesses are
the distribution and supply of electricity. SEEBOARD is engaged in other
businesses, including gas supply, electricity generation and electrical
contracting. SEEBOARD's service area covers approximately 3,000 square
miles in southeast England. The service area extends from the outlying
areas of London to the English Channel.
CSW received approval from the Commission under the 1935 Act to
issue and sell securities in an amount up to 100% of its consolidated
retained earnings (approximately $1,781,000,000 at June 30, 1998) for
investment in EWGs and FUCOs through CSW Energy and CSW International.
Central and South West Corp., et al., HCAR No. 26653 (January 24, 1997).
CSW Energy Services was formed to compete in restructured electric
utility markets and serves as an energy service provider to wholesale and
retail customers. It also engages in the business of marketing, selling,
and leasing to certain consumers throughout the United States certain
electric vehicles and retrofit kits subject to limitations imposed by the
Commission.
C3 Communications has two main lines of business. C3
Communications' Utility Automation Division specializes in providing
automated meter reading and related services to investor-owned municipal
and cooperative electric utilities. C3 Communications also offers systems
to aggregate meter data from a variety of technologies and vendor
products that span multiple communication mode infrastructures including
broadband, wireless network, power line carrier and telephony-based
systems. C3 Communications is an "exempt telecommunications company"
under the 1935 Act.
CSW Credit was originally formed to purchase, without recourse,
accounts receivable from the CSW electric utility subsidiaries to reduce
working capital requirements. Because CSW Credit's capital structure is
more highly leveraged than that of the CSW electric utility subsidiaries
and due to CSW Credit's higher short-term debt ratings, CSW's overall
cost of capital is lower. Subsequent to its formation, under the 1935
Act, CSW Credit's business has expanded to include the purchase, without
recourse,
20
<PAGE> 21
of accounts receivable from certain non-affiliated parties subject to
limitations imposed by the Commission.
EnerShop, an energy-related company under Rule 58, provides energy
services to commercial, industrial, institutional and governmental
customers in Texas. These services help reduce a customer's operating
costs through increased energy efficiencies and improved equipment
operations. EnerShop utilizes the skills of local trade allies in
offering services that include facility analysis; project management;
engineering design; equipment procurement; and construction and
performance monitoring.
CSW Leasing, approved by the Commission in 1985, is a joint
venture with CIT Group/Capital Equipment Financing. It was formed to
invest in leveraged leases.
CSW Common Stock is listed on the New York Stock Exchange, Inc., and the
Chicago Stock Exchange, Inc., under the trading symbol, "CSR." As of August 31,
1998, there were 212,461,876 shares of CSW Common Stock issued and outstanding.
All shares of the common stock of CPL, PSO, SWEPCO and WTU are held by CSW.
CPL has five series of cumulative preferred stock issued and outstanding.
As of June 30, 1998, there were 42,048 shares of 4.00% Series Cumulative
Preferred Stock outstanding; 17,476 shares of 4.20% Series Cumulative Preferred
Stock outstanding; 750,000 shares of Auction Money Market Cumulative Preferred
Stock outstanding; 425,000 shares of Auction Series A Cumulative Preferred Stock
outstanding; and 425,000 shares of Auction Series B Cumulative Preferred Stock
outstanding. CPL has one series of 8.00% Cumulative Quarterly Income Preferred
Securities issued and outstanding, which are listed on the NYSE. As of June 30,
1998, the principal amount of $150,000,000 of such trust preferred securities
was outstanding.
PSO has two series of cumulative preferred stock issued and outstanding.
As of June 30, 1998, there were 44,640 shares of 4.00% Series Cumulative
Preferred Stock outstanding and 8,069 shares of 4.24% Series Cumulative
Preferred Stock outstanding. PSO has one series of 8.00% Trust Originated
Preferred Securities issued and outstanding, which are listed on the NYSE. As of
June 30, 1998, the principal amount of $75,000,000 of such trust preferred
securities was outstanding.
SWEPCO has three series of cumulative preferred stock issued and
outstanding. As of June 30, 1998, there were 37,739 shares of 5.00% Series
Cumulative Preferred Stock outstanding; 1,908 shares of 4.65% Series Cumulative
Preferred Stock outstanding; and 7,386 shares of 4.28% Series Cumulative
Preferred Stock outstanding. SWEPCO has one series of 7.875% Trust Preferred
Securities issued and outstanding, which are listed on the NYSE. As of June 30,
1998, the principal amount of $110,000,000 of such trust preferred stock was
outstanding.
WTU has one series of cumulative preferred stock issued and outstanding.
As of June 30, 1998, there were 23,675 shares of 4.40% Series Cumulative
Preferred Stock outstanding.
CSW's consolidated operating revenues for the twelve months ended June
30, 1998, after eliminating intercompany transactions, were approximately $5.4
billion. Consolidated assets of CSW and its subsidiaries as of June 30, 1998
were approximately $13.8 billion, consisting of
21
<PAGE> 22
$8.4 billion in net electric utility property, plant and equipment and $5.4
billion in other corporate assets. More detailed information concerning CSW and
its subsidiaries is contained in CSW's Annual Report on Form 10-K for the year
ended December 31, 1998 and the Quarterly Report on Form 10-Q for the quarter
ended March 31, 1999, each of which is attached and incorporated by reference as
Exhibits G-17 and G-18, respectively.
c. Merger Sub
Merger Sub, a transitory subsidiary of AEP, was incorporated under the
laws of the State of Delaware, solely for the purpose of effecting the Merger.
Merger Sub has no operations other than those contemplated by the Merger
Agreement. AEP will own all the outstanding common stock, $0.01 par value per
share, of Merger Sub. A copy of the Certificate of Incorporation and By-laws of
Merger Sub are incorporated by reference and attached as Exhibits A-3 and A-4,
respectively. The principal executive office of Merger Sub will be located at 1
Riverside Plaza, Columbus, Ohio.
2. Description of Energy Sales and Facilities
a. AEP
(i) Energy Sales
KwH of Electric Energy Sold (in millions)
Company Twelve Months Ended December 31, 1997
APCo 46,658
CSPCo 22,601
I&M 34,546
KPCo 12,408
KgPCo 1,774
OPCo 55,875
WPCo 1,795
AEP Total 145,423(a)
(a) Total after the elimination of intercompany transactions.
(ii) Electric Generating Facilities
At December 31, 1997, subsidiaries of AEP owned (or leased where
indicated) generating plants with the net power capabilities (winter rating)
shown in the following table:
<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)
</TABLE>
22
<PAGE> 23
<TABLE>
<S> <C> <C>
APCo:
Steam--Coal-Fired:
John E. Amos, Units 1 & 2 St. Albans, West Virginia 1,600
John E. Amos, Unit 3 (APCo share) St. Albans, West Virginia 433(b)
Clinch River Carbo, Virginia 705
Glen Lyn Glen Lyn, Virginia 335
Kanawha River Glasgow, West Virginia 400
Mountaineer New Haven, West Virginia 1,300
Philip Sporn, Units 1 & 3 New Haven, West Virginia 308
Hydroelectric--Conventional:
Buck Ivanhoe, Virginia 10
Byllesby Byllesby, Virginia 20
Claytor Radford, Virginia 76
Leesville Leesville, Virginia 40
London Montgomery, West Virginia 16
Marmet Marmet, West Virginia 16
Niagara Roanoke, Virginia 3
Reusens Lynchburg, Virginia 12
Winfield Winfield, West Virginia 19
Hydroelectric--Pumped Storage:
Smith Mountain Penhook, Virginia 565
5,858
CSPCo:
Steam--Coal-Fired:
Beckjord, Unit 6 New Richmond, Ohio 53(c)
Conesville, Units 1-3, 5 & 6 Coshocton, Ohio 1,165
Conesville, Unit 4 Coshocton, Ohio 339(c)
Picway, Unit 5 Columbus, Ohio 100
Stuart, Units 1-4 Aberdeen, Ohio 608(c)
Zimmer Moscow, Ohio 330(c)
2,595
I&M:
Steam--Coal-Fired:
Rockport Plant (I&M share) Rockport, Indiana 1,300(a)
Tanners Creek Lawrenceburg, Indiana 995
Steam--Nuclear:
Donald C. Cook Bridgman, Michigan 2,110
Gas Turbine:
Fourth Street Fort Wayne, Indiana 18(d)
Hydroelectric--Conventional:
Berrien Springs Berrien Springs, Michigan 3
Buchanan Buchanan, Michigan 2
Constantine Constantine, Michigan 1
Elkhart Elkhart, Indiana 1
</TABLE>
23
<PAGE> 24
<TABLE>
<S> <C> <C>
Mottville Mottville, Michigan 1
Twin Branch Mishawaka, Indiana 3
4,434
KPCo:
Steam--Coal-Fired:
Big Sandy Louisa, Kentucky 1,060
OPCo:
Steam--Coal Fired:
John E. Amos, Unit 3 (OPCo share)St. Albans, West Virginia 867(b)
Cardinal, Unit 1 Brilliant, Ohio 600
General James M. Gavin Cheshire, Ohio 2,600(e)
Kammer Captina, West Virginia 630
Mitchell Captina, West Virginia 1,600
Muskingum Beverly, Ohio 1,425
Philip Sporn, Units 2, 4 & 5 New Haven, West Virginia 742
Hydroelectric--Conventional:
Racine Racine, Ohio 48
8,512
Total Generating Capability.. 23,759
SUMMARY:
Total Steam--
Coal-Fired...................................................... 20,795
Nuclear......................................................... 2,110
Total Hydroelectric--
Conventional.................................................... 271
Pumped Storage.................................................. 565
Other........................................................... 18
Total Generating Capability 23,759
</TABLE>
(a) Unit 1 of the Rockport Plant is owned one-half by AEGCo and one-half by
I&M. Unit 2 of the Rockport Plant is leased one- half by AEGCo and
one-half by I&M. The leases terminate in 2022 unless extended.
(b) Unit 3 of the John E. Amos Plant is owned one-third by APCo and
two-thirds by OPCo.
(c) Represents CSPCo's ownership interest in generating units owned in common
with two unaffiliated public utilities, Cincinnati Gas & Electric Company
and Dayton Power and Light Company.
(d) Leased from the City of Fort Wayne, Indiana. Since 1975, I&M has leased
and operated the assets of the municipal system of the City of Fort
Wayne, Indiana under a 35-year lease with a provision for an additional
15-year extension at the election of I&M.
(e) The scrubber facilities at the Gavin Plant are leased. The lease
terminates in 2010 unless extended.
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<PAGE> 25
APCo, CSPCo, I&M, KPCo and OPCo are parties to an Interconnection
Agreement, dated July 6, 1951, as amended, defining how they share the costs and
benefits associated with the AEP System's generating plants. Sharing is based
upon each company's "member-load-ratio," which is calculated monthly on the
basis of each company's maximum peak demand in relation to the sum of the
maximum peak demands of all five companies during the preceding 12 months. Since
1995, APCo, CSPCo, I&M, KPCo and OPCo have been parties to the AEP System
Interim Allowance Agreement which provides, among other things, for the transfer
of SO2 allowances associated with transactions under the Interconnection
Agreement.
The following table shows the net credits or (charges) allocated among
the parties under the Interconnection Agreement and Interim Allowance Agreement
during the years ended December 31, 1995, 1996 and 1997.
<TABLE>
<CAPTION>
1995 1996 1997(a)
---------------- -------------- ----------------
(in thousands)
<S> <C> <C> <C>
APCo....................... $(252,000) $(258,000) $(237,000)
CSPCo...................... (143,000) (145,000) (138,000)
I&M........................ 118,000 121,000 67,000
KPCo....................... 23,000 2,000 20,000
OPCo....................... 254,000 280,000 288,000
</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, 1997, the total
overhead circuit miles of transmission and distribution lines of the AEP System,
APCo, CSPCo, I&M, KPCo and OPCo and that portion of the total representing 765
Kv lines:
<TABLE>
<CAPTION>
TOTAL OVERHEAD
CIRCUIT MILES OF
TRANSMISSION AND CIRCUIT MILES OF 765
DISTRIBUTION LINES KV LINES
-------------------- ----------------------
<S> <C> <C>
AEP System................. 127,864(a)(b) 2,022
APCo....................... 49,534 641
CSPCo...................... 14,820(a) ---
I&M........................ 20,855 614
KPCo....................... 10,136 258
OPCo....................... 29,448 509
</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
25
<PAGE> 26
reliability of the interconnected electric systems in the region. ECAR members
interchange power and energy with one another on a firm, economy and emergency
basis.
As of December 31, 1997, the AEP System was interconnected through 120
high-voltage transmission interconnections with 26 neighboring electric utility
systems. The all-time and 1997 one-hour peak system demands were 25,940,000 and
24,485,000 kilowatts, respectively (which included 7,314,000 and 4,400,000
kilowatts, respectively, of scheduled deliveries to unaffiliated systems which
the AEP System might, on appropriate notice, have elected not to schedule for
delivery) and occurred on June 17, 1994 and January 17, 1997, respectively. The
net dependable capacity to serve the system load on such dates, including power
available under contractual obligations, was 23,457,000 and 23,669,000
kilowatts, respectively. The all-time and 1997 one-hour internal peak demands
were 19,557,000 and 19,381,000 kilowatts, respectively, and occurred on February
5, 1996 and January 17, 1997, respectively. The net dependable capacity to serve
the system load on such dates, including power dedicated under contractual
arrangements, was 23,765,000 and 23,669,000 kilowatts, respectively.
APCo, CSPCo, I&M, KPCo and OPCo are parties to the Transmission
Equalization Agreement, dated April 1, 1984 (the "Transmission Agreement"),
which defines the method pursuant to which the parties share the costs
associated with their relative ownership of the extra-high-voltage transmission
system (which includes facilities rated 345 Kv and above) and certain facilities
operated at lower voltages (which includes facilities rated 138 Kv and above).
Like the Interconnection Agreement, sharing is based upon each company's
"member-load-ratio."
Other assets owned by AEP include electric distribution systems located
throughout its service area, and property, plant and equipment owned or leased
supporting its electric utility functions.
AEP also owns or leases other physical properties, including real
property, and other facilities necessary to conduct its operations.
(iv) Fuel Supply
The following table shows the sources of power used by the AEP System to
generate electricity:
<TABLE>
<CAPTION>
1995 1996 1997(a)
------ ------ ---------
<S> <C> <C> <C>
Coal......................... 88% 87% 92%
Nuclear...................... 11% 12% 7%
Hydroelectric and other...... 1% 1% 1%
Total.......................... 100% 100% 100%
</TABLE>
AEP's average cost of fuel per million BTUs for the calendar years ended
December 31, 1995, 1996, and 1997 was 145 cents, 140 cents and 140 cents,
respectively.
b. CSW
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<PAGE> 27
(i) Energy Sales
<TABLE>
<CAPTION>
KwH of Electric Energy Sold (in millions)
Company Twelve Months Ended December, 31, 1997
<S> <C>
CPL 21,839
PSO 15,616
SWEPCO 22,533
WTU 7,335
CSW Total 63,157(a)
</TABLE>
(a) Total after elimination of intercompany transactions.
(ii) Electric Generating Facilities
At December 31, 1997, the U.S. electric utility subsidiaries of CSW owned
(or leased where indicated) generating plants with the net power capabilities
(based on summer ambient and water conditions) shown in the following table:
<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 249
J.L. Bates Palm View (Mission), TX 182
La Palma San Benito, TX 195
Laredo Laredo, TX 176
Lon C. Hill Corpus Christi, TX 528
Neuces Bay Corpus Christi, TX 559
Victoria Victoria, TX 482
Steam--Nuclear:
STP Bay City, TX 630(b)
Steam--Coal:
Coleto Creek Fannin (Goliad), TX 632
Oklaunion Vernon, TX 53(c)
Hydroelectric--Conventional:
Eagle Pass Eagle Pass, TX 6
CT--Gas:
La Palma #7 San Benito, TX 48
4,437
CT/Steam--Gas:
Comanche Lawton, OK 273(a)
Steam--Gas:
Northeastern 1 & 2 Oologah, OK 637
</TABLE>
27
<PAGE> 28
<TABLE>
<S> <C> <C>
Riverside Jenks, OK 916
Southwest Washita, OK 475
Tulsa Tulsa, OK 415
Steam--Coal:
Northeastern 3 & 4 Oologah, OK 900
Oklaunion Vernon, TX 106(d)
CT--Gas:
Weleetka Weleetka, OK 163
Diesel--Diesel:
Diesels Oklahoma 25
3,910
SWEPCO:
Steam-Gas:
Arsenal Hill Shreveport, LA 110
Knox Lee Longview, TX 471
Lieberman Mooringsport, LA 273
Lone Star Lone Star (Avinger), TX 50
Wilkes Avinger, TX 880
Steam--Lignite:
Dolet Hills Naborton, LA 262(e)
Pirkey Hallsville, TX 580(f)
Steam--Coal:
Flint Creek Gentry, AR 264(g)
Welsh Pittsburg, TX 1,584
4,474
WTU:
Steam-Gas:
Abilene Abilene, TX 7
Fort Phantom Abilene, TX 362
Lake Pauline Quanah, TX 45
Oak Creek Blackwell, TX 85
Paint Creek Haskell, TX 237
CT-Gas:
Fort Stockton Ft. Stockton, TX 5
CT/Steam--Gas:
Rio Pecos Girvin, TX 137(a)
San Angelo San Angelo, TX 125(a)
Steam--Coal:
Oklaunion Vernon, TX 370(h)
Diesel--Diesel:
Presidio Presidio, TX 2
Vernon Vernon, TX 9
1,384
Total Generating Capability 14,205
</TABLE>
28
<PAGE> 29
SUMMARY:
<TABLE>
<S> <C>
Steam--Gas.................................................. 8,031
Steam--Nuclear.............................................. 630
Steam--Coal................................................. 3,909
Hydroelectric--Conventional................................. 6
CT--Gas..................................................... 216
CT/Steam--Gas............................................... 535
Diesel--Diesel.............................................. 36
Steam--Lignite.............................................. 842
14,205
</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)
All of the generating facilities described above are located on land
owned by CSW's U.S. electric utility subsidiaries or, in the case of jointly
owned facilities, jointly with other participants. The principal plants and
properties of CSW's electric utility subsidiaries are subject to liens of first
mortgage indentures under which CSW's electric utility subsidiaries' first
mortgage bonds are issued.
As part of Applicants' proposed mitigation plan filed with the FERC,
Applicants agreed to divest 250 MW of capacity in ERCOT and 300 MW of generation
capacity in SPP. In the proceedings before the Texas Commission, Applicants
entered into a settlement with the staff of the Texas Commission under which
they agreed to divest 1604 MW of generation capacity in ERCOT (including the 250
MW of generating capacity contained in the proposed FERC mitigation plan). The
generation units subject to divestiture include Lon Hill Units 1-4 (CPL)--546
MW; Nueces Bay Plant (CPL)--559 MW; Joslin Unit 1 (CPL)--249 MW; Frontera Plant
(CSW Energy)--250 MW; and Northeastern Generating Plant (PSO)--300 MW. The
timing of divestiture of the generation capacity located in ERCOT and SPP is
conditioned upon there being no violation of the criteria for
pooling-of-interests accounting treatment of the Merger. If it is determined
that the ERCOT divestiture can proceed immediately after the Merger closes
without jeopardizing pooling-of-interests accounting treatment for the Merger,
sale of the plants would begin no later than 90 days after the Merger closes.
Absent that determination, the divestiture
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<PAGE> 30
would occur approximately two years after the Merger closes to satisfy the
requirements to use pooling-of-interests accounting treatment. The divestiture
of generation capacity located in SPP is also conditioned upon the plant no
longer being required to meet PSO's native load demand requirements following
electric industry restructuring in Oklahoma.
In addition to the generating facilities described above, CSW has
ownership interests in nonutility electrical generating facilities. Information
concerning U.S. facilities is listed below.
Operating Facilities - United States
Capacity Capacity Ownership
Company Location Total Committed Interest Status
Brush II......... CSW Energy Colorado 68 68 47% QF
Ft. Lupton....... CSW Energy Colorado 272 272 50% QF
Mulberry......... CSW Energy Florida 120 110 50% QF
Orange Cogen..... CSW Energy Florida 103 97 50% QF
Newgulf.......... CSW Energy Texas 85 n/a 100% IPP
Sweeny........... CSW Energy Texas 330 90 50% QF
Total....... 978 637
CPL, WTU, PSO, SWEPCO, and CSWS are parties to a Restated and Amended
Operating Agreement dated as of January 1, 1997 ("CSW Operating Agreement"). The
CSW Operating Agreement requires CSW's U.S. electric utility operating
subsidiaries to maintain specified annual planning reserve margins and requires
the subsidiaries that have capacity in excess of the required margins to make
such capacity available for sale to other subsidiaries as capacity commitments.
The CSW Operating Agreement also delegates to CSWS the authority to coordinate
the acquisition, disposition, planning, design and construction of CSW's
generating units and to supervise the operation and maintenance of a central
control center. CSWS, as agent for the CSW System, schedules the energy output
of the system capability to obtain the lowest cost of energy for serving
aggregate system demand and coordinates off-system purchases and sales. The CSW
Operating Agreement has been accepted for filing and allowed to become effective
by the FERC.
(iii) Electric Transmission and Other Facilities
The following table sets forth the total circuit miles of transmission
and distribution lines of the CSW U.S. electric utility operating subsidiaries
as of December 31, 1997:
TOTAL CIRCUIT MILES TOTAL CIRCUIT MILES
OF TRANSMISSION OF DISTRIBUTION
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LINES LINES
--------------- ---------------
CPL... 4,915 28,110
PSO... 3,563 17,916
SWEPCO 3,372 14,240
WTU... 4,490 8,606
----- -----
Total. 16,340 68,872
CSW's U.S. electric utility subsidiaries' electric transmission and
distribution facilities are mostly located over or under highways, streets and
other public places or property owned by others, for which permits, grants,
easements or licenses have been obtained.
CPL and WTU are members of ERCOT, which operates in Texas. Other ERCOT
members include Texas Utilities Electric Company, Houston Lighting & Power
Company, Texas Municipal Power Agency, Texas Municipal Power Pool, Lower
Colorado River Authority, the municipal systems of San Antonio, Austin and
Brownsville, the South Texas and Medina Electric Cooperatives, and several other
interconnected systems and cooperatives. PSO and SWEPCO are members of the SPP,
which includes 18 investor-owned utilities, 11 municipalities, 11 cooperatives,
3 state and 1 federal agency as well as IPPs and power marketers operating in
the states of Arkansas, Kansas, Louisiana, Oklahoma and parts of Mississippi,
Missouri, New Mexico and Texas. ERCOT members interchange power and energy with
one another on a firm, economy and emergency basis, as do the members of the
SPP.
The highest all-time maximum coincident system demand through 1997 was
13,105 MW on July 28, 1997. The 1997 net dependable capacity to serve the system
load was 14,290 MW. Power generation at the time of the peak was 12,817 MW and
net purchases at the time of the peak were 288 MW. CPL, WTU, PSO, SWEPCO and
CSWS are parties to a Transmission Coordination Agreement dated as of January 1,
1997 ("TCA"). The TCA establishes a coordinating committee, which is charged
with the responsibility of overseeing the coordinated planning of the
transmission facilities of CSW's U.S. electric utility operating subsidiaries,
including the performance of transmission planning studies, the interaction of
such subsidiaries with ISOs and other regional bodies interested in transmission
planning and compliance with the terms of the 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.
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<PAGE> 32
(iv) Fuel Supply
The following table shows the sources of power used by the CSW System to
generate electricity:
1995 1996 1997
Natural Gas 47% 40% 38%
Coal 36% 42% 44%
Lignite 9% 10% 10%
Nuclear 8% 8% 8%
Total.. 100% 100% 100%
CSW's average cost of fuel per million BTUs for the calendar years ended
December 31, 1995, 1996, and 1997 was 158 cents, 181 cents and 183 cents,
respectively.
3. Electric Coordination
The Combined System will be physically interconnected and economically
operated as a single interconnected and coordinated system. Upon implementation
of the System Integration Agreement and the System Transmission Integration
Agreement and through the use of Central Dispatch Planning and Central Economic
Dispatch, the Combined System will have a central dispatch system capable of
scheduling the generating resources of the Combined System on an economical,
real-time basis. The Combined System will be physically interconnected through
the 250 MW Contract Path. Each aspect of the electric coordination and
interconnection of the Combined System is discussed below:
a. System Integration Agreement and System Transmission Integration
Agreement.
The System Integration Agreement provides for the coordination of
generation within the Combined System. The System Transmission Integration
Agreement provides for the coordination of transmission within the Combined
System. The agreements, each of which will take effect upon consummation of the
Merger, are described in the Testimony of J. Craig Baker and Dennis W. Bethel
before the FERC which are filed with Exhibit D-1.1 and incorporated by
reference. The agreements and their functions are summarized below.
As noted, the System Integration Agreement provides for the coordination
of generation within the Combined System. AEPSC will coordinate the planning,
operation and maintenance of generating capacity resources and the dispatch of
electricity throughout the Combined System. The coordination of generation is
accomplished through two computer software programs: Central Dispatch Planning
and Central Economic Dispatch. Central Dispatch Planning forecasts (usually on a
day-ahead basis, although sometimes several days ahead) the generation needs of
the Combined System and determines the least-cost allocation of generation
resources available within the Combined System necessary to meet the forecasted
obligations. The central dispatch
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<PAGE> 33
is based on anticipated fuel costs, load levels, wholesale power market
conditions, planned unit maintenance (which units are out of service or
operating below normal operating limits), and prevailing transmission
capabilities (including capacity reserved by third parties). During the morning
of normal working days (Monday through Friday), Central Dispatch Planning will
have scheduled hourly the following day's generation for every unit in the
Combined System (with the exception of Friday, when generation is scheduled for
Saturday, Sunday and Monday).
Central Economic Dispatch computes at regular intervals (currently every
four seconds) the most economic generation dispatch base points resulting from
current operating obligations. While Central Dispatch Planning is based on
predictive conditions, Central Economic Dispatch is a real-time function that
continuously evaluates current operating conditions, and, based on least-cost
allocations and existing transmission constraints, issues new dispatch
instructions to each generating unit within the Combined System.
Central Dispatch Planning and Central Economic Dispatch will be ready to
serve the Combined System prior to the effectiveness of the Merger, and,
accordingly, each will be available to the Combined System immediately upon
consummation of the Merger. Each will utilize the existing electronic
communication infrastructures currently in place in each of the AEP System and
the CSW System. The existing electronic communication infrastructures will feed
data to, and receive instructions from, Central Dispatch Planning and Central
Economic Dispatch via a high speed data link.
The System Transmission Integration Agreement provides for the
coordinated planning, operation and maintenance of the Combined System's
transmission facilities and the assignment among the Combined System's operating
companies of third-party transmission costs incurred to coordinate post-Merger
operations. AEPSC will coordinate the planning, operation and maintenance of
transmission facilities and capacity of the Combined System. The Combined System
will be subject to regulation by the FERC with respect to transmission and the
Combined System intends to operate in full compliance with all applicable FERC
rules and orders regarding, among other things, tariffs, billing and revenue
allocation, immediately upon the consummation of the Merger. In this regard, the
Applicants have entered into a stipulation with FERC Trial Staff resolving all
issues between them regarding the System Integration Agreement, the Transmission
Reassignment Tariff, and the System Transmission Integration Agreement. The
Stipulation with FERC Trial Staff is filed as Exhibit D-1.4 and incorporated by
reference.
b. 250 MW Contract Path
The Combined Company will transmit power from east to west over the 250
MW Contract Path. The 250 MW Contract Path's term is from June 1, 1999 to May
31, 2003, which may be renewed through the Ameren OATT. AEPSC will coordinate
the planning of the transmission capacity interconnecting the Combined System.
In order to increase its firm transmission service rights on the MOKANOK
Line, CSW's subsidiary, PSO, entered into an agreement with WR to provide firm
point-to-point transmission service for the transfer of 38 MW of power from
Ameren. The point of receipt and delivery for the 38 MW of power will be the
point of interface with Ameren and WR's and PSO's undivided interest in the
MOKANOK Line. PSO and another CSW subsidiary, SWEPCO, will transmit the
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<PAGE> 34
38 MW of power from the interface between PSO's and WR's undivided interest in
the MOKANOK Line to PSO's 345 Kv bus at its Northeastern Generating Station. PSO
will transmit the remaining 212 MW of power over its undivided interest in the
MOKANOK Line from the interconnection with Ameren on the MOKANOK Line to PSO's
345 Kv bus at its Northeastern Generating Station. In order to enable the 250 MW
Contract Path to accommodate a 250 MW firm transfer, CSW and Ameren agreed that
Ameren would upgrade Ameren's Albion Substation in order to increase available
transfer capability into Ameren from the east during the summer peak period. The
upgrade, effected by installing a 138 Kv reactor, was completed on August 1,
1998.
Applicants have committed to avoid any possible anticompetitive concerns
attributable to the Merger by agreeing to limit their reservation of firm
transmission service from east to west to 250 MW unless the FERC authorizes them
to go above this limit. See Dr. William Hieronymus' testimony filed as an
exhibit to Exhibit D-1.2 and incorporated herein by reference.
c. Additional Power Transfers
The Applicants expect that from time to time there will be opportunity to
transfer energy economically in the Combined Company from west to east. In these
circumstances, Applicants will make use of their rights to nominate secondary
points of receipt and delivery under their transmission service agreements with
WR and Ameren. PSO has the right to transfer approximately 113 MW of energy on a
non-firm basis across the MOKANOK Line. Ameren's OASIS postings indicate that
there are more than 1000 MW of transfer capability across the Ameren system from
the MOKANOK Line to the east.
In addition to the use of the 250 MW Contract Path, quantities in excess
of the 250 MW can be moved within the Combined System in any given hour by using
non-firm transmission rights. Such additional transfers would be made when
circumstances indicate that they would be economical for post-Merger system
operations after taking into consideration opportunity costs. See generally,
Testimony of J. Craig Baker, filed with Exhibit D-1.1 and incorporated herein by
reference.
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.(1) Thus, the Applicants would continue
to use the HVDC ties
- -----------------------
(1) 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 general matter, the HVDC
ties are available and are not typically constrained. In fact, CSW has the only
existing reservation on the North HVDC tie, and there are no reservations on the
East HVDC tie after the summer of 1999. 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.
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<PAGE> 35
to integrate CSW's Texas assets with its non-Texas assets in the same manner
that previously has been approved by the Commission.
d. Future Participation in an RTO
On June 3, 1999, AEP and four other utilities filed the Alliance RTO
Application, which is currently pending at FERC. 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.(2) 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,(3) FERC found that an RTO would improve efficiencies in the management of
the transmission grid (RTO NOPR mimeo at 90); would improve grid reliability
(RTO NOPR mimeo at 95); would improve market performance (RTO NOPR mimeo at 98);
and would facilitate lighter governmental regulation (RTO NOPR mimeo at 101). It
is FERC's view that all utilities should participate in a FERC-approved RTO.
- -----------------------
(2) 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.
(3) Notice of Proposed Rulemaking, Regional Transmission
Organizations, Docket No. RM99-2-000, 87 FERC Paragraph. 61,173 (May 13, 1999)
("RTO NOPR").
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<PAGE> 36
C. DESCRIPTION OF MERGER AND STATEMENT AS TO CONSIDERATION
1. Background of the Merger
AEP and CSW are seeking to merge to further their mutual strategy of
adapting to an era of historic changes in the electric utility industry. The
electric utility industry is in the process of a transformation to greater
levels of competition in the wholesale and retail energy markets. Technological
advances, consumer pressures and federal and state legislative and regulatory
initiatives are forces affecting this transformation. Efficient, low cost
suppliers of energy with a diverse customer base will be best prepared to
compete successfully in the resulting electric energy marketplace.
Historically, competition in the wholesale and retail electric energy
markets was limited. In the wholesale market, this limitation was due to various
barriers to entry, including the difficulties in obtaining transmission service
over utility systems located between potential buyers and sellers and the
possibility of regulation under the 1935 Act. Pursuant to the Energy Act,
however, Congress authorized the FERC to exempt certain wholesale power sellers
from regulation under the 1935 Act. In 1996, the FERC issued Orders 888 and 889
requiring utilities to provide non-discriminatory, open-access transmission
service upon request. These regulatory developments have resulted in an active,
competitive wholesale market for electricity. Although the retail market for
electricity currently is less developed than the wholesale market, most states
in which the electric utility operating subsidiaries of AEP and CSW provide
retail service have adopted or are actively considering legislative or
regulatory action permitting retail customers to select their electricity
supplier and obligating utilities to provide transmission and distribution
service to competitors. Because of these ongoing legislative and regulatory
activities, the managements of AEP and CSW have concluded that there will soon
be increased competition in the retail sector of the business.
Electric utility companies must adapt quickly to this evolving
competitive environment if they are to succeed in it. Many companies are
pursuing consolidation to diversify business risks and create new opportunities
for earnings growth. Assets, such as a utility's transmission network and low
cost generation, will be key factors in structuring the successful electric
utility of the future. Customers in a competitive market will choose electric
suppliers that are efficient and responsive.
For the past several years, AEP and CSW separately have been focusing
their strategic planning activities on preparing for this fundamental evolution.
AEP and CSW have now determined that a merger of the two companies is the best
way to achieve their compatible long-term goals.
2. Merger Agreement
The following is not a complete description of the Merger Agreement and
is qualified in its entirety by reference to the Merger Agreement, which is
attached and incorporated by reference as Exhibit B-l.
The Merger Agreement provides for a business combination of AEP and CSW
in which Merger Sub will be merged with and into CSW. CSW will be the surviving
corporation and will
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become a wholly-owned subsidiary of AEP. Upon the consummation of the Merger,
each issued and outstanding share of CSW Common Stock (other than the Excluded
Shares) will be exchangeable for 0.60 shares of AEP Common Stock. Based on the
price of AEP Common Stock on December 19, 1997, the transaction would be valued
at $6.6 billion. Each issued and outstanding share of AEP Common Stock will be
unchanged as a result of the Merger.
The former holders of CSW Common Stock will own approximately 40% of the
issued and outstanding AEP Common Stock after the Merger. The Merger is subject
to customary closing conditions, including the receipt of all necessary
governmental approvals, including the approval of the Commission. The Merger is
designed to qualify as a tax-free reorganization under Section 368(a) of the
Internal Revenue Code of 1986, as amended, and will be treated as a
"pooling-of-interests" for accounting purposes.
3. Reasons for the Merger
The Merger offers significant opportunities to create additional value
for shareholders, customers and employees of the Combined Company. The benefits
of the Merger include the following:
- - COST SAVINGS - The Combined Company will be more efficient than either
company standing alone. Merging will allow the companies to create efficiencies
in operations and business processes, eliminate duplicative functions, enhance
their purchasing power, and combine two workforces. The Combined Company should
realize Merger-related non-fuel savings of nearly $2 billion over the first ten
years following the Merger, net of transaction and transition costs, and net
fuel-related savings of approximately $98 million over the same period.
- - COMPETITIVE PRICES AND SERVICES - The Combined Company will use the
efficiencies arising from the Merger to compete effectively in the increasingly
competitive marketplace. Sales to industrial, large commercial and wholesale
customers are at greatest near-term exposure to increased competition; these
customers will choose among potential suppliers those best able to meet their
demands for reliable, low-cost power. The Merger will enable the Combined
Company to serve customers more efficiently and effectively.
- - FINANCIAL STRENGTH - By combining the market capitalization of the
individual companies, the Merger will result in a Combined Company with a
stronger financial base, improved position in the credit markets, and greater
market diversity.
- - GREATER DIVERSIFICATION - The combination of AEP and CSW will diversify
the Combined System's service territory, reducing exposure to adverse changes in
any sector's economic and competitive conditions. The Combined Company will
expand relationships with existing customers and develop relationships with new
customers in its service area, using its combined distribution channels to
market a portfolio of innovative energy-related products at competitive prices.
The Merger will result in a Combined Company with more diversity in fuel and
generation, which will reduce dependence upon any one sector of the energy
industry and exposure to fluctuations in certain commodity prices.
- - INCREASED SCALE - As competition intensifies within the industry, scale
will be one contributor to overall business success. Scale is important in many
areas, including utility
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operations, product development, advertising and corporate services.
Profitability of the Combined Company will be enhanced by the expanded customer
base and the synergies in all of these areas.
4. AEP Management Following the Merger
The Board of Directors of the Combined Company immediately following the
Merger will consist of 15 members and will be reconstituted to include all
then-current board members of AEP, Mr. E. R. Brooks (the current Chairman of
CSW) and four additional outside directors of CSW to be nominated by AEP. Dr. E.
L. Draper, Jr., will be the Chairman and Chief Executive Officer of the Combined
Company. The Merger Agreement also provides that, from and after its
effectiveness, the Combined Company's corporate headquarters will be located in
Columbus, Ohio.
ITEM 2. FEES, COMMISSIONS AND EXPENSES
Thousands
Filing fee for Form S-4 $1,759
Accountants' fees *
Legal fees and expenses *
Shareholder communication and
proxy solicitation expenses *
NYSE listing fee *
Exchanging, printing and
engraving stock certificates *
expenses *
Investment bankers' fees and
expenses *
Consulting fees *
Miscellaneous *
Total *
(*) To be filed by amendment.
The total fees, commissions and expenses expected to be incurred for
transaction and regulatory processing costs are estimated to be approximately
$53 million.
ITEM 3. APPLICABLE STATUTORY PROVISIONS
The following sections of the 1935 Act and the Commission's rules relate
to the Merger:
SECTION OR RULE TRANSACTIONS TO WHICH SECTION OR RULE RELATES
UNDER THE 1935 ACT
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<TABLE>
<S> <C>
6, 7, 12, 32 and 33 Issuance of AEP Common Stock; amendment
and rules existing to AEP's financing authority to allow
thereunder the 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
rules thereunder and 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 Merger of CSWS into AEPSC with AEPSC as
thereunder 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;
- - 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;
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<PAGE> 40
- - 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.
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:
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(1) such acquisition will tend towards interlocking relations or the
concentration of control of public utility companies, of a kind or
to an extent detrimental to the public interest or the interest of
investors or consumers;
(2) in case of the acquisition of securities or utility assets, the
consideration, including all fees, commissions, and other
remuneration, to whosoever paid, to be given, directly or
indirectly, in connection with such acquisition is not reasonable
or does not bear a fair relation to the sums invested in or the
earning capacity of the utility assets to be acquired or the
utility assets underlying the securities to be acquired; or
(3) such acquisition will unduly complicate the capital structure of
the holding company system of the applicant or will be detrimental
to the public interest or the interest of investors or consumers
or the proper functioning of such holding company system.
1. Section 10(b)(1)
Section 10(b)(1) of the 1935 Act requires the Commission to approve a
proposed acquisition unless it finds that the proposed acquisition will "tend
towards interlocking relations or the concentration of control of public utility
companies of a kind or to an extent detrimental to the public interest or the
interest of investors or consumers." As this Section clearly indicates, a merger
does not run afoul of Section 10(b)(1) merely because it causes interlocking
relations or a concentration of control. Rather, a merger will fail the
balancing test set forth in this Section only when the detrimental effects, if
any, from any such interlocking relations or concentration of control caused by
the merger outweigh the benefits of the merger.
a. Interlocking Relations
By its nature, any merger results in interlocking relations between
previously unrelated companies. As the Commission has previously noted: "[W]ith
any addition of a new subsidiary to a holding company system, the Acquisition
will result in certain interlocking relationships between [the two merging
entities]." Northeast Utilities, HCAR No. 25221 (Dec. 21, 1990), modified on
other grounds, HCAR No. 25273 (Mar. 15, 1991), aff'd sub nom. City of Holyoke
Gas & Elec. Dep't v. SEC, 972 F.2d 358 (D.C. Cir. 1992) (citation omitted).
[hereinafter "Northeast I"]. Such "interlocking relationships are necessary to
integrate [the two merging entities.]" Id.
The Merger Agreement provides for the Board of Directors of the Combined
Company to be composed of members drawn from the Boards of Directors of both AEP
and CSW. Specifically, the Board of Directors of the Combined Company will
consist of 15 members including the current Chairman of the Board of CSW and
four other outside directors of CSW to be nominated by AEP. This combined Board
of Directors for the Combined Company is necessary to assure the effective
integration and operation of the Combined Company. As discussed below in Item
3.B.2, the Merger will result in benefits to the public interest and the
interests of investors and consumers. As such, the interlocking relations do not
harm, but rather, promote the interests which Section 10(b)(1) is meant to
protect.
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b. Concentration of Control
Under the Section 10(b)(1) concentration of control test, the Commission
"considers various factors, including the size of the resulting system and the
competitive effects of the acquisition." Entergy Corp., HCAR No. 25952 (Dec. 17,
1993), request for reconsideration denied, HCAR No. 26037 (Apr. 28, 1994),
remanded sub nom. Cajun Elec. Power Coop. Inc. v. SEC, 1994 WL 704047 (D.C. Cir.
Nov. 16, 1994) (citations omitted). [hereinafter "Entergy"]. These factors are
discussed below.
(i) Size
As the terms of Section 10(b)(1) dictate and as the Commission has
recognized, Section 10(b)(1) does not "impose any precise limits on holding
company growth." AEP, supra. Congress condemned the "growth and extension of
holding companies [that] bears no relation to economy of management and
operation or the integration and coordination of related operating properties."
Section 1(b)(4) of the 1935 Act. The Commission has rejected a mechanical size
analysis under Section 10(b)(1) in favor of assessing the size of the resulting
system as it relates to the efficiencies and economies that can be achieved
through the integration and coordination of the new system's utility operations.
Entergy, supra (rejecting "conclusory assertions that the combined systems would
be too large to satisfy [Section 10(b)(1)]" and finding that merger created a
"large system, but not one that exceeds the economies of scale of current
electrical generation and transmission technology.") Section 10(b)(1) allows the
Commission to "exercise its best judgment as to the maximum size of a holding
company in a particular area, considering the state of the art and the area or
region affected." AEP, supra. Other recent transactions confirm that the
Commission evaluates the resulting size of a merging entity in terms of the
overall effects of the merger. For example, in Centerior Energy Corp., HCAR No.
24073 (Apr. 29, 1986) [hereinafter "Centerior"], the Commission stated that a
"determination of whether to prohibit enlargement of a system by acquisition is
to be made on the basis of all the circumstances, not on the basis of size
alone." See also, Northeast I, supra (applying standard articulated in
Centerior, supra, to find acquisition satisfied Section 10(b)(1)). Likewise, the
Division recommended in its 1995 Report that the Commission approach its
analysis of merger and acquisition transactions in a flexible manner with an
emphasis on whether the transaction creates an entity subject to effective
regulation and results in economies and efficiencies as opposed to focusing on
rigid, mechanical tests. 1995 Report at 66-70.
In short, size alone is not suspect. Rather, as the 1935 Act provides,
the concern is an enlargement of the system that is "of a kind or to an extent
detrimental to the public interest or the interest of investors or consumers"
caused "by the growth and extension of holding companies [that] bears no
relation to economy of management and operation or the integration and
coordination of related operating properties." Sections 10(b)(1) and 1(b)(4) of
the 1935 Act.
For purposes of comparison, the table below provides certain operating
information derived from publicly available documents for a selected group of
public utility systems. Each public utility system, with the exception of CSW,
consistently ranks at or near the top of virtually all categories presented.
These data identify and rank the largest public utility systems in the United
States. Among the utilities presented, AEP currently ranges from the second to
the fifth largest public utility system in the United States depending on the
criterion of measurement.
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<PAGE> 43
Giving effect to the Merger as of December 31, 1997, on a pro forma basis, the
Combined Company would have ranged from the largest to the fourth largest public
utility system in the United States, again depending on the criterion of
measurement.
(As of December 31, 1997)
<TABLE>
<CAPTION>
U.S.
Operating Electric
Revenues Total Assets Customers
System ($Millions) ($Millions) ($Millions)
<S> <C> <C> <C>
Duke 16,309 24,020 2.0
Southern 12,611 35,271 3.7
Entergy 9,562 27,001 2.5
PG&E 15,400 30,557 4.5
CSW 5,268 13,451 1.7
AEP 6,161 16,615 3.0
Combined
Company 11,352(a) 30,066 4.7
<CAPTION>
U.S.
U.S. Sales in Market Generating
KwH Capitalization Capacity
System (Billions) ($Millions)(b) (MW)
<S> <C> <C> <C>
Duke 77.5 19,924 17,246
Southern 156.5 17,942 31,146
Entergy 106.8 7,361 21,727
PG&E 79.4 12,661 13,583
CSW 63.2 5,743 14,205
AEP 145.4 9,808 23,759
Combined
Company 208.6 16,381(c) 37,964
</TABLE>
(a) Gives effect to certain reclassifications expected to be adopted by the
Combined Company upon completion of the Merger.
(b) Based on number of shares outstanding multiplied by the closing stock
price at December 31, 1997.
(c) Gives effect to the conversion of CSW Common Stock to AEP Common Stock
following the Merger at the Exchange Ratio.
The table above does not reflect Applicants' agreement, as part of the
Texas settlement, to divest 1604 MW of generation capacity in ERCOT and, as part
of Applicants' FERC mitigation plan, to divest 300 MW of generation capacity in
SPP. Even without taking into account these divestitures of generation capacity,
the data show that, as of December 31, 1997, Southern and PG&E would have been
larger than the Combined Company in total assets; Duke, Southern, and PG&E would
have been larger than the Combined Company in terms of operating revenues; and
Duke and Southern would have been larger than the Combined Company in total
market capitalization. Thus, the data show that the Combined Company will be
comparable in size to other large public utility systems.
Moreover, the size of the Combined Company would not cause a
concentration of control within the relevant region under existing Commission
precedent. In Northeast I, supra, the Commission approved a merger in which the
combined system would have 29% of the peak load capacity, 36.7% of the total
assets and less than one-third of the operating revenues, number of 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").
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<PAGE> 44
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').(4) See Entergy, supra (Commission adopted the applicants'
definition of the relevant region for purposes of measuring size to include
applicants and those electric utilities directly interconnected with either or
both). As the table below indicates, the size of the Combined Company compared
to the size of the Interconnected Utilities and the Combined Company varies from
10 percent to 16 percent depending on the criterion of measurement. Further, if
data from the Applicants' historical wholesale customers are added to these
Interconnected Utilities data (the sum equaling the relevant destination markets
for purposes of measuring market power as described in the testimony of Dr.
Hieronymus before the FERC, attached as exhibits to Exhibits D-1.1 and D-1.2 and
summarized in Item 3.A.1.b.(ii)., 'Antitrust Considerations', infra), then the
size of the Combined Company as a percentage of the destination markets
identified by Dr. Hieronymus is even smaller.
<TABLE>
<CAPTION>
Net Electric Utility Electric Number of Total Net
Plant Revenues Electric Generation
($Thousands) ($Thousands) Customers MwH Sales (MwH)
<S> <C> <C> <C> <C> <C>
Interconnected Utilities $169,463,307 $ 69,737,780 28,075,111(a) 1,224,545,371 1,092,704,814
Combined Company $ 18,512,582$ 9,097,234 4,614,541 194,998,011 199,222,365
Total $187,975,889 $78,835,014 32,689,652 1,419,534,382 1,291,927,179
% of Total represented
by Combined Company 10% 12% 15% 14% 16%
</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
- -------------------------
(4) Interconnected Utilities include Brownsville Public Utilities Board,
Carolina Power & Light Co., Central Illinois Light Co., Central Illinois Public
Service Co., Central Louisiana Electric Co. Inc., Cincinnati Gas & Electric,
Commonwealth Edison Co., Consumers Energy Co., Dayton Power & Light Co., Duke
Power Co., Entergy, Duquesne Light Co., Empire District Electric Co., Grand
River Dam Authority, Houston Light & Power Co., Illinois Power Co., Indianapolis
Power & Light Co., Kentucky Utilities Co., Louisville Gas and Electric Co.,
Lower Colorado River Authority, Monongahela Power Co., Northern Indiana Public
Service Co., Ohio Edison Co., Ohio Valley Electric Corp., Oklahoma Gas and
Electric Co., PSI Energy Inc., San Antonio Public Service Board, Southwestern
Public Service Co., Texas Utilities Electric Co., The Cleveland Electric
Illuminating Co., The Toledo Edison Co., Union Electric Company, Virginia
Electric & Power Co., West Penn Power Co., Western Resources Inc., Southwestern
Power Administration, and Tennessee Valley Authority. Certain other
municipalities and co-ops interconnect with AEP and/or CSW; however, due to the
lack of publicly available information regarding them, their data are not
included herein.
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<PAGE> 45
distributor customers and Southwestern Power Administration has 92
customers comprised of municipalities, federal agencies and cooperatives.
Sources: Edison Electric Institute, Electrical Utility Data,
EZStat Query System (1996); EIA Publication-Financial
Statistics of Major US Investor-Owned Electric Utilities
(1996); EIA Publication Financial Statistics of Major US
Publicly-Owned Electric Utilities (1996).
Specifically, as the table above indicates, at December 31, 1996, the
Combined Company would have represented no more than the following percentages
of the utility industry in the region, in terms of the above criteria: net
electric plant (10%); electric revenues (12%); number of electric customers
(15%); MwH sales (14%); and net generation (16%). As such, the size of the
Combined Company relative to the relevant region is significantly below the 40%
threshold previously cited by the Commission. In fact, two of these percentages
would be even less if the data reflected Applicants' agreement, as part of the
Texas settlement, to divest 1604 MW of generation capacity in ERCOT and, as part
of Applicants' FERC mitigation plan, to divest 300 MW of generation capacity in
SPP.
By definition, any merger creates an entity larger than each of the
constituent parts. However, the size of the Combined Company will not exceed the
economies of scale of current electrical generation and transmission technology
and, therefore, does not exceed the maximum size of a holding company
considering the "state of the art." Technological changes have resulted in power
being transmitted over greater distances with less line loss, single integrated
computer networks that more efficiently dispatch generation sources and control
constricted transmission areas, and generation technologies that have reduced
the cost of power and increased the flexibility of power plant siting. Moreover,
changes in the regulatory and legal framework have resulted in an increase in
non-utility generators, non-utility marketers and brokers. Together, these
technological, legal and regulatory changes have resulted in increased
competition within the industry.(5) 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.(6) If the Commission determines
that an acquisition will tend towards the concentration of control of public
utility companies, it balances this effect against the benefits from the
acquisition to determine whether the acquisition passes the Section 10(b)(1)
balancing test. The Commission "has approved acquisitions that decrease
competition when it concludes
- -------------------------
(5) The "state of the art" is discussed in depth in Item 3.B.1.a below.
(6) See, e.g., Conectiv, HCAR No. 26832 (Feb. 25, 1998) [hereinafter
"Conectiv"].
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<PAGE> 46
that the acquisitions would result in benefits such as possible economies of
scale, elimination of the duplication of facilities and activities, sharing of
production capacity and reserves, and generally more efficient operations."
Northeast I, supra. The Commission has also explained that the "antitrust
ramifications of an acquisition must be considered in light of the fact that
public utilities are regulated monopolies and that federal and state
administrative agencies regulate the rates charged consumers." Id.
When assessing the possible anticompetitive effects of a proposed
acquisition, the Commission is --
primarily concerned with the structure of public utility holding company
systems. The Commission, however, has also considered anticompetitive
issues involving the allocation of excess generating capacity,
transmission access and the flow of electricity over transmission lines
of a holding company system.
Entergy, supra (citations omitted).
The FERC has jurisdiction over the Merger under Section 203 of the FPA.
It will make a finding as to whether the Merger is consistent with the public
interest based, in part, upon consideration of the anticompetitive consequences,
if any, of the proposed transaction. The Commission has relied upon the
expertise of other federal regulators in determining the anticompetitive effects
of proposed merger transactions, and the D.C. Circuit has upheld the
Commission's ability to watchfully defer to other regulators:
[W]hen the SEC and another regulatory agency both have jurisdiction over
a particular transaction, the SEC may 'watchfully defer[]' to the
proceedings held before -- and the result reached by -- that other
agency.
Madison Gas & Elec. Co. v. SEC, 168 F.3d 1337, 1341-42 (D.C. 1999), citing City
of Holyoke Gas & Elec. Dep't v. SEC, 972 F.2d 358 (D.C. Cir. 1992) (dismissing
challenge to order approving merger that asserted Commission could not rely on
FERC and state review of competitive effects) [hereinafter "Madison Gas"].
Consistent with the foregoing, the Division in its 1995 Report recommended that
"the SEC avoid duplicative review of acquisitions and, where possible, defer to
the work of other regulators in reviewing acquisitions." 1995 Report at 66. In
this case, the SEC can watchfully defer to other agencies (namely, the DOJ and
the FERC) on the question of competitive issues because consummation of the
Merger may not take place until and unless potential competitive concerns have
been addressed by these agencies under the HSR Act procedures as well as under
Section 203 of the FPA. If the Commission determines to approve the Merger
(subject to the FERC's approval of the Merger and/or the DOJ's lack of challenge
to the transaction), it can defer to these agencies even if their proceedings
are not yet complete because the Commission retains ongoing authority under
Section 20(a) of the 1935 Act to rescind or further condition its approval of a
transaction. Id.
ii(a). The Role of the DOJ
Pursuant to the HSR Act, AEP and CSW are required to file with the DOJ
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
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<PAGE> 47
proposed transaction and, where the competitive consequences appear substantial,
to permit the DOJ to challenge the legality of the transaction."(7) The HSR Act
prohibits consummation of the Merger until the statutory waiting period has
expired or been terminated. In July 1999, Applicants filed with the DOJ under
the HSR Act.
ii(b). The Role of the FERC
AEP and CSW filed a joint application with the FERC on April 30, 1998,
(see Exhibit D-1.1 filed herewith), as supplemented on January 13, 1999, (see
Exhibit D-1.2 filed herewith), pursuant to Section 203 of the FPA for approval
of the Merger. Applicants and the FERC Trial Staff entered into the FERC
Stipulation under which major issues related to the Merger were resolved,
including all significant competition and rate issues (see Exhibit D-1.3 filed
herewith).
The application, as supplemented, conformed to FERC Order No. 592 in
which the FERC adopted the DOJ/FTC Merger Guidelines as the framework for
analyzing the impact of a merger on competition in affected markets.(8) The
AEP/CSW application to the FERC contained testimony by Dr. William Hieronymus
analyzing the Merger pursuant to FERC Order No. 592. Copies of Dr. Hieronymus'
testimony are filed as exhibits to Exhibits D-1.1 and D-1.2. The analysis
presented therein measures the competitive effect of the Merger within the
relevant destination markets. Dr. Hieronymus concludes that, with the mitigation
measures which the Applicants propose as a condition of the Merger, the Merger
will not adversely affect competition in any of the destination markets that
were analyzed. Dr. Hieronymus' testimony is summarized below:
(x) Product Markets
The FERC presumes the long-term capacity market to be competitive, unless
special factors exist that limit the ability of long-term capacity markets to
develop. The evidence demonstrates that the Combined Company will not control
transmission access, fuel supplies or generation plant sites. Accordingly, the
Combined Company will not have market power in long-term capacity markets.
For the shorter term markets, the FERC applies a market screen analysis
to determine if a merger raises competitive concerns. For that purpose, the FERC
uses four product measures: 1) Total Capacity; 2) Uncommitted Capacity; 3)
Available Economic Capacity; and 4) Economic Capacity.
With respect to the Total Capacity measure, the overall size of the
market will be in excess of 340,000 MW in 1999, growing to almost 360,000 MW in
2001. The Total Capacity of the Combined System is approximately 39,000 MW (less
the 1604 MW of generating assets
- -------------------------
(7) Premerger Practice Notification Manual at xi (American Bar
Association 1991).
(8) Inquiry Concerning the Commission's Merger Policy under the Federal
Power Act: Policy Statement, Order No. 592, Docket No. RM96-6-000, Regulations
Preambles, Paragraph 31,044 at 30,109 (December 30, 1996).
47
<PAGE> 48
located in ERCOT and 300 MW of generating assets located in SPP that Applicants
have agreed to divest). Applying the screening analysis, Dr. Hieronymus
concluded that the market is unconcentrated (an HHI of less than 1000) and,
accordingly, the Merger has no anti-competitive impact with respect to Total
Capacity.
With respect to the Uncommitted Capacity measure, CSW Energy has 705 MW
of uncommitted capacity and AEP has 495 MW of uncommitted capacity. The
combination of the uncommitted capacity represents less than a 15 percent
combined market share. Dr. Hieronymus concluded that the market of Uncommitted
Capacity is unconcentrated and mergers in such markets are presumed to have no
anti-competitive impact.
With respect to the Economic Capacity measure, Dr. Hieronymus concluded
that when the Applicants' mitigation proposal is taken into account, the Merger
significantly deconcentrates the CSW SPP and ERCOT markets and results in HHI
changes below the FERC Order 592 threshold in all but a handful of destination
markets. (The exceptions involve destination markets in which the Combined
Company will have a miniscule market share because the Applicants' use of the
250 MW Contract Path will serve to increase the already high market share of one
or more incumbent sellers that are unrelated to either Applicant.)
With respect to the Available Economic Capacity measure, Dr. Hieronymus
concluded that, for the most part, CSW's SPP and ERCOT markets are
deconcentrated. The AEP market is either deconcentrated or reflects zero HHI
changes in all time periods. The HHI changes for almost all of the other
relevant destination markets and time periods are below the FERC Order No. 592
threshold or are zero or are negative (meaning that the market is
deconcentrated). The few exceptions are in destination markets in which the
Applicants have little or no post-merger market share.
With the inclusion of the 250 MW Contract Path to interconnect the
Applicants' systems, a few additional failures under the screening analysis
resulted for the Economic Capacity Measure in the SPP and ERCOT markets. As to
those markets that did not fall below the minimum benchmark, Applicants, in
their application filed with the FERC, as supplemented, proposed mitigation
measures to offset any increase in market concentration so as to reduce the HHI
to fall within safe harbor levels. AEP and CSW propose to divest ownership of
550 MW of generation capacity (300 MW in the SPP and 250 MW in the ERCOT) by
means of auction. (As part of the settlement with the staff of the Texas
Commission, Applicants have now agreed to divest 1604 MW of generating assets
located in ERCOT, which includes the 250 MW of generating assets located in
ERCOT that will be divested as part of the proposed FERC mitigation measures).
The auction process for the ERCOT and SPP generation capacity is
conditioned upon there being no violation of the pooling-of-interests accounting
treatment used for the Merger. If it is determined that the ERCOT divestiture
can proceed immediately after the Merger closes without jeopardizing
pooling-of-interests accounting treatment for the Merger, sale of the plants
would begin no later than 90 days after the Merger closes. Absent that
determination, the divestiture would occur approximately two years after the
Merger closes to satisfy the requirements to use pooling-of-interests accounting
treatment. The 300 MW of generation to be divested in SPP is also conditioned
upon the plant no longer being required to meet PSO's native
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<PAGE> 49
load demand requirements following electric industry restructuring in Oklahoma
and is no longer required to satisfy SPP reliability criteria. Until these
conditions are met, the Combined Company will sell 300 MW hours of energy per
hour in a system power sale. The divestiture process for the ERCOT capacity will
begin after the completion of the Merger, unless the Commission determines that
a sale within two years of the Merger will cause the pooling-of-interests
accounting treatment to be unavailable. The proposed sales and subsequent
divestitures are, therefore, specifically structured to meet any concerns that
the increases in market concentration in the SPP and ERCOT markets, without
correction, could have anti-competitive effects on those markets.
In interpreting the estimated market shares and HHIs, it is important to
recognize that non-firm energy markets have a number of characteristics that
make the exercise of market power, either jointly or unilaterally, extremely
unlikely. In particular, the numerous ways energy transactions can be packaged,
the diversity of the participants in an evolving and increasingly competitive
market, and the fact that buyers are also sellers at various times will make it
exceedingly difficult for the Combined Company to exercise market power through
coordinated behavior.
As a further mitigation measure, Applicants agreed to waive the Combined
Company's priority with respect to its use of the HVDC ties. As noted in Item
I.B. above, the waiver applies to unplanned (i.e., non-firm) transactions in
ERCOT and non-firm transactions in SPP.
In sum, it is clear that the Merger will have little or no effect on
competition in the relevant product markets.
(y) Vertical Markets
The Merger raises no vertical concerns. AEP and CSW are not transmission
competitors and each operates under FERC Order No. 888 OATTs. AEP and CSW have
filed a joint Order No. 888 compliance tariff applicable to the Combined System
to be made effective as of the Merger closing date. Hence, Applicants are not in
a position to favor each other in operating their transmission systems.
As part of the FERC Stipulation and settlements with the staffs of
various state commissions, AEP and CSW each have committed to join an ISO or
RTO, thus eliminating any remaining concerns regarding the transmission
facilities' impact on competition. Through the ISO or RTO, the transmission
facilities will be operated for the benefit of the system users in a competitive
and non-discriminatory manner. In this regard, on June 3, 1999, AEP joined with
four other utilities in filing the Alliance RTO Application, which is currently
pending at FERC. CSW is participating in the ERCOT independent regional
transmission plan for the portion of its system that is within ERCOT and is
participating in discussions with other interested parties about the formation
of an RTO that would include utility systems in the SPP. As part of the
settlement with the staff of the Texas Commission, Applicants agreed that they
would obtain the Texas Commission's prior approval before withdrawing from
either ERCOT or the SPP.
The Merger raises no vertical issues relating to ownership or control of
scarce generating capacity. There are a number of projects under development and
construction in Texas which
49
<PAGE> 50
will be capable of selling into ERCOT and/or the SPP, including an 800 MW
merchant plant located in Grimes County; a 350 MW merchant plant located in
Uvalde County; a 300-400 MW gas-fired cogeneration facility located at Reynolds
Metals' Sherwin alumina production plant near Corpus Christi; a 1,100 MW
gas-fired, combined cycle plant whose output will be sold to Texas Utilities for
two years; a 1,000 MW gas-fired combined cycle facility located in Edinburg,
Texas; a 700 MW merchant plant is planned for Magic Valley Electric Cooperative;
a 510 MW addition is planned for a cogeneration facility located in Pasadena,
Texas; a 500 MW gas-fired combined cycle facility located in Hidalgo County,
Texas.(9) By utilizing the Combined Company's OATT, customers within the
Combined Company's service territory will be able to access numerous suppliers
that independently have constructed substantial generating capacity in the past
and that have located both within and outside the service territory. In the
longer term, with the introduction of retail competition, it is expected that
retail customers will have access to energy service providers with different
generation sources and mixes.
In addition, Applicants submitted to the FERC testimony by J. Stephen
Henderson demonstrating that, irrespective of the existence of an ISO or RTO,
the Merger will not create any ability or incentive for the Combined Company to
(1) use AEP's transmission system to limit competition in relevant markets into
which CSW sells electricity, or (2) use CSW's transmission system to limit
competition in relevant markets into which AEP sells electricity. A copy of Mr.
Henderson's testimony is filed as an exhibit to Exhibit D-1.2 and is
incorporated by reference. AEP and CSW also presented testimony by Raymond
Maliszewski explaining, among other things, that the configuration of the AEP
System does not permit AEP to affect adversely load flows on third party systems
by departing from economic dispatch of the AEP System. A copy of Mr.
Maliszewski's testimony is filed herewith as Exhibit D-1.2.
In sum, Dr. Hieronymus' testimony demonstrates that taking into account
the Combined Company's mitigation measures, the Merger presents no competitive
problems. Thus, the Merger can be expected to obtain required approval and
clearance from the FERC. See Madison Gas & Electric (the Commission is entitled
to defer to FERC's expertise in evaluating the competitive aspects of a merger).
To the extent the Commission finds that there is any concentration of control
resulting from the Merger, Applicants believe any such concentration of control
is far outweighed by the benefits accruing to the public, investors and
consumers from the Merger, as more fully discussed in Item 3.B.2 below. Thus,
the Merger will not "tend toward . . . the concentration of control" of public
utility companies, of a kind or to an extent detrimental to the public interest
or the interests of investors or customers within the meaning of Section
10(b)(1).
2. Section 10(b)(2)
Section 10(b)(2) of the 1935 Act requires the Commission to approve the
Merger unless it finds that the consideration, including all fees, commissions
and other remuneration, is unreasonable or does not bear a fair relation to the
sums invested in, or the earning capacity of the utility assets underlying the
securities to be acquired.
- -------------------------
(9) Power Generation Markets Quarterly, First Quarter 1999.
50
<PAGE> 51
a. Reasonableness of Consideration
Section 10(b)(2) "does not demand a mathematical equivalence of values
for the terms of the exchange." Entergy, supra. Prices arrived at through arm's
length negotiations are particularly persuasive evidence that the Section
10(b)(2) requirement is met. See, e.g., Northeast I, supra, (citing Ohio Power,
HCAR No. 16753 (June 8, 1970)). Moreover, the assistance of independent
consultants in setting consideration is deemed to be evidence that the
requirement is met. See, e.g., Northeast I, supra (citing Southern Co., HCAR No.
24579 (Feb. 12, 1988)). The Commission also "independently analyze[s] the
financial and operating performances of [the combining entities]" with respect
to such factors as relative market values and dividends per share. Centerior,
supra. Finally, the Commission considers whether the shareholders have approved
the acquisition. Entergy, supra.
Under the standards applied by the Commission in previous utility
mergers, the consideration to be paid by AEP in the Merger is reasonable and
bears a fair relation to the earning capacity of the utility assets underlying
the CSW Common Stock to be acquired, in compliance with Section 10(b)(2). Based
on the Exchange Ratio set forth in the Merger Agreement, the consideration
offered by AEP will be AEP Common Stock which had a market value on December 19,
1997, the last trading day before the Merger was announced, of approximately
$6.6 billion, or approximately $31.20 per share of CSW Common Stock, which was
approximately 20% above the closing price of CSW Common Stock on December 19,
1997. Applicants' belief that the consideration is fair and reasonable is based
on the following reasons, each of which is discussed in detail below:
- Arm's length negotiations between AEP and CSW conducted in a
competitive context resulted in the proposed Exchange Ratio;
- An opinion from AEP's financial adviser, Salomon, states that the
consideration to be paid by AEP with respect to the Merger is
fair, from a financial point of view, to AEP;
- An opinion from CSW's financial adviser, Morgan Stanley, states
that the consideration to be received by CSW's shareholders with
respect to the Merger is fair, from a financial point of view, to
CSW's shareholders;
- Valuation analysis demonstrates the fairness of consideration as
evidenced by the comparative market prices of, and dividends paid
on, the AEP and CSW Common Stock;
- The Applicants' shareholders approved the shareholder actions
necessary to effect the Merger; and
- The inclusion of required closing conditions in the Merger
Agreement serves to assure that the Merger will be consummated on
terms that are fair to Applicants and their shareholders.
(i) Competitive Negotiations
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<PAGE> 52
The chief executive officers of AEP and CSW had informal discussions on
several occasions from January 1997 to March 1997 regarding a merger of the
companies. With CSW's stock price depressed in late April 1997 as a result, in
the opinion of CSW management, of adverse action by the Texas Commission, CSW
management terminated discussions with AEP.
From May through September 1997, CSW management continued to explore a
variety of strategic alternatives. As part of this analysis, CSW management, in
consultation with its advisers, developed a list of screening criteria for use
in analyzing potential merger partners. CSW also considered other strategic
alternatives which could be pursued without a business combination. At a meeting
of the CSW Board of Directors on September 27, 1997, management recommended to
the CSW Board of Directors that CSW seek a merger that could enhance CSW's
ability to implement its long-term vision. The CSW Board of Directors
unanimously authorized CSW management to pursue its search for an appropriate
merger partner while continuing to evaluate CSW's stand-alone options.
In September 1997, the chief executive officers of AEP and CSW resumed
their discussions regarding a stock-for-stock merger. During the ensuing months,
CSW's management also held preliminary discussions, and exchanged non-public
information, with three other electric utilities regarding a possible business
combination and continued to evaluate other stand-alone alternatives. CSW
management met with the CSW Board of Directors and a committee of the CSW Board
of Directors on many occasions during October-December 1997 to update the
directors and receive direction on the course of their discussions.
On November 24, 1997, CSW management and CSW's advisers met with a
committee of the CSW Board of Directors to discuss the progress of the strategic
alternative evaluation process. The committee authorized CSW management to send
to four strategic merger candidates a letter requesting each to advise CSW as to
whether, and on what terms, it was interested in pursuing a strategic
combination with CSW. On December 11, 1997, CSW received affirmative responses
to the request letters from AEP and two of the three other companies.
On December 12, 1997, CSW management and advisers met with a committee of
the CSW Board of Directors to discuss the responses and the status of the
strategic merger candidate evaluation process. After analyzing the responses and
CSW's other stand-alone alternatives, the committee determined that AEP appeared
to be the best strategic merger partner for CSW and that a merger with AEP on
the right terms would be more likely to restore and enhance long-term
stockholder value than any of the other merger or stand-alone strategic
alternatives.
Following negotiations between the chief executive officers of each
company, CSW and AEP agreed to proceed with merger negotiations on the basis of
a proposed exchange ratio of 0.60 shares of AEP Common Stock for each share of
CSW Common Stock. The Board of Directors of both companies approved the Merger
Agreement in meetings on December 21, 1997, and the Merger Agreement was signed
that afternoon.
The Exchange Ratio was agreed to by the Applicants after extensive
deliberations between the two companies involving senior management personnel
assisted by financial and legal advisers skilled in mergers and acquisitions
transactions. Moreover, the negotiations were carried out in a competitive
context with other companies.
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<PAGE> 53
For further information regarding the background of the proposed Merger
between AEP and CSW, reference is made to the Joint Proxy Statement and
Prospectus filed as Exhibit C-2 and incorporated herein by reference.
(ii) Fairness Opinions
As discussed above, the Boards of Directors of AEP and CSW approved the
Merger Agreement and the transactions contemplated thereby. Prior to such
approvals, the Boards received opinions from AEP's and CSW's respective
financial advisers as to the fairness of the proposed consideration. AEP's Board
of Directors received a written opinion from Salomon that, based upon specified
procedures and assumptions, the consideration to be paid by AEP with respect to
the proposed Merger is fair, from a financial point of view, to AEP. CSW's Board
of Directors received a written opinion from Morgan Stanley that the proposed
consideration is fair, from a financial point of view, to the shareholders of
CSW. No limitations were imposed by the AEP Board or the CSW Board upon Salomon
or Morgan Stanley, respectively, with respect to the investigations made or
procedures followed by their respective financial advisers.
In arriving at their respective opinions, Salomon and Morgan Stanley
reviewed (i) the terms of the Merger Agreement; (ii) certain publicly available
business and financial information relating to AEP and CSW; (iii) certain other
internal information concerning AEP and CSW, including financial projections
provided to them by AEP and CSW; (iv) certain publicly available information
concerning the trading of, and the trading market for AEP's and CSW's Common
Stock; (v) certain publicly available information with respect to other
companies they believed to be comparable to AEP and CSW and the trading markets
for such other companies' securities; and (vi) certain publicly available
information concerning the nature and terms of other transactions they
considered relevant to their inquiry. They also met with officers and employees
of AEP and CSW to discuss the foregoing as well as other matters relevant to the
Merger. Copies of the fairness opinions are filed as Annexes II and III to
Exhibit C-2 and are incorporated by reference.
Salomon's fairness opinion was based on eight valuation analyses relating
to, respectively, Discounted Cash Flow Analysis-CSW; Comparable Company
Analysis-CSW; Analysis of Selected Utility Company Mergers and Acquisitions;
Discounted Cash Flow Analysis-AEP; Comparable Company Analysis-AEP; Historical
Trading Ratios Analysis; Contribution Analysis; and Pro Forma Analysis of the
Merger. These analyses supported the fairness of the proposed consideration,
from a financial perspective, to be paid by AEP and are summarized below:
Discounted Cash Flow Analysis-CSW. This analysis was based on certain
operating and financial assumptions for CSW in years 1997 to 2006
provided by CSW and adjusted by the management of AEP. From this
analysis, Salomon derived a range of the implied equity value per share
of CSW Common Stock of approximately $25 to $29. In addition, Salomon
derived a per share present value of the expected Merger savings of $5.
Thus, Salomon derived a reference range for the implied value per share
of CSW Common Stock, including savings, of approximately $30 to $34.
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<PAGE> 54
Comparable Company Analysis-CSW. Salomon reviewed certain publicly
available financial, operating, and stock market information for CSW and
five other publicly-traded utility companies Salomon considered
comparable to CSW. Salomon derived the implied value of the CSW shares on
(1) a stand-alone basis ($21 to $25 per share); (2) with the Merger
savings ($26 to $30 per share); and (3) including a 30% control premium,
but no Merger savings ($27.50 to $32.50 per share).
Analysis of Selected Utility Company Mergers and Acquisitions. Salomon
reviewed a set of completed and proposed utility mergers announced since
August 1996. Salomon calculated multiples based on the offer price for
each target company to such company's respective pre-announcement market
price, book value, earnings and cash flow per share. From this analysis,
Salomon derived a reference range for the implied equity value per CSW
share of $27 to $35. Discounted Cash Flow Analysis-AEP. This analysis was
based on certain operating and financial assumptions for AEP in years
1997 to 2006 provided by AEP. From this analysis, Salomon derived a range
of the implied equity value per share of AEP Common Stock of
approximately $42 to $49. Comparable Company Analysis-AEP. Salomon
reviewed certain publicly available financial, operating, and stock
market information for AEP and five other publicly-traded utility
companies Salomon considered comparable to AEP. Salomon derived a range
of the implied equity value per share of AEP Common Stock of
approximately $44 to $52.
Historical Trading Ratios Analysis. Salomon also reviewed the daily
closing prices of CSW Common Stock and AEP Common Stock during the period
from December 15, 1992 through December 15, 1997 and the historical
trading ratios over such period. During that period the average
historical trading ratio was 0.70. The ratio on December 15, 1997 was
0.52. Contribution Analysis. Salomon reviewed the relative contributions
of each of AEP and CSW to estimated net income and other indicators of
the Combined Company for each of the years 1997 to 2006. This analysis
showed that CSW is expected to contribute a percentage of the Combined
Company's net income ranging from approximately 34% to 40% in 1997 to
2003 before leveling off at 39% in the years 2004 to 2006. CSW
stockholders would own approximately 40% of the outstanding shares of the
Company based on the Exchange Ratio.
Pro Forma Analysis of the Merger. Salomon also analyzed certain pro forma
effects resulting from the proposed combination for the years 2000
through 2006. This analysis was based on financial and operating
assumptions for AEP and CSW, as provided to Salomon by AEP, and assumed
the realization of the cost savings projected by AEP management to result
from the Merger. Based on such analysis, Salomon concluded that the
Merger would be somewhat dilutive to AEP shareholders for the years
2000-2002 and somewhat accretive for the remaining years of the forecast.
Salomon noted that the transaction would generally produce earnings per
share accretion of 10% or more each year for CSW shareholders, but would
result in a lower dividend per original CSW share of more than 10%
through 2003, the reduction continuing to decline thereafter.
(iii) Comparative market prices of and dividends paid on common
stock.
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<PAGE> 55
Market prices at which securities are traded have always been strong
indicators as to values. As shown below, most quarterly price data for CSW
Common Stock and AEP Common Stock, high and low, for the years 1996 and 1997
provide support for the calculation of the Exchange Ratio.
<TABLE>
<CAPTION>
AEP
- -------------------------------------------------------------------------------------
High Low Dividends
- -------------------------------------------------------------------------------------
1996
<S> <C> <C> <C>
1st Qtr........... 44-3/4 40-1/8 0.60
2nd Qtr........... 42-3/4 38-5/8 0.60
3rd Qtr........... 43-1/8 40 0.60
4th Qtr........... 42-1/2 39-1/2 0.60
- -------------------------------------------------------------------------------------
1997
1st Qtr........... 43-3/16 40 0.60
2nd Qtr........... 42-1/2 39-1/8 0.60
3rd Qtr........... 46-5/8 41-1/2 0.60
4th Qtr........... 52 45-1/4 0.60
- -------------------------------------------------------------------------------------
<CAPTION>
CSW
- -------------------------------------------------------------------------------------
High Low Dividends
- -------------------------------------------------------------------------------------
1996
<S> <C> <C> <C>
1st Qtr........... 28-1/2 26-3/8 0.435
2nd Qtr........... 28-7/8 26-1/2 0.435
3rd Qtr........... 28-1/2 25-3/4 0.435
4th Qtr........... 28 25-1/2 0.435
- -------------------------------------------------------------------------------------
1997
1st Qtr........... 26 20-3/4 0.435
2nd Qtr........... 22-1/4 18 0.435
3rd Qtr........... 22-9/16 19-1/2 0.435
4th Qtr........... 27-1/2 20 0.435
- -------------------------------------------------------------------------------------
</TABLE>
(iv) Shareholder Approval
In addition, the holders of AEP Common Stock and the holders of CSW
Common Stock overwhelmingly approved the shareholder actions necessary to effect
the Merger. At the Annual Meeting of Shareholders of AEP held on May 27, 1998,
holders of approximately (i) 71% of all outstanding AEP Common Stock approved an
amendment to the Restated Certificate of Incorporation of AEP increasing the
number of authorized shares of AEP Common Stock, and (ii) 72% of all outstanding
AEP Common Stock approved the issuance of the AEP Common Stock, each necessary
to effect the Merger. Holders of approximately 82% of all outstanding CSW Common
Stock approved the Merger at the Annual Meeting of Stockholders of CSW held on
May 28, 1998.
(v) Merger Agreement
Finally, the Merger Agreement contains a number of closing conditions
that help ensure the continued reasonableness of the consideration. Under
Section 8.1(g), it is a condition precedent to closing, applicable to both AEP
and CSW, that "there shall not have occurred and remain in effect a Divestiture
Event with respect to [either company]."(10) 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(11) shall have
occurred and that there shall exist no fact or
- -------------------------
(10) "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.
(11) "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
55
<PAGE> 56
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 together expect to
incur total transaction and regulatory processing costs of approximately $53
million, including financial advisory fees of approximately $31 million.
Applicants believe that these estimated fees and expenses bear a fair
relation to the value of CSW and the savings to be achieved by the Merger and
are fair and reasonable in light of the size and complexity of the Merger.
Northeast Utilities, HCAR No. 25548 (June 3, 1992), modified on other grounds,
HCAR No. 25550 (June 4, 1992) [hereinafter "Northeast II"] (Commission considers
whether fees and expenses bear a fair relation to the value of the company to be
acquired and the savings to be achieved by the acquisition). Based on the price
of AEP Common Stock on December 19, 1997, the transaction would be valued at
$6.6 billion. As discussed in Item 3.B.2 below, net nonproduction savings of
nearly $2 billion and net fuel-related savings of approximately $98 million are
projected over the first ten years after the Merger.
Moreover, the estimated overall fees are reasonable compared to the
overall fees approved by the Commission in other merger transactions. The total
fees of $53 million to be incurred by Applicants represent approximately 0.8% of
the value of consideration to be paid by AEP, based on the price of AEP Common
Stock on December 19, 1997. The Commission has approved fees, commissions and
expenses of $46.5 million in connection with the acquisition of PSNH by
Northeast, representing approximately 2% of the value of the assets to be
acquired (Northeast I; Northeast II); $47.12 million in connection with the
reorganization of Cincinnati Gas and Electric and PSI Resources as subsidiaries
of CINergy (CINergy Corp., HCAR No. 26146 (Oct. 21, 1994) [hereinafter
"CINergy"]) and $38 million in fees, commissions and expenses in connection with
Entergy's acquisition of Gulf States Utilities Company, representing
approximately 1.7% of the value of the consideration paid to Gulf States'
shareholders (Entergy, supra).
The investment banking fees of approximately $31 million to be incurred
by Applicants represent approximately 0.47% of the value of consideration to be
paid by AEP, based on the price of AEP Common Stock on December 19, 1997. These
fees incurred by Applicants resulted from a marketplace in which investment
banking firms actively compete with each other to act as financial advisers to
merger participants. The Commission has previously approved financial advisory
fees of approximately $10.6 million, representing approximately 0.46% of the
value of the assets to be acquired (Northeast I, supra and Northeast II, supra),
financial advisory fees
- --------------------------------------------------------------------------------
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."
56
<PAGE> 57
representing approximately 0.96% of the aggregate value of the acquisition,
(Southern Co., HCAR No. 24579 (Feb. 12, 1988), modified on other grounds, HCAR
No. 24579A (February 26, 1988), and Amendment No. 9 to Southern Form U-1 (April
13, 1988)), and financial advisory fees of $8.3 million, representing
approximately 0.36% of the value of the consideration paid to Gulf States'
shareholders (Entergy, supra and Amendment No. 24 to Entergy Form U-1 (Nov. 18,
1993)).
As indicated in Item 2 above, the fees and expenses which are not yet
finalized will be filed by amendment when they become available.
For all of the above reasons, the consideration and fees to be paid are
fair and reasonable in compliance with Section 10(b)(2).
3. Section 10(b)(3)
Section 10(b)(3) of the 1935 Act requires the Commission to approve a
proposed acquisition unless the acquisition would unduly complicate the capital
structure of the holding company system, or would be detrimental to the public
interest, the interest of investors or consumers or the proper functioning of
such holding company system.
a. Capital Structure
The Commission has found that an acquisition does not unduly complicate
the capital structure of the holding company system where the effect of a
proposed acquisition on the acquirer's capital structure is negligible and the
debt to equity ratio due to the acquisition is well within "the 65/30%
debt/common equity ratio generally prescribed by the Commission." Entergy, supra
(citing Northeast I). The Commission has approved common equity to total
capitalization ratios as low as 27.6%. See Northeast I, supra.
In this regard, the proposed combination of AEP and CSW will not unduly
complicate the capital structure of the Combined System. The only changes to the
capital structure of AEP will be the acquisition by AEP of CSW Common Stock and
the addition of the capital structure of CSW to AEP's capital structure. CSW and
its subsidiaries have publicly held debt and have publicly held preferred stock
or preferred trust securities, and all CSW Common Stock will be held by AEP and
incorporated within AEP's consolidated financial statements. At December 31,
1997, the respective capital structures of AEP and CSW were as follows:
<TABLE>
<CAPTION>
AEP CSW
(in $ millions) (in $ millions)
<S> <C> <C> <C> <C>
Common Stock Equity............................ $ 4,677 45.52% $ 3,556 44.27%
Preferred Stock................................ 175 1.70% 203 2.53%
Long-Term Debt................................. 5,424 52.78% 8,937 49.02%
Trust Preferred Securities..................... -0- -0- 335 4.17%
Total......................................... $10,276 100.00% $ 8,031 100.00%
</TABLE>
If the Merger had been consummated on December 31, 1997, the pro forma
consolidated capital structure of the Combined Company as of such date
(according to generally accepted
57
<PAGE> 58
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............................ $8,233 44.97%
Preferred Stock................................ 378 2.06%
Long-Term Debt................................. 9,361 51.13%
Total......................................... 335 1.83%
$18,307 100.00%
</TABLE>
(a) Includes $53 million of transactions and regulatory processing costs.
As can be seen from the above tables, the debt to equity ratio is not
altered to any considerable degree by the Merger. The Combined Company's pro
forma consolidated common equity to total capitalization ratio of 44.8% is
substantially higher than Northeast Utilities' recently approved 27.6% common
equity position and comfortably exceeds the "traditionally acceptable 30%
level." Northeast I, supra.
Finally, the common stock that AEP proposes to issue in the Merger has
the same par value, same rights (including voting rights) and preference as to
dividends and distributions as the AEP Common Stock presently outstanding. All
of the issued and outstanding CSW Common Stock will be owned by AEP as a result
of the Merger. As such, there will be no publicly held minority common stock
interest in CSW following the Merger. Thus, the Merger does not complicate the
capital structure of AEP.
b. Public Interest, Interest of Investors and Consumers, and
Proper Functioning of Holding Company System
Section 10(b)(3) also requires the Commission to determine whether the
proposed Merger will be detrimental to the public interest, the interest of
investors or consumers or the proper functioning of the Combined System.
As discussed in greater detail in Item 3.B.2 below, the Merger will
enable the Combined Company to operate more efficiently and economically than
either AEP or CSW could operate independently of the Merger. The Merger will
result in substantial, otherwise unavailable, benefits to the public and to
consumers and investors of both companies -- specifically, savings through labor
cost savings, facilities consolidation, corporate and administrative programs,
non-fuel purchasing economies, and efficiencies from the combined utility
operations. These savings will be passed on to shareholders and consumers. The
shareholders, whose interests are protected by the disclosure requirements of
the Securities Act of 1933 and the Securities and Exchange Act of 1934, have
overwhelmingly approved the shareholder actions necessary to effect the Merger.
See Southern, supra (stating that "[c]oncerns with respect to investors have
been largely addressed by developments in the federal securities laws and in the
securities markets themselves.") The interests of consumers are protected by
both state and federal regulation.
58
<PAGE> 59
Simply stated, the Merger will create an entity that will be poised to
respond effectively to the fundamental changes that have taken and will continue
to take place in the markets for electric power as such markets are being
deregulated and restructured and will create an entity prepared to compete
effectively for consumer's business. As such, consumers, investors, and the
public will be the ultimate beneficiaries of the Merger.
In sum, because the Merger does not add any complexity to AEP's capital
structure and is in the public interest and the interests of investors and
consumers, the requirements of Section 10(b)(3) are met.
B. Section 10(c)
Section 10(c) of the 1935 Act establishes additional standards for
approval of the Merger. Under Section 10(c), the Commission cannot approve:
(1) an acquisition of securities or utility assets, or of any other
interest, which is unlawful under the provisions of Section 8 or is detrimental
to the carrying out of the provisions of Section 11; or
(2) the acquisition of securities or utility assets of a public utility
or holding company unless the Commission finds that such acquisition will serve
the public interest by tending towards the economical and efficient development
of an integrated public utility system.
1. Section 10(c)(1)
Section 10(c)(1) requires that the proposed acquisition be lawful under
the provisions of Section 8 of the 1935 Act. Section 8 prohibits an acquisition
by a registered holding company of an interest in an electric and gas utility
serving substantially the same area without the express approval of the state
commission when that state's law prohibits or requires approval of the
acquisition. Because neither CSW nor AEP has any direct or indirect interest in
any gas utility company, this section is not applicable to the Merger.
Section 10(c)(1) also requires that the Merger not be detrimental to the
carrying out of the provisions of Section 11. Section 11(b)(1) generally
requires a registered holding company system to limit its operations "to a
single integrated public-utility system, and to such other businesses as are
reasonably incidental, or economically necessary or appropriate to the
operations of such integrated public-utility system." Section 11(b)(2) directs
the Commission "to ensure that the corporate structure or continued existence of
any company in the holding-company system does not unduly or unnecessarily
complicate the structure, or unfairly or inequitably distribute voting power
among security holders, of such holding-company system." The following analysis
demonstrates that the Merger meets the standards of Section 11.
a. Section 11(b)(1) (Single integrated public utility system)
The Commission has found that the system of each of the Applicants is a
single integrated electric utility system. See AEP, supra (finding that AEP is a
single integrated system); Central and South West Corp., HCAR No. 22439 (April
1, 1982) (terminating a Section 11(b)(1) hearing and upholding a 1945
determination by the Commission that CSW comprises
59
<PAGE> 60
one integrated public utility system). The following analysis supports a
determination by the Commission that the Merger of these two utility systems
will result in a single integrated electric utility system under Section
11(b)(1).
Section 2(a)(29)(A) of the 1935 Act defines an integrated public utility
system, as applied to an electric utility system, as:
a system consisting of one or more units of generating plants and/or
transmission lines and/or distribution facilities, whose utility assets,
whether owned by one or more electric utility companies, are physically
interconnected or capable of physical interconnection and which under
normal conditions may be economically operated as a single interconnected
and coordinated system confined in its operations to a single area or
region, in one or more States, not so large as to impair (considering the
state of the art and the area or region affected) the advantages of
localized management, efficient operation, and the effectiveness of
regulation.
Under this definition, the Commission has established four standards that
must be met before the Commission will find that an integrated public utility
system will result from a proposed merger of two separate systems:
(i) the utility assets of the systems must be physically
interconnected or capable of physical interconnection;
(ii) the utility assets, under normal conditions, must be economically
operated as a single interconnected and coordinated system;
(iii) the system must be confined in its operations to a single area or
region; and
(iv) the system must not be so large as to impair (considering the
state of the art and the area or region affected) the advantages
of localized management, efficient operation, and the
effectiveness of regulation.
See, e.g., Environmental Action, Inc., v. SEC, 895 F.2d 1255, 1263 (9th Cir.
1990) (citing In re Electric Energy Inc., 38 SEC 658, 668 (1958)).(12) As
demonstrated below, the Merger meets each of these standards.
- -------------------------
(12) Although the integrated utility system requirement has been
interpreted to involve a four-part test, Applicants submit that the requirement
can be fairly interpreted to involve only a three-part test. The plain reading
of the integration requirement suggests the last two tests should be read as one
test. The requirement provides, in pertinent part, that the "system [be]
confined in its operations to a single area or region, in one or more States,
not so large as to impair (considering the state of the art and the area or
region affected) the advantages of localized management, efficient operation,
and the effectiveness of regulation." There is no "and" inserted between "single
area or region" and "not so large as to impair" leading to the conclusion that
there are two distinct tests which the "system" must meet. Rather, the sentence
construction leads to the conclusion that it is the "single area or region"
which must not be so large as to result in the specified impairments. In any
event, the proposed Merger meets either the three-part test, as set forth in the
statute, or the four-part test.
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<PAGE> 61
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(13) that recognized the need of an agency to "adapt [its] rules
and policies to the demands of changing circumstances"(14) and to "treat
experience not as a jailer but as a teacher."(15)
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.
- -------------------------
(13) 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).
(14) NIPSCO, supra, citing Rust v. Sullivan at 186-187. Accord, Sempra,
supra at n. 23.
(15) NIPSCO, supra, citing Shawmut Assn. v. SEC at 796-97. Accord,
Sempra, supra at n. 23.
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<PAGE> 62
Co., HCAR No. 13048 (Nov. 25, 1955) [hereinafter "Yankee Atomic"] ("We think it
is clear from the language of Section 2(a)(29)(A), which defines an integrated
public utility system, that Congress did not intend to imposed [sic] rigid
concepts with respect thereto." (citations omitted)). Section 2(a)(29)(A)
expressly directs the Commission to consider the "state of the art" in analyzing
size and to apply "normal conditions" as the standard for determining whether a
system may be economically operated as a single coordinated system. The
Commission is not constrained by its past decisions interpreting the integration
standards based on a different "state of the art." See AEP, supra (noting that
the state of the art -- technological advances in generation and transmission,
unavailable thirty years prior -- served to distinguish a prior case and
justified "large systems spanning several states.")
The concept of what constitutes an integrated public utility system has
evolved in light of the dramatic changes in the law, technology and structure of
the industry since the passage of the 1935 Act over 60 years ago. In recent
years, the "state of the art" has changed enormously. As the Energy Information
Administration of the Department of Energy aptly noted, "The era of competition
in the electric industry is upon us." Energy Information Administration,
Department of Energy, The Changing Structure of the Electric Power Industry: An
Update (last modified May 30, 1997) <http://www.eia.doe.gov/cneaf/electricity/
chg_str/intro.html>.
The initial groundwork for competition was laid by the passage of PURPA
in 1978, which opened wholesale markets to certain non-utility producers. PURPA
created a new class of non-utility generators, QFs, from which utilities were
required to buy power. The passage of the Energy Act in 1992 marked another
significant step towards the deregulation of the electric power industry. The
Energy Act was designed, among other things, to foster competition in the
wholesale market through (a) amendments to the 1935 Act that facilitated and
encouraged the ownership and operation of generating facilities by EWGs (which
may include IPPs as well as affiliates of electric utilities) and (b) amendments
to the FPA, authorizing the FERC under certain conditions to order utilities
that own transmission facilities to provide wholesale transmission services for
other utilities and entities generating electric power. FERC Order Nos. 888 and
889, issued in April 1996, taken together provide that public utilities must
file OATTs permitting open access to transmission and must functionally or
actually unbundle their transmission services, by requiring them to use their
own transmission tariffs in making off-system and third-party sales.
In response to deregulation in the wholesale market for electricity, many
state legislatures and regulatory commissions either have adopted or currently
are considering the adoption of "retail customer choice" provisions. In general
terms, these initiatives require the electric utility to transmit electric power
over its transmission and distribution system to a retail customer in its
service territory. A requirement to transmit directly to retail customers
permits retail electric customers to purchase electric power, at the election of
such customers, either from the electric utility in whose service area they
reside or from another electric service provider or directly from an electric
generator source.
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
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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.
In Oklahoma, legislation allowing retail competition was passed in April
1997, and amended in September, 1998. Retail choice is scheduled to commence by
July 1, 2002. Currently, restructuring related studies are being conducted and
are expected to be completed by October, 1999.
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 State Corporation 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.
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.
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.
On June 18, 1999, the Governor of Texas signed legislation enacting
retail competition in Texas. Under the legislation, full retail competition is
scheduled to commence by January 1, 2002. Electric rates are frozen for a three
year period from January 1, 1999 to January 1, 2002 and, thereafter, a 6% rate
reduction will be offered to residential and small commercial consumers. In
addition, no power generation company may own and/or control more than 20% of
the installed generation capacity in ERCOT.
On July 6, 1999, the governor of Ohio signed a bill that restructured the
electric utility industry in Ohio affecting OPCo and CSPCo. Under the law,
customer choice in electric energy supply is to begin on January 1, 2001, with a
transition period to end by December 31, 2005. The law provides Ohio electric
utilities the opportunity to recover regulatory assets and other potential
stranded costs. The Ohio Commission will address recovery of stranded costs and
other issues based on each utility's transition plan which is to be filed by the
end of 1999.
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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 100 marketers have registered with the
FERC to trade in electric power. See "Restructuring Energy
Industries: Lessons From Natural Gas," Energy Information
Administration, Natural Gas Monthly, May 1997.
One way in which investor-owned utilities are seeking to improve their
position in today's increasingly competitive market is through mergers and
acquisitions. Between 1986 and 1996, thirty-nine electric investor-owned
utilities merged with other utilities in the industry. Energy Information
Administration, Department of Energy, The Restructuring of the Electric Power
Industry: A Capsule of Issues and Events (Feb. 10, 1998). Between 1992 and the
first half of 1998, 48 investor-owned electric utilities have been involved in
the domestic merger and acquisition process. Edison Electric Institute, "Merger
& Acquisitions," EEI Financial Information (August 28, 1998). AEP and CSW are
seeking to merge to further their mutual strategy of adapting to these historic
changes in the electric utility industry.
Finally, recent years have witnessed technological advances unforeseeable
in 1935. Developments in telecommunications and computer technology, along with
parallel technological breakthroughs in transportation, have dramatically
reduced, if not eliminated, distance as a significant barrier to centralized
management and coordinated operation of any enterprise. It is a truism that
today's "global village" is a much smaller place than the world of 1935.
Developments in the transportation industry have greatly reduced travel times.
And information travels instantly. Computers provide "real time" information to
central management, providing it with comprehensive, timely information and the
capacity to assert central control over diverse operations.
In 1935, "an electric utility system generally included local generation,
transmission and distribution, [and] little long-distance transmission . . ."
Unitil, supra. Power plants were
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relatively small and isolated, and there was no economical way to transmit power
over any great distance. 1995 Report at 1, n. 1 (citation omitted). In today's
world, "improved transmission and monitoring technologies have increased the
feasible geographic bounds for supply choice; a geographic radius of 1,000 miles
or more is currently considered reasonable for choosing among supply options."
Rodney E. Stevenson & David W. Penn, "Discretionary Evolution: Restructuring the
Electric Utility Industry," Land Economics, Vol. 71, No. 3 (August 1, 1995).
Technological advances have occurred with respect to the "size" of
transmission lines. The building and expansion of the bulk power transmission
networks (345 Kv to 765 Kv lines) throughout the United States has allowed for
the transfer of large amounts of power over great distances. The construction of
such facilities has increasingly made it possible for electric utilities with
service territories over large geographic areas to share resources in providing
more reliable and economic service to their customers. There were less than 100
circuit miles of 345 Kv lines prior to 1950 and less than 100 circuit miles of
500 Kv lines prior to 1960. Electric Power Research Institute, Transmission Line
Reference Book (2d ed., revised, 1987) at 15 [hereinafter "Transmission Line"].
The first 765 Kv lines in the United States were built for AEP and were
energized in 1970. Id. at 14. Transmission lines above 189 Kv have grown from
7,800 circuit miles in 1950 to 151,700 circuit miles in 1995. Edison Electric
Institute, EEI Pocketbook of Electric Utility Industry Statistics (42d ed. 1997)
at 38. The contribution percentage of these lines above 189 Kv as compared to
all transmission lines above 22 Kv has grown from 3.3 % in 1950 to 22.6 % in
1995. Id.
Technological advances have also occurred with respect to the "type" of
transmission lines. The application of HVDC technology provides the ability to
transmit bulk power over longer distances with less energy loss and normally
with a smaller investment than with alternating current ("AC") transmission
lines. This technology provides an economical way to interconnect separated AC
power grids and enables power transfers to occur between these systems such that
it not only provides for improved economies, but also provides improvements in
reliability. HVDC technology was not commercially applied in the United States
for bulk power transfers until 1970, with the operation of the Pacific Intertie,
Stage 1 USA. Transmission Line at 17. From 1968 to 1981, there were 11,326 MWs
of HVDC capacity added in North America. Id. HVDC capacity has continued to be
added in different areas of the United States since 1981. In fact, the CSW
System constructed and placed in service a 220 MW HVDC interconnection between
the SPP and ERCOT in December 1984. In August 1995, another HVDC interconnection
rated at 600 MW owned by CSW and several other electric utility partners was
placed in service between the same two power pools, but at a different location.
The application of phase shifting transformers, series compensation, and
flexible alternating current transmission system ("FACTS") technology has also
provided the ability to improve and control the transfer of power and energy
across expansive transmission networks. Their use historically has been more
selective because of the operational problems that accompany their day- to-day
use. However, over the years with improvements in technology and operating
experience, their application is becoming more common. New flexible alternating
FACTS technology can increase the capacity of existing transmission lines by
approximately 20 to 40 percent. Electricity: Innovation and Competition, Hearing
Before the Subcomm. of Energy and Power of the House Comm. on Commerce, 105th
Cong. 38 (1997) (statement of Robert B. Schainker, Manager, Substations,
Transmissions and Substation Business Area Power Delivery
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Group, Electric Power Research Institute). Such technology "help[s] electric
utilities operate their bulk power networks closer to their inherent thermal
limits, while maintaining and/or improving network security and reliability."
Id.
Advances in telecommunications and computer technology have improved the
ability to economically dispatch power systems and control power flow across
such systems. Improvements in telecommunication technology and the growth in
coverage area of telecommunications systems have allowed for the quick and
reliable transfer of data necessary to control and dispatch from a single
location generation that can be scattered over large geographic areas. During
the last 10 to 15 years, the expansion of microwave and fiber optic networks has
provided utilities the ability to transfer information at much greater speeds,
with improved quality, and greater reliability. Prior to the 1970s, data was
transferred at baud rates as low as 75 baud (bit per second), sometimes being
transmitted over the power lines themselves. Today, data transferred from the
field to central control centers is at a minimum 1200-baud rate to accomplish 2
second scan rates. Larger data transfers between control centers are normally
accomplished at transfer rates from 56 kbaud to 224 kbaud.
Computer technology necessary to economically dispatch power systems and
to control power flow across the bulk power transmission system has advanced
significantly since 1935, especially within the last ten years. The improvements
provided by fast and reliable telecommunication network allow for the control
and economic dispatch of power systems that extend over large geographic areas,
providing system operators an almost real time ability to monitor and control
the power system. Current control systems include software programs that can
help the operator analyze the real time operation of the power system and look
for potential problems before they occur. These complex programs have the
ability to suggest corrective measures and, in some cases, implement responses
without system operator participation. Such programs provide utilities greater
ability to obtain more capability out of their existing electric system, improve
system reliability, and improve economies. See, e.g., discussion of Central
Dispatch Planning and Central Economic Dispatch in Item 1.B.3.a, supra.
In addition, significant improvements in transmission and resource
planning have occurred since 1935. There are several software packages available
today that enable the system planner to model the operation of most of the
equipment used on a power system. Studies can be performed that not only
evaluate power transfer capabilities, but also allow the system planner to add
different types of equipment to determine their impact on increasing power
transfer capabilities. Development of such software has enabled the system
planner to determine what equipment functions best as well as where and when it
should be installed. Further technological advances can be expected in the
future as "power engineers" explore the potential for computers to optimize the
efficiency and reliability of the North American power network. Leslie Lamarre,
"The Digital Revolution," EPRI Journal, Jan./Feb. 1998.
The fundamental changes in technology outlined above dramatically alter
the "state of the art" which Congress, more than sixty years ago, directed the
Commission to consider. Such fundamental changes led the Division, in the 1995
Report, to state that it intends to apply a more flexible interpretation of the
integration requirements under the 1935 Act; and the Division recommended that
the Commission "respond realistically to the changes in the utility industry and
interpret more flexibly each piece of the integration equation." 1995 Report at
67. The
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Division further noted that in considering the integration requirements, the
Commission should place more focus on the acquisition's "demonstrated economies
and efficiencies." Id. at 69.
Each of the four integration standards is discussed below.
(i) Interconnection
The Combined System will be physically interconnected or capable of
interconnection. The required method of interconnection is not defined in the
1935 Act. The Commission has recognized that the interconnection requirement
should be applied flexibly to allow for methods of interconnection beyond simply
a transmission line owned by the merging utilities. In this regard, the
Commission has found (which finding was upheld on appeal) sufficient a
"three-year 'firm contract' to use a transmission line owned by two unrelated
parties." WPL Holdings at 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 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.
The 1935 Act does not require two merging utilities to demonstrate, at
the time of the merger application, the method through which they will be
interconnected throughout the lifetime of the combined system. Northeast I supra
(Commission approved a merger where the combining utilities only had an absolute
right to use a third party transmission line for 10 years). The statute also
does not require that the merging utilities be interconnected from the outset.
Rather, the merging utilities need only be "capable of interconnection" to meet
the physical interconnection requirement.(16)
- -------------------------
(16) To meet the Section 11(b)(1) integration standard, the utility
assets of the currently existing system need only be "capable of physical
interconnection" based on the definition found in Section 2(a)(29)(A). In
another recent case, two merging utilities had no contract path but merely an
intention to construct a new transmission tie-line within five years in order to
interconnect their systems. On that basis, the Commission found that the merging
utilities were "capable of being interconnected." New Century Energies Inc., 65
S.E.C. 277, 314-16 (1997) [hereinafter New Century Energies]. By any
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As noted in Item 1.B.3 above, AEP and CSW will interconnect
their systems through the 250 MW Contract Path across the Ameren system. Under
Commission precedent, this satisfies the interconnection requirement of Section
2(a)(29)(A). Moreover, the Applicants have the ability through the Ameren OATT
to renew the Contract Path. Thus, the Contract Path provides the Applicants with
the means to meet the interconnection standard under the Act and, at the same
time, preserves flexibility to enter into more favorable arrangements should
they become available during the four-year term of the Ameren contract. As noted
above, the electric industry is in the process of dynamic change; there is
growing pressure on public utilities to restructure and increasing competition
in the marketplace. Applicants believe that within the next four years there may
be transmission interconnection alternatives available as a result of these
changes and that the Commission therefore should find the Contract Path to be
sufficient. Although the precise method of interconnection has not yet been
determined four years into the future, the Applicants commit to continue to meet
the interconnection requirement at that time.
As noted in Item 1.B.3., Applicants have committed to limit their
reservation of firm transmission service from east to west to 250 MW unless the
FERC authorizes them to go above this limit.(17) See Dr. Hieronymus' testimony
filed as an exhibit to Exhibit D-1.2.
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.(18)
In this regard, the Commission has found that the transmission rights associated
with being a member of an ISO help to satisfy the interconnection requirement.
Conectiv, supra.
(ii) Single Interconnected and Coordinated System
- --------------------------------------------------------------------------------
reasonable measure, an intention to construct a tie-line is far more tenuous
than an actual physical interconnection, by contract or otherwise.
(17) 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.
(18) 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 Combined System will be capable of being economically operated as a
single interconnected and coordinated system, as required by Section
2(a)(29)(A). The Commission has "interpreted this language to refer to the
physical operation of utility assets as a system in which, among other things,
the generation and/or flow of current within the system may be centrally
controlled and allocated as need or economy directs." Conectiv, supra (citing
North American Co., 11 SEC 194, 242 (1942), aff'd, SEC v. North American Co.,
133 F.2d 148 (2d Cir. 1943), aff'd on constitutional issues, 327 U.S. 686
(1946)). Through this standard, Congress "intended that the utility properties
be so connected and operated that there is coordination among all parts, and
that those parts bear an integral operating relationship to one another." Id.
(citing Cities Services Co., 14 SEC 28, 55 (1943)).
The Commission has considered advances in technology and the particular
operating circumstances in applying this integration standard. Unitil, supra
(citation omitted). For example, in Unitil, the Commission found that
participation in a power pool was sufficient to meet the economic integration
standards even though the "definition [of economic integration] reflects an
assumption that the holding company would coordinate the operations of the
integrated system." Similarly, in approving the acquisition of PSNH by
Northeast, the Commission noted that "the operation of the generating and
transmission facilities of PSNH and the Northeast operating companies is
coordinated and centrally dispatched under the NEPOOL Agreement [a regional
power pool agreement]." Northeast I, supra at n. 85. In Conectiv, supra, the
Commission noted that in addition to coordinated operation through an ISO,
Conectiv would also have a central operating transmission and generation control
center for the essentially local functions of the Conectiv system, thereby
meeting the standard.
The Combined System will operate as a single interconnected and
coordinated system through the centralized coordination of generation and
transmission. The centralized coordination within the Combined System will be
accomplished under the System Integration Agreement and the System Transmission
Integration Agreement, both of which will take effect upon consummation of the
Merger, as described above in Item 1.B.3. Through Central Dispatch Planning, the
coordination of each generation unit in the Combined System will be scheduled on
a day ahead basis. Central Economic Dispatch will compute at regular intervals
(currently every four seconds) the most economic generation base points as
dictated by current operating conditions and will adjust the dispatch of each
generating unit in the Combined System. Taken together, the software programs
are designed to forecast and economically dispatch all generation resources to
meet the load requirements of the Combined System every four seconds,
twenty-four hours a day. The Applicants' goal ultimately is to further enhance
the coordination of their companies through participation in a regional RTO.
The RTOs that are evolving under FERC's direction perform similar
planning and reliability functions that regional reliability councils have
performed in the past. Participation in RTOs can enhance the Combined Company's
system reliability in several ways. In the RTO NOPR, as noted above, the FERC
found that an RTO would improve efficiencies in the management of the
transmission grid (RTO NOPR mimeo at 90); would improve grid reliability (RTO
NOPR mimeo at 95); would improve market performance (RTO NOPR mimeo at 98); and
would facilitate lighter governmental regulation (RTO NOPR mimeo at 101). In
addition, RTOs are assuming the functions of administering transmission service
tariffs and performing real time system security and balancing functions that
are related to maintaining reliability and ensuring
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non-discriminatory access to transmission facilities. Thus, AEP's participation
in an RTO is expected to enhance its ability to operate the Combined System in
an efficient and reliable manner.
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.
In addition thereto, the Combined System will be coordinated in a variety
of ways beyond simply the coordination of the generation and transmission within
the system. AEPSC will be the designated agent under the System Integration
Agreement. AEPSC's major functions will be to coordinate the planning and design
or purchase of new generation facilities, the operation and maintenance of
generating capacity resources, economic dispatch, centralized trading and
marketing activities, acquisition and provision of transmission services needed
for inter-zone power transfers and billing and administration. In addition, the
accounting functions of the Combined System will be prepared and consolidated
through the use of a single enterprise-wide financial system. This financial
system will include a general ledger module, accounts receivable and cash
remittance processing modules, an accounts payable module, a purchasing and
materials management module, owned and leased assets modules as well as a single
integrated timekeeping and payroll system. These systems will enable the
Combined Company to have a single accounting organization which will be managed
by a single team in one or more locations.
In applying the 1935 Act's integration standard, the Commission looks
beyond simply the coordination of the generation and transmission within the
system to the coordination of other activities. See, e.g., General Public
Utilities Corp., HCAR No. 13116 (Mar. 2, 1956) [hereinafter "GPU"] (integration
is accomplished through power dispatching by a central load dispatcher as well
as through coordination of maintenance and construction requirements); Middle
South Utilities, HCAR No. 11782 (March 20, 1953), petition to reopen denied,
HCAR No. 12978 (Sept. 13, 1955), rev'd sub nom. Louisiana Public Service Comm'n
v. SEC, 235 F.2d 167 (5th Cir. 1956), rev'd, 353 U.S. 368 (1957), reh'g denied,
354 U.S. 928 (1957) (integration is accomplished through an operating committee
which coordinates not only the scheduling of generation and system dispatch, but
also makes and keeps records and necessary reports, coordinates construction
programs and provides for all other interrelated operations involved in the
coordination of generation and transmission); The North American Co., HCAR No.
10320 (Dec. 28, 1950) (economic integration is demonstrated by the exchange of
power, the coordination of future power demand, the sharing of extensive
experience with regard to engineering and other operating problems, and the
furnishing of financial aid to the company being acquired).
The coordination and integration of the Combined System is expected to be
further achieved through the coordination and integration of information system
networks; procurement
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organizations and organizational structures for Power Generation, Nuclear
Generation, and Energy Delivery and Customer Relations. Each is discussed below:
- Analysis completed to date has concluded that there are
approximately 600 information systems software packages which
support either AEP or CSW operations. This initial analysis has
concluded that these packages can be organized under a single,
integrated information system network with the capability of being
operated from a single location. The network will be supported by
a single data center and will have common software tools and a
single centralized IT development organization. The individual
integration teams are currently analyzing the various software
systems being used by each of the companies in order to identify
the single best system to be utilized to support the Combined
Company in each area.
- AEP and CSW each have created centralized procurement
organizations which assist the business units in preparing bid
solicitations, procuring materials and supplies and managing the
inventory required to support the assets of each business unit.
The Combined Company expects to utilize a single organizational
structure to accomplish these activities.
- AEP and CSW each have created four substantially equivalent
business unit management and organizational structures: Power
Generation, Nuclear Generation, and Energy Delivery and Customer
Relations. Each of these business units has created a combination
of central management and engineering groups with regional and
field organizations designed to provide the services of the
business unit as efficiently as possible. The integration teams
are studying how best to integrate these activities. It is
anticipated that each of the business unit structures recommended
for the Combined Company will be similar to the existing single,
integrated organizational structure that is being used in AEP and
CSW.
- AEP and CSW currently utilize a single service company model to
provide support services, including office, finance, treasury,
legal, corporate communications and other corporate services. Upon
the merger of AEPSC and CSWS, these services would be effectively
provided by combined groups handling office, finance, treasury,
legal, corporate communications and other corporate services.
As dictated by the language under Section 2(a)(29)(A) that the
coordinated system be "economically operated," the Commission further analyzes
whether the coordinated operation of the system results in economies and
efficiencies. See, e.g., City of New Orleans v. SEC, 969 F.2d 1163, 1168 (D.C.
Cir. 1992) (Court supported Commission's reading of the term "economically" to
mean "that facilities, in addition to their physical interconnection, be
consolidated so as to take advantage of efficiencies"); WPL Holdings, Inc., HCAR
No. 26856 (Apr. 14, 1998) (discussing this integration standard as it relates to
the requirement under Section 10(c)(2) that the acquisition tend towards the
economic and efficient development of an integrated system and noting that the
applicants introduced substantial evidence concerning the
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efficiencies to be realized by the combined operation of the merging companies'
generation and transmission systems). The Applicants expect to realize
significant economies and efficiencies as a result of the Merger. As described
in Item 3.B.2 below, Applicants estimate the net non-fuel savings from the
Merger to be nearly $2 billion and the net fuel-related savings to be
approximately $98 million over the first ten years following the Merger.
In short, pursuant to the System Integration Agreement, the Combined
System will be centrally and efficiently planned and dispatched. Pursuant to the
System Transmission Integration Agreement, the operation and management of
transmission within the Combined System will be centrally overseen. Thus, as
with other merger applications approved by the Commission, the Combined System
will be capable of being economically operated as a single interconnected and
coordinated system. The Combined System will be "economically operated" as a
coordinated system as further demonstrated by the variety of means through which
its operations will be coordinated and the efficiencies and economies expected
to be realized by the Merger as described below in Item 3.B.2.
(iii) Single Area or Region
As required by Section 2(a)(29)(A), the Combined System's operations will
be confined to a "single area or region in one or more States." While the terms
"area" and "region" are not defined in the 1935 Act, it is clear that the
"single area or region" requirement does not mandate that a system's operations
be confined to a small geographic area. The Section specifically provides that a
region can encompass more than one state. As Ganson Purcell, Chairman of the
Securities and Exchange Commission, testified before the Subcommittee of the
House Committee on Interstate and Foreign Commerce in 1946:
I wish to make it clear that the Act does not require that an integrated
utility system be broken up, whether or not it crosses State lines, or
that a holding company necessary to integrate the properties of several
operating companies be abolished. . . .(19)
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. . . .(20)
No absolute size limitation is specified. The terms "area" or "region," by their
nature, are capable of flexible interpretation, which permits the Commission to
respond to the current state of the industry and allows the Commission to give
the terms practical meaning and effect. The
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(19) 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).
(20) Id. at 857 (referring to American Gas and Electric system).
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Commission has found that the single area or region test should be applied
flexibly when doing so does not undercut the policies of the 1935 Act "against
'scatteration' -- the ownership of widely dispersed utility properties which do
not lend themselves to efficient operation and effective state regulation."
NIPSCO, supra (applying single area or region requirement with respect to gas
utility system); accord, Sempra, supra. The 1935 Act itself provides, and the
Commission recognizes, that the question of size must be informed by practical
considerations, including its effect, if any, on the "advantages of localized
management, efficient operation, and the effectiveness of regulation"(21) in
light of "the state of the art and the area or region affected" as discussed in
Item 3.B.1.a.(iv) below.(22)
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.(23) 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.,
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(21) 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.
(22) In fact, as discussed in note 11 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.
(23) 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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HCAR No. 13781 (Nov. 28, 1958) (utility assets were within the same area or
region as the acquirer's service area despite a distance of 100 miles crossing
two states); Mississippi Valley Generating Co., HCAR No. 12794 (Feb. 9, 1955)
(single area or region test met where generating station was located 150 air
miles from the territory served by the acquiring company).
In tandem with not specifying the absolute size of an "area" or "region,"
the 1935 Act makes no reference to a set of pre-defined regions with specific
boundaries. It follows that the concept of region is not constrained by
geographical boundaries such as rivers or mountains; nor is it constrained by
regional designations which are part of the common vocabulary (e.g., northeast,
southwest, or midwest).
The Commission's determination of whether the requirement is met is made
in light of "the existing state of the art of generation and transmission and
the demonstrated economic advantages of the proposed arrangement." Connecticut
Yankee Atomic Power Co., HCAR No. 14968 (Nov. 15, 1963); see also, Vermont
Yankee Nuclear Power Corp., HCAR No. 15958 (Feb. 6, 1968), rev'd and remanded on
other grounds, Municipal Elec. Ass'n v. SEC., 413 F.2d 1052 (D.C. Cir. 1969).
The Commission has applied flexibly the requirement based on the facts and
circumstances involved and the practicalities of the situation at hand. See,
e.g., Yankee Atomic, supra.
The Division has recommended that the Commission "interpret the 'single
area or region' requirement flexibly, recognizing technological advances,
consistent with the purposes and provisions of the Act" and that the Commission
place "more emphasis on whether an acquisition will be economical." 1995 Report
at 66, 69. The Division has recognized that "recent institutional, legal and
technological changes . . . have reduced the relative importance of . . .
geographical limitations by permitting greater control, coordination and
efficiencies" and "have expanded the means for achieving the interconnection and
economic operation and coordination of utilities with non-contiguous service
territories." 1995 Report at 69. It has also recognized that the concept of
"geographic integration" has been affected by "technological advances on the
ability to transmit electric energy economically over longer distances, and
other developments in the industry, such as brokers and marketers." Id. Such
advances and developments are breaking down traditional boundaries and concepts
of regions. The Commission has confirmed its support for the Division's study,
citing, in particular, the Division's recommendation that the Commission
"continue to interpret the 'single area or region' requirement of [the 1935 Act]
to take into account technological advances." NIPSCO, supra; accord, Sempra,
supra.
Prior to the Merger, the AEP System and the CSW System will be separated
by only 150 miles at their closest point, a distance which the Commission has
previously found acceptable under the single area or region test. The Combined
Company will operate in eleven contiguous states located in the mid-America
region of the United States, connected in the middle by the states of Arkansas
and Tennessee.(24)
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(24) 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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Moreover, that the Combined Company meets the single region test is
further supported by adopting a definition of region used by the Commission for
purposes of its size analysis under Section 10(b)(1). In Entergy, supra, the
Commission adopted the applicants' definition of the relevant region for Section
10(b)(1) purposes to include themselves and those electric utilities directly
interconnected with either or both. In today's increasingly competitive world,
AEP and CSW do not operate as isolated companies and their geographic region
should be analyzed in terms of their most accessible markets -- the
Interconnected Utilities. The service territories of these Interconnected
Utilities surround the Combined System and effectively close the distance
between the former AEP and CSW, bringing them even closer together.
The Merger represents a logical extension of the AEP System's existing
service territory in light of contemporary circumstances. As the Commission has
recognized, the concept of area or region is not a static one and must be
refashioned to take into account the present realities of the electric industry,
consistent with the purposes of the 1935 Act. These present realities have
effectively shrunk the world in which the industry operates and support a
finding that the concept of a region can encompass four additional states more
than 50 years after the Commission's finding that the current seven-state AEP
System operates within an area or region.
As the restructuring of the electric industry progresses, traditional
boundaries will become more blurred and the contours of regional markets will
change. Structural changes in a closely-related industry subject to similar
regulatory regimes, the natural gas industry, are influencing the restructuring
of the electricity industry and further breaking down traditional
boundaries.(25) 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
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(25) 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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sellers to allocate gas to the highest bidding buyer." Id. at 78. Although it is
"probably premature . . . to conclude that a true North American market for
natural gas has emerged," market integration is improving and "regional clusters
of markets across certain broad areas seem to be highly competitive, even
between U.S. and Canadian markets." Id. at xii.
Developments in the natural gas industry which are eroding traditional
boundaries are being applied to the electricity industry. Many gas marketers are
moving into the new electricity markets, and the development of financial
instruments used in the gas industry, such as spot, forward, futures, and
options contracts, are being imported into the electricity industry. Natural Gas
1996 at xiii. More than 100 energy marketing companies have registered with the
FERC to market electric power on a wholesale basis. Natural Gas Monthly. These
companies will be marketing retail power to retail power markets as well.
Moreover, the developments in electric and gas industries "may imply a close
relationship in the future for both industries." Natural Gas 1996 at xiii. Not
only are gas marketers entering the electricity markets, but "gas and electric
companies are forming mergers and strategic alliances to give customers menus
that allow buyers to bridge the differences between the industries." Id. And the
development of financial markets "may help to integrate the energy markets." Id.
In short, the concept of "area or region" should be interpreted flexibly to keep
pace with the current state of the industry.(26)
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.
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(26) 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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(iv) Localized Management, Efficient Operation and Effective Regulation
Section 2(a)(29)(A), like Section 10(b)(1) discussed above, requires the
Commission to consider the size of the combined system. Section 2(a)(29)(A) has
been interpreted to require that the combined system must not be so large as to
impair (considering the state of the art and the area or region affected) the
advantages of localized management, efficient operation, and the effectiveness
of regulation. As the Commission stated in AEP, supra:
[N]either section can be said to impose any precise limits on holding
company growth. Both sections are couched in discretionary terms. They
require the Commission to exercise its best judgment as to the maximum
size of a holding company in a particular area, considering the state of
the art and the area or region affected. In exercising its discretion,
the Commission must balance the various objectives of the 1935 Act. The
Commission stated in Commonwealth & Southern Corp., HCAR No. 7615 (Aug.
1, 1947):
We do not, in applying particular size standards, lose sight of the
objectives of other criteria. There must be a reconciliation of all objectives
to the end of accomplishing a satisfactory administration of the [1935] Act.
Thus we do not disregard operating efficiency in our determination of whether
size is excessive from the viewpoint of localized management or effectiveness of
regulation. As will be discussed below, difficult balancing decisions need not
be made because each prong of this standard is easily met. The size of the
Combined System does not impair the advantages of localized management,
efficient operation or the effectiveness of regulation. The Merger actually
increases the efficiency of operations.
- Localized Management
The Commission has found that an acquisition does not impair the
advantages of localized management where the new holding company's
"management [would be] drawn from the present management" (Centerior,
supra), or where the acquired company's management would remain
substantially intact (AEP, supra). The Commission has noted that the
distance of corporate headquarters from local management was a "less
important factor in determining what is in the public interest" given the
"present-day ease of communication and transportation." AEP, supra. The
Commission also evaluates localized management in terms of whether a
merged system will be "responsive to local needs." AEP, supra.
The management of the Combined Company will be drawn primarily from the
existing management of AEP and CSW and their subsidiaries. AEP will
continue to maintain its system headquarters in Columbus, Ohio and will
maintain the management structure of its combined subsidiary companies
(including the electric operating and other subsidiary companies of CSW)
essentially intact. CSW and AEP have operated with virtual service
company management which has located management personnel in a number of
operating locations throughout the service territories. In 1996, AEP
reorganized into a centralized management structure with localized
management remaining essentially in place, with the exception of the
electric utility subsidiary headquarters operating management teams being
realigned into either the Power Generation, Nuclear
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Generation, and Energy Delivery and Customer Relations business units.
CSW completed a similar reorganization process in 1994.
For example, at AEP, the subsidiary companies' generation operations were
realigned into the Power Generation and Nuclear Generation business units
while the transmission and distribution operations were realigned into
the Energy Delivery business unit. As part of this realignment,
transmission operations were structured with a centralized management and
engineering organization which oversees three transmission operating
regions. The distribution operations were structured with a centralized
management and engineering structure which oversees 30 distribution
districts which report to one of eight distribution regions. Customer
services functions were also realigned under the Energy Delivery and
Customer Relations business unit into a regional structure with four
customer call centers, a single customer information system and
centralized management of the customer service operations.
As part of these individual reorganization efforts, the electric utility
subsidiaries of AEP began doing business under the AEP brand without
altering their separate legal identities, assets and liabilities,
franchises and certificates of public convenience and necessity.
Likewise, the electric utility subsidiaries of CSW retained their
separate corporate identities, assets and liabilities, franchises and
certificates of public convenience and necessity.
Although the Applicants have just recently launched transition teams that
are studying how the various components of the two organizations will be
combined, the Applicants expect that the impact of the Merger will be
predominantly confined to the merging of CSWS into AEPSC and the
establishment of a business unit and management structure which looks
very much like the existing structures of AEP and CSW. The electric
utility subsidiaries will continue to operate through the regional
offices with local service personnel and line crews available to respond
to customers needs. The Combined Company will preserve the well
established delegations of authority -- currently in place at AEP and CSW
-- which permit the local, district and regional management teams to
budget for, operate and maintain the electric distribution system, to
procure materials and supplies and to schedule work forces in order to
continue to provide the high quality of service which the customers of
AEP and CSW have enjoyed in the past.
The orders of the Oklahoma Commission, the Arkansas Commission, the
Indiana Commission and the Kentucky Commission approving the Merger
impose an extensive list of service quality standards on the utility
operating companies operating within their states. In Oklahoma, the
Oklahoma 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, and Kentucky, 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
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Company's performance in this regard. See, e.g., Public Utility
Commission of Texas Substantive Rule 25.21 et seq.; Louisiana Public
Service Commission General Order of April 30, 1998.
Likewise, the settlement with the staff of the Texas Commission contains
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 coordinate the economic
dispatch of generating units under its control, make economic purchases
of power, and supply power to its customers. The fact that certain
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generating capacity will no longer be controlled by the Combined Company
will not change the centrally coordinated, least-cost approach to
operating the combined system.(27)
- 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.(28)
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(27) In fact, under the Texas Settlement, 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 Settlement Sec. 6.D-F.
(28) 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.(29) 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 recent settlement in the
Texas proceeding contains several provisions designed to ensure the
effectiveness of the Texas Commission's 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 settlement is specifically designed to safeguard 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 and Kentucky.
Applicants are working closely with other regulators (both state and
federal) to obtain the remaining approvals (as described below in Item
4).
b. Section 11(b)(1) (Acquisition of Non-Utility Interests)
Section 11(b)(1) of the 1935 Act also requires that a registered holding
company limit its operations to a single integrated public utility system and
"such other businesses as are reasonably incidental, or economically necessary
or appropriate to the operations of such integrated public-utility system." Each
of CSW's non-utility business interests conforms to the "other business"
standards of the 1935 Act as previously determined by the Commission. The
indirect acquisition by AEP of CSW's non-utility businesses in no way affects
the functional relationship of these businesses to the Combined Company's core
electric business following the Merger. See Item 3.F below for a detailed
discussion on the acquisition by AEP of CSW's non-utility businesses.
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
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(29) 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 Texas settlement contains a similar provision.
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or unnecessarily complicate the structure, or unfairly or inequitably distribute
voting power among security holders, of such holding-company system." The Merger
is consistent with Section 11(b)(2). The resulting capital structure is not
unduly complicated as discussed in Item 3.A.3 above. See, e.g., Sierra Pacific
Resources, HCAR No. 24566 (Jan. 28, 1988), aff'd Environmental Action, Inc., 895
F.2d 1255 (D.C. Cir. 1990) (Commission incorporates its Section 10(b)(3) capital
structure analysis into its Section 11(b)(2) corporate structure analysis).
Voting power is equitably and fairly distributed among the security holders of
each of AEP and CSW and their current subsidiaries, all of which have been
approved by the Commission in previous proceedings. The shareholders of AEP and
CSW, respectively, have overwhelmingly approved the shareholder actions
necessary to effect the Merger or the Merger itself.
Immediately following the Merger, AEP will be a registered holding
company with respect to CSW, which, in turn, will be a registered holding
company with respect to the electric utility subsidiaries and other subsidiaries
it currently owns (with the exception of CSWS, which will be merged into AEPSC,
and CSW Credit, which will be directly held by the Combined Company). See
Exhibit E-6. Although it is intended that these interests will be restructured,
the final ownership structure has not yet been determined. Accordingly,
Applicants request that CSW survive as a holding company interposed between AEP
and the electric utility subsidiaries and a portion of the other subsidiaries it
currently owns for a period of up to eight years following the closing of the
Merger.
Applicants have determined that the proposed transitional corporate
structure of the Combined Company following the Merger will be in the best
interests of the Combined Company's shareholders and ratepayers. The continued
existence of CSW as an intermediate holding company will result in AEP having a
tax basis in CSW equal to the aggregate tax basis of the CSW shareholders in CSW
prior to the Merger. This tax basis would be lost if CSW were not retained as an
intermediate holding company. See Exhibit J for an explanation of certain
relevant tax basis issues. Retaining the appropriate tax basis in CSW will allow
AEP to realize significant tax savings in the event that AEP were to divest CSW
assets in a future taxable transaction (although AEP does not at present have
any plan to divest CSW assets). Because the costs and complications associated
with the survival of CSW as an intermediate holding company are minimal, AEP and
CSW management have determined that the transitional structure will contribute
to the positive future financial condition of the Combined Company and will
maximize shareholder value.
Although CSW will have an important economic purpose following the
Merger, CSW will have minimal operational functions. As an intermediate holding
company, CSW largely will be a conduit between AEP and its subsidiaries with
respect to capital contributions, if any, and dividends. The future management
of the Combined Company does not anticipate that CSW will be involved in any
intra-system financing other than maintaining its current guarantees on the
debts of its subsidiaries and participating in the Money Pool (as previously
authorized by the Commission) during the transitional period after the Merger to
the extent necessary. Moreover, the future management of the Combined Company
does not anticipate that CSW will engage in securities transactions (except as
noted in the previous sentence); acquire securities, utility assets or other
interests; or enter into or take any step in the performance of any service,
sales, or construction contract. CSW will continue to make, keep and preserve
accounts and records and make any required reports to the Commission and other
appropriate agencies.
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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).(30) Corporate
structures including two tiers of holding companies are specifically envisioned
under the 1935 Act and its Rules, and, in this case, the existence of two
registered holding companies in one system will not result in unnecessary or
undue complications. To the contrary, the minimal complications that may be
introduced by the continued existence of CSW are necessary and appropriate in
serving the interests of the Combined Company, its shareholders and ratepayers.
(i) The Existence of Two Tiers of Registered Holding Companies
in a Single Integrated Public-Utility System Is Not
Prohibited under the 1935 Act
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
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(30) 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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tiers of holding companies through the 'great-grandfather clause' of Section
11(b)(2).(31) 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.'(32) See also, Rule 87(c)
(providing that, in the context of service, sales, and construction contracts,
it is Rule 85, as opposed to Rule 87, that is applicable to a 'subsidiary which
is itself a registered holding company'). In summary, the transitional corporate
structure of the Combined Company, which includes AEP as the top registered
holding company and CSW as a subsidiary registered holding company, satisfies
the first requirement of Section 11(b)(2).
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(31) 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.').
(32) 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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<PAGE> 85
(ii) The Existence of CSW Will Not Unduly or Unnecessarily
Complicate the Structure of the Holding Company System
The second prong of Section 11(b)(2) requires that the Commission ensure
that 'the corporate structure or continued existence of any company in the
holding-company system does not unduly or unnecessarily complicate the structure
. . . of such holding-company system.' The existence of a subsidiary holding
company does not run afoul of Section 11(b)(2) merely because it causes the
structure of the holding company system to be more complicated. Rather, the
existence of a company violates Section 11(b)(2) only if it causes unnecessary
or undue complications. The Commission has interpreted Section 11(b)(2) to
require the elimination of any holding company that serves no useful purpose or
economic function. See, e.g., WPL Holdings, Inc., HCAR No. 25377 (Sept. 18,
1991); Peoples Gas Light and Coke Co., HCAR No. 15929 (Dec. 22, 1967); Voting
Trustees of Granite City Generating Co., HCAR No. 14739 (Nov. 5, 1962).
In prior proceedings, the Commission has determined that the existence of
a second tier holding company satisfies the Section 11(b)(2) test. See, e.g.,
Entergy, supra (the Commission found that the addition of an exempt sub-holding
company to a registered holding company system did not create an undue or
unnecessary corporate complexity); Cinergy Corp, HCAR No. 26146 (Oct. 21, 1994)
(the Commission approved a merger where a registered holding company would be
the parent of an exempt holding company). Moreover, the Commission has in other
circumstances allowed a holding company system with two tiers of registered
holding companies. See Annual Report on U5S of Central and South West
Corporation and Southwestern Electric Power Company for year ended December 31,
1997 (Central and South West Corporation and its wholly owned subsidiary,
Southwestern Electric Power Company, are both registered holding companies);
Citizens Utilities Company, HCAR No. 25331 (June 14, 1991) (Louisiana General
Services, Inc. and its wholly owned subsidiary, LGS Pipeline, Inc., were both
exempt, registered holding companies prior to a merger).
In this case, the temporary survival of CSW as a holding company will
result in minimal complications. CSW will not perform any significant
operational functions. Although it will continue to guarantee the indebtedness
of its subsidiaries and make borrowings to fund the Money Pool and for other
subsidiaries as previously authorized by the Commission to the extent necessary
during the transitional period following the Merger, it will largely function as
a conduit between the Combined Company and the CSW subsidiaries. The Applicants
anticipate that CSW will not engage in securities transactions (except as noted
in the previous sentence); acquire securities, utility assets or other
interests; or enter into or take any step in the performance of any service,
sales, or construction contract. One of the complications that might have
arisen, the need to file two annual reports, has been eliminated by Rule 1(c).
These minimal complications are neither 'unnecessary' nor 'undue.' To the
contrary, any minor complications, and any negligible expenses resulting
therefrom, are necessary to assure appropriate tax and accounting treatment and
to preserve the potential for significant tax savings. The survival of CSW will
benefit the Combined Company's shareholders and its ratepayers. The
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<PAGE> 86
transitional structure certainly will not result in a 'highly-pyramided and
complex holding company system' at odds with the purposes of the 1935 Act.(33)
Vermont Yankee, supra.
In sum, the 1935 Act itself and the Rules thereunder, the policies behind
the Act, and the basic Commission interpretations of Section 11(b)(2), all point
to an obvious conclusion: the transitional survival of CSW is consistent with
the standards of Section 11(b)(2). Nevertheless, additional discussion of the
role of tax considerations under the Commission's interpretation of the 1935 Act
is helpful in light of several cases decided by the Commission in the
early-1950s and before. Not only are these cases distinguishable from the case
at hand, but other cases serve to support the conclusion that the Applicants
meet the standards of Section 11(b)(2).
(iii) CSW Will Perform a Useful Economic Purpose by Preserving
Appropriate Tax Treatment Resulting from the Merger, and
its Survival for Such Purpose Does Not Delay or Disrupt the
Commission's Administration of the 1935 Act
The structuring of business activities for tax planning purposes is not
inimical to public policy considerations and is a legitimate goal under the 1935
Act. As the Commission has held, 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
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(33) 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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District of Delaware (Order, Mar. 13, 1956) (the Commission modified its order
directing a registered holding company to liquidate and dissolve, where the
holding company could transform itself into an investment company and serve a
useful purpose by providing shareholders with tax advantages). Moreover, the
Commission has implied that a useful purpose for a holding company is to
facilitate tax advantages by citing the lack of tax advantages as a factor in
its determination that a holding company should be dissolved. United Light &
Power Company, HCAR No. 6603 (Apr. 30, 1946) (the Commission found that 'there
[wa]s no need for the continued existence' of a registered holding company, in
part, because the holding company's existence no longer offered tax advantages
due to changes in the tax laws).
The Commission has 'recognized the importance of tax considerations'
under Section 11 and has 'sought to cooperate in achieving that type of
rearrangement [under Section 11] which imposes the least tax burden on the
company and the security holders, so long as the choice does not result in
frustrating the Act or in delaying the attainment of its objectives.' Engineers
Public Service Co., HCAR No. 7041 (Dec. 19, 1946); cf. Standard Power & Light,
HCAR No. 12208 (Nov. 9, 1953) (Commission allowed holding company, subject to a
liquidation and divestment order, to divest itself of only a portion of the
interests in its subsidiary to preserve tax advantages because such a plan did
not, under the circumstances, delay or interfere with compliance with the 1935
Act). The existence of tax savings is a compelling reason to maintain a given
structure under Section 11(b)(2), provided that 'the continued existence of this
[security] structure will not be detrimental to the public interest or the
interest of investors or consumers.' Community Gas and Power Company, HCAR No.
4915 (Mar. 4, 1944).
The continued existence of CSW will serve a useful function in the
holding company system by facilitating appropriate tax treatment and by
preserving potentially significant tax savings. These savings are a compelling
reason for the transitional survival of the CSW holding company, and the
existence of CSW will not be detrimental to the public interest, the interest of
investors or consumers, or the Commission's administration of the 1935 Act.
Finally, it should be noted that in a few proceedings in the 1940's to
early-1950's, the Commission determined that potential tax benefits (to only or
potentially only a portion of the shareholders and, in one case, where the
benefits could be achieved by other means), taken alone, were not sufficient to
justify relief from dissolution findings and orders or commitments that had been
made in the early stages of implementation of the 1935 Act. See Engineers Public
Service Company, HCAR No. 7041 (Dec. 19, 1946); Electric Bond and Share Company,
HCAR No. 11004 (Feb. 6, 1952); International Hydro-Electric System, HCAR No.
9535 (Dec. 6, 1949), aff'd sub nom., Protective Committee For Class A
Stockholders v. SEC, 184 F.2d 646 (2nd Cir. 1950).(34) These decisions are not
apposite here, however, where the Commission has
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(34) 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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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.
Economic efficiency is the driving force behind the Merger; its purpose
is to create an entity well situated to compete effectively in an increasingly
active market. Applicants project $1,966 million of net non-fuel cost savings
over the ten-year period immediately following consummation of the Merger. These
savings will be passed on to shareholders and customers of the Combined Company.
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, regardless of whether these actual merger-related savings are
achieved. Applicants also anticipate net fuel-related savings of approximately
$98 million over this same period that will be passed on to customers. Thus, the
Merger will allow the Combined Company to realize the "opportunities for
economies of scale, the elimination of duplicate facilities and activities, the
sharing of production capacity and reserves and generally more efficient
operations" described by the Commission in AEP, supra.
The nonproduction cost savings resulting from the Merger are set forth in
the testimony of Thomas J. Flaherty before the Texas Commission, a copy of which
is included in Exhibit D-5.1 and incorporated by reference. As explained by Mr.
Flaherty, the Combined Company is expected to achieve the following
nonproduction costs savings:
<TABLE>
<CAPTION>
Savings Category Millions
<S> <C>
Elimination of Duplicate Corporate and Operations Support Staffing $ 996
Elimination of Duplicate Corporate and Administrative Programs 1,044
Purchasing Economies (Not Fuel-related) 367
Total Savings 2,407
Less: Costs to Achieve (a) (248)
Premerger Initiatives (193)
</TABLE>
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<PAGE> 89
<TABLE>
<S> <C>
Net Savings $1,966
</TABLE>
(a) Does not include contingent change in control payments.
Assuming a March 31, 1999 closing, AEP and CSW estimate available
synergies and cost savings resulting from the Merger, net of costs necessary to
achieve these reductions, for each of the first ten years following the Merger
of approximately $17 million (9 months), $102 million, $135 million, $162
million, $181 million, $243 million, $255 million, $259 million, $267 million,
$275 million and $70 million (3 months), respectively, for a total of $1,966
million. The savings in the first five years are expected to be lower than in
the later years due to the costs incurred to achieve the savings. Of the $1,966
million in total anticipated net savings, Applicants estimate that approximately
$713 million of the total savings will be allocated to the pre-Merger CSW and
approximately $1,253 million will be allocated to pre-Merger AEP. Moreover, even
though the savings are shown over 10 years only, it is expected that some of
these savings will continue to be realized over a much longer period. See
Testimony of Thomas J. Flaherty included in Exhibit D-5.1.
The Applicants' estimates of Merger savings have been provided to the
staffs of all eleven state commissions which will have retail rate jurisdiction
over the Combined Company (Arkansas, Indiana, Kentucky, Ohio, West Virginia,
Michigan, Tennessee, Virginia, Louisiana, Oklahoma and Texas). In each of those
states, the Applicants have responded to discovery requests from participants,
and have defended the proposed level of savings as being achievable. In each of
those states, the Applicants have either received state commission orders or
entered into stipulations with the commission's staff (and other parties) which
establish the level of savings that will be shared with ratepayers and which
guarantee to consumers the savings regardless of whether they are achieved. The
amount of the savings as well as Applicants' plans for allocating the savings
have been approved by the state commissions of Arkansas, Louisiana, Indiana,
Kentucky, and Oklahoma.
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 settlement with the staff of the Texas
Commission includes 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.
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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 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. Moreover,
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.
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 staffs of the Texas and Oklahoma Commissions support Applicants'
divestiture of generation assets given the mitigation measures that Applicants
have proposed to protect ratepayers. As part of the settlement in Texas, the
Texas commission staff, the Office of Public Utility Counsel, and the other
settling parties agreed to several significant provisions designed to protect
consumers from the economic effects of the divestiture, including (i) a
requirement that proceeds from the 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, and
(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.
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Applicants estimate that the Combined Company will also realize
approximately $98 million in net fuel-related savings over the same 10 year
period. J. Craig Baker's testimony before the FERC (a copy of which is included
in Exhibit D-1.1 and is incorporated by reference) explains that these savings
will result from the central coordinated dispatch of energy by the Combined
Company. These savings will be realized by customers.
These expected savings exceed the anticipated savings in a number of
other acquisitions approved by the Commission. See, e.g., New Century 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).
As the Commission has observed, with reference to the requirement of
Section 10(c)(2) that a proposed combination yield economies and efficiencies,
"specific dollar forecasts of future savings are not necessarily required; a
demonstrated potential for economies will suffice even when these are not
precisely quantifiable." Centerior, supra (citation omitted). In this regard,
the Merger will result in additional benefits which, although not precisely
quantifiable, are nonetheless significant.
Two of these principal additional benefits relate to the Combined
Company's generation mix and system reliability. The Merger will result in a
more balanced generation mix that is less susceptible to fuel price volatility
and supply interruptions. In addition, the Combined System will be better
situated to provide more reliable electric service than is possible for AEP and
CSW on a stand-alone basis. For example, the Combined System will share in a
larger generating base after the Merger. As a result, the Combined System will
have more generating resources to call on when units are down for maintenance or
due to an unscheduled outage. In addition, each of AEP and CSW has a higher risk
of unserved load than would be the case for the Combined System, since each of
AEP and CSW on a stand-alone basis has access to fewer interconnections to
neighboring systems for emergency support.
C. SECTION 10(f)
Section 10(f) provides that:
The Commission shall not approve any acquisition as to which an
application is made under this section unless it appears to the
satisfaction of the Commission that such State laws as may apply in
respect of such acquisition have been complied with, except where the
Commission finds that compliance with such State laws would be
detrimental to the carrying out of the provisions of section 11.
Each of AEP's and CSW's obligation to consummate the Merger is
conditioned, among other things, on the receipt of all requisite state
regulatory approvals. State regulatory approvals have been obtained from the
Oklahoma Commission, the Arkansas Commission, the Indiana Commission, and the
Kentucky Commission. Applicants have also reached a settlement with the staffs
of the Texas Commission and the Louisiana Commission who support the Merger as
being in the public interest. See Item 4, infra, for further discussion of
regulatory approvals and the
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standard of review applicable to such approval. When the other approvals have
been obtained, the Merger will comply with Section 10(f).
D. INTRA-SYSTEM FINANCING AND OTHER COMMISSION AUTHORIZATIONS.
In order to maximize the efficiencies resulting from the Merger, the
Applicants seek authority for the Combined Company to reorganize, consolidate
and, where necessary, restate certain of the intra-system financing and other
authorizations previously issued by this Commission to each of AEP, CSW, and
their respective subsidiaries, as discussed in more detail below.
Applicants request approval, effective upon consummation of the Merger,
to merge CSWS with and into AEPSC. Applicants request that, upon the merger of
CSWS into AEPSC, AEPSC succeed to certain of the authority of CSWS as set forth
in various Commission orders (which orders are summarized in Exhibit I-1
attached hereto) and that such activities with respect to CSWS include AEPSC.
Certain of the non-utility businesses of CSW (each a 'CSW Non-utility
Business') conduct activities that are substantially equivalent to the
activities of one or more non-utility subsidiaries of AEP (each an 'AEP
Non-utility Business'). Applicants request approval, as deemed appropriate by
management, for the Combined Company to directly or indirectly acquire, and for
CSW to transfer to the Combined Company, CSW Non-utility Businesses through: (1)
merger of one or more CSW Non-utility Businesses with one or more wholly owned
non-utility subsidiaries (either presently existing and performing substantially
equivalent activities or to be formed, if appropriate) of the Combined Company
(each a 'Combined Non-utility Business'), (2) the dividending or distribution of
the common stock of one or more CSW Non-utility Businesses from CSW to the
Combined Company, or (3) the acquisition of the assets or common stock of one or
more CSW Non-utility Businesses by one or more Combined Non-utility Businesses.
Applicants request approval, if management deems appropriate, to consolidate
each CSW Non-utility Business with its corresponding AEP Non-utility Business
into a single 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
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consummation of the Merger, the authority of CSW to issue and sell securities in
an amount up to 100% of its consolidated retained earnings for investment in
EWGs and FUCOs as provided by Central and South West Corp. et al., HCAR No.
26653 (Jan. 24, 1997) shall cease. To the extent that AEP and CSW were
authorized, pursuant to Sections 32 and 33 of the 1935 Act and the rules
thereunder, to invest up to 100% of their consolidated retained earnings in EWG
and FUCO interests, the Combined Company should also be authorized to invest up
to 100% of its combined consolidated retained earnings in EWG and FUCO
interests. Applicants therefore propose that, upon consummation of the Merger,
the authority of the Combined Company to issue and sell securities in an amount
up to 100% of its consolidated retained earnings for investment in EWGs and
FUCOs shall be the same as that provided by American Elec. Power Co., HCAR No.
26864 (Apr. 27, 1998) and American Elec. Power Co., HCAR No. 26516 (May 10,
1996), except that for purposes of determining the amount of consolidated
retained earnings as contemplated by American Elec. Power Co., HCAR No. 26864
(Apr. 27, 1998) and American Elec. Power Co., HCAR No. 26516 (May 10, 1996),
'consolidated retained earnings' shall consist of the consolidated retained
earnings of the Combined Company.
Currently, the CSW System uses short-term debt, primarily commercial
paper, to meet working capital requirements and other interim capital needs. In
addition, to improve efficiency, CSW has established a system money pool (the
'Money Pool') to coordinate short-term borrowings for CSW, its U.S. electric
utility subsidiary companies and CSWS, as set forth in various Commission orders
(which orders are summarized in Exhibit I-2 attached hereto). AEP has no
equivalent to the Money Pool. Applicants hereby request authorization, upon
consummation of the Merger and on the same terms and conditions as set forth in
the orders summarized in Exhibit I-2, to permit: (1) the Combined Company, AEP's
U.S. electric subsidiary companies and AEPSC to participate in the Money Pool,
and (2) the Combined Company to manage and to fund the Money Pool. Exhibit I-2
summarizes the existing authority associated with the Money Pool and states the
additional authority requested for the Money Pool upon consummation of the
Merger. Applicants request that following the Merger, both the Combined Company
and CSW (for a transitional period) will have in aggregate the authority that
CSW has with respect to those orders summarized in Exhibit I-2.
CSW Credit purchases, without recourse, the accounts receivable of CSW's
U.S. electric utility subsidiary companies and certain non-affiliated utility
companies. The sale of accounts receivable provides CSW's U.S. electric utility
subsidiary companies with cash immediately, thereby reducing working capital
needs and revenue requirements. In addition, because CSW Credit's capital
structure is more highly leveraged than that of the CSW U.S. electric utility
subsidiaries and due to CSW Credit's higher short-term debt ratings, CSW's
overall cost of capital is lower. CSW Credit issues commercial paper to meet its
financing needs. Applicants hereby request approval, effective upon consummation
of the Merger, for the Combined Company to directly acquire, and for CSW to
transfer to the Combined Company, the business of CSW Credit through: (1) the
merger of CSW Credit with a subsidiary of the Combined Company to be formed, if
appropriate, (2) the dividending or distribution of the common stock of CSW
Credit from CSW to the Combined Company, or (3) the acquisition of the assets or
common stock of CSW Credit by a subsidiary of the Combined Company to be formed,
if appropriate. Applicants request that, upon the acquisition of the business of
CSW Credit by the Combined Company, the resulting company ('New Credit') succeed
to all of the authority of CSW Credit as set forth in various Commission orders
(which orders are summarized in Exhibit
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I-3 attached hereto). Exhibit I-3 summarizes the existing authority of CSW
Credit and states the authority requested for New Credit.
CSW has supported the financing and other activities of its subsidiaries
through obtaining Commission approval to issue and guarantee certain
indebtedness. After the Merger it may be more efficient or even commercially
necessary for the Combined Company to support certain of the financing
arrangements and business activity previously supported by CSW. Applicants
hereby request approval for the Combined Company, upon consummation of the
Merger, to support those financing and other activities presently supported by
CSW, including the issuance and guaranteeing of indebtedness, pursuant to those
orders of the Commission summarized in Exhibit I-4. Exhibit I-4 describes the
existing authority of CSW which Applicants seek to duplicate in favor of the
Combined Company. It is Applicants' intention that, following the Merger, both
the Combined Company and CSW will simultaneously have in aggregate the authority
that CSW currently has with respect to those orders summarized in Exhibit I-4.
The Combined Company does not seek to widen such authority which will
necessarily remain limited to the orders described in Exhibit I-4. The practical
effect of this approval would be to insert the Combined Company alongside CSW in
virtually all instances where CSW is mentioned in such orders.
Pursuant to Central and South West Corp., HCAR No. 26616 (Nov. 27, 1996),
this Commission confirmed previous authority and granted additional authority
such that CSW was authorized, through December 31, 2001, to offer 10,000,000
shares of CSW Common Stock pursuant to its Dividend Reinvestment and Stock
Purchase Plan, of which approximately 2,000,000 remain unissued. Pursuant to
American Elec. Power Co., HCAR No. 26553 (Aug. 13, 1996) this Commission
confirmed previous authority and granted additional authority such that AEP was
authorized, through December 31, 2000, to offer 54,000,000 shares of AEP Common
Stock pursuant to its Dividend Reinvestment and Direct Stock Purchase Plan.
Applicants hereby request that, as soon as practicable upon consummation of the
Merger, (1) the authority of CSW's Dividend Reinvestment and Stock Purchase Plan
be terminated, and (2) the Combined Company be authorized to issue 55,200,000
shares of AEP Common Stock through December 31, 2000 pursuant to its Dividend
Reinvestment and Direct Stock Purchase Plan consistent otherwise with all the
terms and conditions set forth in American Elec. Power Co., HCAR No. 26553 (Aug.
13, 1996).
Pursuant to Central and South West Corp., HCAR No. 26413 (Nov. 21, 1995),
this Commission confirmed previous authority and granted additional authority
such that CSW was authorized to issue and sell a total of 5,000,000 shares of
CSW Common Stock to the trustee of the Central and South West Thrift Plan, of
which approximately 4,400,000 remain unissued. Pursuant to American Elec. Power
Co., HCAR No. 26786 (Dec. 1, 1997), this Commission confirmed previous authority
and granted additional authority such that AEP was authorized, through December
31, 2001, to sell 8,800,000 shares of AEP Common Stock to the trustee of the
American Electric Power System Employees Savings Plan. Applicants hereby request
that, upon consummation of the Merger, (1) the authority of CSW to issue shares
of CSW Common Stock to the Central and South West Thrift Plan be terminated, and
(2) the Combined Company be authorized to issue 11,440,000 shares of AEP Common
Stock through December 31, 2001 in connection with the American Electric Power
System Employees Savings Plan and the Central and South West Thrift Plan (for a
transitional period) consistent otherwise with all the terms and
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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 each of the subsidiary companies of AEP,
provides various technical, engineering, accounting, administrative, financial,
purchasing, computing, managerial, operational and legal services to each of the
AEP subsidiary companies. Pursuant to the service agreements, these services are
provided at cost. The Commission has previously determined that AEPSC is so
organized and its business is so conducted as to meet the requirements of
Section 13(b) of the 1935 Act and Rule 88 thereunder. Amer. Elec. Power Service
Corp., HCAR No. 21922 (Feb. 19, 1981) (order authorizing service agreement
between service company and operating subsidiaries).
Similarly, CSWS is a service company which, pursuant to service
agreements signed with each of the subsidiary companies of CSW, provides various
technical, engineering, accounting, administrative, financial, purchasing,
computing, managerial, operational and legal services to each of the CSW
subsidiary companies. Pursuant to the service agreements, these services are
provided at cost. The Commission has also previously determined that CSWS is so
organized and its business is so conducted as to meet the requirements of
Section 13(b) of the 1935 Act and Rule 88 thereunder. Central and South West
Corp., HCAR No. 26293 (May 18, 1995).
Upon consummation of the Merger, CSWS will be merged with AEPSC, and
AEPSC will be the surviving service company for the Combined System. Applicants
intend that AEPSC will enter into an amended service agreement with AEP's
subsidiary companies and CSW's subsidiary companies. The proposed amended
service agreement is filed as Exhibit B-2. Under the amended service agreement,
AEPSC will provide the managerial, administrative, financial, technical, and
other services previously provided by the two service companies, CSWS and AEPSC.
The execution and performance by the respective parties of the amended service
agreement is subject to Section 13(b) of the 1935 Act and the rules thereunder.
To the extent not exempt under rules or otherwise under the 1935 Act,
Applicants' subsidiaries will provide
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services to each other at cost unless otherwise authorized by Commission orders.
See, e.g., Central and South West Corp., HCAR No. 26887 (June 19, 1998), AEP
Energy Services, Inc., HCAR No. 26267 (April 5, 1995) and AEP Resources, Inc.,
HCAR No. 26962 (Dec. 30, 1998) (authorizing certain non-regulated subsidiaries
of Applicants to provide services at fair market value).
The amended service agreement to be entered into between AEPSC and the
utility and nonutility subsidiary companies of AEP and CSW, which, pending
Commission approval, will become effective upon the consummation of the Merger,
is similar to those service agreements currently in place. Under the terms of
the amended service agreement, AEPSC will render services to the subsidiary
companies of the Combined Company at cost. AEPSC will account for, allocate and
charge its costs of the services provided on a full cost reimbursement basis
under a work order system consistent with the Uniform System of Accounts for
Mutual and Subsidiary Service Companies. Costs incurred in connection with
services performed for a specific subsidiary company will be billed 100% to that
subsidiary company. Costs incurred in connection with services performed for two
or more subsidiary companies will be allocated in accordance with the
attribution bases set forth in Exhibit B-3. Indirect costs incurred by AEPSC
which are not directly allocable to one or more subsidiary companies will be
allocated in proportion to how either direct salaries or total costs are billed
to the subsidiary companies depending on the nature of the indirect costs
themselves. The time AEPSC employees spend working for each subsidiary will be
billed to and paid by the applicable subsidiary on a monthly basis, based upon
time records. Each subsidiary company will maintain separate financial records
and detailed supporting records showing AEPSC charges.
Several state commissions have already approved the Merger and included
codes of conduct that will govern the relationship between AEPSC, the operating
companies, and other affiliated companies. For example, the orders of the
Indiana, Kentucky, Louisiana and Arkansas Commissions approving the Merger all
contain detailed guidelines relating to affiliate transactions. The order of the
Oklahoma Commission approving the Merger grants the Oklahoma Commission and the
State Attorney General access to the books and records of AEP and its affiliates
and subsidiaries (including their participation in joint ventures) with respect
to matters and activities that relate to Oklahoma retail rates. The settlement
with the staff of the Texas Commission requires compliance with a detailed code
of conduct governing activities among the Combined Company's subsidiaries. These
orders and agreements, consistent with state law, generally require certain
separations and safeguards between utility and nonutility affiliates to prevent
cross-subsidization and preferential treatment of nonutility affiliates.
Applicants hereby request that the Commission approve the amended service
agreement between AEPSC and the subsidiary companies of the Combined Company and
the related attribution bases listed in Exhibit B-3. The proposed attribution
bases are based on cost-drivers emphasizing factors that correlate to the volume
of activity that is inherent in performing certain services. The frequency at
which each attribution basis will be recalculated is noted in Exhibit B-3.1.
Exhibit B-3.2 compares the proposed attribution bases to the attribution
bases currently used by both AEPSC and CSWS. This exhibit also includes
explanations for the proposed differences. In all cases, the proposed
attribution bases are based on the attribution bases
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currently used by either AEPSC or CSWS with some variations. Exhibit B-3.3
identifies the scope of each of the attribution bases by class of companies.
Exhibit B-3.4 describes the services that will be performed by AEPSC after the
Merger and lists the attribution bases associated with each major service
category.
AEP currently utilizes the following principles in coordinating its work
order and billing control, planning and budgeting and internal audit functions
and expects that these principles will continue to govern such functions
following the Merger. An AEPSC work order may be initiated by AEPSC or by a
subsidiary company of AEP. Any AEPSC work order, whether for a single company or
multiple companies, including the proposed cost allocation method, must be
reviewed and approved by the AEPSC Corporate Accounting Department and then by a
person appointed by the subsidiary company. As a result of the centralization in
AEPSC of the responsibilities previously assigned to the officers of the
subsidiary companies, the Corporate Planning and Budgeting Department of AEPSC
has been appointed by the subsidiary companies to approve work orders. Corporate
Planning and Budgeting is independent of the AEPSC work order billing process,
which is maintained by the Corporate Accounting Department of AEPSC.
Time records are completed by or for each employee in AEPSC and approved
by work group supervisors. Charges are accumulated by the Corporate Accounting
Department of AEPSC and billed to each AEP subsidiary company at the end of each
month. These bills are reviewed for reasonableness and approved on behalf of the
AEP subsidiary companies by Corporate Planning and Budgeting.
Management has developed strategic performance measures for AEP and its
subsidiary companies as a business enterprise. These measures include earnings
per share, total shareholder return, competitive cost comparison, market share,
customer satisfaction and loyalty, employee development, safety and
productivity, and environmental performance. Management has developed targets
against which to measure the performance of AEP and its subsidiaries on a
consolidated basis. In addition, based upon these strategic performance measures
and targets, management has developed performance measures and targets for each
business group. These measures and targets focus on the business group, not on
the corporate entity; however, the expected impact of proposed plans and budgets
on expenses of the subsidiary companies is determined.
Efficiency in business operations is important in order to achieve
targets in some of the strategic performance measures, such as earnings per
share and competitive cost comparison. A new planning and budgeting system,
including activity based management, has been developed and implemented. This
system focuses on the business process - a network of related and interdependent
activities performed to achieve a specific purpose. It provides cost information
quickly and allows managers to evaluate the efficiency and value of processes,
including trends and internal benchmarks.
Using this planning and budgeting system, an annual budget is prepared by
each business unit and support organization and submitted to the Office of the
Chairman for approval. The Office of the Chairman consists of the Chairman of
the Board, President and Chief Executive Officer of AEP and AEPSC and the
executive vice presidents of AEPSC that report to him. A majority of these
officers are also directors and executive officers of each of the subsidiary
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companies. The Corporate Planning and Budgeting Group assists the business units
and support organizations in the planning and budgeting process and monitors
expenses. It also determines and reports the expected impact of proposed plans
and budgets on the expenses of the subsidiary companies.
The planning and budgeting process for AEPSC is part of the overall
process for the business units and support organizations and subject to approval
by the Office of the Chairman.
The AEPSC Internal Audits Department continuously conducts audits of the
functions of AEP and its subsidiaries, including those of AEPSC, to ensure that
proper internal controls exist and to determine if they are functioning as
intended and are efficient and effective. As a part of the audit plan, the
Internal Audits Department performs audits of the AEPSC work order system and
related billings to AEP subsidiary companies. The purpose of the audits is to
render an opinion on the internal controls over the work order billing process
and compliance with Commission-approved cost allocation billing methodologies.
The Internal Audits Department completed the latest review in 1997 and expressed
an opinion that the internal controls are functioning properly and that the
costs are being allocated to AEP subsidiary companies in accordance with the
Commission-approved cost allocation billing methodologies. The Department will
perform its next audit of the work order system and related billings in 1999 and
then every two years.
The Vice President of Internal Audits (the "Vice President") reports to
the Chairman of the Audit Committee of the Board of Directors of AEP (the "Audit
Committee"). Administratively, the Vice President reports to the Executive Vice
President - Financial Services of AEPSC. The Vice President attends each meeting
of the Audit Committee. In accordance with New York Stock Exchange listing
requirements, the Audit Committee is comprised solely of outside directors.
In December of each year, the results of the year's audit activities are
reviewed with the Audit Committee and the following year's audit plan is
reviewed and approved by the Audit Committee. The Audit Committee annually
reviews and approves the Internal Audits Department Charter to ensure that it
sufficiently allows the Vice President to carry out his duties. The Vice
President meets privately with the Audit Committee several times during the year
and has the addresses and telephone numbers of the Audit Committee members and
is free to contact them at any time. The Vice President is reminded in these
private meeting sessions that he has such freedom.
F. ACQUISITION OF NON-UTILITY BUSINESSES
Section 10(c)(1) provides that the Commission shall not approve an
acquisition that is "detrimental to the carrying out of the provisions of
Section 11." Section 11(b)(1) limits the non-utility interests of a registered
holding company to those that are "reasonably incidental, or economically
necessary or appropriate to the operations of such integrated public-utility
system." The Commission may find that a non-utility business meets this standard
when it finds that the interest in the business is "necessary or appropriate in
the public interest or for the protection of investors or consumers and not
detrimental to the proper functioning of such [integrated] system." CSW has a
number of non-utility businesses that AEP will indirectly acquire as a result
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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).(35) Such businesses have an operating or functional
relationship to CSW's utility operations. See, e.g., Conectiv, supra (the
Commission has interpreted section 11(b)(1) "to require the existence of an
operating or functional relationship between the utility operations of the
registered holding company and its nonutility activities.")
Upon consummation of the Merger, the non-utility businesses of CSW will
become indirect subsidiaries of AEP. To the extent that Commission approval is
necessary for the acquisition of CSW's non-utility businesses, the acquisitions
should be approved because the indirect ownership of CSW's non-utility
businesses by AEP in no way affects the functional relationship of these
businesses to the Combined Company's core electric business following the
Merger. Moreover, acquisition of these businesses is in the public interest and
consistent with the applicable standards under the 1935 Act.
G. ORGANIZATION OF MERGER SUB; ACQUISITION OF MERGER SUB COMMON STOCK
Merger Sub was organized solely for the purpose of effecting the Merger
and has not conducted any activities other than in connection with the Merger.
Merger Sub has no subsidiaries. Each share of common stock of Merger Sub, par
value $0.01 per share, to be issued to AEP and outstanding immediately before
the consummation of the Merger will be converted into one share of CSW Common
Stock upon consummation of the Merger. Thus, the sole purpose for Merger Sub is
to serve as an acquisition subsidiary of AEP for purposes of effecting the
Merger. Approval of this Application-Declaration will constitute approval of the
acquisition by AEP of the common stock of Merger Sub.
ITEM 4. REGULATORY APPROVAL
Set forth below is a summary of the material regulatory requirements affecting
the Merger. Failure to obtain any necessary regulatory approval or any adverse
conditions that are imposed in connection with any necessary regulatory
approval, including the failure to obtain appropriate ratemaking treatment, may
affect the consummation of the Merger.
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(35) 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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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.(36)
Further, both AEP and CSW are required to file notification and report forms
under the HSR Act with the DOJ with respect to the Merger. Additional consents
from or notifications to governmental agencies may be necessary or appropriate
in connection with the Merger.
Applicants already have obtained regulatory approvals of the Nuclear Regulatory
Commission, the Arkansas Commission, the Oklahoma Commission, the Louisiana
Commission, the Kentucky Commission, and the Indiana Commission. A settlement
has been reached with FERC trial staff which resolves most issues, including
issues related to rates and competition. A stipulated settlement with the
commission staff and key intervenor groups has been reached in the Texas
proceeding, and Applicants anticipate that the FERC and the remaining state
commissions asserting jurisdiction over the Merger will make similar public
interest findings and issue orders approving the Merger in the near future.
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 1999. 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
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(36) 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 and the Kentucky 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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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. The NRC Order is filed as Exhibit
D-6.2, and incorporated by reference. After the Merger, CPL, as an operating
utility subsidiary of the Combined Company, will continue to own the identical
pre-Merger interests in the STP and STP Operating.
C. FEDERAL POWER ACT
Section 203 of the FPA provides that no public utility may sell or
otherwise dispose of its jurisdictional facilities, directly or indirectly merge
or consolidate its facilities with those of any other person, or acquire any
security of any other public utility, without first having obtained
authorization from the FERC. On April 30, 1998, AEP and CSW filed a joint
application with the FERC seeking approval of the Merger, as supplemented on
January 13, 1999. See Exhibits D-1.1 and D-1.2. A procedural schedule has been
adopted by FERC which directs the Administrative Law Judge to issue an Initial
Decision no later than November 24, 1999. This schedule will allow FERC to issue
a decision no later than March 2000. Under Section 203 of the FPA, the FERC will
approve a merger if it finds the merger to be 'consistent with the public
interest.'
On June 24, 1999, Applicants and the FERC trial staff filed the FERC
Stipulation resolving major issues related to the Merger, including all
significant competition and rate issues. In addition, FERC Trial Staff agreed to
support a finding that the Merger will have no adverse effect on competition.
The FERC Stipulation is filed as Exhibit D-1.3.
Under the terms of the FERC Stipulation, prior to the consummation of the
Merger, AEP will file with the FERC a proposal whereby it would transfer certain
control area functions relating principally to reliability and access to an
RTO.(37) As part of the transfer, AEP agreed to transfer functions relating to
transmission service, transmission security and control area responsibility to
the RTO. In addition thereto, prior to December 31, 2000, AEP will file with the
FERC an unconditional application to transfer the corresponding control area
functions relating principally to reliability and access, controlled and/or
operated by AEP and currently located in the SPP to a FERC-approved RTO directly
interconnected with the facilities located outside the SPP.
The FERC Stipulation also addresses rates for transmission services and
ancillary services and confirms, subject to FERC guidance on the timing of
divestiture, that the previously
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(37) As noted in Item I.B.2.d. above, on June 3, 1999, AEP and four
other utilities filed the Alliance RTO Application. CSW is participating in the
ERCOT independent regional transmission plan for the portion of its system that
is within ERCOT and is participating in discussions with other interested
parties about the formation of an RTO that would include utility systems in the
SPP.
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announced generation divestiture program will satisfy the market power concerns
of the FERC trial staff. In its filing with FERC, the Applicants proposed
divesting ownership of 300 MW of generation capacity at CSW's Northeastern Power
Station Units 3 and 4 and 250 MW of generation capacity located at the Frontera
Power Plant, a merchant power plant being constructed by a CSW subsidiary near
Mission, Texas.
In addition to the waiver of transmission priorities that is explained in
the FERC testimony of Stephen B. Jones, Applicants agreed that they will not
assert the "AES/TVA" priority for any transfers of non-firm energy from AEP West
to AEP East for a period of four years from the date of the consummation of the
Merger.
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.
E. ARKANSAS COMMISSION
SWEPCO is subject to the jurisdiction of the Arkansas Commission.
Pursuant to Section 23-3-306(b) of the Arkansas Statutes, and Arkansas
Commission approval is required before any person may merge with or otherwise
acquire control of a domestic public utility. The Arkansas Commission must
approve a merger application unless it finds that one or more of five adverse
circumstances would result from the transaction. The circumstances include an
adverse effect on the public utility's existing obligations or quality of
service, a reduction in competition for the provision of utility services within
the state, and an adverse effect on the financial condition of the public
utility.
On June 12, 1998, AEP, CSW and SWEPCO filed an application with the
Arkansas Commission seeking Arkansas Commission approval of the Merger, a copy
of which is filed as Exhibit D-2.1 and incorporated by reference. On August 13,
1998, the Arkansas Commission issued an order conditionally approving the
Merger, a copy of which is filed as Exhibit D-2.2 and incorporated by reference.
F. LOUISIANA COMMISSION
SWEPCO is subject to the jurisdiction of the Louisiana Commission.
Pursuant to Louisiana Statutes Section 45:1164, the Louisiana Commission is
granted general supervisory authority over public utilities operating in the
state and, under this authority, the Louisiana Commission has held that its
approval or non-opposition is required prior to the sale, lease, merger,
consolidation, stock transfer, or any other change of control or ownership of a
public utility subject to its jurisdiction. The Louisiana Commission reviews
merger applications pursuant to an 18 factor test that generally relates to the
impact of the transaction on competition, the financial condition of the
utility, quality of service, public health and safety, employment, and other
similar "public interest" matters.
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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 conditionally approving the
Merger, a copy of which is filed as Exhibit D-4.2 and incorporated by reference.
The order of the Oklahoma Commission is currently the subject of an appeal.
H. TEXAS COMMISSION
CPL, SWEPCO, and WTU are subject to the jurisdiction of the Texas
Commission. Pursuant to Section 14.101 of the Texas Utilities Code, each
transaction involving the sale of at least 50 percent of the stock of a public
utility must be reported to the Texas Commission within a reasonable time. On
April 30, 1998, AEP, CSW, CPL, SWEPCO and WTU reported the Merger to the Texas
Commission for its review, as supplemented on January 15, 1999. See Exhibits
D-5.1 and D-5.2.
In reviewing a transaction involving the sale of at least 50 percent of
the stock of a Texas utility, the Texas Commission is required to determine
whether the action is consistent with the public interest, taking into
consideration factors such as the reasonable value of the property, facilities,
or securities to be acquired, disposed of, merged, transferred, or consolidated,
and whether the transaction will adversely affect the health or safety of
customers or employees, result in the transfer of jobs of Texas citizens to
workers domiciled outside of Texas, or result in the decline of service. If the
Texas Commission determines that a transaction is not in the public interest, it
may take the effect of the transaction into consideration in ratemaking
proceedings and disallow the effect of such transaction if such transaction will
unreasonably affect rates or service.
In the proceedings before the Texas Commission, Applicants reached a
settlement 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
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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 will not file testimony in
that proceeding. Furthermore, agreements have been reached with several
wholesale customer groups including South Texas Electric Cooperative (STEC) and
its member distribution cooperatives, the City of Brownsville Public Utility
Board, the East Texas Cooperatives, which includes East Texas Electric
Cooperative Inc., Northeast Texas Electric Cooperative, Inc., and Tex-La
Electric Cooperative of Texas, Inc., and a group of transmission dependent
utilities (TDUs), which includes Magic Valley Electric Cooperative, Inc. Mid-Tex
Generation and Transmission Electric Cooperative, Inc. and its members and
Rayburn Country Electric Cooperative.
I. INDIANA COMMISSION
On April 26, 1999, the Indiana Commission issued an order approving a
stipulation and settlement agreement among AEP, CSW, and the staff of the
Indiana Commission, a copy of which is filed as Exhibit D-8.1 and incorporated
by reference.
J. KENTUCKY COMMISSION
On May 24, 1999, the Kentucky Commission issued an order approving the
stipulation among AEP, CSW, Kentucky Industrial Customers Inc., Kentucky
Industrial Steel, Inc., and the Kentucky Attorney General, a copy of which is
filed as Exhibit D-7.1 and incorporated by reference.
K. MISSOURI COMMISSION
No regulatory authorization is required from the Missouri Commission.
However, in an effort to address concerns raised by the Missouri Commission with
respect to competitive impacts that may occur as a result of Applicants' use of
the Contract Path, Applicants agreed that, as part of a settlement between
Applicants and the Missouri Commission, the Missouri Commission may initiate,
within four years of the consummation of the Merger, a review by the FERC of the
Merger's effects on retail competition, assuming retail competition has been
implemented in Missouri. The settlement also gives the FERC discretion to decide
if mitigation measures are necessary to the extent that the review results in a
finding that the Contract Path is harmful to competition. Any relief ordered by
FERC cannot extend beyond six years after the consummation of the Merger.
L. 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.
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ITEM 5. PROCEDURE
The Commission is respectfully requested to issue and publish not later
than November 20, 1998, the requisite notice under Rule 23 with respect to the
filing of this Application-Declaration, such notice to specify a date not later
than December 15, 1998, by which comments may be entered and a date not later
than December 16, 1998, as the date after which an order of the Commission
granting and permitting this Application-Declaration to become effective may be
entered by the Commission.
It is submitted that a recommended decision by a hearing or other
responsible officer of the Commission is not needed for approval of the Merger.
The Division of Investment Management may assist in the preparation of the
Commission's decision. There should be no waiting period between the issuance of
the Commission's order and the date on which it is to become effective.
ITEM 6. EXHIBITS AND FINANCIAL STATEMENTS
Exhibit
Number Description
*A-1 Copy of Restated Certificate of Incorporation of AEP, dated October
29, 1997 (filed as Exhibit 3(a) to the Quarterly Report on Form 10-Q
for the period ended September 30, 1997 (File No. 1-3525) and
incorporated herein by reference)
*A-2 Second Restated Certificate of Incorporation of CSW (filed as
Exhibit 3(1) to the Form 10-K for the fiscal year ended December 31,
1997 (File No. 1-1443) and incorporated herein by reference)
*A-3 Certificate of Incorporation of Merger Sub
*A-4 By-laws of Merger Sub
*B-1 Agreement and Plan of Merger among AEP, CSW and Merger Sub, dated at
December 21, 1997 (filed as Annex A to the Registration Statement on
Form S-4 on April 15, 1998 (Registration No. 333-50109) and
incorporated herein by reference))
*B-2 Proposed Service Agreement between AEPSC and subsidiaries of the
Combined Company
*B-3 Proposed Attribution basis List
*B-3.1 Update Frequencies Applicable to the Proposed AEPSC Attribution
Bases
*B-3.2 Comparison of AEPSC and CSWS Current Attribution Bases to Proposed
Post-Merger AEPSC Attribution Basis
*B-3.3 Scope of the Proposed Post-Merger AEPSC Attribution Bases by Class
of Companies
105
<PAGE> 106
*B-3.4 Description of Services to be Provided by AEPSC Post-Merger and
Associated Attribution bases by Category of Services
*C-1 Registration Statement of AEP on Form S-4 (as amended) (filed as
Registration Statement No. 333-50109 and incorporated herein by
reference)
*C-2 Joint Proxy Statement and Prospectus (included in Exhibit C-1)
*D-1.1 Joint Application of jurisdictional subsidiaries of AEP and CSW
before the FERC, together with exhibits, appendices and workpapers,
dated April 30, 1998 (filed on Form SE) and consisting of:
VOLUME 1 - Exhibit D-1.1
Transmittal Letter dated April 30, 1998 for Section 203 of the FPA and
part 33 of the FERC's Regulations
Joint Application of AEP and CSW for Authorization and Approval of Merger
for Section 203 Filing
Appendix 1 -Designation of the Territories Served, by States and Counties
Appendix 2 -Morgan Stanley Letter to the Board of Directors concerning
Merger; Opinion Letter from Salomon Smith Barney to Board of
Directors dated December 21, 1997
Appendix 3 -AEP and CSW Companies Community and Franchise Expiration Date
Exhibit A - Certified Copy of a Resolution of the Board of Directors of
Central and South West Corporation Adopted on December 21, 1997
Exhibit B - Statement of Measures of Control of Ownership over AEP and
CSW
Exhibit C - Balance Sheets and Supporting Plant Schedules
Exhibit D - Consolidated Statement of Contingencies and Commitments as
of December 31, 1997
Exhibit E - Income Statements
Exhibit F - Analysis of Retained Earnings
Exhibit G - Copies of State and Federal Applications and Exhibits
Exhibit H - Agreement and Plan of Merger among AEP and CSW
Exhibit I - Territory Service Maps of AEP, CSW and the Ameren
Interconnection
VOLUME 2 - Exhibit D-1.1
106
<PAGE> 107
Testimonies and Exhibits for Section 203 Filing of the Following
Witnesses: Draper, Shockley, Munczinski, Baker, Hieronymus, Jones,
Bethel and Maliszewski
VOLUME 3 - Exhibit D-1.1
Workpapers of Witnesses Munczinski and Hieronymus for Section 203 Filing
VOLUME 4 - Exhibit D-1.1
Transmittal Letter dated April 30, 1998 for Section 205 of the FPA and
part 35 of the FERC's Regulations
System Integration Agreement among AEP companies and CSW companies
AEPSC Transmission Reassignment Tariff
Testimony and Exhibits of J. Craig Baker in Support of the System
Integration Tariff
System Transmission Integration Agreement among AEP companies and CSW
companies
Testimony and Exhibits of Dennis W. Bethel in Support of the System
Transmission Integration Agreement
VOLUME 5 - Exhibit D-1.1
Transmittal Letter dated April 30, 1998 for Section 205 of the FPA
Open Access
Transmission Service Tariff of the AEP System
VOLUME 6 - Exhibit D-1.1
AEP System Procedures for Implementation of the FERC Standards of Conduct
Testimony and Exhibits of Dennis W. Bethel
Testimony and Exhibits of Bruce M. Barber
VOLUME 7 - Exhibit D-1.1
Workpapers of Dennis W. Bethel
*D-1.2 Supplemental and Direct Testimony before the FERC, January 13, 1999
filed herewith on Form SE) and consisting of:
VOLUME 1 - Exhibit D-1.2
Transmittal Letter dated January 13, 1999
Supplemental and Direct Testimonies and Exhibits for the Following
Witnesses: Baker, Jones, Smith, Maliszewski, Henderson
107
<PAGE> 108
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 (filed _______, 1999).
*D-2.1 Joint Application of AEP, CSW and SWEPCO before the Arkansas
Commission, together with exhibits, appendices, and workpapers,
dated June 12, 1998 (filed on Form SE) and consisting of:
VOLUME 1 - Exhibit D-2.1
Joint Application with Exhibits of AEP, SWEPCO, and CSW regarding Merger
Exhibit A - AEP's Corporate Structure and Listing of Affiliate Companies
and Business Engaged
Exhibit B - Restated Certificate of Incorporation of AEP
Exhibit C - Statement of Directors' and Officers' Qualifications
Exhibit D - AEP's 1997 Summary Report to Shareholders
Exhibit E - Annual Report of AEP on Form 10-K for the Year Ended
December 31, 1997 (File No. 1-3525)
Exhibit F - Quarterly Report of AEP on Form 10-Q for the Quarter Ended
March 31, 1998 (File No. 1-3525)
Exhibit G - Registration Statement of AEP on Form S-4, Amendment No. 1
(Registration No. 333-50109)
Exhibit H - Notice to Customers of SWEPCO
108
<PAGE> 109
VOLUME 2 - Exhibit D-2.1
Direct Testimony and Exhibits of the Following Witnesses: Draper,
Shockley, Flaherty, Baker, Munczinski, Roberson, Davis, Hieronymus,
Mitchell, Pena, Martin and Bailey
VOLUME 3 - Exhibit D-2.1
Workpapers of Witness Roberson
Workpapers of Witness Davis
VOLUME 4 - Exhibit D-2.1
Continued Workpapers of Witness Davis
Workpapers of Witness Pena
Workpapers of Witness Martin
Workpapers of Witness Munczinski
VOLUME 5 - Exhibit D-2.1
Workpapers of Witness Flaherty
VOLUME 6 - Exhibit D-2.1
Continued Workpapers of Witness Flaherty
D-2.2 Order of Arkansas Commission conditionally approving the Merger, dated
August 13, 1998
*D-3.1 Joint Application of AEP, CSW and SWEPCO before the Louisiana Commission,
together with exhibits, appendices and workpapers, dated May 15, 1998
(filed on Form SE) and consisting of:
VOLUME 1 - Exhibit D-3.1
Joint Application of SWEPCO, CSW, and AEP for Approval of Proposed
Business Combination
Testimony and Exhibits of the Following Witnesses: Draper, Shockley,
Flaherty, Baker, Munczinski, Roberson, Davis, Hieronymus, Mitchell,
Pena, Martin and Bailey
VOLUME 2 - Exhibit D-3.1
Workpapers of Witness Roberson
Workpapers of Witness Davis
109
<PAGE> 110
VOLUME 3 - Exhibit D-3.1
Continued Workpapers of Witness Davis
Workpapers of Witness Pena
Workpapers of Witness Martin
Workpapers of Witness Munczinski
VOLUME 4 - Exhibit D-3.1
Workpapers of Witness Flaherty
VOLUME 5 - Exhibit D-3.1
Continued Workpapers of Witness Flaherty
D-3.2 Order of the Louisiana Commission conditionally approving the Merger,
dated July 29, 1999 (to be filed by amendment)
*D-4.1 Joint Application of AEP, CSW and PSO before the Oklahoma Commission,
together with exhibits, appendices and workpapers, dated August 14, 1998
(filed on Form SE) and consisting of:
VOLUME 1 - Exhibit D-4.1
Joint Application of AEP, PSO and CSW regarding Proposed Merger
Appendix 1-Statement Required by 17 O.S. sec. 191.3
Appendix 2 -Notice of Hearing
Exhibit A - AEP's Corporate Structure and Listing of Affiliate Companies
and Business Engaged
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)
110
<PAGE> 111
Exhibit G - Registration Statement of AEP on Form S-4, Amendment No. 1
(Registration No. 333-50109)
VOLUME 2 - Exhibit D-4.1
Direct Testimony and Exhibits of the Following Witnesses: Draper,
Shockley, Flaherty, Baker, Munczinski, Roberson, Davis, Hieronymus,
Mitchell, Pena, Evans and Bailey
VOLUME 3 - Exhibit D-4.1
Workpapers of Witness Flaherty
VOLUME 4 - Exhibit D-4.1
Continued Workpapers of Witness Flaherty
Workpapers of Witness Munczinski
Workpapers of Witness Roberson
VOLUME 5 - Exhibit D-4.1
Workpapers of Witness Davis
VOLUME 6 - Exhibit D-4.1
Continued Workpapers of Witness Davis
Workpapers of Witness Pena
Workpapers of Witness Evans
D-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
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<PAGE> 112
VOLUME 3 - Exhibit D-5.1
Workpapers of Witness Roberson
Workpapers of Witness Davis
Workpapers of Witness Pena
Workpapers of Witness Evans
*D-5.2 Direct Testimony, Supplemental Direct Testimony and Second Supplemental
Direct Testimony before the Texas Commission, January 15, 1999 (filed
herewith on Form SE) and consisting of:
Transmittal Letter dated January 15, 1999
Supplemental and Direct Testimonies and Exhibits of the Following
Witnesses: Hieronymus, Jones, Mitchell, Roberson
D-5.3 Stipulation and Agreement between the Public Utility Commission of Texas
General Counsel, the State of Texas (in its capacity as a consumer of
electricity), the Texas Industrial Energy Consumers, Low Income
Intervenors, the Office of Public Utility Counsel, and the Steering
Committee of the Cities of McAllen, Corpus Christi, Victoria, Abilene,
Big Lake, Vernon and Paducah.
*D-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 (to be filed by
amendment)
*E-1 Map of AEP service area, major transmission lines and interconnection
points (filed on Form SE)
*E-2 Map of CSW service area, major transmission lines and interconnection
points (filed on Form SE)
*E-3 Map of transmission lines showing the 250 MW Contract Path linking the
Combined System (filed on Form SE)
*E-4 AEP corporate chart (filed on Form SE)
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<PAGE> 113
*E-5 CSW corporate chart (filed on Form SE)
*E-6 Combined Company corporate chart after the Merger (filed on Form SE)
F-1 Opinion of Counsel (to be filed by amendment)
F-2 Opinion of Counsel (to be filed by amendment)
F-1-1 Past-tense Opinion of Counsel (to be filed by amendment)
F-2-1 Past-tense Opinion of Counsel (to be filed by amendment)
*G-1 Annual Report of AEP on Form 10-K for the year ended December 31, 1997,
as amended, (File No. 1-3525) and incorporated herein by reference
*G-2 Quarterly Report of AEP on Form 10-Q for the quarter ended March 31, 1998
(File No. 1-3525) and incorporated herein by reference
*G-3 Quarterly Report of AEP on Form 10-Q for the quarter ended June 30, 1998
(File No. 1-3525) and incorporated herein by reference
*G-4 Annual Report of CSW on Form 10-K for the year ended December 31, 1997
(File No. 1-1443) and incorporated herein by reference
*G-5 Quarterly Report of CSW on Form 10-Q for the quarter ended March 31, 1998
(File No. 1-1443) and incorporated herein by reference
*G-6 Quarterly Report of CSW on Form 10-Q for the quarter ended June 30, 1998
(File No. 1-1443) and incorporated herein by reference
*G-7 AEP Consolidated Balance Sheet as of June 30, 1998 (incorporated by
reference to the Quarterly Report on Form 10-Q of AEP for the quarterly
period ended June 30, 1998 (File No. 1-3525)
*G-8 Combined Company Unaudited Pro Forma Combined Balance Sheet at June 30,
1998
*G-9 AEP Statement of Income for the period ended June 30, 1998 (incorporated
by reference to the Quarterly Report on Form 10-Q of AEP for the
quarterly period ended June 30, 1998 (File No. 1-3525)
*G-10 Combined Company Unaudited Pro Forma Combined Statement of Income for the
twelve-month period ended June 30, 1998
*G-11 Combined Company Unaudited Pro Forma Combined Statement of Retained
Earnings for the twelve-month period ended June 30, 1998
*G-12 CSW Consolidated Balance Sheet as of June 30, 1998 (incorporated by
reference to the Quarterly Report on Form 10-Q of CSW for the quarterly
period ended June 30, 1998 (File No. 1-1443)
113
<PAGE> 114
*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
*H Proposed Form of Notice
*I-1 CSWS Authorizations
*I-2 Short-Term Borrowing Program
*I-3 CSW Credit Authorizations
*I-4 CSW Guarantee Authorizations
*J Tax Basis Discussion
K Agreement between Applicants and International Brotherhood of Electrical
Workers
* Previously filed.
ITEM 7. INFORMATION AS TO ENVIRONMENTAL EFFECTS
The Merger neither involves "major federal actions" nor "significantly
[affects] the quality of the human environment" as those terms are used in
Section (2)(C) of the National Environmental Policy Act, 42 U.S.C. Sec. 4332.
The only federal actions related to the Merger 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.
114
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SIGNATURE
Pursuant to the requirements of the Public Utility Holding Company
Act of 1935, the undersigned companies have duly caused this statement to be
signed on their behalf by the undersigned thereunto duly authorized.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: /s/ A. A. Pena
-------------------------------------------
Treasurer
CENTRAL AND SOUTH WEST CORPORATION
By: /s/ Wendy G. Hargus
-------------------------------------------
Treasurer
Dated: August 19, 1999
115
<PAGE> 1
Exhibit D-1.3
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
American Electric Power Company, Inc. ) Docket Nos. EC98-40-000
And ) ER98-2770-000
Central and South West Corporation ) ER98-2786-00
STIPULATION OF AMERICAN ELECTRIC POWER COMPANY, INC.
CENTRAL AND SOUTH WEST CORPORATION AND
COMMISSION TRIAL STAFF
For the purposes of evaluating the justness and reasonableness of the
System Integration Agreement, the Transmission Reassignment Tariff and the
System Transmission Integration Agreement proposed by American Electric Power
Company, Inc. ("AEP") and Central and South West Corporation
("CSW")(collectively "Applicants"), the Applicants and the Trial Staff hereby
enter into this Stipulation. This Stipulation resolves all issues between
Applicants and the Trial Staff regarding the System Integration Agreement, the
Transmission Reassignment Tariff and the System Transmission Integration
Agreement in the above-referenced consolidated dockets ("this proceeding"),
except the pricing of system energy exchanges under the System Integration
Agreement. Applicants and the Trial Staff stipulate and agree as follows:
I. SYSTEM INTEGRATION AGREEMENT (SIA)
A. ARTICLE 7.3 OF THE SYSTEM INTEGRATION AGREEMENT WILL BE MODIFIED TO
READ AS FOLLOWS:
Whenever either the AEP East Zone or the AEP West Zone has surplus
capacity relative to is capacity planning reserve requirements or
otherwise has capacity available for sale, and the other zone has
insufficient capacity relative to its capacity planning reserve
requirements, the surplus zone, acting through the Agent, shall make
its surplus capacity available to the other zone for periods of one
(1) year or less, subject to the Interconnection Constraints. Such
capacity exchanges shall only be made when the selling region's
foregone opportunity cost to sell capacity is lower than the buying
region's decremental capacity purchase cost.
<PAGE> 2
B. THE FOLLOWING DEFINITIONS WILL BE ADDED TO THE SYSTEM INTEGRATION
AGREEMENT:
Foregone Opportunity cost as it relates to capacity exchanges means
what the supplier could have sold the capacity for in its own zonal
market if the capacity exchange did not take place, i.e., Market
Price. The determination of Market Price shall be based on actual
sales of similar characteristics to unaffiliated third parties. In the
event that no such sales are available, documentable offers from
unaffiliated third parties shall determine the Market Price. In the
event that no such offers are available, a published index of capacity
market price shall determine the Market Price.
Decremental Capacity Cost in the recipient zone means the lower of the
recipient's cost of capacity installation or capacity purchase price
in its own zonal market, i.e., Market Price. The determination of
Market Price shall be based on actual purchases of similar
characteristics from unaffiliated third parties. In the event that no
such purchases are available, documentable offers from unaffiliated
third parties shall determine the Market Price. In the event that no
such offers are available, a published index of capacity market price
shall determine the Market Price.
Owned General Capacity is the aggregate capacity of the electric power
sources of the zone, in Kilowatts, that is normally expected to be
available to carry load. Such capacity shall include (i) the capacity
installed at the generating stations owned by the operating companies
in the zone and (ii) the capacity available to the operating companies
of the zone through arrangements with affiliated companies or
unaffiliated companies, if so designated by the Operating Committee
with the approval of the operating companies.
C. THE FOLLOWING PROVISION WILL BE ADDED TO THE TEXT AT THE END OF
PARAGRAPH A2 OF SERVICE SCHEDULE A:
At such time as the Agent determines an allocation among the operating
companies of new capacity that AEP has constructed or purchased, AEP
will convey its decision respecting such allocation to its wholesale
customers buying at a cost-of-service rate and each state regulatory
commission with jurisdiction over the operating companies. Each such
customer buying at a cost-of-service rate and each state regulatory
commission shall retain any right provided them under the Federal
Power Act to challenge AEP's decision.
D. ALLOCATION OF TRADING MARKET REALIZATIONS
Add as the last two sentences to Service Schedule D, Paragraph D3 --
Allocation of Trading and Marketing Realizations, the following
language: "This allocation of trading market realization shall be in
effect until the last day of the fifth full calendar year following
the consummation of the merger. At least sixty days prior to the day
specified in the preceding sentence, Agent shall file with the
-2-
<PAGE> 3
FERC under Section 205 of the Federal Power Act the methodology to
allocate trading market realizations thereafter, supported by evidence
demonstrating the justness and reasonableness of the filed
methodology."
E. PRICING OF SYSTEM ENERGY EXCHANGES
Applicants and Trial Staff agree that the issue of pricing for system
energy exchanges pursuant to Service Schedule C would be most efficiently
addressed as a policy issue briefed directly to the Commission. Accordingly, it
is the intention of Applicants and Trial Staff that each will present their
position on this aspect of the System Integration Agreement directly to the
Commission for resolution and that the issue need not be addressed by the
Presiding Judge.
II. TRANSMISSION REASSIGNMENT TARIFF (TRT)
A. TERMINATION PROVISIONS
The words "in accordance with Commission regulations" will be added after
the word "Agreement" in the first line of Section 3.3 of the Form of Service
Agreement.
B. REFUNDS FOR RECALLED TRANSMISSION CAPACITY
Article III.D. shall be modified to include the following sentence at the
end:
The availability of refunds for service sold under this Transmission
Reassignment Tariff shall be covered in the Service Agreement, or, for
short-term transactions, in the umbrella Service Agreement, between AEP and
the Eligible Customer purchasing the reassigned transmission capacity.
C. EFFECT OF TARIFF TERMINATION
Amend Section IV.C of the Transmission Reassignment Tariff by adding this
sentence to the end: "A notice of termination of this tariff by Reseller shall
1) terminate Reseller's obligation to provide service under any new Service
Agreement or provide new transactions under an umbrella Service Agreement
immediately and 2) eliminate all tariff obligations at the time that the last
remaining service arrangement initiated prior to the notice of termination is
completed."
III. SYSTEM TRANSMISSION INTEGRATION AGREEMENT (STIA)
The following sentence from Part A2 of Service Schedule A in the System
Transmission Integration Agreement,
When new Transmission Facilities are acquired or installed after the
effective date of the Agreement to meet the Combined System's
requirements, the associated costs shall be allocated between the AEP
East Zone and AEP West Zone in
-3-
<PAGE> 4
proportion to the amount of new Transmission Facilities required in
each zone, as determined by the Agent.
will be deleted and replaced by:
Likewise, the operating companies in the AEP East Zone and the
operating companies in the AEP West Zone each shall have full
responsibility for all costs relating to new Transmission Facilities they
may acquire or install in their respective zones after the effective date
of the Agreement which do not create a direct linkage between the AEP East
and West Zones. When new Transmission Facilities are acquired or installed
after the effective date of the Agreement to further integrate the AEP East
and West Zones, the associated costs shall be allocated equally between the
AEP East Zone and AEP West Zone.
IV. GENERAL PROVISIONS
Applicants and the Trial Staff shall support this Stipulation in all
proceedings before this Commission, and based on this Stipulation, Applicants
and the Trial Staff shall support a finding that the above-mentioned
agreements, as modified by this stipulation, are just and reasonable.
Applicants and the Trial Staff further agree that neither will challenge any
presentation by a signatory to this stipulation with respect to the matters at
issue in this proceeding, so long as such presentation is in accord with this
Stipulation, and that each will support this Stipulation as a resolution of the
matters addressed herein as consistent with the requirements of the Federal
Power Act. Each party shall be free to argue, in response to challenges by
other parties, that this Stipulation is justified as a compromise of more
favorable positions or principles that such party supported, but neither party
may ask the Commission to vary from this Stipulation for purpose of this
proceeding.
This Stipulation is not intended to bind any party that is not a signatory
hereto, and is not intended to set a precedent for future cases or to bind any
party in any further proceeding with respect to any matter set forth herein. No
term in this Stipulation may be modified without the express written consent of
all signatories.
/s/ James A. Pepper /s/ J.A. Bouknight
James A. Pepper J.A. Bouknight, Jr.
Commission Trial Staff Counsel for American
Electric Power Company, Inc.
/s/ Clark Evans Downs
Clark Evans Downs
Counsel for Central and
South West Corporation
-4-
<PAGE> 5
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
American Electric Power Company, Inc. ) Docket Nos. EC98-40-000
And ) ER98-2770-000
Central and South West Corporation ) ER98-2786-000
STIPULATION OF AMERICAN POWER COMPANY, INC.,
CENTRAL AND SOUTH WEST CORPORATION
AND COMMISSION TRIAL STAFF
For the purposes of evaluating the consistency of the merger proposed by
American Electric Power Company, Inc. ("AEP") and Central and South West
Corporation ("CSW")(collectively "Applicants") with the public interest and for
evaluating the rates proposed by the Applicants for transmission and ancillary
services for post merger operations, Applicants and the Trial Staff hereby enter
into this Stipulation. This Stipulation resolves all issues between Applicants
and the Trial Staff regarding the matters set for hearing in the
above-referenced consolidated dockets ("this proceeding") except for the issues
pertaining to system integration agreements and ratepayer protection. In
addition, a question related to the timing of divestiture will be resolved by
direct presentation to the Commission, as described below.
Applicants and the Trial Staff stipulate and agree as follows:
I. RATES
The rates identified in Attachment A to this Stipulation shall be placed
into effect as of the date on which the merger is consummated. Notwithstanding
the foregoing, the Applicants shall have the right to tender for filing pursuant
to section 205 of the Federal Power Act changes in any or all of
<PAGE> 6
the rates identified in Attachment A and to seek an effective date on or after
the date on which the merger is consummated.
II. REGIONAL TRANSMISSION ORGANIZATION
A. Prior to consummation of the merger AEP will file with the Federal
Energy Regulatory Commission ("FERC") a proposal to transfer to a
regional transmission organization ("RTO") the operation and control
of bulk transmission facilities owned, controlled, and/or operated by
AEP in Indiana, Michigan, Kentucky, Ohio, Tennessee, Virginia and
West Virginia ("AEP East"). In addition, Applicants reconfirm the
commitments made in paragraph 7A of the Stipulation and Agreement
attached to the order of the Indiana Utility Regulatory Commission
dated April 26, 1999 in Cause No. 41210, which paragraph is reproduced
in Attachment B to this Stipulation and incorporated herein.
B. Prior to December 31, 2000, AEP will file with the FERC an
unconditional application to transfer the operation and control of
bulk transmission facilities owned, controlled and/or operated by AEP
and currently located in the Southwest Power Pool ("AEP West") to a
FERC-approved RTO directly interconnected with the AEP West
transmission facilities. Such transfer of operations shall be
consistent with the applicable RTO. The above date shall be extended,
if necessary, to 75 days after FERC issues an order on an RTO to which
AEP is a signatory that is filed before June 30, 2000.
C. If AEP meets its commitments pursuant to provision A in a manner other
than joining the Midwest ISO, the provisions of the following
paragraphs C.1., C.2., C.3. shall
<PAGE> 7
apply. If AEP meets its commitments pursuant to provision A by joining the
Midwest ISO, then only paragraph C.2. shall apply.
1. For AEP East, AEP will provide generation dispatch information necessary
for the Midwest ISO to monitor the effect of such dispatch on the loading
of the Midwest ISO's constrained transmission facilities. The Midwest ISO,
in consultation with AEP, shall determine the format, quantity, and timing
of the data submissions necessary to perform such monitoring. The
information provided by AEP shall be subject to appropriate confidentiality
provisions. AEP's obligation to submit such data shall be effective at such
time as the Midwest ISO has procedures in place to assure that there is no
disclosure of company-specific information or contemporaneous data.
2. For AEP East, AEP agrees to transfer functions relating to transmission
service, transmission security and control area responsibility, as
described in Attachment C, to the FERC-approved RTO to which it transfers
operation and control of its bulk transmission facilities pursuant to
provision A. AEP will transfer these functions by leasing and/or selling
the present AEP System Control Center ("SCC") site and facilities to the
RTO, and providing the present SCC employees the opportunity to transfer to
the RTO with all the financial conditions necessary to create independence
from AEP. AEP's transfer of such functions shall be conditional on:
a) the RTO, in consultation with AEP, determining that the RTO has the
capability to accept responsibility for these functions;
<PAGE> 8
b) systems being in place for AEP to retain economic dispatch and
automatic general control ("AGC") functions and allow separation for
wholesale transaction billing;
c) the RTO, in consultation with AEP, developing guidelines and
procedures whereby the Area Control Error ("ACE") values calculated
and communicated by the RTO to AEP are combined with AEP's own
economic dispatch values to permit AEP to directly pulse its
generating units under AGC; and
d) transmission functions other than those listed in Attachment C to this
Stipulation being transferred to other AEP regional facilities.
3. AEP commits to participate in ancillary services and balancing markets
developed by the RTO or an RTO-authorized Regional Power Exchange. AEP will
bid to redispatch generators consistent with bidding requirements
established by the RTO for all parties that control the dispatch of
generating facilities taking service from the RTO.
<PAGE> 9
III. INTERIM TRANSMISSION PROVISION
A. It is AEP's position that it currently is, and at all times has been,
in compliance with all applicable requirements with respect to the
provision of transmission service, including its open access
transmission tariff. AEP's agreement to the following conditions
shall not be construed as evidence of or an admission that its
current or historical practices are or have been in violation of any
such applicable requirement.
1. AEP will file for a declaratory order that its "flexible
point-to-point" service is permitted under AEP's Open Access
Tariff or other transmission service agreements on file with the
Commission.
2. AEP will post on OASIS the status of all AEP East transmission
facilities, including planned maintenance, for the period of the
ATC postings.
B. AEP will follow ECAR Security Coordinator procedures for posting
transmission loading relief ("TLR") logs.
IV. DIVESTITURE
Applicants and Trail Staff agree that the Applicants will divest the
Frontera and Northeastern Units 3 and 4 as proposed in the testimony of Witness
Stephen B. Jones, with a buy-back condition and the presentation of one reserved
issue. The divestiture requirement must not infringe upon AEP-West's ability to
serve native load. The divestiture proposal should include a buy-back clause
such that AEP West can purchase the firm power it needs to serve native load.
<PAGE> 10
The reserved issue will be presented directly to the Commission for
decision based on the comments on this settlement submitted by the participants
in this proceeding. Specifically, the Commission's Trial Staff, the Applicants,
and other parties shall have the right to address in comments whether the
Commission should order an immediate divestiture of these facilities or whether
the divestiture should occur under both the conditions stated in Witness Jones'
testimony and the additional conditions incorporated in the stipulation entered
into in the proceeding before the Oklahoma Corporation Commission, Cause No.
PUD 980000444, dated April 16, 1999 and attached as Attachment D to this
Stipulation. These additional conditions are contained in Section 7, third
paragraph of the stipulation and require an informational filing before the
Oklahoma Corporation Commission should the conditions proposed by the Applicants
in this FERC proceeding be changed.
Trial Staff and the Applicants agree that the question of whether
immediate divestiture should be required should be presented to the Commission
in light of two questions. The first question is whether it is appropriate to
permit the timing of the divestiture to occur so as to assure that pooling of
interests accounting not be jeopardized. The second question is whether a
change in the timing for the divestiture for Northeastern Units 3 and 4 is
consistent with the deference that the Commission should provide to the Oklahoma
Corporation Commission's determination as to the conditions necessary to protect
the interests of Applicants' Oklahoma retail customers. Trial Staff and
Applicants further agree to limit their comments in support of their position on
this reserved issue to the two questions stated in this paragraph. Applicants
reserve the right to address other arguments raised in the comments of other
parties that assert other bases to accelerate the timing of the divestiture of
the Frontera and Northeastern Units 3 and 4.
<PAGE> 11
Applicants agree that the conditions of sale for Northeastern Units 3 and
4 will provide that the purchaser(s) of the units shall be guaranteed that
planned (maintenance) outage schedules shall be made only with the mutual
consent of the merged company and the purchaser(s).
V. APPLICANTS' WAIVER OF TRANSMISSION PRIORITY
In addition to the waiver of transmission priorities otherwise available
to Applicants that is contained in the testimony of Witness Stephen B. Jones,
Applicants further agree that they will not assert the "AES/TVA" priority for
any transfers of energy from AEP West to AEP East for a period of four years
from the date of the consummation of the merger.
VI. LOSSES AND LOSS COMPENSATION SERVICE
A. The Real Power Loss Factor stated in Sections 15.7 and 28.5 of the post
merger AEP open access transmission tariff ("Tariff") shall be 3.3% for
AEP East and shall be 2.9% for AEP West.
B. The following sentence shall be added after the second sentence of
SCHEDULE 20 of the Tariff regarding Loss Compensation Service: "Charges
for Loss Compensation Service shall be pursuant to rates negotiated
between the Transmission Customer and the Transmission Provider."
C. The following sentence shall be added after the first sentence of
SCHEDULES 7 and 8 of the Tariff regarding Firm and Non-Firm
Point-to-Point Transmission Service: "Capacity Reservations at the
Point(s) of Receipt will be inclusive of transmission losses, unless the
Transmission Customer opts to deliver energy to compensate for losses at
a different point pursuant to another capacity reservation."
<PAGE> 12
VII. GENERAL PROVISIONS
Applicants and Trial Staff shall support this Stipulation in all
proceedings before this Commission, and based on this Stipulation, Trial Staff
shall support a finding that the merger will have no adverse effect on
competition. Applicants and the Trial Staff further agree that neither will
challenge the other party's presentation with respect to the matters at issue
in this proceeding, so long as such presentation is in accord with this
Stipulation, and that each will support this Stipulation as a resolution of the
matters addressed herein as consistent with the requirements of the Federal
Power Act. Each party shall be free to argue, in response to challenges by
other parties, that this Stipulation is justified as a compromise of more
favorable positions or principles that such party supported, but neither party
may ask the Commission to vary from this Stipulation for purpose of this
proceeding.
This Stipulation is not intended to bind any party that is not a signatory
hereto, and is not intended to set a precedent for future cases or to bind any
party in any further proceeding with respect to any matter set forth herein. No
term in this Stipulation may be modified without the express written consent of
both parties.
<TABLE>
<S> <C>
/s/James A. Pepper /s/J.A. Bouknight
- ------------------- ------------------------
James A. Pepper J.A. Bouknight, Jr.
Commission Trial Staff Counsel for American
Electric Power Company, Inc.
/s/Clark Evans Downs
--------------------------
Clark Evans Downs
Counsel for Central and
South West Corporation
</TABLE>
May 24, 1999
<PAGE> 13
ATTACHMENT A
Settlement Rates
----------------
Transmission and Ancillary Services
-----------------------------------
All values in $/MW-mo. unless otherwise stated
AEP East
- --------
Transmission:
Point to Point Firm $1,420.00
Network $349,712,000 Net Annual Revenue Requirement
Rolling 12 CP Load Ratio Share
<TABLE>
<CAPTION>
Ancillary Services Purch.% Gen. Unit Cap. Rate Monthly Rates
- ------------------ ------- ------------------- -------------
<S> <C> <C> <C>
Sch. 1 $57.71
Sch. 2 $73.00
Sch. 3 1.0% $5,300 $53.00
Sch. 5 1.5% $5,300 $79.50
Sch. 6 1.5% $5,300 $79.50
</TABLE>
AEP West
- --------
Transmission
Point to Point Firm $1,050.00
Network $162,036,000 Net Annual Revenue Requirement
Summer 4CP Load Ratio Share
<TABLE>
<CAPTION>
Ancillary Services Purch.% Gen. Unit Cap. Rate Monthly Rates
- ------------------ ------- ------------------- -------------
<S> <C> <C> <C>
Sch. 1 $ 30.00
Sch. 2 $ 48.05
Sch. 3A
SPP 1.2% $2,609 $ 31.31
EROCT 1.1% $2,445 $ 26.90
Sch. 3B
SPP * $2,609
ERCOT * $2,445
Sch. 5
SPP 2.1% $3,482 $ 73.12
ERCOT 5.9% $3,121 $184.14
Sch. 6
SPP 2.1% $3,487 $ 72.80
ERCOT 5.9% $3,121 $164.14
</TABLE>
* Load Following Purchase Obligation equals the difference between actual load
measured on 15-minute intervals and the hourly scheduled delivery.
<PAGE> 14
AEP and CSW Companies
Term Sheet on Settlement Rates
ER98-2766-000
<TABLE>
<CAPTION>
REACTIVE REGULATION SPINNING SUPPLEMENTAL
TRANSMISSION SCHEDULING SUPPLY SERVICE RESERVE RES.
DESCRIPTION SERVICE SCHEDULE 1 SCHEDULE 2 SCHEDULE 3 SCHEDULE 5 SCHEDULE 6
- ----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
AEP EAST ZONE AREA:
- ----------------------------------------------------------------------------------------------------------------------------
Net Annual Revenue Requirement $349,712,000 $14,212,586 $17,978,148
- ----------------------------------------------------------------------------------------------------------------------------
Monthly Service Rate ?????? Mo. 1,420.00 67.71 73.00 63.00 79.50 79.50
- ----------------------------------------------------------------------------------------------------------------------------
Weekly Service Rate $???? 326.79 13.26 16.90 12.20 18.30 18.30
- ----------------------------------------------------------------------------------------------------------------------------
Daily On-Peak Service Rate 65.35 1.69 3.30 2.44 3.66 3.66
- ----------------------------------------------------------------------------------------------------------------------------
Hourly On-Peak Service Rate $?? 4.09 0.08 0.21 0.15 0.23 0.23
- ----------------------------------------------------------------------------------------------------------------------------
Daily-Off Peak Service Rate $??? DAY 49.68 1.89 2.40 1.74 2.61 2.61
- ----------------------------------------------------------------------------------------------------------------------------
Hourly Off-Peak Service Rate $??? 1.95 0.08 0.10 0.07 0.11 0.11
- ----------------------------------------------------------------------------------------------------------------------------
Cost of Generating Capacity $??? Mo. 5,300.00 5,300.00 5,300.00
- ----------------------------------------------------------------------------------------------------------------------------
Requirement per MW of load(1) 1.0% 1.5% 1.5%
- ----------------------------------------------------------------------------------------------------------------------------
AEP WEST ZONE Spp-Reg. & 1F Spinning Res. Supplemental Res.
- ----------------------------------------------------------------------------------------------------------------------------
Net Annual Revenue Requirement $162,005,000 4,629,600 1,415,076
- ----------------------------------------------------------------------------------------------------------------------------
Monthly Service Rate $????-Mo. 1,050.00 30.00 48.05 31.31 73.12 72.60
- ----------------------------------------------------------------------------------------------------------------------------
Weekly Service Rate $?????-Wk. 241.94 0.90 11.08 7.20 16.83 16.75
- ----------------------------------------------------------------------------------------------------------------------------
Annual Service Rate $?????-Yr. 48.33 0.99 2.21 1.44 3.37 3.85
- ----------------------------------------------------------------------------------------------------------------------------
Hourly On-Peak Service Rate $?? 3.02 0.04 0.14 0.39 0.21 0.21
- ----------------------------------------------------------------------------------------------------------------------------
Daily Off-Peak Service Rate $???-Day 34.52 0.99 1.50 1.02 2.40 2.39
- ----------------------------------------------------------------------------------------------------------------------------
Hourly Off-Peak Service Rate$? 1.44 0.04 0.07 0.04 0.10 0.10
- ----------------------------------------------------------------------------------------------------------------------------
Cost of Generating Capacity $???-Mo. Sch 3-A&B
2,609.00 3,482.00 3,467.00
- ----------------------------------------------------------------------------------------------------------------------------
Requirement per MW of Loan(1) 3A=1.2% 2.1% 2.1%
- ----------------------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE> 15
<TABLE>
<CAPTION>
$8=15min
AEP WEST ZONE ERCOT - REG. RESPONSE R ADD 1 RESP. RES.
<S> <C> <C> <C>
Monthly Service Rates $????-Mo. 26.90 154.14 184.14
Weekly Service Rates $????-Wk. 6.19 42.38 42.38
Daily On-Peak Service Rate $???-Day 1.24 8.48 8.48
Hourly On-Peak Service $???? 0.08 0.53 0.53
Daily Off-Peak Service Rate $???-Day 0.58 6.05 6.06
Hourly Off-Peak Service Rate $? 0.4 0.25 0.25
Cost of Generating Capacity $/??-Mo. Sch.3-A&B 3,121.00 3,121.00
2,446.00
Requirement per MW of load(1) 3A=1.1%, 5.9% 5.9%
3B=15 min.
</TABLE>
(1) Purchase Obligation in % of reserved capacity for Schedules 3A, 5 & 6.
Schedules 3B in SPP and ERCOT defines Load Following billing determined as the
largest difference between the maximum load each hour, measured over 15-minute
intervals, and the hourly scheduled delivery.
<PAGE> 16
ATTACHMENT B
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
FERC-approved Regional Transmission Organization directly
interconnected with AEP transmission 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.
<PAGE> 17
ATTACHMENT C
1. TRANSMISSION SERVICE FUNCTIONS
A. The RTO will administer AEP's Open Access Transmission Tariff and any
succeeding RTO Tariff as follows:
1. When the RTO, in consultation with AEP, determines that it is capable
of centrally calculating ATCs on data partially or totally developed
by the RTO it will calculate and post ATCs on OASIS.
2. The RTO will assume responsibility for transmission service contracts.
3. When the RTO determines, in consultation with AEP, that it is capable
of performing the function, the RTO will manage the single OASIS site
for the AEP System.
4. When the RTO determines, in consultation with AEP, that it is
capable of performing the function, it will have the sole authority
to receive, evaluate, and approve or deny all transmission service
requests on the AEP System.
5. The RTO will offer to provide losses and ancillary services and
verify customer self-provision of such services.
6. The RTO will perform settlement/billing for transmission service
and ancillary services.
B. The RTO will return revenues to AEP, and/or allocate revenue to AEP and
other RTO transmission owners, as applicable.
II. TRANSMISSION SECURITY FUNCTIONS
A. The RTO will perform the role of NERC Security Coordinator.
<PAGE> 18
B. The RTO will perform congestion management.
C. The RTO will approve transmission maintenance requests and outages.
III. CONTROL AREA FUNCTIONS
A. When the RTO, in consultation with AEP, determines that it is capable
of performing the function, the RTO will be the single entity with
responsibility to schedule energy transactions over approved
transmission reservation paths.
B. The RTO will coordinate and participate in time corrections.
C. The RTO will assure the maintenance of NERC/ECAR operating reserves.
D. The RTO will maintain load-generator balances (Control Area
Regulation) by sending ACE signals to generating companies or
independent generators that have contracted to provide regulation.
E. The RTO will perform check out (after-the-fact) of energy MWH
transactions with other control areas, and perform inadvertent
accounting.
<PAGE> 19
ATTACHMENT D
SECTION 7. MITIGATION.
To mitigate any perceived impacts of the merger on the Applicants' market
power, the Applicants have proposed in their FERC merger application a
mitigation plan which includes the following:
(1) Divestiture of 300 megawatts of coal-fired generating capacity at
the Northeastern generating plant after such plant is no longer
required to meet PSO's native load demand requirements subsequent
to industry restructuring in Oklahoma.
(2) Sale of 300 megawatts per hour of energy on an interim basis
prior to the divestiture of the Northeastern capacity.
(3) Waiver of PSO's priority to the use of CSW interfaces with other
transmission systems to import centrally dispatched energy from
the existing AEP system in excess of 250 megawatts.
(4) Waiver of PSO's priority to the use of CSW interfaces to import
non-firm energy from non-affiliates.
(5) Schedule CSW's use of the two high voltage direct current (HVDC)
ties between ERCOT and the SPP on a first-in-time basis for
certain transactions.
The Applicants commit to hold PSO Oklahoma retail customers harmless
from adverse impacts from these transactions. Attachment 4 to this agreement
describes the methodology that the Applicants will follow in order to hold PSO
Oklahoma retail customers harmless from adverse effects of the interim
mitigation sale.
<PAGE> 1
Exhibit D-2.2
ARKANSAS PUBLIC SERVICE COMMISSION
IN THE MATTER OF THE JOINT APPLICATION OF )
AMERICAN ELECTRIC POWER COMPANY, INC., )
SOUTHWESTERN ELECTRIC POWER COMPANY, )
AND CENTRAL AND SOUTH WEST ) DOCKET NO. 98-172-U
CORPORATION FOR APPROVAL OF MERGER ) ORDER NO. 9
ORDER
On June 12, 1998, American Electric Power Company, Inc. ("AEP"),
Central and South West Corp. ("CSW"), and Southwestern Electric Power Company
("SWEPCO") (collectively, "Applicants") filed an application in this docket for
approval of a proposed merger of AEP and CSW, the holding company which owns
SWEPCO. In connection with the merger, Applicants requested approval of their
proposed regulatory plan ("PRP"), which would set forth the regulatory and rate
treatment of merger-related benefits and costs for SWEPCO in Arkansas. The
application was supported by the pre-filed Direct Testimony and Exhibits of
Applicants' witnesses Richard E. Munczinski, J. Craig Baker, Thomas J. Flaherty,
R. Russell Davis, Armando A. Pena, Thomas V. Shockley, Thomas E. Mitchell,
William H. Hieronymus, Mark A. Bailey, Karen C. Martin, Mark D. Roberson, and
Dr. E. Linn Draper.
On June 12, 1998, the Commission issued Order No. 1 in this docket
establishing a procedural schedule, with a hearing date of July 13, 1998. On
June 26, 1998, Applicants and the General Staff of the Commission ("Staff")
filed their Joint Motion to Defer Consideration of the Regulatory Plan and to
Establish a Procedural Schedule. The Commission granted the joint motion by its
Order No. 4, dated July 1, 1998. The procedural schedule was subsequently
amended by Order No. 7, dated September 9, 1998.
<PAGE> 2
DOCKET NO. 98-172-U
PAGE 2
On August 13, 1998, the Commission issued its Order No. 5, approving
the merger subject to certain conditions, including the Commission's findings
and orders with respect to the PRP. Order No. 6, dated August 19, 1998,
corrected certain errors in Order No. 5.
In accordance with the procedural schedule established in Order No. 7,
Staff filed on October 23, 1998, the Testimony and Exhibits of Alice D. Wright,
J. Bret Franks, and Mark Witkowski addressing certain aspects of the PRP. On
November 3, 1998, Applicants and Staff filed a Regulatory Plan Stipulation and
Agreement ("RSPA") executed by Applicants and Staff and a Joint Motion to Accept
the Regulatory Plan Stipulation and Agreement and to Cancel the Remaining
Testimony Filing Dates. On November 4, 1998, Order No. 8 canceled the remaining
testimony filing dates and directed that the RSPA be considered at the public
hearing previously scheduled for December 1, 1998. The Commission further
ordered the parties to file testimony in [TEXT MISSING]
On December 1, 1998, a public hearing was held to consider the RPSA.
Although invited, no public comment was offered. The testimony and exhibits of
Applicants' witnesses Munczinski, Baker, Flaherty, and Davis were entered into
the record, as were the testimony and exhibits of Staff witnesses Witkowski,
Wright and Franks.
In support of the RPSA, Mr. Munczinski testified that the RPSA,
together with the stipulation approved by Orders No. 5 and 6, provides a fair
sharing of the merger's benefits between SWEPCO's Arkansas customers and the
Applicants. Mr. Munczinski noted that the RPSA provides for five years of annual
rate reductions as well as a direct pass-through of merger-related fuel savings.
He additionally noted that the RPSA does not preclude the Commission from
pursuing other rate actions it may deem appropriate or affect the terms and
conditions of the stipulation approved in Orders No. 5 and 6. Finally, Mr.
Munczinski testified
<PAGE> 3
DOCKET NO. 98-172-U
PAGE 3
that the RPSA holds Arkansas retail customers harmless from unforeseen events
that materially diminish the estimated benefits of the merger and from major
deviations from those estimates, including any negative effects of
merger-related market power mitigation measures. In response to questions from
Staff counsel, Mr. Munczinski provided further details of his understanding of
the Applicants' commitments to SWEPCO's Arkansas retail customers T. 219-24.
Staff witness Mr. Witkowski also testified in support of the RPSA. Mr.
Witkowski pointed out that the RPSA provided specific rate benefits through its
rate reduction rider. Those benefits will continue for at least five years and
potentially beyond that period. The rate reduction will begin at $685,000 in the
first year and increase each year to $1,541,000 in year five. Mr. Witkowski
testified that the RPSA provides a better match of merger savings with costs
than would the PRP and noted that the RPSA also insulates Arkansas ratepayers
from certain merger-related costs. He added that Paragraph 7 of the stipulation
approved by Orders No. 5 and 6 provided additional protection to Arkansas
ratepayers by requiring that they receive any additional benefits or conditions
imposed by order of any other jurisdiction. Mr. Witkowski concluded that the
RPSA, in conjunction with the conditions imposed by Orders No. 5 and 6
adequately protect ratepayers and provide equitable merger benefits for
ratepayers and shareholders.
The Commission finds that the RPSA represents a fair and reasonable
sharing of merger benefits and costs between Arkansas' SWEPCO customers and
Applicants' shareholders and is in the public interest. This finding is based on
the evidence discussed above, including, specifically, the testimony of Mr.
Munczinski in response to questions from Staff counsel and the condition that
Applicants accept the representations therein. In conjunction with the
conditions specified in Orders No. 5 and 6 and the agreement approved therein,
the RPSA should provide
<PAGE> 4
DOCKET NO. 98-172-U
PAGE 4
adequate protection to Arkansas ratepayers from the potential for merger-related
detriment. Nevertheless, there remains the possibility of adverse merger-related
effects resulting from decisions in other jurisdictions, particularly at the
federal level. The RPSA is thus conditionally approved, pending final action by
other relevant authorities. Applicants are directed to continue to file with
this Commission copies of all final, non-appealable orders from other
jurisdictions related to their proposed merger.
BY ORDER OF THE COMMISSION
This 17th day of December, 1998.
/s/ Lavenski R. Smith, Chairman
/s/ Sam I. Bratton, Jr., Commissioner
/s/ Julius D. Kearney, Commissioner
/s/ Bill Mathis (acting)
Jan Sanders
Secretary of the Commission
<PAGE> 5
BEFORE THE
ARKANSAS PUBLIC SERVICE COMMISSION
IN THE MATTER OF THE JOINT APPLICATION OF )
AMERICAN ELECTRIC POWER COMPANY, INC., )
SOUTHWESTERN ELECTRIC POWER COMPANY, )
AND CENTRAL AND SOUTH WEST ) DOCKET NO. 98-172-U
CORPORATION FOR APPROVAL OF MERGER )
REGULATORY PLAN STIPULATION AND AGREEMENT
American Electric Power Company, Inc. ("AEP"), Southwestern Electric
Power Company ("SWEPCO"), and Central and South West Corporation ("CSW")
(collectively referred to as the "Applicants"), and the General Staff of the
Arkansas Public Service Commission ("Staff"), jointly referred to as the
"Parties", respectfully submit this Joint Motion stating:
1. The Applicants commit and agree to implement the rate freeze as
proposed in their Application and supporting testimony.
2. SWEPCO will implement a net merger savings rider in Arkansas that
will reduce rates to customers by the annual amounts shown in Attachment A
beginning with the first revenue month after the effective date of the merger.
Each individual year's rate reduction will apply for a twelve month period, with
the year five reduction continuing to apply in years following the end of year
five until new base rates for SWEPCO become effective. The annual rate reduction
amounts shown in Attachment A will be allocated to rate classes based upon
revenue requirements to be determined in the pending earnings review. At the end
of the five year period, cost amortization and shareholder saving imputations
shall terminate.
<PAGE> 6
DOCKET NO. 98-172-U
PAGE 2
3. 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; systems
integration costs; operations integration costs including telecommunication
costs; and facilities consolidation costs. The costs to achieve the merger are
to be recovered through merger savings. For Arkansas retail jurisdictional
ratemaking purposes, SWEPCO will defer its share of the lesser of the estimated
or actual costs to achieve as incurred over a five year period. These costs will
be amortized over a five year period beginning with the effective date of the
merger. The amortized cost for each year shall be proportionate to the net
merger savings amount reflected in Attachment A for the corresponding year.
4. If changes in retail base rates of SWEPCO in Arkansas occur within
the first five years after the effective date of the merger, the following rate
treatments will be reflected:
(a) Estimated non-fuel operation and maintenance expense
merger savings net of 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.
(b) Amortization 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. The unamortized balance of
costs to achieve will not be included in rate base
and no return will be allowed on the unamortized
balance of costs to achieve.
<PAGE> 7
DOCKET NO. 98-172-U
PAGE 3
(c) The merger savings rate reduction rider will continue as
described in Paragraph 2 above.
(d) It is the intent of the Parties that the provisions of this
Paragraph 4 relating to cost amortizations and shareholder
savings imputation in the event of a base rate proceeding will
terminate five years after the effective date of the merger.
(e) Attachment B is an example of the retail base rate treatment
described in this section.
5. If the electric utility industry in Arkansas is restructured prior
to the end of the fifth year after the effective date of the merger, the rider
benefits, cost amortization, and shareholder savings imputation should be
reduced consistent with the functional segregation of unbundled restructured
rates. It is the intent of the Parties that the cost amortizations and
shareholder savings imputations would continue for the five year term for those
functions subject to continued rate of return regulation. It is also the intent
of the Parties that the benefits would continue for the period of time in which
the net merger savings rider set forth in Paragraph 2 remains in effect for
those functions subject to continued rate of return regulation.
6. All fuel savings shall be passed through to Arkansas retail
customers in accordance with SWEPCO's fuel adjustment clause. After consummation
of the merger, the Applicants agree to report to the Arkansas Public Service
Commission in the monthly full report the amount of energy savings based on a
combined joint dispatch. These savings will be the internal economies for energy
transfers from the East to West Zones within the AEP system.
7. The Applicants agree to hold harmless the retail customers of SWEPCO
from unforeseen events that materially diminish the estimated benefits of the
merger and from major
<PAGE> 8
DOCKET NO. 98-172-U
PAGE 4
deviations from the Applicants' stated representations of estimated merger
benefits. The Applicants also agree to hold harmless the retail customers of
SWEPCO from any negative economic effects of market power mitigation plans
implemented as a part of the merger as determined on a calendar year basis.
8. This Regulatory Plan Stipulation and Agreement supplements the
conditions reflected in Orders No. 5 and No. 6 in this Docket, dated August 13,
1998 and August 19, 1998, respectively. The Parties specifically agree that the
provisions of Paragraph 7 of the July 10, 1998 Stipulation and Agreement shall
apply to this Regulatory Plan Stipulation and Agreement.
9. In furtherance of the provisions of Paragraph No. 3 of the
Stipulation and Agreement entered into by the Parties and filed of record July
10, 1998, the Applicants agree to work with the General Staff to address the
issue raised in the Quality of Service Evaluation dated August 11, 1998.
10. This Regulatory Plan Stipulation and Agreement is expressly
contingent upon receipt of an order by the APSC approving the regulatory plan as
reflected herein, and is contingent upon the completion of the merger.
11. The Parties agree that this Regulatory Plan Stipulation and
Agreement with regard to the Proposed Regulatory Plan is in the public interest
and should be approved in its entirety by the Commission.
12. In the event the Commission does not accept, adopt, and approve
this Regulatory Plan Stipulation and Agreement in its entirety and without
modification, the Parties agree that this Regulatory Plan Stipulation and
Agreement shall be void and of no effect. In the event, the Parties agree that
no Party shall be bound by any of the provisions or agreements contained herein,
all Parties shall be deemed to have reserved all their respective rights and
remedies in this
<PAGE> 9
DOCKET NO. 98-172-U
PAGE 5
proceeding, and no Party shall introduce this Regulatory Plan Stipulation and
Agreement or writings, discussions, negotiations, or other communications of any
type related to this Regulatory Plan Stipulation and Agreement in any
proceeding.
Agreed to this 3rd day of November, 1998.
/s/ Illegible_____________________________
Counsel for American Electric Power
Company, Inc.
/s/ Illegible_____________________________
Counsel for Central and South West Corporation
and Southwestern Electric Power Company
/s/ Susan E. D'Auteuil____________________
Counsel for the General Staff of the Arkansas
Public Service Commission
<PAGE> 10
Attachment A
AEP/CSW MERGER
NET ANNUAL MERGER SAVINGS
AND ARKANSAS CUSTOMER RATE REDUCTIONS ($000)
<TABLE>
<CAPTION>
(1) (2) (3) (4)
Net Customer Rate Shareholder
Period Merger Savings Reduction Savings
------ -------------- --------- -------
<S> <C> <C> <C>
Year 1 1,235 685 550
Year 2 1,899 1,054 845
Year 3 2,278 1,264 1,014
Year 4 2,574 1,428 1,146
Year 5 2,777 1,541 1,236
</TABLE>
*The Year 5 amount will continue until the effective date of the first base rate
change after Year 5.
<PAGE> 11
Attachment B
AEP/CSW MERGER
EXAMPLE OF BASE RATE CASE TREATMENT
BASED ON YEAR 3 ($000)
<TABLE>
<S> <C> <C> <C>
CREDIT PER RIDER CONTINUES (1,264)
INCLUDED IN TEST YEAR: (3,284)
GROSS MERGER SAVINGS
CHANGE IN CONTROL AMORTIZATION 250
OTHER CTA AMORTIZATION 756
-------------
TOTAL CTA AMORTIZATION 1,006
-----------
NET MERGER SAVINGS IN TEST YEAR (2,278)
ADD BACK TO TEST YEAR COST OF SERVICE:
CUSTOMER SHARE (Attachment A - Year 3,
Col. 3) 1,264
SHAREHOLDER PORTION (Attachment A -
Year 3, Col. 4) 1,014
--------------
2,278
-----------
NET BASE RATE REDUCTION 0
-----------
CUSTOMER RATE REDUCTION (1,264)
==========
</TABLE>
<PAGE> 1
Exhibit D-3.2
EXHIBIT REM-1
Page 1
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 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 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.
<PAGE> 2
EXHIBIT REM-1
Page 2
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 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 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
<PAGE> 3
EXHIBIT REM-1
Page 3
System Integration Agreement, the notice provisions contained in
Paragraph 12 of the Affiliate Transaction Conditions of this
Stipulation and Settlement shall apply.
To allow the Commission to monitor the fuel costs of
SWEPCO-La. to ensure that ratepayers do not pay Merger fuel costs as a
result of the merger and/or any mitigation, measures undertaken by the
Applicants, the Applicants assume 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 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
<PAGE> 4
EXHIBIT REM-1
Page 4
$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 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.
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 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.
<PAGE> 5
EXHIBIT REM-1
Page 5
10. SWEPCO and AEP shall commit to maintain 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 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 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
<PAGE> 6
EXHIBIT REM-1
Page 6
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 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, 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> 7
EXHIBIT REM-1
Page 7
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 SWFPCO's cost of service and/or revenue requirement.
3. AEP will cooperate with audits ordered by the Louisiana Commission of
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 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
<PAGE> 8
EXHIBIT REM-1
Page 8
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 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.
<PAGE> 9
EXHIBIT REM-1
Page 9
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 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.
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 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
<PAGE> 10
EXHIBIT REM-1
Page 10
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, 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.
<PAGE> 11
EXHIBIT REM-1
Page 11
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 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 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 miles,
regulations or orders of general applicability adopted by the
Commission regarding generation assets in an open access environment
<PAGE> 12
EXHIBIT REM-1
Page 12
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 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 presented 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 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.
<PAGE> 13
EXHIBIT REM-1
Page 13
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 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 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
<PAGE> 14
EXHIBIT REM-1
Page 14
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 months following the consummation of the
merger, the Company will retain 50% of the merger savings, computed
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 1.1% annual productivity
adjustment. For each subsequent year, the CYCPI-U will be for the month
representing the midpoint of the twelve month future year period as
published on the Consumer Price Indexes home page
(http://stats.bls.gov/cpihome.htm).
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
<PAGE> 15
EXHIBIT REM-1
Page 15
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
mercer 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 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) to the
power of (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 retained by the Company.
<PAGE> 16
EXHIBIT REM-1
Page 16
III. TIMING OF SSM STIRCREDIT 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 to the Commission's
subsequent review and approval. Copies of the SSM filings will be
provided to the Commission's 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 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 filings
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 D. However, the Company and other parties agree that the
schedules filed pursuant to this provision will not be determinative
for ratemaking
<PAGE> 17
EXHIBIT REM-1
Page 17
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 consultants and Special Counsel and to
provide timely, accurate and comprehensive responses to discovery.
<PAGE> 18
EXHIBIT REM-1
Page 18
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 $191,833
(Excluding Account Nos. 501, 518, 536, 547 and 555)
II. Less:
A. Transmission Fees (Account 565) (7,292)
B. Merger Costs(Costs to Achieve, Transaction Costs, Separation Payments)
C. Costs of Early Retirement or Other Cost Reductions 0
D. Operating Lease Expense* 0
(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>
- --------------------------------
*FERC Accounts 507, 525, 540, 550, 567, 589, and 931.
<PAGE> 19
EXHIBIT REM-1
Page 19
Attachment B
FUTURE YEAR NORMALIZED (FYNE)
OPERATION AND MAINTENANCE EXPENSE
SWEPCO SAVINGS SHARING MECHANISM
(000)
<TABLE>
<CAPTION>
Twelve Months
Ended
MM, DD, YY
----------
<S> <C>
I. Total Actual 1998 Non-Fuel O&M Expense
(Excluding Account Nos. 501, 518, 536, 547 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>
- -----------------------------
*FERC Accounts 501, 525, 540, 550, 567, 589, and 931.
<PAGE> 20
EXHIBIT REM-1
Page 20
Attachment C
ILLUSTRATION OF OPERATION OF SWEPCO MERGER SAVINGS SHARING MECHANISM
<TABLE>
<CAPTION>
YEAR 1 YEAR 2 YEAR 3 YEAR 4 YEAR 5 YEAR 6
------ ------ ------ ------ ------ ------
DESCRIPTION
<S> <C> <C> <C> <C> <C> <C>
Base Year O&M Expenses $100,000 $100,000 $100,000 $100,000 $100,000 $100,000
Future Year CPI-U 103,000 106,090 109,273 112,551 115,927 119,405
Base Year CPI-U 100,000 100,000 100,000 100,000 100,000 100,000
Future Year CPI-U/Base Year CPI-U 1.030 1.061 1.093 1.126 1.159 1.194
Productivity Factor Offset -0.011 -0.022 -0.033 -0.045 -0.056 -0.068
SSM Base Year Escalation Factor 1.019 1.039 1.059 1.081 1.103 1.126
Base Year Normalized Expense, Esc &
Prod Offset $101,900 $103,878 $105,938 $108,078 $110,305 $12,621
Future Year Normalized Expenses $101,000 $102,010 $103,080 $104,060 $105,101 $106,152
Total Company Savings (FYNE-BYNE) ($900) ($1,868) ($2,906) $(4,017) ($5,204) ($6,469)
Louisiana Jurisdictional Factor 40.00% 40.00% 40.00% 40.00% 40.00% 40.00%
Louisiana Jurisdictional Merger
Savings ($360) ($747) ($1,162) ($1,607) ($2,082) ($2,588)
Customers Allocation of Savings @50% ($180) ($374) ($581) ($803) ($1,041) ($1,294)
</TABLE>
<TABLE>
<CAPTION>
YEAR 7 YEAR 8
------ ------
DESCRIPTION
<S> <C> <C>
Base Year O&M Expenses $100,000 $100,000
Future Year CPI-U 122,987 126,677
Base Year CPI-U 100,000 100,000
Future Year CPI-U/Base Year CPI-U 1.230 1.267
Productivity Factor Offset -0.080 -0.091
SSM Base Year Escalation Factor 1.150 1.175
Base Year Normalized Expense, Esc &
Prod Offset $115,029 $117,531
Future Year Normalized Expenses $107,214 $108,286
Total Company Savings (FYNE-BYNE) ($7,815) ($9,245)
Louisiana Jurisdictional Factor 40.00% 40.00%
Louisiana Jurisdictional Merger
Savings ($3,126) ($3,698)
Customers Allocation of Savings @50% ($1,563) ($1,849)
</TABLE>
NOTE: Years in the column headings refers to the twelve month implementation
periods commencing on the first day of the fifteenth month following
consummation of the merger.
<PAGE> 21
EXHIBIT REM-1
Page 21
Attachment D
SOUTHWESTERN ELECTRIC POWER COMPANY
RATE BASE/RATE OF RETURN
FOR THE TEST YEAR ENDED DECEMBER 31, 1997
<TABLE>
<CAPTION>
(1) (2) (3) (4) (5)
Total Company
Line Schedule Total Company Pro Forma
No. Description Reference Per Books Adjustments Balance
--- ----------- --------- --------- ----------- -------
<S> <C> <C> <C> <C> <C>
1 Plant in service:
2 Plant in service W/P B-2 $ 3,005,002,647 (40,121,808) 2,964,880,839
3 Construction work in progress W/P B-2 51,665,071 (8,281,517) 43,383,554
4 Plant acquisition adjustment W/P B-2 18,043,976 0 18,043,976
5 Plant held for future use W/P B-2 80,704 (80,704) 0
--------------- ------------- ---------------
6 Gross Plant $ 3,074,792,398 $ (48,484,029) $ 3,026,308,369
7 Accumulated depreciation W/P B-3 (1,225,864,541) 14,267,639 (1,211,596,902)
--------------- ------------- ---------------
8 Net Plant $ 1,848,927,857 $ (34,216,390) $ 1,814,711,467
9
10 Working capital:
11 Cash working capital W/P B-9 (90,078,456) 0 (90,078,456)
12 Prepayments W/P B-6 38,498,880 (23,698,126) 14,800,754
13 Operating materials and
supplies W/P B-7 27,132,307 (2,840,083) 24,292,225
14 Fuel inventories W/P B-8 26,415,233 30,699,587 57,114,820
15 Additions and deductions:
16 Customer deposits W/P B-13 (14,358,583) 0 (14,358,583)
17 Deferred credits W/P B-11 (4,015,924) 1,939,285 (2,076,639)
18 Additional rate base items W/P B-10 25,523,062 32,374,843 57,897,905
0
--------------- ----------- ---------------
19 Net total investment $ 1,858,044,376 $ 4,259,116 $ 1,862,303,492
20 Accumulated deferred income
taxes W/P B-12 (410,575,785) 5,079,396 (405,496,389)
21 Deferred investment tax
credit - pre 1971 W/P B-12 (345,089) 0 (345,089)
--------------- ------------- ---------------
22 Rate Base $ 1,447,123,502 $ 9,338,512 $ 1,456,462,014
=============== =========== ===============
23 Net operating income (current
prices) 145,540,459 (28,706,042) 116,834,417
24 Rate of return (current prices) 10.057% 8.022%
</TABLE>
<PAGE> 22
EXHIBIT REM-1
Page 22
Attachment D
Southwestern Electric Power Company
Electric Utility Plant
For the Test Year Ending December 31, 1997
<TABLE>
<CAPTION>
Pro Forma Total
FERC Total Company Company
Line Account Balance Balance
No. Description Number Dec. 31, 1997 Adjustments Dec. 31, 1997
--- ----------- ------ ------------- ----------- -------------
<S> <C> <C> <C> <C>
1 Electric Plant in Service 101,106
2 Intangible Plant
3 Organization 301 12,201 12,201
4 Miscellaneous Intangible Plant 303 28,926,874 28,926,874
------------- ------------ -------------
5 Total Miscellaneous Intangible Plant 28,939,075 0 28,939,075
------------- ------------ -------------
6 PRODUCTION
7 Stearn Production Plant - Coal & Lignite
8 Land and Land Rights 310 9,186,653 9,186,653
9 Structures and improvements 311 226,605,778 226,605,778
10 Coal Unit Railroads 311 1,792,037 1,792,037
11 Boiler Plant Equipment 312 692,076,017 692,076,017
12 Rail Cars 312 31,947,035 31,947,035
13 Engines and Engine Driven
Gener. 313 0 0
14 Turbogenerator Units 314 177,789,455 177,789,455
15 Accessory Electric Equipment 315 47,309,527 47,309,527
16 Misc. Power Equipment 316 34,084,763 34,084,763
17 AFUDC Rate Adjustment W/P B-4 0 (38,201,579) (38,201,579)
------------- ------------ -------------
18 Total Steam Production Plant 1,220,791,265 (38,201,579) 1,182,589,686
------------- ------------ -------------
19 Steam production Plant - Gas & Oil
20 Land and Land Rights 310 743,582 743,582
21 Structures and improvements 311 21,809,310 21,809,310
22 Boiler Plant Equipment 312 72,031,354 72,031,354
23 Gas Unit Pipelines 312 1,259,681 1,259,681
24 Engines and Engine Driven Gener. 313 0 0
25 Turbogenerator Units 314 56,144,494 56,144,494
26 Accessory Electric Equipment 315 7,162,215 7,162,215
27 Misc. Power Equipment 316 4,983,273 4,983,273
------------- ------------ -------------
28 Total Steam Production Plant 164,113,909 0 164,113,909
------------- ------------ -------------
29 TRANSMISSION PLANT
30 Land and Land Rights 350 1,147,105 1,147,105
31 Land and Land Rights 350.2 23,906,233 23,906,233
32 Structure and Improvements 352 7,411,953 7,411,953
33 Station Equipment 353 178,456,520 178,456,520
34 Towers and Fixtures 354 36,124,941 36,124,941
35 Poles and Fixtures 355 92,882,931 92,882,931
36 Overhead Conductors and Devices 356 115,893,914 115,893,914
37 Underground Conduits 357 0 0
38 Underground Conductors and 358
Devices 295 295
39 Roads and Trails 359 132,266 132,266
40 AFUDC Rate Adjustment W/P B-4 0 (1,893,630) (1,893,630)
------------- ------------ -------------
41 Total Transmission Plant 455,956,158 (1,893,630) 454,062,528
------------- ------------ -------------
</TABLE>
<PAGE> 23
EXHIBIT REM-1
Page 23
Attachment D
Southwestern Electric Power Company
Electric Utility Plant
For the Test Year Ending December 31, 1997
<TABLE>
<CAPTION>
Pro Forma
Total Company Total
FERC Balance Company
Line Account Dec. 31, Balance
No. Description Number 1997 Adjustments Dec. 31, 1997
--- ----------- ------ ---- ----------- -------------
<S> <C> <C> <C> <C>
42 DISTRIBUTION PLANT
43 Land and Land Rights 360 1,574,190 1,574,190
44 Land and Land Rights 360.2 2,283,509 2,283,509
45 Structures and Improvements 361 2,693,807 2,693,807
46 Station Equipment 362 113,398,298 113,398,298
47 Storage Battery Equipment 363 0 0
48 Poles, Tower, and Fixtures 364 182,418,283 182,418,283
49 Overhead Conductors and Devices 365 73,085,051 73,085,051
50 Underground Conduit 4355 17,860,530 17,860,530
51 Underground Conductors and Devices 367 73,085,051 73,085,051
52 Line Transformers 368 184,224,384 184,224,384
53 Services 369 24,482,183 24,482,183
54 Meters 370 53,226,081 53,226,081
55 Installations on Customer Premises 371 28,904,132 28,904,132
56 Leased Property on Customer
Premises 372 0 0
57 Street Lighting and Signal Systems 373 22,247,734 22,247,734
58 AFUDC Rate Adjustment W/P B-4 0 132,282 132,282
------------ ------------ ------------
59 Total Distribution Plant 861,365,663 132,282 861,497,945
------------ ------------ ------------
1 GENERAL PLANT
2 Land and Land Rights 389 4,459,415 4,459,415
3 Structures and Improvements 390 84,430,237 84,430,237
4 Office Furniture and Equipment 391 14,130,237 14,130,237
5 Computer Equipment 391 12,458,854 12,458,854
6 Transportation Equipment 392 27,873,033 27,873,033
7 Stores Equipment 393 1,720,571 1,720,571
8 Tools, Shop and Garage Equipment 394 6,395,189 6,395,189
9 Laboratory Equipment 395 5,126,472 5,126,472
10 Powered Operated Equipment 396 1,950,016 1,950,016
11 Communication Equipment 397 47,175,608 47,175,608
12 Miscellaneous Equipment 398 861,098 861,098
Other Tangible Property (Fuel) 399 67,256,045 67,256,045
AFUDC Rate Adjustment - Fu
W/P B-4 0 (1,052,872) (1,052,872)
13 AFUDC Rate Adjustment W/P B-4 0 893,991 893,991
------------ ------------ ------------
14 Total General Plant 273,836,577 (158,881) 273,677,696
------------ ------------ ------------
15 TOTAL ACCOUNT 101 AND 106 3,005,002,647 (40,121,808) 2.,964,880,839
16 Plant Held for Future Use 105 80,704 (80,704) 0
17 Construction Work in Progress 107 51,665,071 (8,281,517) 43,383,554
18 Plant Acquisition Adjustment 114 18,043,976 18,043,976
------------ ------------ ------------
19 TOTAL ELECTRIC PLANT 3,074,792,398 (48,484,029) 3,026,308,369
============= =========== =============
</TABLE>
<PAGE> 24
EXHIBIT REM-1
Page 24
Attachment D
Southwestern Electric Power Company
Accumulated Provision for Depreciation, Amortization and Depletion
For the Test Year Ending December 31, 1997
<TABLE>
<CAPTION>
FERC Total Company W/P B-3 & Pro Forma
Line Account Balance Dec. 31, W/P B-4 Balance
No. Description Number 1997 Adjustments Dec. 31, 1997
--- ----------- ------ ---- ----------- -------------
<S> <C> <C> <C> <C> <C>
1 Accumulated Provision for
2 Depreciation 108
3 Production - Steam $ 694,173,999 $ 23,172,551 $ 717,346,550
4 Transmission 152,328,547 (13,707,722) 138,620,825
5 Distribution 306,109,948 (20,700,365) 285,409,583
6 General 26,819,051 (3,032,103) 23,786,948
7 Lignite Depletion 20,496,682 20,496,682
8 Transportation 17,145,521 17,145,521
9 Retirement Work In Progress (4,472,945) (4,472,945)
-------------- ------------ --------------
$1,212,600,803 $(14,267,639) $1,198,333,164
10 Accumulated Amortization for
11 Intangible Plant 111 8,457,094 8,457,094
12 Accumulated Amortization for
13 Plant Acquisition Adjustment 115 4,806,644 4,806,644
-------------- ------------ --------------
14 Total Accumulated Provision for
15 Depreciation and Amortization $1,225,864,541 $ (14,267,639) $ 1,211,596,902
============== ============= ===============
</TABLE>
<PAGE> 25
EXHIBIT REM-1
Page 25
Attachment D
SWEPCO
CASH WORKING CAPITAL
FOR THE TEST YEAR ENDED DECEMBER 31, 1997
<TABLE>
<CAPTION>
(1) (2) (3) (4) (5) (6) (7)
Total Adjusted
Line Company Pro Forma Test Year Revenue
No. Description Ref. Per Books Adjustment Amount Lag Days Ref.
--- ----------- ---- --------- ---------- ------ -------- ----
<S> <C> <C> <C> <C> <C> <C> <C>
1 Fuel 383,007,632 (1,799,003) 381,228,629 3.93
2 Deferred Fuel (603,883) 603,883 - 3.93
3 Purchased Power 25,927,920 - 25,927,920 3.93
4 Total Fuel and Purchase Power 408,331,669 (1,175,120) 407,156,549 3.93
5 Total Oper & maint 191,665,267 1,886,414 193,551,681 3.93
6 Taxes other than income A/C #4081 55,952,213 (358,497) 55,603,716 3.93
7 Federal Income Tax-Current 45,158,544 (11,602,231) 33,556,313 3.93
8 Federal Income Tax-Deferred (6,646,437) (5,932,359) (12,578,796) 3.93
9 State Income Tax-Current 4,764,450 (1,786,899) 2,977,551 3.93
11 Depreciation and Amortization 43,276,557 95,228,017 27,211,431 122,439,448 3.93
12 Gain on Sale of Emission Allowance (135,568) - (135,568) 3.93
13 3.93
----------- ------------- ------------
14 Subtotal 794,328,156 8,242,738 802,570,894
15 Interest on Long-Term Debt A/C #427-429 49,971,270 4,830,123 54,801,393 3.93
16 Preferred Stock Dividend A/C #437 2,466,627 (107,566) 2,359,051 3.93
17 Return on common equity 59,673,958 6 59,673,964 3.93
---------- ------------ -----------
18 Net operating income 112,111,855 4,772,563 116,834,417
=========== ============= ============
19 Working Capital Requirement for Cost of 906,440,010 12,965,301 919,405,311
Service =========== ============= ============
20 Sales and Use Taxes B-9 Pg 2
21 Minimum Bank Balances A/C #1350.9000
22 Net Working Capital Requirement
</TABLE>
<TABLE>
<CAPTION>
(8) (9) (10) (11)
Line Expenses Net Lag CWC CWC
No. Description Lead Days Days Factor Requirement
--- ----------- --------- ---- ------ -----------
<S> <C> <C> <C> <C>
1 Fuel 32.77 (28.84) -0.07881 (30,043,522)
2 Deferred Fuel 3.93 0.01073 -
3 Purchased Power 38.61 (34.69) -0.09478 (2,457,394)
4 Total Fuel and Purchase Power
5 Total Oper & maint 40.58 (36.65) -0.10014 (19,382,129)
6 Taxes other than income 122.92 (119.00) -0.32513 (18,078,299)
7 Federal Income Tax-Current 84.05 (80.12) -0.21891 (7,345,863)
8 Federal Income Tax-Deferred 3.93 0.01073 (134,938)
9 State Income Tax-Current 24.26 (20.33) -0.05555 (165,416)
11 Depreciation and Amortization 3.93 0.01073 1,313,458
12 Gain on Sale of Emission Allowance 3.93 0.01073 (1,454)
13 3.93
14 Subtotal
15 Interest on Long-Term Debt 90.31 (86.38) -0.23602 (12,934,429)
16 Preferred Stock Dividend 46.32 (42.40) 0.11584 (273,281)
17 Return on common equity 3.93 0.01073 640,147
18 Net operating income -
-----------
19 Working Capital Requirement for Cost of (88,863,122)
Service
20 Sales and Use Taxes (1,402,362)
21 Minimum Bank Balances 187,028
-----------
22 Net Working Capital Requirement (90,078,458)
============
</TABLE>
<PAGE> 26
EXHIBIT REM-1
Page 26
Attachment D
SWEPCO
CASH WORKING CAPITAL FOR FUEL, O&M AND OTHER TAXES
FOR THE TEST YEAR ENDED DECEMBER 31, 1997
<TABLE>
<CAPTION>
(1) (2) (3) (4) (5) (6) (7)
Line Total Company Pro Forma Adjusted Test Revenue
No. Description Ref. Per Books Adjustment Year Amount Lag Days Ref.
--- ----------- ---- --------- ---------- ----------- -------- ----
<S> <C> <C> <C> <C> <C>
1 GAS 85,995,697 (400,194) 85,595,503 3.93
2 COAL 218,213,811 (1,015,491) 217,198,320 3.93
3 LIGNITE 76,983,477 (358,254) 76,625,223 3.93
4 OIL 1,088,162 (5,064) 1,083,098 3.93
5 FUEL - CSWS 724,628 - 724,628 3.93
6 OTHER FUEL - OIL - - - 3.93
7 OTHER FUEL - DIESEL 1,857 - 1,857 3.93
8 OTHER FUEL - GAS - - - 3.93
------------ ------------ ------------ ----
9 TOTAL FUEL 383,007,532 (1,779,003) 381,228,629 3.93
10 PURCHASED POWER - AFFILIATE 7,836,057 - 7,836,057 3.93
11 PURCHASED POWER - OTHER 18,091,863 - 18,091,863 3.93
------------ ------------ ------------ ----
12 TOTAL PURCHASED POWER 25,927,920 - 25,927,920 3.93
13 PAYROLL 55,023,443 (2,609,272) 52,414,171 3.93
14 O&M - CSWS 43,923,851 648,827 44,572,678 3.93
15 CSW CREDIT FACTORING - 9,327,765 9,327,765 3.93
16 OTHER O&M 92,717,973 (3,520,461) 89,197,512 3.93
------------ ------------ ------------ ----
17 TOTAL O&M 191,665,267 1,886,414 195,512,126 3.93
18 AD VALOREM TAX 33,204,298 (928,572) 32,275,726 3.93
19 FUTA (36,654) (36,654) 3.93
20 SUTA 77,345 77,345 3.93
21 FICA 4,297,246 (276,425) 4,020,821 3.93
22 PAYROLL TAXES - CSWS 1,724,550 1,724,550 3.93
23 PUC ASSESSMENTS 923,559 166,696 1,090,255 3.93
24 OCCUPATIONAL TAX 47,756 47,756 3.93
25 TEXAS FRANCHISE TAX 1,800,000 810,824 2,610,824 3.93
26 OTHER STATE FRANCHISE TAX 2,422,886 (499,074) 1,923,812 3.93
27 CITY FRANCHISE FEES 8,435,125 135,520 8,570,645 3.93
28 TEXAS CROSS RECEIPTS TAX 3,353,282 (54,965) 3,298,317 3.93
SUPERFUND TAXES (Note 1) (287,500) 287,500 - 3.93
29 FEDERAL HIGHWAY USE TAX 320 - 320 3.93
------------ ------------ ------------ ----
30 TOTAL TAXES OTHER THAN INCOME 55,962,213 (358,497) 55,603,716 3.93
31 SALES & USE TAX - BY WIRE 21,199,353 21,199,353 3.93
32 SALES & USE TAX - BY CHECK 578,432 578,432 3.93
------------ ------------ ------------ ----
33 TOTAL SALES AND USE TAX 21,777,784 - 21,777,784 3.93
(8) (9) (10) (11)
Expenses
Line Lead Net Lag CWC CWC
No. Description Days Days Days Requirement
--- ----------- ---- ---- ---- -----------
<S> <C> <C> <C> <C> <C>
1 GAS 51.76 (47.83) -0.13105 (11,217,667)
2 COAL 21.86 (17.93) -0.04913 (10,670,718)
3 LIGNITE 41.93 (36.00) -0.10412 (7,977,942)
4 OIL 48.13 (44.20) -0.12110 (131,159)
5 FUEL - CSWS 26.96 (23.03) -0.06311 (45,730)
6 OTHER FUEL - OIL 3.93 0.01076 -
7 OTHER FUEL - DIESEL 65.28 (61.35) -0.16808 (312)
8 OTHER FUEL - GAS - 3.93 0.01076 -
------- ------- -------- ------------
9 TOTAL FUEL 32.77 (28.84) -0.07881 (30,043,522)
10 PURCHASED POWER - AFFILIATE 37.85 (33.92) -0.09294 (728,319)
11 PURCHASED POWER - OTHER 38.81 (34.88) -0.09557 (1,729,075)
------- ------- -------- ------------
12 TOTAL PURCHASED POWER 38.61 (34.69) -0.09478 (2,457,394)
13 PAYROLL 26.41 (22.48) -0.06160 (3,228,553)
14 O&M - CSWS 26.96 (23.03) -0.06311 (2,812,899)
15 CSW CREDIT FACTORING 3.93 - 0.00000 -
16 OTHER O&M 59.32 (55.39) 0.15176 (13,536,995)
------- ------- -------- ------------
17 TOTAL O&M 40.58 (36.65) -0.10014 (19,578,447)
18 AD VALOREM TAX 191.33 (187.40) -0.51343 (16,571,257)
19 FUTA 74.12 (70.19) -0.19230 7,049
20 SUTA 63.11 (59.19) -0.16215 (12,542)
21 FICA 18.28 (14.35) -0.03932 (158,097)
22 PAYROLL TAXES - CSWS 26.96 (23.03) -0.06311 (108,833)
23 PUC ASSESSMENTS 6.09 (2.16) -0.00592 (6,454)
24 OCCUPATIONAL TAX (112.73) 116.66 0.31962 15,264
25 TEXAS FRANCHISE TAX 64.62) 68.55 0.18780 490,315
26 OTHER STATE FRANCHISE TAX (118.53) 122.46 0.33550 645,437
27 CITY FRANCHISE FEES 77.16 (73.24) -0.20065 (1,719,698)
28 TEXAS CROSS RECEIPTS TAX 76.92 (72.99) -0.19998 (659,588)
SUPERFUND TAXES (Note 1) - 3.93 0.01076 -
------- ------- -------- ------------
29 FEDERAL HIGHWAY USE TAX (115.55) 119.48 0.32733 105
30 TOTAL TAXES OTHER THAN INCOME 122.92 (119.00) -0.32513 (18,078,299)
31 SALES & USE TAX - BY WIRE 27.03 (23.10) -0.06330 (1,341,926)
32 SALES & USE TAX - BY CHECK 42.06 (38.14) -0.10448 (60,436)
------- ------- -------- ------------
33 TOTAL SALES AND USE TAX 27.49 (23.57) -0.06439 (1,402,362)
</TABLE>
Note 1: Correction entries to reverse 1996 expenses. No cash receipts or
payments
<PAGE> 27
EXHIBIT REM-1
Page 27
Attachment D
SOUTHWESTERN ELECTRIC POWER COMPANY
PREPAYMENTS
FOR THE TWELVE MONTHS ENDED DECEMBER 31, 1997
<TABLE>
<CAPTION>
(1) (2) (3) (4) (5)
Line Schedule Total Company Pro Forma Total Company
No. Description Reference Per Books Adjustments Pro Forma
--- ----------- --------- --------- ----------- ---------
<S> <C> <C> <C> <C> <C>
1 Monthly Balances:
2 December, 1996 $ 13,394,706 $ - $ 13,394,706
3 January, 1997 14,285,043 - 14,285,043
4 February, 1997 14,851,119 - 14,851,119
5 March, 1997 15,252,090 - 15,252,090
6 April, 1997 15,401,590 - 15,401,590
7 May, 1997 15,250,326 - 15,250,326
8 June, 1997 14,304,151 - 14,304,151
9 July, 1997 15,101,264 - 15,101,264
10 August, 1997 15,939,930 - 15,939,930
11 September, 1997 15,870,908 - 15,870,908
12 October, 1997 15,528,589 - 15,526,589
13 November, 1997 13,554,370 - 13,554,370
14 December, 1997 13,677,712 - 13,677,712
------------- ------------- ------------
15 13 Month Average 14,800,754 0 14,800,754
16 Prepaid Pension Asset - 13 Month Average 23,698,126 (23,698,126) 0
------------- ------------- ------------
17 Total Prepayments-A/C 1650 - 13 Month Average 38,498,880 (23,698,126) 14,800,754
============= ============= ============
</TABLE>
<PAGE> 28
EXHIBIT REM-1
Page 28
Attachment D
SOUTHWESTERN ELECTRIC POWER COMPANY
MATERIALS AND SUPPLIES
FOR THE TWELVE MONTHS ENDED DECEMBER 31, 1997
<TABLE>
<CAPTION>
(1) (2) (3) (4) (5)
Line Schedule Total Company Pro Forma Total Company
No. Description Reference Per Books Adjustments Pro Forma
--- ----------- --------- --------- ----------- ---------
<S> <C> <C> <C> <C> <C>
1 Monthly Balances:
2 December, 1996 $ 29,265,405 $ (2,980,061) $26,305,344
3 January, 1997 29,429,091 (2,952,801) 26,476,289
4 February, 1997 29,021,578 (2,911,519) 25,110,059
5 March, 1997 28,659,213 (2,904,994) 25,754,219
6 April, 1997 28,052,400 (2,975,724) 25,076,676
7 May, 1997 27,433,626 (2,941,392) 24,492,234
8 June, 1997 27,433,626 (2,957,154) 24,874,795
9 July, 1997 26,782,924 (2,936,799) 23,846,125
10 August, 1997 26,468,390 (2,895,251) 23,573,139
11 September, 1997 25,401,974 (2,863,676) 22,538,298
12 October, 1997 25,099,605 (2,955,520) 22,144,085
13 November, 1997 24,751,493 (2,886,700) 21,864,793
14 December, 1997 24,522,348 (1,779,483) 22,742,865
15 13 Month Average $ 27,132,307 $ (2,840,0831) $24,292,225
============= ============== ===========
</TABLE>
Purpose of adjustment - The adjustment is to remove the portion of materials
and supplies associated with AECC's ownership portion
of Flint Creek Power Plant. These materials and
supplies are recorded on SWEPCO's books.
<PAGE> 29
EXHIBIT REM-1
Page 29
Attachment D
SOUTHWESTERN ELECTRIC POWER COMPANY
FUEL INVENTORIES
FOR THE TEST YEAR ENDING DECEMBER 31, 1997
<TABLE>
<CAPTION>
Book Physical Inv. Ownership Optimal Level Pro Forma
Description Balance Adjustment Adjustment Adjustment Balance
----------- ------- ---------- ---------- ---------- -------
<S> <C> <C> <C> <C> <C>
Oil
Lieberman Power Plan 662,928 - - - 662,928
Knox Lee Power Plant 381,320 - - - 381,320
Lone Star Power Plant 33,150 - - - 33,150
Wilkes Power Plant 274,691 - - - 274,691
Welsh Power Plant 250,999 - - - 250,999
Flint Creek Power Plant 444,367 - - - 444,367
Pirkey Power Plant - - - -
Coal
Welsh Power Plant 12,593,561 - - 24,047,174 2,629,794
Flint Creek Power Plant 5,538,390 1,605,614 (6,101,085) 7,946,486 8,989,405
Lignite
Pirkey Power Plant 2,680,873 - (430,383) 379,304 2,629,794
Dolet Hills Power Plant 3,554,954 - (1,652,164) 4,904,668 6,807,457
Total Fuel Inventory 26,415,233 1,605,614 (8,183,633) 37,277,605 57,114,820
26,415,233 30,699,587 57,114,820
</TABLE>
Purpose: The purpose of the optimal level adjustment is to increase fuel
inventory for each coal power plant to 60 days of inventory and the Pirkey and
Dolet Hills Lignite plants to 21 and 30 days of inventory, respectively.
- -------------------------------------------------------------------------------
<TABLE>
<CAPTION>
INVENTORY LEVEL ADJUSTMENT
Optimal 12/31/97 Price Pro Forma Ownership Pro Forma
Tons Per Ton Ending Bal. Adjustment Ending Bal.
---- ------- ----------- ---------- -----------
<S> <C> <C> <C> <C> <C>
Welsh Power Plant 1,460,371 $ 25.09 36,640,708 36,640,708
Flint Creek Power Plant 486,790 $ 31.00 15,090,490 (2) (6,101,085) 8,989,405
Pirkey Power Plant 264,036 $ 11.59 3,060,177 (1) (430,383) 2,629,794
Dolet Hills Power Plant 384,179 $ 22.02 8,459,622 (1) (1,652,164) 6,807,457
</TABLE>
PHYSICAL INVENTORY ADJUSTMENT
<TABLE>
<CAPTION>
Optimal 12/31/97 Price Pro Forma
Tons Per Ton Ending Bal.
---- ------- -----------
<S> <C> <C> <C>
Flint Creek Power Plant 51,794 $ 31.00 1,605,614
</TABLE>
(1) Pirkey Power Plant and Dolet Hills Power Plant are adjusted by their
ownership percentages of total optimal time.
(2) Flint Creek Power Plant is adjusted by AECC's portion of MWH's
generated of the total optimal tons.
<PAGE> 30
EXHIBIT REM-1
Page 30
Attachment D
SOUTHWESTERN ELECTRIC POWER COMPANY
CUSTOMER DEPOSITS
FOR THE TWELVE MONTHS ENDED DECEMBER 31, 1997
<TABLE>
<CAPTION>
(1) (2) (3) (4) (5)
Line Schedule Total Company Pro Forma Total Company
No. Description Reference Per Books Adjustment Pro Forma
--- ----------- --------- --------- ---------- ---------
<S> <C> <C> <C> <C> <C>
1 Monthly Balances:
2 December, 1996 $ 10,497,074 - $10,497,074
3 January, 1997 10,471,669 - 10,471,669
4 February, 1997 10,424,773 - 10,424,773
5 March, 1997 10,368,557 - 10,368,557
6 April, 1997 10,372,330 - 10,372,330
7 May, 1997 10,362,815 - 10,382,815
8 June, 1997 10,361,001 - 10,361,001
9 July, 1997 10,424,381 - 10,424,381
10 August, 1997 10,564,757 - 10,564,757
11 September, 1997 10,735,824 - 10,735,824
12 October, 1997 10,960,745 - 10,960,745
13 November, 1997 11,056,367 - 11,056,367
------------- -----------
14 December, 1997 11,353,235 - 11,353,235
------------- -----------
TRANSMISSION SERVICES DEPOSITS
1 Monthly Balances:
December, 1996 $ - $ -
January, 1997 - -
February, 1997 - -
March, 1997 - -
April, 1997 - -
May, 1997 - -
16 June, 1997 645,419 - 645,419
17 July, 1997 1,315,314 - 1,315,314
18 August, 1997 1,128,219.74 - 1,315,314
19 September, 1997 1,259,137 - 1,259,137
20 October, 1997 2,103,977 - 2,103,977
21 November, 1997 3,115,623 - 3,115,623
------------- --------- -----------
22 December, 1997 3,005,348 - 3,005,348
------------- --------- -----------
23 TOTAL DECEMBER CUSTOMER DEPOSITS 14,358,583 0 14,358,583
------------- --------- -----------
</TABLE>
<PAGE> 31
EXHIBIT REM-1
Page 31
Attachment D
<TABLE>
<CAPTION>
Southwestern Electric Power Company
Additional Deductions to Rate Base - Deferred Credits
For the Test Year Ending December 31, 1997
Pro Forma
Line Balance Balance
No. Description 31-Dec-97 Adjustments 31-Dec-97
---- ----------- --------- ----------- ---------
<S> <C> <C> <C> <C>
1 Miscellaneous Deposits 2,000 2,000
2 Bremco Liability 1,849,639 1,849,639
3 Property Salvage Proceeds 225,000 225,000
4 Non Rate Base 1,939,285 (1,939,285) 0
--------- ---------- --------
4,015,924 (1,939,285) 2,076,639
========= ========== =========
</TABLE>
<PAGE> 32
EXHIBIT REM-1
Page 32
Attachment D
<TABLE>
<CAPTION>
Southwestern Electric Power Company
Additional Rate Base Items
For the Twelve Months Ending December 31, 1997
Total Company
Total Company Pro Forma
Line Balance Balance
No. Description Dec. 31, 1997 Adjustments Dec. 31, 1997
---- ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C>
1 Regulatory Assets:
2 AMAX Coal Contract 15,709,474 (1,963,684) 13,745,790
3 Ft. Davis R&D Project 2,473,338 0 2,473,338
4 South Tie Asset Costs 0 10,226,802 10,226,802
5 Severance Costs - W/P D-1-35 0 2,558,583 2,558,583
6 Fuel Litigation & Consulting Costs 0 18,488,452 18,488,452
7 Deferred Charges:
8 Deferred DSM Costs 0 5,097,942 5,097,942
9 Accum. Amort. Of Deferred DSM Costs 0 (933,053) (933,053)
10 Cajun Merger Costs Deferred 5,200,027 (5,200,027) 0
11 Deliberative Polling - TX 2,140,223 0 2,140,223
12 Rate Case Expenses - Estimated 0 2,950,000 2,950,000
13 Recoverable Inventory - W/P D-1-16 0 1,149,828 1,149,828
---------- ---------- ----------
14 Total 25,523,062 32,374,843 57,897,905
========== ========== ==========
</TABLE>
<PAGE> 33
EXHIBIT REM-1
Page 33
Attachment D
<TABLE>
<CAPTION>
SOUTHWESTERN ELECTRIC POWER COMPANY
ACCUMULATED DEFERRED INCOME TAXES
FOR THE TEST YEAR ENDED DECEMBER 31, 1997
Total Company
Total Company Pro Forma Pro Forma
Per Books Adjustments Balance
------------- ----------- ------------
<S> <C> <C> <C>
ADIT Account
2820.xxxx (410,312,903) 9,516,867 (400,796,036)
2830.xxxx (74,840,339) 2,813,490 (72,026,849)
1900.xxxx 84,649,850 (7,250,961) 77,398,889
------------ ---------- ------------
(400,503,392) 5,079,396 (395,423,996)
------------ ---------- ------------
Net reg asset/liability
2540.xxxx (114,668,688) - (114,668,688)
1823.xxxx 104,596,295 - 104,596,295
------------ ---------- ------------
(10,072,393) - (10,072,393)
Total - ADIT (410,575,785) 5,079,396 (405,496,389)
============ ========== ============
ITC Account 2550
Pre-71 (345,089) - (345,089)
Post 70 (66,499,892) - (66,499,892)
------------ ---------- ------------
Total (66,844,981) - (66,844,981)
============ ========== ============
</TABLE>
<PAGE> 34
EXHIBIT REM-1
Page 34
EXHIBIT C
Attachment D
<TABLE>
<CAPTION>
SOUTHWESTERN ELECTRIC POWER COMPANY
COMPONENTS OF CAPITAL
FOR THE TEST YEAR ENDED DECEMBER 31, 1997
(1) (2) (3) (4) (5)
Line Schedule Capital Pro-Forma Adjusted
No. Description Reference Per Books Adjustments Capital
---- ----------- --------- --------- ----------- -------
<S> <C> <C> <C> <C> <C>
1 Long-Term Debt C-1 $ 639,524,230 $ -- $ 639,524,230
2 Preferred Stock C-2 34,312,853 (3,972,926) 30,339,927
3 Common Equity 702,235,261 3,972,926 706,208,187
--------------- ------------- -------------
4 Total Capital $ 1,376,072,344 $ -- $1,376,072,344
=============== ============= ==============
</TABLE>
<TABLE>
<CAPTION>
SOUTHWESTERN ELECTRIC POWER COMPANY
COMPONENTS OF CAPITAL
FOR THE TEST YEAR ENDED DECEMBER 31, 1
(1) (6) (7) (8)
Weighted
Line Capital Cost Average
No. Description Ratio Rate Cost
---- ----------- ------- ---- --------
<S> <C> <C> <C> <C>
1 Long-Term Debt 46.47460817% 8.09611592% 3.76263800%
2 Preferred Stock 2.20482064% 7.34628663% 0.16197200%
3 Common Equity 51.32057119% 7.98351560% 4.09718600%
----------- ---------- ----------
4 Total Capital 100.00% 8.02179600%
====== ==========
</TABLE>
<PAGE> 35
EXHIBIT REM-1
Page 35
Attachment D
<TABLE>
<CAPTION>
SOUTHWESTERN ELECTRIC POWER COMPANY
STATEMENT OF OPERATING INCOME
FOR THE TEST PERIOD ENDING DECEMBER 31, 1997
Total Company
Total Company Pro Forma
Dec. 31, 1997 Adjustments Dec. 31, 1997
--------------- ----------------- -----------------
<S> <C> <C> <C>
REVENUES
Total Electric Operating Revenues $ 939,868,615 (20,463,304) $ 919,405,311
Fuel $ 383,007,632 (1,779,003) $ 381,228,629
Deferred Fuel (603,883) 603,883 0
Purchased Power 25,927,920 0 25,927,920
--------------- ----------------- -----------------
Total Fuel and Purchased Power $ 408,331,670 (1,175,120) $ 407,156,550
--------------- ----------------- -----------------
Operations Expense $ 147,627,296 (5,633,248) $ 141,994,048
Maintenance Expense 44,037,971 7,519,662 51,557,633
Depreciation Expense $ 91,093,281 17,179,415 $ 108,272,696
Amortization Expense 4,134,736 10,032,016 14,166,752
Other Taxes 55,962,212 (358,497) 55,603,716
Gain on Sale of Emission Allowances (135,568) 0 (135,568)
--------------- ----------------- -----------------
Operating Expenses Before Income Taxes 342,719,928 28,739,348 371,459,277
--------------- ----------------- -----------------
Federal Income Taxes 43,174,551 (18,400,860) 24,773,691
Deferred Investment Tax Credit (4,662,444) 790,877 (3,871,567)
State Income Taxes 4,764,450 (1,711,507) 3,052,943
--------------- ----------------- -----------------
Total Income Taxes 43,276,557 (19,321,490) 23,955,067
--------------- ----------------- -----------------
Net Operating Income $ 145,540,459 (28,706,042) $ 116,834,417
=============== ================= =================
Rate Base $ 1,447,123,502 $ 9,338,512 $ 1,456,462,014
Rate of Return 10.06% 8.02%
</TABLE>
<PAGE> 36
EXHIBIT REM-1
Page 36
Attachment D
SOUTHWESTERN ELECTRIC POWER COMPANY
ADJUSTMENTS TO OPERATING INCOME STATEMENT
FOR THE TEST YEAR ENDED DECEMBER 31, 1997
<TABLE>
<CAPTION>
WP D-1-2 WP D-1-3 WP D-1-4 WP D-1-5
WP D-1-1 Customer Adjust Auto OPEBS
Total Company Factoring Deposit Depreciation & Purchase SFAS 106
Per Books Expenses Interest Amortization Assistance Adjustment
<S> <C> <C> <C> <C> <C> <C>
Revenues
Residential Sales $ 289,723,381
Commercial Sales 192,115,273
Industrial Sales 263,206,856
Pub St. & Highway Lighting 15,139,937
Other Sales to Public Authorities 12,084,316
------------- ------------- ----------- ------------- ------------- -------------
$ 772,269,763 $ -- $ -- $ -- $ -- $ --
Off System Sales 146,915,557
Forfeited Discounts & Service Rev 3,073,881
Rent From Electric Property 1,958,632
Other Electric Revenue 15,650,781
Required Adjustment for Rate Filing 0
------------- ------------- ----------- ------------- ------------- -------------
Total Electric Operating Revenues $ 939,868,615 $ -- $ -- $ -- $ -- $ --
Fuel $ 383,007,632
Deferred Fuel (603,883)
Purchased Power 25,927,920
------------- ------------- ----------- ------------- ------------- -------------
Total Fuel and Purchased Power $ 408,331,670 $ -- $ -- $ -- $ -- $ --
------------- ------------- ----------- ------------- ------------- -------------
Operations Expense $ 147,627,296 9,327,765 846,680 (804,000) (783,931)
Maintenance Expense 44,037,971
Depreciation Expense 91,093,281 17,179,415
Amortization Expense 4,134,736 2,062,072
Other Taxes 55,962,212
Gain on Sale of Emission Allowances (135,568)
------------- ------------- ----------- ------------- ------------- -------------
Operating Expenses Before Income
Taxes $ 342,719,928 $ 9,327,765 $ 846,680 $ 19,241,487 $ (804,000) $ (783,931)
------------- ------------- ----------- ------------- ------------- -------------
Operating Income Before Income
Taxes $ 188,817,016 $ (9,327,765) $ (845,680) $ (19,241,487) $ (804,000) $ (783,931)
Federal Income Taxes $ 43,174,551
Deferred Investment Tax Credit (4,662,444)
State Income Taxes 4,764,450
------------- ------------- ----------- ------------- ------------- -------------
Total Income Taxes $ 43,276,557 $ -- $ -- $ -- $ -- $ --
------------- ------------- ----------- ------------- ------------- -------------
Net Operating Income $ 145,540,459 $ (9,327,765) $ (845,680) $ (19,241,487) $ 804,000 $ 783,931
============= ============= =========== ============= ============= =============
</TABLE>
<PAGE> 37
EXHIBIT REM-1
Page 37
Attachment D
<TABLE>
<CAPTION>
WP D-1-6 WP D-1-7 WP D-1-8 WP D-1-9 WP D-1-10 WP D-1-11
Pension DSM Reclass Recognize Reverse Dues
SFAS 87 Amortization Cr. Line and South Tie Central Lab Recorded Above
Adjustment Adjustment Filing Fees Costs Revenues The Line
---------- ------------ ------------ --------- ----------- --------------
<S> <C> <C> <C> <C> <C> <C>
Revenues
Residential Sales
Commercial Sales
Industrial Sales
Pub St & Highway Lighting
Other Sales to Public Authorities
----------- -------------- ---------- ------------- -------- ----------
$ -- $ -- $ -- $ -- $ -- $ --
Off System Sales
Forfeited Discounts & Service Rev
Rent From Electric Property
Other Electric Revenue 2,842
Required Adjustment for Rate Filing
Total Electric Operating Revenues
----------- -------------- ---------- ------------- -------- ----------
$ -- $ -- $ -- $ -- $ 2,842 $ --
Fuel
Deferred Fuel
Purchased Power
----------- -------------- ---------- ------------- -------- ----------
Total Fuel and Purchased Power $ -- $ -- $ -- $ -- $ -- $ --
----------- -------------- ---------- ------------- -------- ----------
Operations Expense 2,057,720 (4,552,851) 145,693 (10,226,802) (70,714)
Maintenance Expense
Depreciation Expense
Amortization Expense 832,978 2,045,360
Other Taxes
Gain on Sale of Emission Allowances
Operating Expenses Before Income ----------- -------------- ---------- ------------- -------- ----------
Taxes $ 2,057,720 $ (3,719,873) $ (145,693) $ (8,181,442) $ $ (70,714)
----------- -------------- ---------- ------------- ----------
Operating Income Before Income Taxes $(2,057,720) $ (3,719,873) $ (145,693) $ (8,181,442) $ 2,842 $ 70,714
Federal Income Taxes
Deferred Investment Tax Credit
State Income Taxes
Total Income Taxes
----------- -------------- ---------- ------------- -------- ----------
$ $ $ $ $ $
----------- -------------- ---------- ------------- -------- ----------
Net Operating Income $(2,057,720) $ 3,719,873 $ (145,693) $ 8,181,442 $ 2,842 $ 70,714
=========== ============== ========== ============= ======== ==========
</TABLE>
<PAGE> 38
EXHIBIT REM-1
Page 38
Attachment D
<TABLE>
<CAPTION>
WP D-1-13 WP D-1-16
WP D-1-12 Amortization WP D-1-14 WP D-1-15 Reverse WP-D-1-1
of Litigation Inventor
Fed. & State and Amortization Write-off & Increase
Income Tax Consulting of Rate Reverse Allow Distribution
Adjustments Costs Case Expense Laredo Expense Amortization C Expense
------------ ------------- ------------- -------------- ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
Revenues
Residential Sales
Commercial Sales
Industrial Sales
Pub St. & Highway Lighting
Other Sales to Public Authorities ____________ _____________ _____________ _____________ _____________ _____________
$ - $ - $ - $ - $ - $ -
Off System Sales
Forfeited Discounts & Service Rev.
Rent From Electric Property
Other Electric Revenue
Required Adjustment for Rate Filing _____________ _____________ _____________ _____________ _____________ _____________
Total Electric Operating Revenues $ - $ - $ - $ - $ - $ -
Fuel
Deferred Fuel
Purchased Power _____________ _____________ _____________ _____________ _____________ _____________
Total Fuel and Purchased Power $ - $ - $ - $ - $ - $ -
_____________ _____________ _____________ _____________ _____________ _____________
Operations Expense (1,090,376) (1,149,828)
Maintenance Expense 7,993,000
Depreciation Expense
Amortization Expense 2,312,038 983,333 229,966
Other Taxes
Gain on Sale of Emission Allowances _____________ _____________ _____________ _____________ _____________ _____________
Operating Expenses Before Income
Taxes $ - $ 2,312,038 $ 983,333 $ (1,090,376) $ (919,862) $ 7,993,000
_____________ _____________ _____________ _____________ _____________ _____________
Operating Income Before Income Taxes $ - $ (2,312,038) $ (983,333) $ 1,090,376 $ 919,862 $ (7,993,000)
Federal Income Taxes (18,400,860)
Deferred Investment Tax Credit 790,877
State Income Taxes (1,711,507)
_____________ _____________ _____________ _____________ _____________ _____________
Total Income Taxes $ (19,321,490) $ - $ - $ - $ - $ -
_____________ _____________ _____________ _____________ _____________ _____________
Net Operating Income $ 19,321,490 $ (2,312,038) $ (983,333) $ 1,090,376 $ 919,862 $ (7,993,000)
============= ============= ============= ============= ============= =============
</TABLE>
<PAGE> 39
EXHIBIT REM-1
Page 39
Attachment D
<TABLE>
<CAPTION>
WP D-1-20
WP D-1-18 WP D-1-19 Adjust WP D-1-21 WP D-1-23
Customer Other Property Fuel Adjust SFAS 112
Annualization Taxes Insurance Revenue Expense to
Adjustment Adjustment Expense Adjustment "Pay-As-You-Go"
------------- --------- ---------- --------- --------------
<S> <C> <C> <C> <C> <C>
Revenues
Residential Sales 5,965,768 (15,167,323)
Commercial Sales
Industrial Sales
Pub St & Highway Lighting
Other Sales to Public Authorities ____________ _____________ _____________ _____________ _____________
$ 5,965,768 $ - $ - $ (15,167,323) $ -
Off System Sales
Forfeited Discounts & Service Rev.
Rent From Electric Property
Other Electric Revenue 266,408
Required Adjustment for Rate Filing _____________ ____________ _____________ _____________ _____________
Total Electric Operating Revenues $ 8,017,298 $ - $ - $ (15,167,323) $ -
Fuel
Deferred Fuel
Purchased Power _____________ _____________ _____________ _____________ _____________
Total Fuel and Purchased Power $ - $ - $ - $ - $ -
_____________ _____________ _____________ _____________ _____________
Operations Expense 655,615 473,500
Maintenance Expense
Depreciation Expense
Amortization Expense 0
Other Taxes (358,497)
Gain on Sale of Emission Allowances _____________ _____________ _____________ _____________ _____________
Operating Expenses Before Income Taxes $ - $ (358,497) $ 655,615 $ $ 473,500
_____________ _____________ _____________ _____________ _____________
Operating Income Before Income Taxes $ 8,017,298 $ 358,497 $ (655,615) $ (15,167,323) $ (473,500)
Federal Income Taxes
Deferred Investment Tax Credit
State Income Taxes
_____________ _____________ _____________ _____________ _____________
Total Income Taxes $ - $ - $ - $ - $ -
_____________ _____________ _____________ _____________ _____________
Net Operating Income $ 8,017,298 $ 358,497 $ (655,615) $ (15,167,323) $ (473,500)
============= ============= ============= ============= =============
</TABLE>
<PAGE> 40
EXHIBIT REM-1
Page 40
Attachment D
<TABLE>
<CAPTION>
WP D-1-28
WP D-1-24 WP D-1-25 WP D-1-26 WP D-1-27 Amortization
Adjustment Open Unbilled TFO of
of CSWS Access Revenue Expense Deliberative
Billings Adjustment Adjustment Adjustment Polling
---------- ------------ ----------- ---------- ------------
<S> <C> <C> <C> <C> <C>
Revenues
Residential Sales
Commercial Sales
Industrial Sales
Pub St. & Highway Lighting
Other Sales to Public Authorities ____________ _____________ _____________ _____________ _____________
$ - $ - $ - $ - $ -
Off System Sales
Forfeited Discounts & Service Rev.
Rent From Electric Property
Other Electric Revenue (169,000)
Required Adjustment for Rate Filing _____________ ____________ _____________ _____________ _____________
Total Electric Operating Revenues $ - $ - $ (169,000) $ - $ -
Fuel
Deferred Fuel
Purchased Power _____________ _____________ _____________ _____________ _____________
Total Fuel and Purchased Power $ $ $ $ $
_____________ _____________ _____________ _____________ _____________
Operations Expense (682,611) 6,290,574 (5,005,286)
Maintenance Expense
Depreciation Expense
Amortization Expense 713,408
Other Taxes (358,497)
Gain on Sale of Emission Allowances _____________ _____________ _____________ _____________ _____________
Operating Expenses Before Income Taxes $ (682,611) $ 6,290,574 $ - $ (5,005,286) $ 713,408
_____________ _____________ _____________ _____________ _____________
Operating Income Before Income Taxes $ 682,611 $ (6,290,574) $ (169,000) $ 5,005,286 $ (713,408)
Federal Income Taxes
Deferred Investment Tax Credit
Sate Income Taxes
_____________ _____________ _____________ _____________ _____________
Total Income Taxes $ - $ - $ - $ - $ -
_____________ _____________ _____________ _____________ _____________
Net Operating Income $ 682,611 $ (6,290,574) $ (169,000) $ 5,005,286 $ (713,408)
============== ============== ============== ============== =============
</TABLE>
<PAGE> 41
EXHIBIT REM-1
Page 41
Attachment D
<TABLE>
<CAPTION>
WP D-1-29
Reduce Fuel WP D-1-30 WP D-1-31 WP D-1-32 WP D-1-33
Exp. for Adjustment to RTP & STOU Eliminate Payroll
Time of Use Mine Closing Revenue Walker Co. Annualization
Sales Expense Adjustment Revenue Adjustment
----------- ------------- ---------- ---------- -------------
<S> <C> <C> <C> <C> <C>
Revenues
Residential Sales (2,561,349)
Commercial Sales
Industrial Sales
Pub St. & Highway Lighting
Other Sales to Public Authorities ____________ _____________ _____________ ____________ _____________
$ - $ - $ (2,561,349) $ - $ -
Off System Sales
Forfeited Discounts & Service Rev.
Rent From Electric Property
Other Electric Revenue (320,167)
Required Adjustment for Rate Filing
Total Electric Operating Revenues _____________ _____________ _____________ _____________ _____________
$ - $ - $ (2,561,349) $ (320,167) $ -
_____________ _____________ _____________ _____________ _____________
</TABLE>
<PAGE> 42
EXHIBIT REM-1
Page 42
Attachment D
<TABLE>
<CAPTION>
WP D-1-34 WP D-1-36 WP D-1-37 WP D-1-38
CSWS Payroll WP D-1-35 Wholesale Pro Forma Facilities
Annualization Severance Refund Revenue Charges
Adjustment Adjustment Adjustment Adjustment Adjustment
------------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Revenues
- -----------------------------------
Residential Sales (35,052) (1,071,116)
Commercial Sales
Industrial Sales
Pub St & Highway Lighting
Other Sales to Public Authorities _____________ _____________ _____________ _____________ _____________
$ - $ - $ - $ (35,052) $ (1,071,116)
Off System Sales (7,479,430) (88,990)
Forfeited Discounts & Service Rev.
Rent From Electric Property
Other Electric Revenue 1,160,106
Required Adjustment for Rate Filing _____________ ____________ _____________ _____________ _____________
Total Electric Operating Revenues $ - $ - $ (7,479,430) $ (35,052) $ -
Fuel 17,126
Deferred Fuel
Purchased Power _____________ _____________ _____________ _____________ _____________
Total Fuel and Purchased Power $ 17,126 $ - $ - $ - $ -
_____________ _____________ _____________ _____________ _____________
Operations Expense 642,156 (1,055,322)
Maintenance Expense 6,671
Depreciation Expense
Amortization Expense 852,861
Other Taxes
Gain on Sale of Emission Allowances _____________ _____________ _____________ _____________ _____________
Operating Expenses Before Income Taxes $ 648,827 $ (202,461) $ - $ - $ -
_____________ _____________ _____________ _____________ _____________
Operating Income Before Income Taxes $ (665,953) $ 202,461 $ (7,479,430) $ (35,052) $ -
Federal Income Taxes
Deferred Investment Tax Credit
State Income Taxes
_____________ _____________ _____________ _____________ _____________
Total Income Taxes $ - $ - $ - $ - $ -
_____________ _____________ _____________ _____________ _____________
Net Operating Income $ (665,953) $ 202,461 $ (7,479,430) $ (35,052) $
============= ============= ============== ============== =============
</TABLE>
<PAGE> 43
EXHIBIT REM-1
Page 43
Attachment D
<TABLE>
<CAPTION>
WP D-1-39
Economic WP D-1-40
Development Deferred
Rider Fuel Total Total Company
Adjustment Adjustment Adjustments Pro Forma
----------- ---------- ----------- -------------
<S> <C> <C> <C> <C>
Revenues
- -----------------------------------
Residential Sales 537,781 (3,288,904) (15,620,195) 274,103,185
Commercial Sales 0 192,115,273
Industrial Sales 0 263,206,856
Pub St. & Highway Lighting 0 15,139,937
Other Sales to Public Authorities 0 12,084,316
_____________ ____________ ____________ _____________
$ 537,781 $ (3,288,904) $(15,620,195) $ 756,649,568
Off System Sales (5,783,298) 141,132,259
Forfeited Discounts & Service Rev. 0 3,073,881
Rent From Electric Property 0 1,958,632
Other Electric Revenue 940,189 16,590,971
Required Adjustment for Rate Filing 0 0
_____________ ____________ ____________ _____________
Total Electric Operating Revenues $ 537,781 $ (3,288,904) $(20,463,304) $ 919,405,311
Fuel (1,779,003) 381,228,629
Deferred Fuel 603,883 603,883 0
Purchased Power 0 25,927,920
_____________ ____________ ____________ _____________
Total Fuel and Purchased Power $ - $ 603,883 $ (1,175,120) $ 407,156,550
_____________ ____________ ____________ _____________
Operations Expense 537,781 $ (5,633,248) $ 141,994,048
Maintenance Expense 7,519,662 51,557,633
Depreciation Expense 17,179,415 108,272,696
Amortization Expense 10,032,016 14,166,752
Other Taxes (358,497) 55,603,716
Gain on Sale of Emission Allowances 0 (135,568)
_____________ ____________ ____________ _____________
Operating Expenses Before Income Taxes $ 537,781 $ - $ 28,739,348 $ 371,459,277
_____________ ____________ ____________ _____________
Operating Income Before Income Taxes $ - $ (3,892,787) $ (48,027,532) $ 140,789,484
Federal Income Taxes $ (18,400,860) 24,773,691
Deferred Investment Tax Credit 790,877 (3,871,567)
State Income Taxes $ (1,711,507) $ 3,052,943
_____________ ____________ ____________ _____________
Total Income Taxes $ - $ - $ (19,321,490) $ 23,955,067
_____________ ____________ ____________ _____________
Net Operating Income $ $ (3,892,787) $ (28,706,042) $ 116,834,417
============= ============= ============= =============
</TABLE>
<PAGE> 1
Exhibit D-4.2
BEFORE THE CORPORATION COMMISSION OF THE STATE OF OKLAHOMA
JOINT APPLICATION OF AMERICAN )
ELECTRIC POWER COMPANY, INC., )
PUBLIC SERVICE COMPANY OF )
OKLAHOMA AND CENTRAL AND SOUTH ) CAUSE NO. PUD 980000444
WEST CORPORATION REGARDING )
PROPOSED MERGER ) ORDER NO. 432267
HEARING: April 19, 20 and 21, 1999
Before Robert E. Goldfield, Administrative Law Judge
May 11, 1999, before the Commission en banc
APPEARANCES: Cody L. Graves, Attorney for American Electric Power
Company, Inc.
Jack P. Fite, Clark Evans Downs and Jay M. Gait, Attorneys for
Public Service Company of Oklahoma and Central and South West
Corporation
Deborah Jacobson, Assistance General Counsel for the Public
Utility Division of the Oklahoma Corporation Commission
Marchi C. McCartney and Jeffrey P. Southwick. Staff Counsel
for Consumer Services Division of the Oklahoma Corporation
Commission
Deborah R. Morgan, Assistant Attorney General. Counsel for the
Office of the Attorney General
Patrick D. Shore. Attorney for the Oklahoma Association of
Electric Cooperatives
C. Max Speegle. Attorney for Municipal Electric Systems of
Oklahoma
Robert D. Steward, Jr. and Harry H. Selph, II. Attorneys for
Oklahoma Gas and Electric Company
<PAGE> 2
FINAL ORDER
BY THE COMMISSION
The Corporation Commission of the State of Oklahoma ("Commission"),
being regularly in session, and the undersigned Commissioners being present and
participating, there comes on for consideration and action the report of the
Administrative Law Judge in the above-entitled Cause and the appeals thereto.
The procedural history in this Cause is set forth at pages 2 and 3
of the Report and Recommendations of the Administrative Law Judge ("Report") and
is incorporated herein as if fully set forth.
SUMMARY OF EVIDENCE
The Summary of Evidence found on pages 7 through 58 of the Report is
adopted as the Summary of Evidence of the Commission.
Oklahoma Association of Electric Cooperatives ("OAEC") and Municipal
Electric Systems of Oklahoma ("MESO") filed appeals to the Report and argued
that 17 O.S. Section 191.5 does not authorize or allow the exercise of
"conditional approval" by the Commission of a merger. They argued that the
statute provides that a merger application shall be approved unless one of the
five conditions is found, in which case the merger shall be disapproved. They
argued that the ALJ found that market power would exist and competition in
Oklahoma would be harmed, and therefore the ALJ's "conditional approval" was
beyond the jurisdiction of the Commission. (See the Report, at page 58.) OAEC
and MESO further argued that as a result of this finding, under the above
statute, the Commission was without discretion, and must deny the merger.
2
<PAGE> 3
OG&E argued that if the Commission determined, as a matter of law,
that it does not have the authority to approve the merger with conditions, the
request for approval of the merger should be rejected. In the alternative, if
the Commission found as a matter of law that the Oklahoma merger statute (17
O.S. Sections 191.1 et seq.) did permit approval by the Commission of a
merger subject to conditions. OG&E suggested various conditions. OG&E stated
that if the merger should go forward, that the market and public interest should
be protected from any negative impact of the merger.
OG&E also noted its disagreement with the ALJ as to the
recommendation regarding line loss being exclusively a Federal Energy Regulatory
Commission jurisdictional issue. It is the position of OG&E that this Commission
does have jurisdiction over the line loss issue. OG&E counsel stated that an
OG&E witness, Stephen Heibson, quantified the line loss issue to be worth at
least $15 million over a 10 year period, as a direct result of the merger and,
OG&E's customers should not have to bear the cost of that loss.
OG&E stated that the Southwest Power Pool ("SWPP") should be
recognized as the final arbitrator as to the mitigation of the congestion issue,
and requested that the Commission direct the parties to go to the SWPP to
establish appropriate mitigation measures. OG&E recommended that the Merger be
denied for now, without prejudice, until the Applicants could show that the
conditions recommended by this Commission are met and then, upon a showing by
the Applicants that the conditions have been met, the merger could go forward
without harm.
The Joint Applicants' Brief in Support of the ALJ's Report and
arguments before the Commission, disputed characterization of the ALJ's Report
made by MESO and OAEG. Specifically, the ALJ did not find the existence of the
statutory standard that "substantial" harm
3
<PAGE> 4
would be caused to competition. The ALJ further found that the impact of the
merger which would lessen competition was "negated" by the Joint Applicants'
commitment to engage in joint planning. Specifically, the ALJ's Report states as
follows on page 58:
"The primary areas of inquiry raised by Intervenor OG&E and others,
relating to whether the merger would lessen competition in the
furnishing of public utility service in the state, is negated by the
Joint Applicants' commitment to engage in joint planning and the
involvement of the Southwest Power Pool." (emphasis supplied)
The Joint Applicants argued that the ALJ had not found any of the
conditions existed which would require the Commission to deny the merger.
The Joint Applicants argued that the order issued in the
Southwestern Public Service Company ("SPS") Public Service Company of Colorado
("PSO") merger approval case (PUD 960000231) was a similar order as that
recommended by the ALJ. The Commission's order, Order No. 405423, approved a
Stipulation which required studies of the proposed interconnection between SPS
and PSCO to be performed. Alternatives to the proposed interconnection,
including using existing high-voltage, direct current interconnections, were to
be examined. Another required study was to examine the options and the cost of
expanding import and export capability between SPS's system and the Southwest
Power Pool.
By following the recommendations of the ALJ, it was argued the
Commission is stating that none of the conditions exist if the Stipulation is
approved and the Southwest Power Pool is engaged.
MESO and OAEC argued it was error for the ALJ to strike a portion of
Dr. Sinclair's testimony as being outside of the parameters of the study
guidelines approved for use
4
<PAGE> 5
in this case by Order No. 430244. The essence of their argument is that only the
Joint Applicants were subject to the guidelines approved in Order No. 430244.
Further, it was presented that the testimony was relevant and should be given an
appropriate weight by the Court.
The Commission finds this argument unpersuasive. All parties agreed
to the guidelines, and it was the testimony of OG&E's witness that OG&E felt
bound by the Commission's order. It is the Commission's decision that all
parties were bound by the guidelines contained in Order No. 430244.
(Attached as Attachment B for reference.)
FINDINGS OF FACT AND CONCLUSIONS OF LAW
After considering the Report of the Administrative Law Judge and the
arguments made during the hearing on exceptions, the Commission makes the
following findings of fact and conclusions of law:
The Commission finds that it has jurisdiction over this merger and
the authority to issue this order pursuant to 17 O.S. Section 191.1 et seq. and
OAC 165:5-7-57. Further, this Commission has jurisdiction over Public Service
Company of Oklahoma regarding retail rates, and the effect that the merger might
have on those rates, pursuant to 17 O.S. Section 152.153 and Okla.
Const. Art. 9, Section 18.
Based upon the argument of counsel and an examination of the ALJ's
findings and recommendations, the Commission finds that the adoption of the
ALJ's Report and the recommendations contained therein is within this
Commission's jurisdiction. This Commission issues many orders which contain
directives. It is not unusual for this Commission to allow an applicant
permission to perform some activity (such as in oil and gas orders) and to take
other actions such as implementing a new tariff if certain directives are
followed. This case is no different. All parties except OAEC and MESO stated
that this Commission had the authority to
5
<PAGE> 6
issue an order which would contain directives. This Commission is of the opinion
that its order in the SPS case was proper and that an order in this Cause
adopting the ALJ's Report is within the jurisdiction of this Commission.
The Commission further finds that the ALJ acted within the scope of
his authority to limit the testimony to the agreed upon study parameters which
were found in Order No. 430244.
The Commission further finds that although competition would be
lessened as a result of this merger, it does not meet the level required under
Section 191.5(A)(2), that competition would be "substantially" lessened, and
therefore, the Commission finds that the condition contemplated under the
statute does not exist.
This Commission further finds that the safeguards are present and
that it will continue to have jurisdiction over retail electric competition in
this state.
The Attorney General for the State of Oklahoma ("Attorney General")
recommended to the Commission that the ALJ Report be adopted as a fair and
reasonable balance of the interests of the parties involved. The Attorney
General further noted that the SWPP is a forum in which both the Applicants and
OG&E are members, and as such, should receive fair consideration.
Staff recommended that the ALJ Report be adopted as the order of
this Commission. The Staff believes that congestion does exist on the system,
and recommends further study on this issue. Staff noted that the Applicants is
to divest certain assets to address some market power concerns. Certain
mitigation measures are addressed (see page 7, Section 7 of the Stipulation,
Attachment A) which are designed with the intention to allow entry into the
competitive market. The Applicants commit to hold the current jurisdictional
customers
6
<PAGE> 7
harmless and identify that the merger does not create any stranded costs. The
Applicants also have committed to regional planning, either through an
Independent System Operator ("ISO") or a Regional Transmission Organization
("RTO").
The Commission having considered the record in this Cause and the
Appeals to the Report, adopts the Findings of Fact and Conclusions of Law
contained within the Report of the Administrative Law Judge as the findings of
fact and conclusions of law of the Commission. The Commission therefore finds
that the merger should be approved, consistent with the recommendations of the
ALJ's report.
ORDER
IT IS THEREFORE THE ORDER OF THE CORPORATION COMMISSION OF THE STATE
OF OKLAHOMA that the findings of the Administrative Law Judge be adopted as the
Findings and Conclusions of this Commission.
IT IS FURTHER ORDERED that the recommendations of the Administrative
Law Judge, including the Stipulation attached thereto, are hereby adopted by the
Commission. Said Report is attached to this order as "Attachment A".
IT IS FURTHER ORDERED that the merger between American Electric
Power Company, Inc., Public Service Company of Oklahoma and Center & Southwest
Corporation is hereby approved consistent with the Report of the Administrative
Law Judge.
CORPORATION COMMISSION OF OKLAHOMA
/s/ED APPLE, Chairman
/s/BOB ANTHONY, Vice-Chairman
/s/DENISE A. BODE, Commissioner
Done and performed this 17th day of May, 1999.
7
<PAGE> 8
BY ORDER OF THE COMMISSION:
/s/CHARLOTTE W. FLANAGAN, Secretary
8
<PAGE> 9
BEFORE THE CORPORATION COMMISSION OF THE STATE OF OKLAHOMA
JOINT APPLICATION OF AMERICAN )
ELECTRIC POWER COMPANY, INC., )
PUBLIC SERVICE COMPANY OF )
OKLAHOMA AND CENTRAL AND ) CAUSE NO. PUD 98 0044
SOUTH WEST CORPORATION )
REGARDING PROPOSED MERGER )
HEARING: April 19, 20 and 21, 1999
Before Robert E. Goldfield, Administrative Law Judge
APPEARANCES: Cody L. Graves, Attorney for American Electric Power
Company, Inc.
Jack P. Fite, Clark Evans Downs and Jay M. Galt,
Attorneys for Public Service Company of Oklahoma and
Central and South West Corporation
Deborah Jacobson, Assistant General Counsel for the
Public Utility Division of the Oklahoma Corporation
Commission
Marchi C. McCartney and Jeffrey P. Southwick, Counsel
for Consumer Services Division of the Oklahoma
Corporation Commission
Deborah R. Morgan, Assistant Attorney General,
Counsel for the Office of the Attorney General
Patrick D. Shore, Attorney for the Oklahoma
Association of Electric Cooperatives
C. Max Speegle, Attorney for Municipal Electric
Systems of Oklahoma
Robert D. Stewart, Jr. and Harry H. Selph, II,
Attorneys for Oklahoma Gas and Electric Company
<PAGE> 10
REPORT AND RECOMMENDATIONS
The following is the Report and Recommendations of the Administrative Law Judge
("ALJ") regarding the Joint Application of American Electric Power Company, Inc.
("AEP"), Public Service Company of Oklahoma ("PSO") and Central and South West
Corporation ("CSW") regarding a proposed merger.
I. PROCEDURAL HISTORY
On August 14, 1998, AEP, PSO and CSW ("Applicants" or "Joint Applicants")
filed a Joint Application and Statement requesting this Commission approve a
proposed business combination in which CSW operating companies and subsidiaries,
including PSO, would become operating companies and subsidiaries of AEP.
The Office of the Attorney General ("AG"), Oklahoma Association of
Electric Cooperatives ("OAEC"), Municipal Electric Systems of Oklahoma, Inc.
("MESO"), International Brotherhood of Electrical Workers ("IBEW"), Oklahoma Gas
and Electric Company ("OG&E"), the Consumer Services Division ("CSD") of the
Oklahoma Corporation Commission ("OCC") and the Public Utility Division of the
OCC ("PUD" or "Staff") were granted intervention.
On September 25, l998, OG&E filed a Motion to Compel or Dismiss
Application. Also on that date OAEC filed a Motion to Strike Testimony or
Dismiss the Application.
The Joint Applicants filed a Motion to Withdraw Statement filed October
15, 1998. By agreement of the parties, the Motion was presented to the ALJ on
October 20, 1998. The parties objected to the Commission granting the Motion as
amended by the Joint Applicants. The Commission thereafter issued Order No.
427699 granting the Motion to Withdraw Statement and holding in suspense the
time frame contained within 17 O.S. Section 191.2 and ordering that a new
2
<PAGE> 11
time would commence on the filing of a new Statement upon which the Joint
Applicants would rely for their relief requested in the Cause.
On October 26, 1998, this Commission issued Order No. 427700 (Order
Regarding Discovery) which stated that the Joint Applicants could file a new
Statement as required by 17 O.S. Section 191.2 which was to include a retail
market study and load flow analysis as described in the Order after which the
statutory time limits contained within 17 O.S. Section 19l.5(b) would commence.
On November 30, 1998, this Commission issued Order No. 428530 (Amended
Scheduling Order) which was superceded by Order No. 429667, which granted the
AG's Motion to Hold the Hearing in Abeyance.
On February 25, 1999, the Joint Applicants filed its Amended Statement and
Application after which a Second Amended Scheduling Order (Order No.
430719) was issued March 9, 1999.
On April 1, 1999, the Joint Applicants filed a Motion to Strike the
Testimony of Dr. Sinclair as being contrary to the directives of Order No.
430244, issued February 16, 1999. Based upon the argument of counsel the ALJ
struck page 30, line 25 through page 33, line 2 and Exhibit RAS-2. An exception
to this ruling was noted to MESO and the OAEC.
On April 15, 1999, OG&E filed a Motion to Strike the Rebuttal Testimony of
Raymond M. Maliszewski. The oral arguments were held on April 19, 1999, prior to
the taking of testimony. Based upon the arguments of counsel, the ALJ struck
page 14, beginning with line 8 through page 16, line 13 and page 23, line 11
(the word "Furthermore") through line 15 (the end of the sentence with the word
"occur") and Exhibits RMM-4 and RMM-5 of Mr. Maliszewski's testimony. An
exception was noted for the Joint Applicants.
3
<PAGE> 12
The trial on the merits was held before the ALJ on April 19, 20 and 21,
1999.
II. SUMMARY OF STIPULATION
The Joint Applicants, PUD, CSD, and AG announced that a stipulation had
been reached on various issues between the parties. Mr. David Carpenter
testified on behalf of the Joint Applicants in support of the Stipulation
(Exhibit No. 209, attached to this Report).
DAVID G. CARPENTER
Mr. Carpenter testified that the Stipulation provides for net non-fuel and
non-purchase power O & M savings to be shared through a net merger savings rate
rider over the next five years after the effective date of the merger.
Attachment 1 of the Stipulation, column 5, reflected the annual amount of rate
reduction which would be reflected in the rate reduction rider over the next
five years. In the sixth year after the effective date of the merger, the
customer rate reduction rider would increase to $9,409,000 until the next base
rate proceeding after the end of the fifth year at which time the net merger
savings rate reduction rider will be terminated [pp. 176-177].
Mr. Carpenter further testified that the Stipulation provided that the
cost to achieve the merger would be deferred and amortized. Costs to achieve the
merger are those costs which are incurred within the time period ending two
years after the effective date of the merger. Those costs will be deferred and
amortized over a five-year period of time.
Attachment 2 sets forth the allocation of the net merger savings rider
between customer classes. Attachment 3 contains an example of how merger savings
will be treated in future base rate cases. The example used was based upon year
three after the effective date of the merger. Mr. Carpenter explained how the
net merger savings for the test year were arrived at, and then how the add-back
to the test year cost of service of the Oklahoma customer rate reduction would
be $5,878,000.
4
<PAGE> 13
Mr. Carpenter also gave an example if the merger savings were $5 million
higher than predicted and how the formula worked so that retail customers
received all of the additional merger savings over and above those set forth in
Attachment 1.
In the event that the electric utility industry in Oklahoma is
restructured, and the services provided by PSO are unbundled into regulated and
unregulated services, the merger savings and associated amortization and
shareholder imputation will continue. Therefore, customers will continue to
receive the full level of merger savings on the regulated portion of the rates.
In the event that a general rate proceeding is initiated by a party other
than PSO, subsequent to industry restructuring and prior to the end of the fifth
year, then the rider benefits, cost amortization, and shareholder net savings
amputations shall be reduced proportionally to the rates of the unregulated,
unbundled services.
Fuel and purchase power expense savings derived from the merger will be
flowed through the fuel adjustment clause to customers in accordance with the
current practice.
Other provisions of the Stipulation provide for the Staff and AG to have
access to copies of books and records of AEP and its affiliates as necessary to
review the transactions of PSO. The Joint Applicants have also agreed that
stranded costs, if any that PSO may seek to recover in the future will be on a
stand-alone basis and that PSO does not have any stranded costs currently.
Further, the merger does not create any stranded costs.
Mr. Carpenter testified that the agreement holds harmless Oklahoma
retail customers from any adverse effects of the mitigation plan filed at the
FERC.
Section 8 of the Stipulation states that the Joint Applicants will not
seek to increase base rates prior to January 1, 2003, except for certain Force
Majeure provisions. If a review is sought by the Joint Applicants from January
1, 2003 through the end of the fifth year after the effective
5
<PAGE> 14
date of the merger, then the Joint Applicants will make a $5 million reduction
to a revenue requirement otherwise determined to be reasonable by the
Commission.
The Force Majeure provisions found in Section 9 provide that PSO will have
the burden of proving that its request for relief is a good faith request, that
the event or occurrence was not directly or indirectly caused by PSO, that the
occurrence has at least an annual impact of $6 million, and that PSO has no
direct or indirect control over the event or occurrence.
The agreement also has provisions regarding a hold harmless for PSO's cost
of capital, a commitment to comply with quality of service standards which were
set forth in Attachment 5, a most favored nations provision which provides that
Oklahoma retail customers will receive the same equivalent net benefits and
conditions as any other state related to settlements of the merger case or
orders related to the merger. In addition, a hold harmless provision for retail
customers from any unforeseen events that materially diminished the estimated
benefits of the merger is contained in the Stipulation.
The Stipulation at Section 15 contains an agreement that states that if
the merger is not consummated, PSO would not seek to recover merger-related
transition, transaction, or termination fees from Oklahoma retail customers.
Section 16 states that PSO will not incur any debt or pledge the stock of
PSO in a manner that, upon an affiliate's default, would permit a creditor to
have recourse against the regulated assets of PSO.
Section 17 is a commitment by the Joint Applicants to join a regional
transmission authority by the latter of six months prior to retail customer
choice or December 31, 2001.
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<PAGE> 15
The agreement also provides for Joint Applicants to notify the Commission
at the time the merger is closed and the agreement becomes effective. Further,
the agreement is to not be precedential for other proceedings in the future.
Mr. Carpenter recommended that the Stipulation be approved.
Pursuant to a question from the Attorney General's office, Mr.
Carpenter stated that if a rate case takes place after year five from the
effective date of the closing, Section 3(d) provides there will be no estimated
non-fuel operation and maintenance expense savings included in the cost of
service. There will be no amortization of costs to achieve included in the cost
of service and the merger savings rate reduction rider will terminate. In
essence, everything will be the same in setting rates as before the merger.
At the conclusion of Mr. Carpenter's testimony the Joint Applicants
moved into the record the pre-filed testimonies of Mr. Mark Bailey (Exhibit
Nos. 21 and 78); Mr. David Carpenter (Exhibit No. 120); Mr. Russell Davis
(Exhibit Nos. 16 and 121); Dr. Linn Draper (Exhibit No. 10); Mr. Bruce Evans
(Exhibit Nos. 20 and 77); Mr. Richard Munczinski (Exhibit Nos. 14, 74, 118,
133 and 195); Mr. Thomas Mitchell (Exhibit Nos. 18 and 122); Mr. Armando Pena
(Exhibit 19); Mr. Thomas Shockley (Exhibit No. 11); and Mr. Eric Zausner
(Exhibit No. 138). The Joint Applicants submitted the testimony as support
for the Stipulation and there were no objections to allowing the testimony to
be submitted into the record and relied upon by the ALJ with all parties
waiving cross-examination of those particular witnesses.
The following witnesses pre-filed testimony in this Cause regarding
issues that were settled in the Stipulation: Mr. Bill Burnett (Exhibit No.
111) on behalf of CSD; Ms. Evelyn H. Francik (Exhibit No. 58), Ms. Roya Z.
Soltani (Exhibit No. 57) and Mr. Robert C. Thompson (Exhibit No. 113) on
behalf of PUD; and Mr. Michael L. Brosch (Exhibit Nos. 114 and 170) on
7
<PAGE> 16
behalf of the AG. Cross-examination of these witnesses was waived and since
their testimony was filed prior to an agreement being reach, their testimony
should be conformed to the Stipulation.
III. SUMMARY OF EVIDENCE
THOMAS J. FLAHERTY
Mr. Thomas J. Flaherty, the National Partner - Energy Consulting and a
partner in the Deloitte & Touche Consulting Group LLC (Deloitte Consulting)
testified on behalf of the Joint Applicants. Mr. Flaherty's testimony contained
within Exhibits 12 and 119 was accepted into the record without objection.
According to Mr. Flaherty, the merger of the Joint Applicants is anticipated to
result in cost savings that should permit rates in the future to be below the
level that otherwise would have been necessary on a stand-alone basis for either
AEP or CSW operating companies. The merger is estimated to produce approximately
$2.4 billion of nonproduction cost savings, before approximately $248 million of
out-of-pocket costs to achieve these savings, and $193 million of cost cutting
measures planned or initiated by each of the Companies prior to the merger
("premerger initiatives"), and is expected by management of AEP and CSW to
provide an opportunity to benefit all stakeholders, including customers,
shareholders and employees, and result in a stronger, more competitive company.
The estimated nonproduction cost savings reflect the potential creation of
cost reduction or cost avoidance opportunities through the ability to
consolidate separate, stand-alone operations into a single entity. This
consolidation and integration thus may enable duplicative functions and
positions to be eliminated, similar corporate activities to be combined, avoided
or reduced in scope, external purchases of commodities and services to be
aggregated, and capital expenditures to be avoided.
The savings, by category, were identified as follows:
8
<PAGE> 17
Total Nonproduction Cost Savings
<TABLE>
<CAPTION>
1999 - 2009
Savings Category ($ Millions)
--------------------------------------------------------------
<S> <C>
Corporate and Operations Support Staffing 996
Corporate and Administrative Programs 1,044
Purchasing Economies (Nonfuel) 367
-----
Total Savings 2,407
Less: Costs to Achieve (248)
Premerger Initiatives (193)
-----
Net Savings 1,966
=====
</TABLE>
Recent utility mergers and acquisitions in other states have produced
substantial benefits to customers in the form of operational synergies and cost
savings that reduce rates or slow the rate of growth in rates. Benefits to
customers, however, will not materialize without costs being incurred and risks
being assumed. In merger transactions, shareholders assume the risk that the
merged entity will achieve the strategic, financial, and operational benefits
set forth as the rationale for the proposed combination. To the extent these
objectives are not attained (e.g., failing to realize cost savings),
shareholders suffer from eroded equity value and/or lower returns. It is a well
established regulatory principle that, to compensate for these risks and to
reflect the shareholders' willingness to fund the costs necessary to realize
potential cost savings, the costs to achieve both these savings and the
underlying transaction should be fully recovered and the resulting net cost
savings should be equitably shared with shareholders.
Mr. Flaherty testified that based on his experience in other mergers, and
on his direct involvement with the identification, evaluation, and
quantification efforts related to estimated cost savings in this and other
transactions, the process utilized by the Joint Applicants for estimating
potential merger cost savings was consistent with the process utilized by other
companies in previous merger transactions. Consequently, Mr. Flaherty believes
that the level of
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<PAGE> 18
merger savings identified by the Joint Applicants is reasonably attainable
provided that management of the combined company executes its integration plans
in a manner consistent with its intent and how other utilities have pursued
similar opportunities.
In response to questions from Mr. Shore, Mr. Flaherty testified that he
had done studies in other merger cases where the companies were physically
separated [p. 20]. Those included Public Service Company of Colorado and
Southwestern Public Service Company, Wisconsin Power and Light, Iowa Electric
Light and Power and, Interstate Power, and, Washington Water Power and Sierra
Pacific Resources [p. 19].
Mr. Flaherty further testified that as a general proposition, there arc
more synergies for saving money when two merging companies are
similarly-sized entities. AEP and CSW are not similarly-sized utilities.
Mr. Flaherty further testified that studies regarding possible merger
benefits had been conducted on two prior occasions in 1997, and that the results
in those undertakings were similar in total amounts as the work which was
performed subsequent to the announcement of the merger [p. 25].
In answering questions from Mr. Stewart, Mr. Flaherty testified that
the total savings were approximately S2 billion [p. 28].
In calculating proposed merger savings, Mr. Flaherty used 3% for general
inflation, 4% for wages and salaries, and 5% for certain other professional
services category as escalation factors. The escalation factors reflected the
Joint Applicants' stand-alone forecast assumptions as well as from the
Conference Board Group, which includes some 50 economists [p. 34].
WILLIAM HIERONYMOUS
Dr. William Hieronymous, Senior Vice-President of PHB-Hagler Bailly,
testified on behalf of the Joint Applicants. Dr. Hieronymous' testimony
contained in Exhibits 17, 80, 137
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<PAGE> 19
and 193 was accepted into the record without objections. Dr. Hieronymous
prepared the Applicants' analysis of the competitive effects of the merger, and
sponsored both direct and rebuttal testimony for this proceeding.
Dr. Hieronymous' testimony was based on the FERC's requirements and this
Commission's order relating to the effect of the merger on retail competition in
Oklahoma. His fundamental conclusion is that the merger has no substantial
negative impact on competition. The analysis conducted according to FERC
requirements showed no negative impact on any Oklahoma market when the
Applicants' proposed mitigation measures are taken into account. Sensitivities
were conducted that assumed greater transmission capability, lower transmission
rates and AEP joining the Midwest ISO. These showed a similar lack of impact on
competition.
His analysis demonstrates that the merger will not turn CSW and PSO into
significantly more powerful competitors in Oklahoma. AEP historically has made
no sales whatsoever into Oklahoma. According to Dr. Hieronymous, AEP is not a
competitor in the Oklahoma market today, nor is it likely to become one because
it has more lucrative markets elsewhere.
The 250 MW transmission path that CSW has reserved to implement the System
Integration Agreement does have a small competitive impact on the market. By
bringing 250 MW of low cost AEP power into CSW, irrespective of whether AEP has
better alternatives elsewhere, the merger creates savings for Oklahoma
consumers. It also increases Applicants' market share. To mitigate the impact of
the 250 MW transfer, Applicants have offered to sell 550 MW of capacity to
competitors which helps deconcentrate those markets in Oklahoma and Texas in
which CSW was the largest seller.
Pursuant to this Commission's Order No. 427700, his direct testimony also
includes an analysis of the impacts of loop flow on market power. The transfer
of AEP energy through
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<PAGE> 20
Ameren causes somewhat greater loop flow effects than the imports it replaces.
This results in an increase in concentration in some third-party markets in some
time periods. Applicants' share of these markets is small and, indeed, smaller
than CSW's share was before the merger. Any increase in concentration is due to
the increased market share of the incumbent in that market, not CSW.
His rebuttal testimony addresses the supposed harm that the merger causes
to competition in these non-CSW areas. The Applicants do not gain market power.
According to Dr. Hieronymous, no intervenor has presented evidence to
demonstrate that the merger of CSW with AEP will cause CSW to have increased
market power. The supposed harm from the merger is that it caused Applicants to
reserve transmission that no other party wanted to reserve. Applicants have
mitigated any increase in their own market share that results. He rejected
OG&E's position that Applicants must also mitigate the increase in OG&E's market
share.
The idea that a party that contracts for firm transmission service must
compensate any other party that is adversely affected by resulting loop flows is
directly contrary to FERC policy. The fact that the contract was related to a
merger does not clothe unintended and minor effects of loop flow on third
parties with any market power significance.
The other market power issue raised by Intervenors is whether Applicants'
mitigation effectively transfers control to the buyer of the interim contract of
the divested capacity. The interim contract fully transfers the economic
interest in the contracted power. This reduction in Applicants' share of the
market is the purpose of the mitigation. Because Applicants must deliver on the
contract under all foreseen circumstances, the fact that they have not
transferred direct ownership in any specific plant does not matter.
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<PAGE> 21
Concerning the divestiture of the Northeastern capacity, Intervenors'
complaint is that PSO will continue to be the plant operator and will control
the timing of scheduled outages. Abuse of such control would require scheduling
outages when prices are predictably high. Even if one ignores the regulatory
response to this action, the fact is that the owner of the divested capacity
would have grounds to sue CSW and have every prospect of collecting damages.
On cross-examination by Mr. Selph, Dr. Hieronymous testified that his
firm developed a competitive analysis screening model designed to address
issues and analysis that are required by Appendix A of the FERC Merger Policy
Statement which his firm used in regard to this merger [p. 45, ls. 10-17].
The model provided a method to identify whether the merger presents market
power concerns [p. 45, ls. 18-21]. In the Merger Policy Statement, FERC
adopted the Department of Justice/Federal Trade Commission Merger Guidelines
which are intended to evaluate the competitive effects of a proposed merger
on competition [p. 45, ls. 24-25 and p. 46, ls. 1-9]. The Guidelines set out
steps for merger analysis to assess, among other things, market concentration
by use of the Herfindahl-Hirschman Index ("HHI") [p. 46, ls. 10-21]. Dr.
Hieronymous testified that in regard to the AEP-CSW merger, his firm's
screening model for economic capacity before mitigation identified five (5)
screen failures outside of CSW, four of which occurred in the State of
Oklahoma [p. 46, ls. 22-25 and p. 47, ls. 1-4]. He stated that the model
showed an HHI change for the summer peak period of 66 points relating to OG&E
and 57 points relating to Western Farmers Electric Cooperative ("Western
Farmers") [p. 47, Is. 20-22 and p. 48, ls. 4-9]. He also stated that the
model showed an HHI change for the summer off-peak period of 175 points
relating to OG&E and 70 points relating to Western Farmers [p. 47, ls. 23-25
and p. 48, ls. 10-11]. He stated that under the Guidelines, for a highly
concentrated market, if the HHI change exceeds 50, the Guidelines provide
that the merger potentially raises
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<PAGE> 22
significant competitive concerns and if the change in HHI exceeds 100, it is
presumed that the merger is likely to create or enhance market power, absent
mitigation [p. 48, ls. 12-19]. Dr. Hieronymous stated that the Applicants'
merger proposal includes mitigation so he is principally looking at the results
of the merger inclusive of the proposed mitigation [p. 48, l. 25 and p. 49, ls.
1-3]. Dr. Hieronymous accepted the assertion that the Applicants' 250 megawatts
reservation results in the reduction in import capability into some of the
Oklahoma destination markets [p. 49, ls. 18-25 and p. 50, l. 1]. He also stated
that the reservation does have some adverse impacts on the availability of
transmission into Oklahoma [p. 50, ls. 5-11].
On redirect examination, Dr. Hieronymous testified that his studies
pointed out that, after mitigation, the summer peak and summer off-peak
periods in terms of the concentrating effect of the transfer on OG&E's and
Western Farmers' markets showed a change in HHI of -5 points and -23 points,
respectively, as to OG&E and -47 points and -48 points, respectively, as to
Western Farmers, and thus, he stated the mitigation, coupled with the
transfer, deconcentrates those markets [p. 52, ls. 12-25 and p. 53, ls. 1-15].
MARK D. ROBERSON
Mr. Mark D. Roberson, Vice President - Regulatory Affairs for CSW,
testified on behalf of the Joint Applicants. Mr. Roberson's testimony contained
in Exhibits 15, 75, 134 and 194 were accepted into the record without
objections. According to Mr. Roberson, during the first ten years following
closing, the proposed AEP/CSW merger is anticipated to provide net non-fuel
savings of approximately $152 million and fuel savings of approximately $11.8
million to PSO's Oklahoma retail jurisdiction.
It was Mr. Roberson's opinion that the proposed merger will not impair
retail competition in Oklahoma or adversely affect PSO's ability to fulfill its
contractual commitments. The companies will integrate their system operations
according to the terms of the System Integration
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<PAGE> 23
Agreement, which has been presented for approval at the FERC. In addition to
various state regulatory filings, approvals are being requested from the FERC,
the Securities and Exchange Commission under the Public Utility Holding Company
Act of 1935, the Federal Trade Commission and Department of Justice under the
Hart-Scott-Rodino Act, the Nuclear Regulatory Commission and the Federal
Communications Commission.
Mr. Roberson's testimony was given before the parties to the
Stipulation had reached an agreement. Therefore, portions of Mr. Roberson's
pre-filed testimony appear to be inconsistent with the Stipulation.
CSW and AEP are willing to protect customers from any changes in PSO's
stranded costs arising from the merger, and will not oppose a Commission order
approving the merger which contains a merger condition limiting the basis of
PSO's stranded costs to PSO's assets and obligations. Further, it is not
necessary to perform additional production cost modeling of different power
interchange levels between AEP and CSW to find that the merger is not
detrimental to the public interest. The production cost studies performed based
upon the interchange levels which have been secured show that the merger does
produce fuel cost benefits for customers.
Mr. Roberson also committed that AEP and CSW are willing to protect PSO
customers from any adverse impacts from cost changes which arise due to
implementation of the proposed market power mitigation plan.
In explaining the mitigation plan, Mr. Roberson testified the Joint
Applicants had committed at the FERC to divest 300 megawatts (MW) of capacity at
PSO's Northeastern Plant (Units 3 and 4) in the Southwest Power Pool (SPP) and
250 MW of capacity at CSW Energy's Frontera Plant in the Electric Reliability
Council of Texas ("ERCOT") upon the fulfillment of
15
<PAGE> 24
certain conditions to mitigate potential market power concerns. In the time
between the merger's closing and the fulfillment of the specified conditions,
interim energy sales will be used to mitigate market power concerns. In the SPP,
the sales will be interim system sales totaling 300 MW that are available all
hours of the year, but which are subject to repurchase by AEP/CSW in the case of
a system emergency. If the company recalls generation capacity, in the event of
a system emergency pursuant to SPP operating rules or the CSW System Operating
Agreement, it will make energy sold in the interim financially firm to the
buyers affected. In ERCOT, the interim sale will be a unit sale for 250 MW of
energy from CSWE's Frontera Plant. The interim sales will cease when the
capacity is divested [pp. 57-58].
The sales revenues and incremental costs from the interim system sales in
the SPP transactions will be treated for ratemaking purposes like all other
off-system sales transactions. The Joint Applicants have committed to hold
customers harmless from negative net margins (revenues, less incremental costs
of energy and repurchased power) that might occur on an annual basis from the
interim system sale in the SPP.
For the Northeastern Units owned by PSO, divestiture would not occur until
after implementation of retail competition in Oklahoma (which is now targeted
for July 1, 2002).
The Joint Applicants have developed a procedure for measurement of margins
arising from the proposed 300 MW mitigation interim sale, and for crediting the
customer share of margins on an annual basis, which will be sold from the CSW
System and delivered in the Southwest Power Pool. The buyer will be responsible
for paying $14/MWh for energy delivered, and will make a fixed payment,
determined by auction, for the right to receive the low-cost energy. The Joint
Applicants will incur incremental costs for fuel to produce the energy, for
repurchase of energy at market prices when required to serve native load, and
for
16
<PAGE> 25
hedges to manage fuel and gas price risks associated with the transaction. Each
of these cost components must be accurately measured to determine the economic
benefit resulting from the transaction.
An hourly calculation of the incremental cost is required to ensure that
the fuel cost incurred to serve retail customers is based on the lowest
reasonable cost from available sources of generation, referred to as Regulatory
Mitigation Reconstruction. An hourly redispatch process is necessary to allocate
lower cost sources of generation to native load, and then to allocate the higher
cost resources for off-system transactions, such as the mitigation sale. By
performing an hourly calculation, the procedure ensures that ratepayers are
charged the lower-cost resources, and that off-system transactions are charged
the higher-cost resources.
All costs and revenues from the transaction will be added together to
determine the margin. Since the incremental unit dispatched for PSO is often
natural gas, the incremental dispatch costs will frequently exceed the S14/MWh
energy revenues. The revenues from the auction payment from the buyer must be
reflected in the determination by the margin. Buyers will base their payment
upon their estimates of market prices, which are expected to be significantly
higher than $14/MWh on an annual basis. Positive net gains will be flowed
through to customers consistent with the sharing procedures in effect for
off-system sale gains. If a negative gain occurred for a twelve-month period, it
would be absorbed by shareholders.
The Regulatory Mitigation Reconstruction cost procedure will provide a
reliable mechanism for a meaningful "hold harmless" protection for customers
from the impacts of the market power mitigation transaction. An annual sharing
mechanism for the benefits of the mitigation sale will most fairly capture all
of the cost changes arising from the sale and share the net benefits with
customers.
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<PAGE> 26
Regarding the proposed divestiture of Northeastern capacity, such
mitigation is not planned until generation prices are no longer subject to
regulation in Oklahoma, and therefore hold harmless protections are not required
from the effects of divestiture. However, if the Joint Applicants' plan for
divestiture changes, and divestiture is required earlier, hold harmless
provisions could be required, and the Joint Applicants are willing to propose
appropriate provisions for OCC approval. Applicants are willing to accept fair
hold harmless conditions for the mitigation sale as a condition of merger
approval [p. 61].
In response to questions from Mr. Speegle, Mr. Roberson stated that the
purchaser of the Northeastern Units would be required to enter into an
operating agreement which would set forth the terms and conditions of the
joint owners' participation in the plant [p. 62]. Further, Mr. Roberson was
not aware of any draft operating agreements in existence for the
divestiture. It was further generally contemplated that PSO would retain
certain management rights and the right to operate the plant [p. 63].
Mr. Shore inquired regarding the proposed estimated $11.8 million in
fuel savings to be realized by customers of PSO over a ten-year period.
According to Mr. Roberson, the savings are derived from PSO customers
receiving AEP's coal generation which in general had a lower variable cost
than CSW companies' incremental gas generation [p. 65].
In response to questions regarding the mitigation proposal, Mr. Roberson
testified that two conditions had to be satisfied prior to divestiture of 300 MW
at Northeastern. Those conditions were that a pooling of interest accounting had
to be satisfied for the merger as a whole and PSO would not have an obligation
to serve at least 300 MW of native load [p. 68]. The interim sale would continue
until those conditions would be satisfied [p. 70]. It is contemplated that a
bidding process would be used for the interim sale [p. 70].
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<PAGE> 27
In response to questions from Mr. Stewart, Mr. Roberson stated that the
$11.8 million in fuel savings will not arise from the sale of capacity but
from the energy exchanges that occur hour-to-hour [p. 72].
Mr. Roberson describes the interim sale as a sale of firm energy [p. 72].
In describing when PSO could repurchase in the event of a system emergency, Mr.
Roberson explained that this event would only be triggered when PSO would not
have other resources available either internally or through the points of
interconnection that PSO has with others [p. 74]. Although the party purchasing
the energy will lose that energy, that party will still receive the market price
benefit associated with that energy [p. 74]. Whether or not the purchasing party
would be able to secure electricity elsewhere, Mr. Roberson stated would depend
on where the buyer was located and where the buyer was trying to deliver the
power [p. 75].
In response to questions from Ms. Morgan, Mr. Roberson stated that any
gains from the interim sale of the 300 MW should be treated as off-system sales
are currently, i.e., 25% to shareholders and 75% to customers.
In response to questions from Ms. Jacobson, Mr. Roberson testified that
under the current system of regulation in Oklahoma, PSO would have no
stranded costs and the merger does not create any stranded costs [p. 89].
On cross-examination by Mr. Stewart, Mr. Roberson said that the interim
sale of energy under Applicants' mitigation plan is "firm" except for the
need for PSO to recall the energy to serve its native load and then only when
PSO is physically unable to acquire resources from the market [p. 72, ls. 1-4
and 20-24]. If the energy were recalled by PSO, Mr. Roberson stated it is
possible, depending on where the owner was located, that there might not be
any power to replace that energy [p. 73, ls. 15-24]. He also stated he would
not be able to speculate as to
19
<PAGE> 28
whether the buyer could replace the resources [p. 75, ls. 6-8]. The buyer of
that energy would then be entitled to receive as compensation for the inability
to replace the power, the market price of the energy according to a published
index [p. 74, ls. 21-24 and p. 75, ls. 1 - 2]. This situation could cause the
buyer of the energy to have physical problems which Mr. Roberson characterized
as load shedding or interruptible customer shedding [p. 76, ls. 7-13].
Mr. Roberson also testified under cross-examination that the $11.8
million savings for PSO customers relates to hour-to-hour electricity
exchanges from AEP to CSW [p. 70, ls. 21-25 and p. 71, ls. 1-11]. He had
previously testified that the savings related to a ten-year period [p. 55,
Is. 8-10]. Mr. Roberson explained that because of the lower costs structure
of AEP with respect to variable costs, because coal is cheaper than gas, the
Applicants' studies show that the predominant power flow direction is east to
west [p. 71, ls. 11-18], although the agreement provides go either way.
Concerning the portion of the Applicants' mitigation measures relating
to the sale of capacity, Mr. Roberson testified that the terms of such a sale
have not yet been worked out but that AEP might want some provision providing
for a right of first refusal for AEP should the buyer of that capacity decide
to sell its interest [p. 78, ls. 23-25 and p. 79, ls. 1-9]. He testified
that AEP does have some agreements today for existing joint units that have
right of first refusal provisions. He did not know whether such a provision
would be part of a future agreement [p. 80, Is. 9-13].
STEPHEN B. JONES
Mr. Stephen B. Jones, the Director of Issues Management for CSW,
testified on behalf of the Joint Applicants. Mr. Jones' testimony contained
in Exhibit 135 was accepted into the record without objection. Mr. Jones
explained the market power mitigation measures proposed by the
20
<PAGE> 29
Joint Applicants in their application for approval of the merger at the FERC. He
attached his FERC testimony as an exhibit.
The mitigation plan proposes the divestiture of ownership interests in two
CSW plants. The Frontera plant located in the Electric Reliability Council of
Texas (ERCOT) and the Northeastern plant located in the Southwest Power Pool
(SPP). The Frontera plant is under construction and owned by CSW Energy, Inc.
When completed, the facility will be an exempt wholesale generator merchant
plant. The Northeastern plant is located in Oklahoma and serves PSO.
Joint Applicants will divest an ownership interest in 300 MW of the
Northeastern plant in two equal lots of 150 MW from Unit 3 and Unit 4 through an
auction process devised to obtain the greatest possible value for the sale. No
buyer can purchase both lots, and the divestiture cannot cause violations of the
post-merger Herfindahl-Hirschman Index ("HHIs") in any CSW/SPP destination
market or contiguous destination market.
PSO will maintain operational control of the Northeastern plant through an
operating agreement with the purchasers, who will have the right to capacity at
any time and to the extent that the units are available for operation. In
addition, at any time the units are available and PSO is not fully scheduling
PSO's interests in the units, the purchasers will have the right to purchase at
marginal cost any energy available. PSO will have a reciprocal right. The
operating agreement will also provide for mutually agreed upon maintenance
schedules and coordination on other operating matters.
This divestiture cannot happen unless both of the following have occurred:
- two years have passed since consummation of the merger as
required by pooling of interest accounting; and
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<PAGE> 30
- retail access and entry by alternate suppliers in Oklahoma has
caused a reduction in PSO's native load obligations to where the 300
MW of divested capacity is no longer required to satisfy SPP
reliability criteria.
The divestiture of the Northeastern units was selected because these units have
the location and price characteristics necessary to provide effective mitigation
in the CSW/SPP region and Oklahoma has set a statutory goal of full consumer
choice by July 1, 2002. Consequently, the introduction of retail competitors
into Oklahoma will allow the divestiture of these units without undermining
PSO's ability to fulfill its native load obligation.
Mr. Jones testified the OCC should find that the merger will not have an
adverse impact on wholesale and retail competition within the state, and that
the mitigation proposal will not have an adverse impact on customers served by
PSO.
In response to questions from Mr. Speegle, Mr. Jones testified he was
familiar with how jointly owned plants are operated and he assumed that PSO
personnel would continue to operate the Northeast Plant [p. 98]. Further,
the operating agreement would include how the plant was going to be
scheduled, O& M costs, the governing structure, and when capital additions
are made to the plant [p. 100].
The right of first refusal would not be contained within the operating
agreement if it would ruin the mitigation purpose of the divestiture [p. 101].
In response to questions from Mr. Shore, Mr. Jones testified that the
reason for having two purchasers of 150 MW blocks is to avoid creating a market
power problem [p. 102]. Mr. Jones further testified that if the Oklahoma
Legislature passes a statute in the next session, or sometime before 2002, that
says all generation shall be unregulated and electric utilities will have no
obligation to native load, then one of the conditions for divestiture will have
been met. However, if the Legislature says that there shall be a transition
period where default customers will be supplied by PSO, even though it is
unbundled as part of the restructuring process, then
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the condition might not be met. However, whenever PSO has 300 MW or more of
capacity in excess of those obligations then the divestiture can occur [pp.
103-104].
In response to questions from Mr. Stewart, Mr. Jones testified that AEP
companies would not be allowed to purchase the capacity, nor a company which
would possess market power after the purchase of the capacity [p. 105]. Mr.
Jones further testified that there is no problem with OG&E bidding on the
capacity [p. 106]. Pursuant to re-direct, Mr. Jones testified that as part
of the condition of the offer of sale that HHI violations do not occur as a
result of the sale [p. 111]. It would be more difficult for OG&E to bid on
Northeastern and not exceed the market power test than an entity remote to
Oklahoma [p. 112, ls. 2-6].
RAYMOND M. MALISZEWSKI
Mr. Raymond M. Maliszewski testified on behalf of the Joint Applicants.
Mr. Maliszewski's testimony contained in Exhibits 136 and 192 was accepted into
the record without objections. The participants in this case agreed that the
Applicants would conduct a system performance analysis of the bulk transmission
networks in Oklahoma to determine the impact of the proposed 250 MW power
transfer from AEP to CSW.
Applicants evaluated load flow performance of the Oklahoma systems for the
summer, spring/fall and winter seasons of 1999 with and without the AEP to CSW
power transfer. Applicants compared the results of with and without cases to
evaluate system performance and provide an indication of the AEP to CSW transfer
impact.
The Applicants' analysis examined:
a) the incremental impact of the 250 MW transfer on flows on all the
bulk transmission lines in Oklahoma as well as the rest of the
interconnected network;
b) the ability of the Oklahoma transmission networks to support single
contingency operations, i.e., the outage of each transmission line;
and
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<PAGE> 32
c) the impact that the power transfer would have on the power transfer
capabilities of the other Oklahoma utilities with each of the
directly connected neighboring systems.
According to Mr. Maliszewski, the parties agreed that the Applicants would
perform a conventional linear load flow analysis. The Applicants also agreed to
verify these results with an AC load flow analysis as required to take into
account the voltage performance considerations of the Oklahoma systems if they
are significant. The Applicants' results are documented in Exhibit RMM-5.
According to Mr. Maliszewski, the analysis showed:
- The 250 MW AEP to CSW power transfer causes small changes
in incremental power flows on the Oklahoma bulk transmission
facilities that are widely distributed throughout the network,
ranging from 0 MW to about 30 MW on 345 kV lines in Oklahoma.
Considering that the 345 kV lines typically carry several
hundred MW and have thermal capacity of at least 1000 to 1200
MW, these are relatively small changes. In some cases there
will be no change, in others, a small amount of reduction, and
in still others a slight increase.
- The system is capable of supporting transmission outages with
the 250 MW power transfer. Thus, the reliability of power
supply to Oklahoma customers is not undermined by the 250 MW
power transfer.
- The AEP/CSW power transfer will have no more impact on
Oklahoma line flow patterns and the ability of Oklahoma
utilities to import and export energy than power transfers
made by any other Oklahoma system. Any change in
generation dispatch or power transfer in any Oklahoma
system will result in a change in power flow patterns on
every other Oklahoma system, some of which will be an
addition to base power flows, while others will be a
subtraction.
- In general, over the entire year, spring, fall, winter and
summer, there will continue to be significant levels of ATC
available to the other Oklahoma systems. In those situations
where no transfer capability existed to begin with, due to
some existing inherent limitation, this condition cannot
change.
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<PAGE> 33
Overall, it was Mr. Maliszewski' s conclusion that these studies clearly
demonstrate that the AEP to CSW 250 MW power transfer will not have a material
detrimental impact on the Oklahoma bulk transmission network.
OG&E claimed that Applicants' study was flawed because Applicants had used
an incorrect transformer rating that OG&E had supplied. In his rebuttal
testimony, Mr. Maliszewski described a revised study of OG&E's ability to import
power from the systems to which OG&E is interconnected. That revised study
showed that the conclusions drawn from Applicants' original analysis were not
affected by the change in the transformer rating. In particular, Applicants'
earlier finding that even before the AEP/CSW transfer OG&E would be unable to
import energy from the Entergy system was still true even with the higher rating
on the OG&E transformer at the Fort Smith station. OG&E's transformers at Fort
Smith already operate very near their emergency ratings in contingency
conditions, and had little margin remaining to accommodate load growth or
contingency conditions.
OG&E also claimed that it would suffer significantly increased losses
due to the AEP to CSW transfer. Mr. Maliszewski explained the flaws in
OG&E's analysis [p. 117,l. 24].
Based on its flawed analyses, OG&E made claim to compensation for the cost
of adding a new transformer at Fort Smith and to cover the cost of increased
losses. Mr. Maliszewski testified that such remedies are at odds with
established industry practice, and that granting the requested relief would have
the effect of inhibiting the competition that Oklahoma and the federal
government are seeking to foster.
In response to questions from Mr. Speegle, Mr. Maliszewski testified that
transmission service is requested from transmission owners through the processes
that have been established
25
<PAGE> 34
by the FERC, including using the OASIS. Once the reservation has been granted it
is filed before the FERC and not at the Oklahoma Corporation Commission [p.
122].
In response to questions from Mr. Shore, Mr. Maliszewski testified that
the parties had agreed that Applicants should perform an all encompassing study
of the interconnected network between and including the AEP service area and the
CSW and other Oklahoma systems. Mr. Maliszewski further explained that the
parties had discussed how the study was to be carried out, what base cases were
to be used, the source of the base case information, the load levels that would
be studied and the kinds of system performance analyses that the Applicants
would undertake [pp. 123-125]. Mr. Maliszewski testified that Applicants agreed
to the performance of the interconnected network for the outage of every key
transmission element within the interconnected network to determine whether
there would be any detrimental impacts resulting from the 250 MW transaction.
Applicants also undertook to examine the transfer capability between each
directly connected utility within Oklahoma, with and without the 250 MW
transaction, in order to determine whether the transaction had any impact on
those transfer capabilities [pp. 128-129].
In a February 4, 1999 technical conference, of the parties' engineers,
OG&E had requested that the Joint Applicants also examine what effect the
proposed 300 MW divestiture of capacity at the Northeastern plant would have on
the Oklahoma systems. The Joint Applicants were of the opinion that it was not
appropriate to make such a study using a base case year of 1999 when the
proposed divestiture would not occur earlier than 2002. However, the Joint
Applicants agreed to carry out an analysis, which was discussed in Mr.
Maliszewski's testimony [p. 129].
26
<PAGE> 35
In response to questions from Mr. Stewart, Mr. Maliszewski stated that
the conduct of load flow studies is a well-established industry practice [p.
133, ls. 9-10].
According to Mr. Maliszewski, the agreement among the parties
contemplated a basic DC analysis, which does not consider certain system
characteristics but allows expeditious analysis of hundreds of system
contingencies and in most cases produces accurate results. Applicants used
the same software and study process that the Southwest Power Pool uses in
making similar studies. Mr. Maliszewski testified that the agreement among
the parties also contemplated that the DC analysis would be supplemented by
AC analysis, which does consider system characteristics such as resistance
and voltage levels, as required [p. 135, ls. 14-24]. [p. 7, 1.9 of rebuttal]
in his rebuttal testimony, Mr. Maliszewski explained that, contrary to the
claim of OG&E witness Kuebeck, the Applicants had performed the required AC
analyses [pp. 135-140].
According to Mr. Maliszewski the agreement reached between the parties at
the technical conference called for a DC Analysis because a conventional linear
load flow analysis was simply an alternative terminology for a DC Analysis. DC
Analysis is by its very nature a linear analysis, so that when one says a
conventional linear analysis, it was understood by all engineers that DC load
flow analysis would be used [p. 135, ls. 8-13].
In response to questions from Ms. Jacobson, Mr. Maliszewski testified
that he had seen no evidence that the merger would burden the Oklahoma
transmission network to an extent that would require transmission system
reinforcement [p. 167, ls. 12-16].
On cross-examination by Mr. Stewart, Mr. Maliszewski testified that the
six base cases studied by the Applicants were full-blown legitimate AC load
flow base cases [p. 135, ls. 14-17]. Mr. Maliszewski testified that the
determination of whether to use an AC or DC analysis is a
27
<PAGE> 36
function of the purpose of the study to begin with and the judgment of the
engineer who is reviewing the result to determine whether the study results are
sufficient for his purposes [p. 138, ls. 19-23]. He stated that in its
calculation procedure the DC analysis does not capture resistance, reactive
aspects or voltage variations, that you would expect to see on the AC solution
[p. 140, ls. 6-10]. It was for that reason that relative to the conventional
load flow analysis that a supplemental AC analysis to evaluate voltage
performance was performed [p. 140, ls. 12-16].
On cross-examination by Mrs. Jacobson, Mr. Maliszewski testified that line
losses cannot be prevented. He said they are a natural phenomena. He stated that
whenever current flows in a transmission line the current produces flows through
a resistance, and losses are simply the heating of that resistance or that
transmission line [p. 162, ls. 11-20]. He stated line losses are a natural
consequence of system operation. He stated, whenever power flows from a
transmission line, losses are going to occur [p.
165, ls. 3-9].
In response to a question from the Court, Mr. Maliszewski stated that
if the merger in its implementation resulted in a definitive overload
condition at the Fort Smith station which did not exist before, then it
appears one solution would be for a reinforcement at Fort Smith [p. 170, ls.
7-11]. Mr. Maliszewski stated in his rebuttal testimony filed on April 12,
1999 (Exhibit 192) that prior to the merger, the Fort Smith transformer does
have a small amount of capacity to accommodate load growth and other system
conditions [Exhibit 192 at p. 22, ls. 18-20].
CRAIG BAKER
Mr. Craig Baker, Vice - President - Transmission Policy for AEP, testified
on behalf of the Joint Applicants. Mr. Baker's testimony contained in Exhibits
13, 76 and 196 was accepted into the record without objections. Mr. Baker
described the System Integration Agreement (SIA) through which the companies
will integrate their power supply resources, explained the central
28
<PAGE> 37
economic dispatch of the merged company's generating units and the
production-related benefits that will accrue as a result of the post-merger
operations of AEP and CSW.
The SIA provides for the distribution of power supply costs and benefits
between the two zones, the east zone (presently AEP's system) and the west zone
(presently CSW's system). The existing intra-system agreements will continue to
govern the distribution of costs and benefits within the zones. It is the intent
of the Applicants to centrally dispatch the combined system and eventually to
combine the control area functions of the east and west zones. However,
generation dispatch priorities will be the same as pre-merger, i.e., each zone's
most economic generation will be used to serve its native load and previously
committed firm load contracts.
Under the SIA, the price in the purchasing zone will be one-half of the
sum of the foregone opportunity cost to sell capacity in the supplier zone and
the decremental capacity purchase cost in the purchasing zone. For example, if
PSO needs to purchase capacity and the price of capacity is $4.00 in the CSW
zone and $2.00 in the AEP zone, PSO would purchase at a price of $3.00 (The
$2.00 AEP zone price plus one-half the difference between the CSW zone price of
$4.00 and the AEP zone price of $2.00). If the situation is reversed, i.e., the
CSW zone price is less than the AEP zone price, then PSO would make the purchase
in the CSW zone since it is cheaper, thereby paying the same price they would
have paid absent the merger. Energy works in the same manner. For energy the
price is the lower of CSW's decremental cost or one-half of the sum of AEP's
out-of-pocket costs and CSW's zone decremental cost.
Mr. Baker also estimated the production-related benefits and costs
associated with the post-merger operations of the combined company.
Production-related benefits will result from the economic transfer of energy
among the east and west zone companies to displace relatively
29
<PAGE> 38
higher cost generation in one zone with relatively lower cost generation from
the other zone. The net production-related savings are as follows:
<TABLE>
<S> <C>
Gross Production Savings $198 million
Transmission Wheeling Costs ($39 million)
Net Fuel Related Savings $159 million)
Foregone Net Revenue ($61 million)
-------------
Net Production Related Savings $ 98 million
============
</TABLE>
According to Mr. Baker, the merger affords the opportunity for
production-related savings through the economic dispatch and transfer of energy
between zones in a real-time manner benefiting CSW's and AEP's customers.
Mr. Baker submitted rebuttal testimony to respond to the recommendations
of Staff witness Crosslin that Applicants join an Independent System Operator
("ISO"). He also provided documentation related to affiliate purchases of
capacity and energy.
In response to Mr. Crosslin's recommendation that Applicants be required
to join an ISO at their earliest opportunity to further mitigate transmission
market power concerns, Mr. Baker stated the Applicants are willing to join a
properly organized ISO of large geographic scope with a truly independent
governance structure, broad authority over transmission pricing and reliability,
and appropriate configuration and fair provisions for transmission pricing and
revenue distribution. According to Mr. Baker, AEP has not joined the Midwest ISO
(MISO) because it has a number of flaws including that MISO covers too narrow a
geographic area. The decision of other utilities to the north and east of AEP
not to join MISO undermines the ability of MISO to facilitate access to major
power markets and MISO does not have an efficient pricing mechanism or fair
revenue distribution. AEP is working with a group of utilities, called the
Alliance, to either form a separate ISO or to join a reformed MISO. In Oklahoma,
CSW's has been active in working with the Oklahoma staff and other utilities
toward an ISO in the SPP.
30
<PAGE> 39
Mr. Baker testified that the Staff's concern that affiliate sales of
capacity or energy under the proposed System Integration Agreement ("SIA") will
cause Oklahoma ratepayers to pay a higher price for electricity than they would
have paid absent the merger was unfounded. The merger will not effect the price
or the need for capacity by PSO, but will afford an additional opportunity for
PSO to purchase AEP capacity.
Under the SIA, the price in the purchasing zone will be one-half of the
sum of the foregone opportunity cost to sell capacity in the supplier zone and
the decremental capacity purchase cost in the purchasing zone. For example, if
PSO needs to purchase capacity and the price of capacity is $4.00 in the CSW
zone and $2.00 in the AEP zone, PSO would purchase at a price of $3.00 (The
$2.00 AEP zone price plus one-half the difference between the CSW zone price of
$4.00 and the AEP zone price of $2.00). If the situation is reversed, i.e. CSW
zone price is less than the AEP zone price, then PSO would make the purchase in
the CSW zone since it is cheaper, thereby paying the same price they would have
paid absent the merger. Energy works in the same manner. For energy the price is
the lower of CSW's decremental cost or one-half of the sum of AEP's
out-of-pocket costs and the CSW's zone decremental cost.
Mr. Baker testified that the Applicants are committed to participation in
an Independent System Operator (ISO) or other RTO arrangement. Since April 1998,
AEP has participated in discussions regarding the development of the Alliance
RTO and, as described below, the process is currently expected to lead to a
Federal Energy Regulatory Commission ("FERC") filing this year.
Beginning July 1, 1998, CSW/Southwest Power Pool ("CSW/SPP") has
participated in the Southwest Power Pool short-term tariff, under which SPP
controls access to the SPP members systems, including the CSW/SPP system, for
short-term transactions. In addition, in
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<PAGE> 40
December 1998, the SPP filed with the FERC an enhanced regional transmission
tariff, which provides control and access for long-term transmission service.
CSW/SPP has also been an active participant in the development of an SPP-RTO.
Currently, the SPP has a regional tariff that applies to short-term (less
than a year) transactions. Under that tariff, the SPP determines transmission
access for purposes of those transactions and is directly responsible for
maintaining the node of the SPP.
RTO membership provides a number of public benefits. Two of the most
important are:
(1) further assistance of non-discrimination in the offering of open
access transmission; and
(2) the broadening of energy markets.
Applicants' RTO activities are designed to achieve both of these benefits in the
near term.
In response to a question from the ALJ as to whether his testimony
regarding ISO's/RTO's was tempered by the stipulation, Mr. Baker indicated the
Applicants had committed to join an RTO by a date certain [pp. 15-16].
In response to cross-examination from Mr. Stewart, Mr. Baker explained
that the System Integration Agreement, which deals with generation production
costs, and the System Transmission Integration Agreement, which deals with
transmission facilities, provide a basis for maintaining the costs and
benefits to each zone within the zone and to share benefits that are achieved
through the merger among the zones [pp. 18-19]. He also testified that these
agreements require FERC approval [p. 20]. Mr. Baker further testified that
as contemplated under the agreement, AEP Service Company would take over the
functions of CSW Service Company after the merger is consummated [p. 22]. He
additionally testified that the applicants would not enter into a transaction
that would impose more costs on PSO's customers [pp. 24-24].
32
<PAGE> 41
Mr. Baker further testified on cross-examination by Mr. Stewart, that
the System Transmission Integration Agreement and System Integration
Agreement between AEP and CSW are for a term of five years with the ability
for them to roll-over for additional periods unless terminated [p. 18, ls.
5-9 and p. 19, ls. 18-24]. Mr. Baker also testified that it is projected
that PSO will be short of capacity in the years 1999 and 2000 [p. 23, ls.
10-19]. He stated that the shortage that PSO will need to supply would be to
meet the combination of load and reserves requirements [p. 23, ls. 20-25].
Mr. Baker testified that consideration was given by AEP to the losses that
would occur on the Ameren system associated with the transfer of power from
AEP to CSW but AEP did not do an independent loss study with respect to
losses on the CSW system for that transfer [p. 25, ls. 13-25 and p. 26, ls.
1-9]. The analysis that was done held the losses constant in both systems
[p. 26, Ls. 3-4].
In response to questions from Ms. Jacobson, Mr. Baker testified as to
the relative timelines for FERC approval of ISO/RTO applications [pp. 26-28].
On re-direct Mr. Baker reiterated that sales to CSW of up to 250 MW
would be required if savings to CSW would result [p. 29].
ROBERT A. SINCLAIR
Dr. Robert A. Sinclair testified on behalf of the Municipal Electric
Systems of Oklahoma and the Oklahoma Association of Electric Cooperatives to
address economic matters that arise out of the merger between AEP and CSW,
collectively ("the Applicants").
According to Dr. Sinclair, the basic competitive problem with this merger
lies in two facts. First, both Applicants are large regional utilities with
control over vast generating resources and transmission facilities. Second, the
merger is taking place in a region of the country where generation supply has
become a critical problem whereby generating capacity has not kept up with the
growth in demand and transmission capacity has not been adequately
33
<PAGE> 42
expanded. This has led to drastic price increases as recently as last summer.
These prevailing conditions certainly heighten the competitive impact of the
merger, especially given the large size of both companies and their geographic
location at the northern and southern ends of the Midwest. While Mr. Sinclair's
testimony, as stricken does not contain empirical market share calculations that
would illustrate the competitive impact of the merger, his testimony does
contain a thorough description of the competitive problems that the merger
entails.
Dr. Sinclair examined a number of market structure variables to assess the
merger's competitive effects. These other variables include: (1) the potential
of the merger to give rise to anticompetitive effects; (2) entry conditions; (3)
efficiencies; and (4) whether one of the firms is likely to exit the market with
its assets because of financial stress. In examining each of these four factors,
the conclusion is that the merger, (1) will facilitate the exercise of
unilateral market power; (2) is likely to enhance conspiratorial market power
and tacit collusion; (3) will create adverse competitive effects related to the
control of the regional transmission system; (4) will create market power that
is not likely to be undercut by free and easy entry; (5) will not create cost
savings that are remarkable by industry standards (and, indeed, evidence
suggests that costs are lower in smaller utilities); and (6) is not initiated to
save one of the merger partners from exiting the market with its assets because
of financial stress. Consequently, the merger would provide the merged entity
with increased market power, unmitigated by other economic factors.
In addition to his market power analysis, he also analyzed the proposed
mitigation measures and found that they were inadequate. The Applicants propose
two main mitigation measures. The first is to "divest" about 300 MW of capacity
in the SPP and about 150 MW in the Electric Reliability Council of Texas
("ERCOT"). The second measure is a promise not to invoke priority rights (the
AES-TVA priority) affecting transmission usage from power transfers
34
<PAGE> 43
from AEP to CSW. The idea behind both of these measures is an attempt at
diminishing the increased concentration that results from the merger.
The "divestiture" proposal is supposed to reduce the post-merger
concentration to a level that is comparable to the concentration level
pre-merger. But in addition to being of inadequate magnitude to reduce
concentration to pre-merger levels, the scheme does not really release the
capacity from CSW's control. And the interim measure to make energy sales is
unsatisfactory because such sales are non-firm and, thus, would not be of
sufficient quality to serve retail demands.
The Applicants promise not to invoke certain priority rights also will not
mitigate the increased concentration resulting from the merger. The basic
competitive problem is that, as a result of the merger, AEP will gain control of
the bulk of low-cost capacity that can be delivered to CSW's SPP ("CSW-SPP")
control area by controlling access to the transmission capacity into CSW-SPP
from the east. Currently, a large number of firms have somewhat equal access to
this transmission capacity. After the merger, because of certain operational
advantages, AEP will be able to gain priority in using the scarce transmission
capacity into CSW from the east. In an effort to alleviate this problem, the
Applicants propose to reduce the priority at which they can make transfers from
AEP to CSW. This measure is not sufficient to ensure the preemption of other
suppliers because the new Company will still have advantages in obtaining
available transmission capacity over other suppliers.
Dr. Sinclair also rebuts the Applicants' economic analysis. The rebuttal
is in two parts. First, he explains why the market concentration analysis of
Applicants' economic witness Hieronymous is not an adequate basis from which to
draw conclusions about the competitive impact of the merger. Basically, Dr.
Hieronymous did not consider certain important market
35
<PAGE> 44
supply conditions in the Midwest that are likely to have a determinative effect
on market power. The second part of Dr. Sinclair's rebuttal involves an
examination of the mitigation measures proposed by the Applicants. As noted
above, these measures are not sufficient to ameliorate the severe competitive
consequences of the merger.
Dr. Sinclair's main recommendation is that the merger should not be
approved. However, if it is nonetheless approved, generation divestiture should
be required to address market power problems. Significant amounts of CSW's
generation should be divested to multiple entities in order to address the
market power problems in this case. Along with this, the Commission should
require that the Applicants join a functional, Independent System Operator
("ISO") before the merger is approved.
On cross-examination by Ms. Jacobson, Dr. Sinclair testified that he
was familiar with FERC Order No. 592 and that his mitigation recommendations
of divestiture and a requirement to join an ISO were consistent with the
requirements of that order. He also testified on cross-examination by Ms.
Jacobson that Order No. 592 also provides that expansion of the transmission
system could also be a mitigation measure [pp. 37-38].
On cross-examination by Mr. Downs, Dr. Sinclair testified it was
practically feasible for American Electric Power to deliver power into
Oklahoma but that such power would have to be bundled with ancillary services
in the SPP to assure reliable service [p. 39, ls. 5-14]. It was Dr.
Sinclair's opinion this had not been done in the past because AEP's resources
were committed to serving AEP's retail customers [pp. 39-40].
Dr. Sinclair testified on cross-examination that he would modify the
delivered price test to take into account anticipated or historical
equilibrium conditions for analyzing the effects of the merger. When asked
whether such a model left a lot of room for the exercise of judgment or
36
<PAGE> 45
even bias, Dr. Sinclair responded that all economic models require judgment and
there could be bias injected [p. 41, ls. 18-23].
Dr. Sinclair testified the adjustments he made to the models were in an
attempt to reveal market power [p. 42].
Dr. Sinclair admitted on cross-examination that the transfer capacity
from the Ameren system under summer peak to CSW is 760 MW [p. 44, ls. 5-11].
He stated that in his model, he used 1,260 MW as an ATC on the Ameren-CSW
path. Dr. Sinclair stated that this figure had no empirical basis but was
used in an attempt to model transmission conditions, which he expected to
prevail in the future under certain new transmission institutions, such as an
ISO. Dr. Sinclair stated the level he chose was to test the sensitivity of
the model and was based upon his informed judgment as an economist [pp.
43-45].
On further cross-examination by Mr. Downs, Dr. Sinclair discussed his
conclusion that, in order to mitigate market power increases that result from
the merger, Applicants should divest 2,000 MW of capacity. Dr. Sinclair
admitted that 2000 MW was an amount larger than the 1260 MW path from Ameren
to CSW that he expected to be available in the future. Regarding the
accuracy of his estimates, Dr. Sinclair stated that his recommendation for
divestiture had no empirical basis but it was better over estimate rather
than under estimate [p. 50,Il. 20 - p. 51, 1-8].
On redirect examination, Dr. Sinclair testified that all economists need
to rely on informed judgment in making an analysis. He further stated that Dr.
Hieronymous delivered price tests required certain judgments be made. He
testified that, in an appendix to his FERC testimony, Dr. Hieronymous argues a
number of points about the methodology to be used in the FERC delivered price
test. Dr. Sinclair stated he applied his informed judgment based upon
37
<PAGE> 46
certain market realities of events which have either transpired in recent months
or that are forecast in the future based on generation supply [pp. 54-55].
Finally, Dr. Sinclair testified that, he had heard statements that AEP
has not limited itself to the 250 MW firm transfer to the CSW system. In
fact, Dr. Sinclair said he had heard that Applicants had reserved the right
to apply to the FERC for non-firm transfers above the 250 MW level [p. 56,
ls. 7-12].
MELVIN H. PERKINS, JR.
Melvin H. Perkins, Jr. was called as the first witness for Oklahoma Gas
and Electric Company ("OG&E"). Mr. Perkins has been employed by OG&E since
1972 in Transmission and distribution engineering and operations. He is
presently Manager of Operations in the Power Delivery business unit and is
responsible for the OG&E system transmission operations, substation
construction, operations and maintenance and metering. This includes
responsibility for transmission system security and tariff administration
including compliance with FERC Orders 888 and 889. Mr. Perkins received a BS
degree in Electrical Engineering from the University of Oklahoma in 1972.
His Responsive Direct Testimony filed on March 29, 1999 (Exhibit 165), and
the summary of his testimony dated April 19, 1999 (Exhibit 212) were accepted
into the record [p. 64, ls. 12-13].
Mr. Perkins testified that the capability to import power into Oklahoma
will be significantly impacted by the energy transfer proposed in the merger of
American Electric Power Company, Inc. ("AEP") and Central and South West
Corporation ("CSW"). His testimony was offered to show that Available
Transmission Capability ("ATC") is significantly reduced and he urged the
Commission to deny the merger application at this time and to encourage the
Applicants to come forward with a joint planning initiative to restore the
Oklahoma transmission system to pre-merger conditions.
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Mr. Perkins testified that the OG&E system is comprised of 4300 miles of
transmission interconnected with other companies at 43 points. The bulk 345kv
system began with joint planning between OG&E and Public Service Company of
Oklahoma ("PSO") and resulted in several joint ownership lines. He stated that
this highly integrated system of transmission facilities relies on close
coordination between utility companies to ensure continued reliability and
market efficiency. He testified that this coordination could include daily
communication regarding maintenance, service restoration, and other issues.
Mr. Perkins stated that ATC is an indicator of import and export capacity
with each of the companies interconnected with OG&E. Among other factors, ATC
includes a margin for reliability. He said that this reliability margin is
reserved for generation in one transmission area that provides a backup supply
for another area. He stated that ATC is calculated by running complex computer
models of the system. These models contain thousands of transmission system
elements that have information about each element.
He testified that OG&E has assigned an incorrect rating to one of these
elements, a large power transformer in the OG&E Fort Smith Substation, and that
caused the ATC to be understated. This rating was changed as a result of
reviewing the Applicants' study and the original study was rerun by OG&E
producing results found in Mr. Perkins' pre-filed testimony.
He testified that these new results actually reflect a higher ATC from
Entergy to OG&E; however, he asserted that the transfer proposed by the
Applicants in this case still significantly lowers ATC values. Mr. Perkins
testified that ATC is lowered by approximately 94% from Entergy to OG&E due to
the proposed transfer. Chart 1 in Mr. Perkins' pre-filed testimony (Exhibit 165,
p. 4) shows that the import capability from Western Resources is lowered by
approximately 73% and the import capability from CSW will be lowered by 65%. One
possible
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mitigation OG&E identified through the testimony of Mr. Perkins is to upgrade
the Fort Smith Substation transformer at a cost of approximately $10,900,000.
Mr. Perkins testified that with the time limitations under the merger, OG&E did
not make any in-depth investigation to determine if any other upgrade might be a
solution to the problems caused by the transfer of power in accordance with the
merger. [p. 64, ls. 18-23]. He stated that joint planning with OG&E, CSW, and
other transmission owners in the region would be necessary to determine if the
Fort Smith Substation transformer upgrade is the best solution.
Mr. Perkins testified that OG&E does not expressly oppose the merger but
initiated its intervention for due diligence reasons. He stated that there are
certain conditions created by the merger that are clearly not acceptable and not
in the best interest of Oklahoma customers. He said that OG&E remains ready to
work with the Applicants to determine the extent of necessary mitigation
measures so that the merger can go forward and pre-merger conditions can be
retained. Mr. Perkins said that OG&E requests that the merger application be
denied and that the Applicants be ordered to engage in joint planning with costs
to restore pre-merger conditions to be paid by the Applicants.
Mr. Perkins testified on cross-examination that the joint planning
requested by OG&E will require the parties to study the problems caused and
agree on a set of parameters for a computer model [p. 65, ls. 14-17 and p.
77, ls. 23, 24] and then look at what mitigation measures are necessary to
restore the pre-merger conditions [p. 78, ls. 3-4]. The computer model must
include the flows that are on the system along with those related to the
merger transaction [p. 78, ls. 12-17].
On cross-examination, Mr. Perkins admitted that he had no experience in
transmission planning, as distinguished from operations [p. 84, ls. 4-6]. He
did not know what an annual load
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factor was [p. 82, ls. 20-21]. He stated the head of the OG&E transmission
planning function was probably more knowledgeable about the status of OG&E's
transmission system than he was [p. 9 1, ls. 1-3]. He was not able to testify
regarding the models used by the Southwest Power Pool for its databases in
preparing its own computer model to analyze the transmission system and did not
know how many points of interconnection OG&E had with Entergy [p. 86, ls. 16-19
and p. 91, 1.23 - p. 92, 1.3]. With regard to many of these matters, Mr. Perkins
said that Mr. Kuebeck would be the best person to ask [p. 82, l. 20 - p. 89, l.
20 and p. 94, ls. 1-2].
Mr. Perkins further stated that OG&E's study showed that there is no
pre-existing condition that would cause congestion on the OG&E system [p. 78,
ls. 23-25 and p. 79, ls. 1-4].
Mr. Perkins further testified that OG&E had submitted a five-year
transmission construction plan to the Southwest Power Pool and that such plan
did not contemplate any system upgrade designed to address overloads at or in
relation to OG&E's Fort Smith station [p. 86, l. 20 - p. 87, 1. 4]. Mr. Perkins
agreed that the Southwest Power Pool had adopted Coordinated Planning
Procedures, which were an attachment to the SPP Regional Open Access
Transmission Tariff. He explained that under such procedures, the SPP conducts
seasonal assessments of the expected performance of the regional transmission
network and notifies transmission owners of violations of reliability criteria.
It is then the responsibility of the transmission owner either to explain why
the violation finding is not valid or to identify alterations to the
transmission system that would correct the violation. Mr. Perkins agreed that,
under the procedures, the SPP staff would participate in the conduct of studies
needed to study any such violation and that the procedures make provision for
sharing of the costs of a system upgrade among those who benefit from the
upgrade [p. 87, .l 5 - p. 88, l.5].
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Mr. Perkins testified that the merger related study conducted by OG&E
showed that the transformer upgrade for the Fort Smith Substation will
resolve the constraints on the OG&E transmission system [p. 107, ls. 21-24,
p. 112, ls. 22-24 and p. 113, ls. 2-4].
On cross-examination Mr. Perkins admitted that OG&E had posted on the SPP
OASIS a zero Available Transfer Capability for imports from Entergy for the
summer of 1999. He explained that the zero ATC was based on notification from
the SPP that loop flow from transactions by other utilities had impacted OG&E's
import capability. Mr. Perkins stated that the zero ATC posting had been made in
April and that the transactions referred to by the SPP as impacting OG&E did not
include any transfer from AEP to CSW. Mr. Perkins testified that OG&E had
retained an outside consulting firm, PCA, to analyze the impact on OG&E's system
of transfers from AEP to CSW. He further stated that he had seen the results of
PCA's studies but claimed not to be familiar with Table 1 to PCA's study report
and referred all questions about the report to Mr. Kuebeck [p. 99, ls. 12-13 and
p. 101, ls. 7-16].
Mr. Perkins further testified that, while OMPA and WFEC had firm
transmission reservations on the OG&E system, he did not know how OMPA or
WFEC used those reservations or where their power supply resources were
located. Mr. Perkins testified that according to OG&E's answers to the
Applicants' data request (Exhibit 213) that OMPA had no firm transmission
reservation of the Entergy system for imports into OG&E's control area [p.
102, l. 11 - p. 105, l. 19]. However, on redirect examination, Mr. Perkins
explained that the Applicants' data request related to "use" of firm
transmissions and does not reflect the reservations that OMPA has on the
system [p. 113, ls. 6-22].
On redirect examination Mr. Perkins stated that AEP would not be
required to pay for services under the SPP tariff with respect to the merger
transaction [p. 112, ls. 12-14]. He also
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stated that AEP would not have any financial obligation under the SPP tariff to
pay for upgrades caused by the merger transaction because AEP has not requested
transmission service through the SPP [p. 112, ls. 16-21].
PETER P. KUEBECK
OG&E's next witness was Peter P. Kuebeck. Mr. Kuebeck is employed by
OG&E as Supervisor of Transmission Scheduling. His Responsive Direct
Testimony, filed on March 29, 1999 (Exhibit 164), the volume two of two
volumes, which Mr. Kuebeck sponsored and which contains the work papers
relating to the studies performed by OG&E in this case and was also filed on
March 29, 1999 (Exhibit 168) and the summary of Mr. Kuebeck's testimony, as
redacted, dated April 19, 1999 (Exhibit 214), were accepted into the record
[p. 131, ls. 15-21].
Mr. Kuebeck testified that Applicants, AEP and CSW propose a multi-year
arrangement by which a large transfer of electric energy will be sent cross
country from Ohio to Texas. He stated that, this transfer, which he referred
to as the Merger Transaction, involves a vast distance, broadly distributed
flows and impacts across multiple states and control areas. Mr. Kuebeck
testified that Applicants were asked to perform a transfer study [p. 117, ls.
4 and 5]. The parameters for the study were agreed upon by the parties in
this case and became a part of an Order of this Commission. Mr. Kuebeck
takes issue with the study performed by the Applicants in the following
respects:
1. The transmission system study performed by the Applicants demonstrates
that the proposed merger and transfer of 250 megawatts of energy from AEP to
CSW, the Merger Transaction, cannot be accommodated without negatively affecting
import Available Transfer Capability ("ATC") on the existing transmission grid
in Oklahoma. The proposed Merger Transaction will impose a significant
limitation on electric energy import capability to the State of Oklahoma. The
Applicants insist that there is no ATC from Entergy to OG&E, yet conclude
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that their own transaction along this same path can be accommodated. He
testified, however, that the Applicants' Merger Transaction is the incremental
transaction that takes away virtually all of the ability of the Fort Smith
substation to carry any other imports of power and reduces import capability
across the transmission system serving Oklahoma [p. 117, ls. 16-18].
2. The studies that Mr. Kuebeck performed with data provided by the
Applicants demonstrate that transfer considerations were overlooked in the
Applicants' study. Specifically, Applicants failed to perform a meaningful
Linear Transfer Analysis by AC solutions, and Applicants ignored the
Transmission Reliability Margin for each studied contingency.
a. Linear Transfer Analysis is used to determine the level of
reliable transfer capability from one area to another. The studies Mr.
Kuebeck performed for OG&E utilized an AC methodology that is inherently
more accurate than the DC studies used by the Applicants. An AC analysis
considers transformer tap settings, generator MVAR limits, shunt devices,
transmission line MVAR loading, and voltage performance of the network.
Energy transfers across vast distances require complete AC analysis for
accurate determination of network performance.
b. Transmission Reliability Margin ("TRM") is that amount of
transmission capacity used in this region to supply generation resources
from adjacent utility systems to maintain generation reliability in the
event of generator forced outages. Applicants failed to consider TRM in
their analysis. The Applicants failed to recognize the absolute Available
Transfer Capability at the points of interconnection. The Merger
Transaction reduces ATC severely at all north and east import points for
the purchase of energy outside Oklahoma. The Applicants insist that TRM of
other companies is inconsequential to the AEP to CSW transfer of energy.
That aside, the Applicants have
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reported that there is a decrease in First Contingency Incremental
Transfer Capability ("FCITC") into OG&E after subtracting the 250 megawatt
transfer. Applicants' own study shows there is a significant reduction in
import capability to Oklahoma.
3. Mr. Kuebeck performed a Loss Study for OG&E using the load flow data
submitted by Applicants. The study revealed increased losses for OG&E as energy
flows on parallel paths through the OG&E system to CSW SPP and CSW ERCOT. Losses
appear as loads to generators, requiring the generators to produce more power
and use more fuel. The additional fuel cost for the losses caused by the Merger
Transaction will be paid for by all OG&E customers. Mr. Hiebsch provides
quantitative cost estimates for this impact in his responsive direct testimony.
Mr. Kuebeck further testified that Applicants were asked by this
Commission to perform and submit a study that would identify transmission
constraints that might result from this merger. Using the Applicants' data Mr.
Kuebeck performed studies to verify the conclusions reached by the Applicants.
According to Mr. Kuebeck, while all of these studies reflect a decrease in
import capability into the State of Oklahoma as a result of the Merger
Transaction, Applicants suggest that these results should be ignored. Mr.
Kuebeck stated that the studies he performed clearly demonstrate harm to
Oklahoma's electric consumers, and Applicants should propose and agree to
implement mitigation measures that will eliminate that harm.
Mr. Kuebeck criticizes Applicants for relying too heavily on DC transfer
studies rather than relying on the more accurate AC studies. Out of the
estimated 2,000 to 3,000 cases studied by the Applicants, only 12 of the studies
were done with an AC solution to verify the DC transfer study [p. 128, ls. 17-24
and p. 129, ls. 2-12].
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Mr. Kuebeck testified that the OG&E transmission line losses were
calculated using the winter 1999 case provided by the Applicants [p. 129, ls.
16-17]. Although an hour by hour computation of the line losses throughout
the entire year would yield a more precise calculation, Mr. Kuebeck is
comfortable that the figures on the exhibit he sponsored are representative
of what would be the annual loss on OG&E's system [p. 130, ls. 5-20]. He
explained that there are two types of power on OG&E's system negatively
impacted by the merger: real power measured in megawatts [p. 132, Is. 12-23]
and reactive power measured in MVARs [p. 133, ls. 1-8]. Mr. Kuebeck
estimates that the merger will increase line losses on OG&E's transmission
system by 5 megawatts in real power [p. 130, ls. 23-25] and by 44 MVARs of
reactive power [p. 133, ls. 13-17, Exhibit PPK-1]. Mr. Kuebeck explained
that as the transmission system becomes loaded, it is necessary to supply
more capacity MVARs to the system to maintain the voltage [p. 133, ls. 18-24
and p. 134, ln. 2].
Mr. Kuebeck testified that he is familiar with the SPP coordinated
planning procedures. The seasonal assessments that the SPP does as
contemplated by those procedures is done to point to violations in
reliability. Mr. Kuebeck testified that SPP has not advised OG&E that any of
its facilities are in violation of the SPP reliability criteria [p. 153, ls.
5-15].
In response to cross-examination, Mr. Kuebeck admitted that OG&E's OASIS
postings were at variance with the chart in Mr. Perkins' testimony that
purported to list OG&E's Available Transfer Capabilities for imports from OG&E's
interconnected neighbors. In particular, where Mr. Perkins' chart had shown that
before the AEP/CSW merger OG&E would have an ATC from Entergy of 139 MW the OG&E
OASIS posting showed zero ATC. Mr. Kuebeck testified that Entergy had similarly
posted a zero ATC value for imports into OG&E from Entergy, which Mr. Kuebeck
said was appropriate [p. 142, l 22 - p. 144, l. 21].
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Where Mr. Perkins' chart had shown a pre-merger ATC from GRDA. of 417
MW and a post-merger ATC of 392 MW, Mr. Kuebeck stated that the OG&E OASIS
posting showed only 231 MW of ATC available from GRDA. prior to the merger
[p. 144, l. 21 - p. 145, l. 5]. Mr. Kuebeck further admitted that OG&E's
OASIS postings showed that OG&E had provided for no Transmission Reserve
Margin (TRM) in relation to its import capabilities from any of its
interconnected neighbors other than Entergy [p. 166, l. 13 - p. 167, l. 7].
Mr. Kuebeck testified that he was comfortable with OG&E's OASIS postings [p.
144, l. 21 p. 148, l. 12].
Mr. Kuebeck also admitted that DC analyses were customarily used to
study the performance of the transmission network under contingency
conditions to expedite the analysis of hundreds of different contingency
conditions and that the study process that Applicants followed in this case
mirrored the process that the Southwest Power Pool ordinarily follows [p.
150, l. 4 p. 151, l. 22]. Mr. Kuebeck agreed that, contrary to his prefiled
testimony, Applicants had performed AC studies to confirm the reasonableness
of their DC studies [p. 128, l. 14 - p. 129, l. 3] and that in all but one
instance the AC results were consistent with the DC results [p. 167, ls.
4-6].
Mr. Kuebeck agreed that linear load flow analyses involve a systematic
evaluation of the loss of individual bulk power system elements on other
elements of the interconnected network but that his study of the effect of
the AEP to CSW transfer on OG&E's import capabilities was based on an
assessment of only 31 contingencies [p. 155. Is. 8-12; p. 161, ls. 14-16 and
p. 186, ls. 18-20]. Mr. Kuebeck said that it was important to select the
appropriate outages to study where you know they can make a difference. It
was for this reason that he studied outages of Fort Smith station because it
has a history of outages including four outages in the last three years. Mr.
Kuebeck pointed to Fort Smith as an example of where operating judgment and
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system knowledge helps in selecting the appropriate contingencies to study [p.
154, l. 17 - p. 155, l. 3].
Mr. Kuebeck admitted that originally if any studies were put forward in
this proceeding by OG&E, PCA would do the studies [p. 160, ls. 8-13].
However, in the last days of March, OG&E decided that it should perform its
own studies [p. 160, ls. 8-13]. Mr. Kuebeck stated that based on the
information provided by OG&E, it was reasonable for the Applicants to assume
that the Fort Smith transformer limit is a pre-existing condition [p. 169,
ls. 14-23]. Mr. Kuebeck admitted that Table 1 to the PCA study showed that
the Fort Smith 161/500 MVA transformer, even when modeled at its correct
emergency rating, overloaded when the Fort Smith 161/345 MVA transformer was
out of service even before the AEP to CSW transaction, but that the SPP had
not informed OG&E of any reliability violation. Mr. Kuebeck had earlier
corrected his testimony on direct examination by stating that the AEP to CSW
transfer would affect loadings on Fort Smith by less than 5%, not 20% [p.
115, ls. 11-12 and [p. 169, l. 11 - p. 170, l. 10].
Table 1 to PCA's study report showed that a transmission line on the
Entergy system would be the element that would limit to zero firm power
transfers from Entergy to OG&E [p. 174, ls. 6-16]. When asked about this, Mr.
Kuebeck contended that the consultant's analysis was not reliable because
neither OG&E nor its consultant had confirmed with Entergy that transmission
lines on Entergy's system would actually respond to contingencies as indicated
in the PCA study. Mr. Kuebeck testified that OG&E had made no recent effort to
engage in coordinated planning with Entergy [p. 169, ls. 6-14].
After rejecting PCA's original results, which were based on a
full-blown contingency analysis which studied the outage of 9000
interconnected system facilities [p. 178, l. 86], PCA was asked to do a
different study. Mr. Kuebeck explained that the second PCA study produced
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no equivalent to Table 1 to the first PCA study and that the second study was
based on a different set of transfers and may include different modeling of
generation changes [p. 186, ls. 3-14]. When asked why he had stated in direct
testimony that the PCA studies were consistent with the studies Mr. Kuebeck had
done, Mr. Kuebeck stated that they were generally because they both examined the
effects of the AEP to CSW transfer [p. 191, l. 19 - p. 192, l. 1].
When asked about the loss study that he had done, Mr. Kuebeck agreed
that he had used a winter season base case prepared by the SPP in January
1998 rather than the SPP base cases that Applicants and OG&E had used for
determining the loop flow effects of the AEP to CSW transfer, which were
prepared by the SPP in December 1998 [p. 193, l. 10 - p. 194, l. 4]. Mr.
Kuebeck agreed that the PCA study, which was based on the Summer 1999 base
case prepared in December 1998, showed that at the summer peak additional
losses resulting from the AEP to CSW transfer would be 3.1 MW not the 5.5 MW
Mr. Kuebeck had found based on the older winter base case [p. 195, ls.
7-21]. Mr. Kuebeck readily admitted that his measure of incremental losses
associated with the AEP to CSW transfer does overstate the amount of
incremental losses that OG&E would experience on an average annual basis [p.
195, l. 23 - p. 196, l. 2].
Mr. Kuebeck was cross-examined about his Exhibit PPK-3, which shows the
impacts that a number of transactions for which firm transmission
reservations have been made that include service in the month of August 1999
would have on OG&E's Fort Smith station [p. 204, l. 16 - p. 205, l. 17]. Mr.
Kuebeck stated that there were other long-term transactions on this list that
would have an impact on Fort Smith station loadings that would be about the
same or greater than the AEP to CSW transfer [p. 206, l. 1 - p. 209, l. 7].
Mr. Kuebeck further agreed that some of the uses made by Western Farmers and
OMPA of the OG&E system were modeled in the base
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case and would therefore not be affected by any reduction in ATC resulting from
the merger [p. 211, l. 16 - p. 213, l. 4].
GUSTAVO E. BAMBERGER
OG&E's next witness was Gustavo E. Bamberger, an economics consultant
from Chicago, Illinois. Dr. Bamberger is a Principal and Vice President of
Lexecon Inc., an economics consulting firm that specializes in the
application of economics to legal and regulatory issues. He received a B.A.
degree from Southwestern at Memphis, and M.B.A. and Ph.D. degrees from the
University of Chicago Graduate School of Business. Responsive Direct
Testimony, filed in this cause on March 29, 1999 (Exhibit 167). Exhibit 167
and the summary of Dr. Bamberger's testimony, as redacted, dated April 19,
1999 (Exhibit 216), were accepted into the record [p. 13, ls. 5-10].
Dr. Bamberger testified that Lexecon Inc. had been asked by OG&E to
analyze the likely effect of the proposed merger of AEP and CSW on buyers of
electricity in Oklahoma. Based on the available evidence, they reached the
following conclusions:
FIRST, absent additional mitigation measures, the proposed AEP/CSW merger
likely will harm a substantial number of Oklahoma consumers because it
will reduce available transmission capacity into Oklahoma from relatively
low-cost power suppliers.
SECOND, Applicants' proposed mitigation measures fail to address the
merger-induced reduction in available transmission into Oklahoma.
THIRD, Applicants' proposed mitigation measures do not alleviate market
power concerns.
Dr. Bamberger testified that the proposed merger reduces transmission into
Oklahoma. He stated that as a condition of the proposed merger, Public Service
of Oklahoma ("PSO"), a CSW company, has entered into transmission service
agreements with Ameren and Western
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Resources ("the Ameren contract"),
whereby PSO purchased 250 megawatts of firm "point-to-point" transmission
service for the period June 1, 1999 to May 31, 2003. If it were not for the
merger, CSW was not planning to purchase firm energy from AEP; instead, CSW
intended to utilize different transmission resources to reach alternate energy
suppliers. Thus, Dr. Bamberger concluded that this sale is merger related.
Dr. Bamberger testified that Applicants concede that CSW's use of the
Ameren transmission path will affect the availability of transmission in other
parts of the state because AEP/CSW's use of the Ameren path causes "loop flows"
over other parts of the Oklahoma transmission system. He explained that loop
flows are power flows on portions of a transmission system owned by utilities
that are not involved in a particular power transaction.
Dr. Bamberger stated that because less transmission will be available as a
result of the merger, certain transactions between Oklahoma utilities and power
suppliers likely will be precluded. That is, if the merger is completed (without
additional mitigation), power purchasers in Oklahoma, like OG&E, will not be
able to import as much power from outside of the state. This reduction in
transmission capability also likely will affect several other entities in
Oklahoma, including the Oklahoma Municipal Power Authority and Western Farmers
Electric Cooperative. In effect, a reduction in the availability of transmission
reduces the geographic size of the market in which an Oklahoma utility can
purchase power, thus reducing OG&E's (and others') ability to import lower-cost
power into Oklahoma. Dr. Bamberger concluded that such a reduction in the
availability of relatively low-cost power harms Oklahoma consumers.
Dr. Bamberger further testified that Applicants' proposed mitigation
measures do not address the effect of the merger on transmission. He stated that
Applicants concede that the proposed merger raises market power concerns. In
response to these concerns, Applicants
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propose certain mitigation measures. Dr. Bamberger testified, however, that
Applicants' proposed mitigation measures fail to address the merger-induced
reduction in the geographic size of those markets. That is, even if the proposed
mitigation measures reduce concentration in Oklahoma to the pre-merger level,
they do not return a transmission capability into Oklahoma to the pre-merger
level because the proposed mitigation measures do not affect merger-induced loop
flows. Dr. Bamberger testified that the solution to the merger-induced reduction
in transmission capability is straightforward. It can be mitigated by increasing
transmission capacity at points where the Ameren transaction-related loop flows
would reduce the availability of transmission. Such a mitigation measure would,
in effect, return the geographic size of the market to pre-merger levels.
Dr. Bamberger testified that because the proposed merger affects the size
of the geographic market, Applicants' use of an "HHI" analysis to evaluate the
effectiveness of the proposed mitigation measures is misleading. Applicants'
analysis consists of comparing pre-merger HHIs in particular geographic markets
to post-merger HHIs in smaller geographic markets. In Dr. Bamberger's opinion,
Applicants' economic analysis is flawed because the pre-merger and post-merger
HHIs are based on markets of different geographic sizes.
Dr. Bamberger testified that Applicants' proposed mitigation measures do
not alleviate market power concerns. He said that even if the pre-merger extent
of the geographic market were re-established by upgrading transmission capacity
to offset merger-induced loop flows, Applicants' mitigation measures do not
alleviate concerns that the merger will allow a merged AEP/CSW to exercise
market power. Dr. Bamberger stated that Applicants claim that they will mitigate
market power concerns in Oklahoma by divesting generation assets. In particular,
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Applicants claim that they will "divest" 300 megawatts of generating capacity
from PSO's Northeastern plant (which has a total generating capacity of about
1,500 megawatts).
Dr. Bamberger stated that in general, divestiture can be a reasonable
approach for mitigating market power concerns (but not loop flow concerns)
because it removes the divested assets from the control of the merging parties.
However, Applicants' mitigation proposal falls short of divestiture. First,
Applicants concede that their proposed "divestiture" will not take place until
sometime after July 1, 2002. Indeed, AEP and PSO have not committed to divest
generation assets by any particular point in time. Second, the "divestiture"
fails to eliminate AEP/CSW's control of the "divested" asset. In particular,
AEP/CSW likely will be able to influence when outages will be scheduled at the
"divested" plant.
Dr. Bamberger stated that if AEP/CSW can override the objections of the
owners of the "divested" 300 megawatts (or if they do not object), AEP/CSW could
use its control of the Northeastern plant to exercise market power by
restricting the output of the Northeastern plant at times when such a reduction
in output could substantially raise electricity prices. It is Dr. Bamberger's
opinion that the proposed mitigation measures may make it easier for AEP/CSW to
exercise market power because it may allow the merged firm to raise market price
by restricting the output of the "divested" 300 megawatts of generating capacity
at no cost to AEP/CSW.
Dr. Bamberger testified that under Applicants' proposed interim mitigation
measures, that is, until the proposed "divestiture" of 300 megawatts takes
place, CSW will conduct interim system energy sales from the Northeastern plant
at a specified price. It is his understanding that under the terms of the
proposed sales contracts, CSW will be able to recall the energy under certain
"emergency" conditions. If it does so, CSW will be obligated to compensate the
owners of the energy, at a yet-to-be specified amount.
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It is Dr. Bamberger's opinion that this interim mitigation measure fails
to alleviate market power concerns. First, the merged firm will maintain
operational control of the to-be-divested plant during the interim period. As
stated in Dr. Bamberger's testimony, Applicants may have an incentive to
exercise market power by scheduling outages strategically. Second, if the amount
of compensation that CSW must pay to the owners of the financially firm energy
in the event of a recall is not related to the price of energy at that time, CSW
may have an incentive to recall the energy, thereby profiting from the
difference between market price and the amount it must pay to compensate the
owners of the financially firm energy.
Dr. Bamberger testified further that even if his concerns about the
proposed mitigation measures were unfounded, Applicants concede that their
proposed mitigation measures fail to prevent concentration levels from
increasing substantially in several areas of Oklahoma, including OG&E's service
area. That is, Applicants concede that, as a result of the proposed merger,
concentration in several areas of Oklahoma will increase substantially.
Dr. Bamberger testified that OG&E's concerns about the availability of
relatively low cost power as a consequence of the merger are not overstated,
contrary to the criticisms of the Applicants' consultant, Dr. Hieronymous.
Dr. Bamberger noted, first of all, that Dr. Hieronymous did not deny that the
merger would have an effect on such availability but only claimed that the
effect would be relatively small. Dr. Bamberger testified that there is not
any reason to believe that the effect will be small. He testified that the
effects will likely increase into the future [p. 11, ls. 22-25 and p. 12, ls.
1-11].
Dr. Bamberger testified that the merger would harm the 60 cities
represented by the Municipal Electric Systems of Oklahoma because it will
cause a reduction in import capability [p. 13, ls. 14-24]. Dr. Bamberger
compared this situation to a quota on the import of low priced
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cars. He stated that what the loop flows, in effect, do is reduce the
availability of transmission and that is like a quota on relatively low cost
power. He stated that being denied access to some of this low cost power,
because of the loop flows, harms anybody who would have an opportunity to buy
such relatively low cost power [p. 13, l. 25 and p. 14, ls. 1-10].
Dr. Bamberger testified that the Applicants' plan of divestiture under
their mitigation measures has nothing to do with the reduction of
transmission and how that would increase costs to Oklahoma consumers [p. 16,
ls. 9-22 and p. 17, ls. 4-9]. Dr. Bamberger also stated that some of the
terms relating to the proposed mitigation measures are ambiguous, for
example, the price that the owners of the financially firm energy will get
making it difficult for an economist to be able to evaluate the effectiveness
of the measure [p. 12, ls. 18-24 and p. 17, ls. 10-15].
Under cross-examination, Dr. Bamberger testified that he did not make
an independent evaluation of the impact of the on transmission capability and
that he was not competent to perform loop flow studies. Dr. Bamberger noted,
however, that both Mr. Maliszewski and Dr. Hieronymous found that the merger
caused negative impacts on import capability. Dr. Bamberger observed that
the Appendix A analysis (under the FERC Merger Policy Statement) done by Dr.
Hieronymous showed that the amount of power that can be imported into the
OG&E service area is reduced [p. 19, ls. 12-25 and p. 20, ls. 1-10]. Dr.
Bamberger also testified that he relied upon OG&E's engineering studies which
show that loop flows would reduce transmission and Mr. Maliszewski's studies
which showed the same thing, so he did not do any additional investigation
beyond noting that both sides agree [p. 20, ls. 12-25 and p. 21, ls. 1-2].
Although the Applicants and OG&E disagree as to the extent transmission
capabilities are reduced, Dr. Bamberger found the parties' agreement to be
significant [p. 25, ls. 18-25 and p. 26, ls 1-20].
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Dr. Bamberger concluded that the effect of the merger on the
availability of transmission will likely increase the cost of electricity to
a substantial number of customers. This conclusion was based on his
observation that absent the merger, CSW would utilize different transmission
resources to reach alternative energy suppliers and that AEP was unlikely to
be a supplier in Oklahoma and Texas in the future because it has more
lucrative opportunities elsewhere [p. 27, is. 2-12, 23-25 and p. 28, ls.
14-17]. Dr. Bamberger cites the testimony of Mr. Maliszewski and Dr.
Hieronymous to support this conclusion [p. 28, ls. 8-25 and p. 29, ls. 1-6].
Dr. Bamberger concludes that the Oklahoma Municipal Power Authority and
Western Farmers Electric Cooperative will be affected by the merger-induced
reductions in transmission capability because they rely on the transmission
system of OG&E [p. 31, ls. 11-18]. He reaches this understanding in reliance
on the testimony of Mr. Hiebsch without independent knowledge of the facts
[p. 31, ls. 19-25 and p. 32, l. 4].
On further cross-examination, Dr. Bamberger was advised that
Applicants' interim mitigation measures include a sale of energy from CSW's
system, not just from the Northeastern plant, as Dr. Bamberger had
testified. However, Dr. Bamberger stated that that fact did not make a
difference in his opinions [p. 35, ls. 3-19].
STEPHEN F. HIEBSCH
The final witness called on behalf of OG&E was Stephen F. Hiebsch. Mr.
Hiebsch is the manager of Market Solutions for OG&E which is the research and
service support group of the Marketing and Customer Care Division. Market
Solutions contains traditional areas such as cost of service, revenue needs,
rate making, electric forecasting for both retail and wholesale, and load
research. It also includes areas such as customer research, financial analysis
and market studies. Mr. Hiebsch earned his B.S. degree in business and
mathematics from Southwestern College in Winfield, Kansas. He did graduate work
at Wichita State University in Wichita,
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Kansas, and earned a Master's Degree in Economics from Oklahoma State
University. He has also completed an additional 30 hours of graduate courses in
economics from Oklahoma State University. Mr. Hiebsch has previously been
recognized as an expert witness before this Commission in the areas of economic
forecasts, economic analysis, financial analysis and costs of capital. His
Responsive Direct Testimony, filed on March 29, 1999 (Exhibit 166), and the
summary of his testimony dated April 19, 1999 (Exhibit 217), were accepted into
the record [p. 47, l. 19].
Mr. Hiebsch testified that the purpose of his testimony was to identify
the concerns that OG&E has with the proposed merger of AEP and CSW, and its
subsidiary, PSO, from a competitive and ratepayer impact perspective, and the
relief OG&E seeks from the Commission. He stated that OG&E is concerned that the
merger of AEP and CSW, as structured with their proposed mitigation measures,
will constrict both the number of energy suppliers and the extent to which
energy suppliers are able to participate in the Oklahoma marketplace. He
testified that this reduction in marketplace participants has the likely effect
of raising electric prices by limiting competition.
Mr. Hiebsch stated it was his understanding that this merger will be
approved automatically if the Commission does not affirmatively reject the
merger in the time permitted under Oklahoma law. He said it was also his
understanding that under Oklahoma law, the Commission should disapprove the
merger if the effect of the merger substantially lessens competition in the
furnishing of public utility service in this State. He stated that under the
conditions that will prevail in the post-merger world, based upon Applicants'
filings and OG&E's review of those filings, it leads OG&E to believe that this
merger will have a significant adverse impact on competition in Oklahoma.
Furthermore, any savings which might be achieved for
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PSO's Oklahoma customers comes at the expense of customers of the remaining
electric providers in this State.
Mr. Hiebsch stated that he believes the mitigation measures of the
Applicants may never occur since they are based upon Applicants' own subjective
determinations of their need for capacity. He also feels that the divestiture of
300 megawatts of capacity is likely to never occur since growth in load of this
size could occur in a short period of time. Mr. Hiebsch testified that there is
evidence in the record that PSO is already short of capacity, referring to
Exhibit SFH-3 to his Responsive Direct Testimony (Exhibit 166).
Mr. Hiebsch testified that historically OG&E has had the ability to
purchase power off-system for economic reasons. As an example, he stated that
the Fort Smith substation is the primary interconnect to OG&E for power coming
from the East. In his prefiled testimony, he discussed the various reasons for
purchasing power from off system suppliers. He testified that while historically
these amounts have not been large, with the changing competitive environment,
economy power purchases will increase. He testified that Exhibit SFH-8 to his
Responsive Direct Testimony (Exhibit 166) is an example of historic capabilities
but is not an indication of the expected growth that is likely to occur. Mr.
Hiebsch referred to Mr. Perkins' chart which shows OG&E's entire system is
impacted by the 250 megawatts transfer. He stated that in addition to the
Entergy interconnection (Fort Smith substation), major interconnection
capabilities with SPA, Western Resources and CSW are also significantly reduced.
Mr. Hiebsch stated that these increased system wide transmission
constraints substantially lessen competition in Oklahoma after the merger. The
constraints remove the opportunity to make economic power purchases on behalf of
Oklahoma consumers. Also,
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Economic Development will be hurt by the increased transmission constraints
which limit competition.
Mr. Hiebsch also stated that these constraints hurt more than just OG&E's
customers. Cooperative Association members served by Western Farmers and
municipal customers served by the Oklahoma Municipal Power Authority, likewise,
will be hurt. He said that consumers throughout the State of Oklahoma will be
affected by this reduction in import capabilities. The increased transmission
constraints limit the geographic size of the marketplace which decreases the
opportunity for obtaining purchased energy at a competitive price. Mr. Hiebsch
concludes that this hurts all Oklahoma customers.
Mr. Hiebsch stated that another negative impact of the merger is the
increased transmission line losses as testified to in Mr. Kuebeck's testimony.
Mr. Hiebsch testified that these increased line losses cause OG&E's Oklahoma
retail and wholesale customers to pay approximately $1.5 million per year more
in fuel costs as shown in Exhibit SFH-9 to his Responsive Direct Testimony
(Exhibit 166). He stated that in CSW's Proxy Statement, March 5, 1999, which is
Exhibit SFH-10 to his testimony (Exhibit 166), the Applicants claim that the PSO
customers will receive an $11.8 million fuel cost savings over the next 10
years. By multiplying the annual increased fuel expenditure by 10, the estimated
cost to OG&E's Oklahoma retail and wholesale customers attributable to line
losses is $15 million over 10 years. Thus, he concludes OG&E's customers are
subsidizing PSO's customers. He stated that this does not address any impact
that might be placed on transmission systems other than OG&E's.
Mr. Hiebsch testified that OG&E's requested litigation measures are as
follows:
1. The Applicants must bear all capital expenditures necessary to return
the transmission system and the Fort Smith Substation to the pre-merger
conditions. He stated that
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the preliminary estimate of this expenditure according to Mr. Perkins is
approximately $11 million.
2. The Applicants must bear all expenditures necessary to install the
equipment required to correct power factor,
3. Applicants should pay the increased $15 million in fuel costs that is
related to increased line losses.
4. Contrary to past practice between PSO and OG&E, there was no effort on
the part of the Applicants to conduct any joint planning for future operations.
Since OG&E was not fully informed of the Applicants' plans, any conclusions
drawn thus far must be considered preliminary. OG&E requests that the Applicants
engage in joint planning with the other electric providers in the State to more
fully understand the impacts of the merger and resulting operations will have on
the State. Furthermore, OG&E requests that the Applicants and the other electric
providers in the State work together to resolve issues and problems that arise
from this joint planning.
Mr. Hiebsch testified that OG&E and its customers must be held harmless
from any required capital investments and increased operating costs caused by
post-merger operations. He stated that OG&E urges the Commission to dismiss the
Application at this time.
Mr. Hiebsch testified that notwithstanding the comments of Dr.
Hieronymous, OG&E's purchases of power at the Entergy interconnect during the
summers of 1996, 1997 and 1998, which is depicted on Exhibit SFH-8 (Exhibit 166)
does not overstate the amount of purchases that OG&E makes through the Entergy
system. He stated that the path for the energy was actually reserved and payment
for the energy was made and, at the time the power was to flow to OG&E, a
determination was made, based on weather and other factors, whether OG&E needed
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the power or would sell the power to other entities [p. 45, ls. 16-25 and p. 46,
ls. 1-22]. On cross-examination, Mr. Hiebsch testified that Exhibit SFH-8 was
introduced to show that there are availabilities to purchase energy off-system
through the Fort Smith Substation for OG&E to buy economy purchases of energy so
it can lower costs to its customers. He also stated the purpose was to show that
this type of trading has gone on in the past and as the competitive environment
grows in the future, these purchases could become much larger [p. 55, ls.
14-24]. Mr. Hiebsch testified that the megawatt hours listed on his exhibit for
the days of May in 1998 showed instances where actual physical delivery of
energy was made. However, he could not testify as to which of the megawatt hours
for the month of May in 1998, if any, were actually delivered to OG&E [p. 56,
ls. 5-20].
On cross-examination, Mr. Hiebsch admitted that he had assumed that in
each hour of the year additional losses caused by transfers from AEP to CSW
would be equal to the losses Mr. Kuebeck had calculated that OG&E would
experience at the hour of the winter peak on OG&E's system [p. 61, l. 21 - p.
62, l. 13]. Mr. Hiebsch further admitted that he had determined the cost of
additional losses caused by a 250 MW transfer from AEP to CSW by assuming
that OG&E would burn additional natural gas to make up for such losses [p.
61. l. 2 - p. 63, l. 16]. Mr. Hiebsch testified that OG&E's average annual
fuel cost was approximately 52% of its average annual gas cost for generating
electricity [p. 60, ls. 1-5]. Mr. Hiebsch testified that he had concluded
that the merger would cause OG&E to incur additional losses at a cost of $15
million over the first ten years after consummation of the AEP/CSW merger by
multiplying an annual cost of $1.5 million, by 10 years. Mr. Hiebsch
testified that Applicants have planned to transfer power from AEP to CSW for
the length of the contract [p. 63, ls. 1-25].
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JIMMY D. CROSSLIN
Mr. Jimmy D. Crosslin, Tariff and Cost of Service Coordinator for PUD,
testified on behalf of Staff. Mr. Crosslin testified in support of the
Stipulation, Exhibit No. 209, which was presented to the Court and accepted
into the record in this Cause on April 19, 1999. Mr. Crosslin testified that
the terms of the Stipulation are a fair compromise and asked the Commission
to accept the Stipulation, as a balance of all interests involved. Mr.
Crosslin testified that the Stipulation is fair, just and reasonable, as to
the issues it addresses.
Mr. Crosslin testified that the Public Utility Division also gave serious
consideration, in its review of the Applicants' proposed merger, to the impact
it may have on competition in Oklahoma, and the effect it will have on Oklahoma
jurisdictional ratepayers.
Mr. Crosslin testified that the regulatory plan as initially proposed by
the Applicants should be rejected, and stated Staff has developed an alternative
plan. Staff recommends that the regulatory plan ultimately approved by the
Commission provide meaningful benefits to the ratepayers and that to accomplish
this goal, Staff proposes the merger savings be credited against the customer's
bill. Mr. Crosslin testified that Staff's proposal provides for a fair and
expedient manner to flow the merger savings to ratepayers. Mr. Crosslin
testified that he recommends a five-year regulatory plan be adopted to address
the regulatory treatment of merger synergies and the cost to achieve the
synergies. Mr. Crosslin testified Staff further recommends that each year
following the merger closing, the Joint Applicants distribute 50% of the
jurisdictional merger synergies to the ratepayers as shown on Attachment A of
the December 19, 1998 prefiled testimony of Jimmy D. Crosslin. Mr. Crosslin
testified that Staff's plan allows for the customers to receive a merger synergy
credit each August following the merger approval date. Mr. Crosslin testified
that the merger synergy credit rider should be effective until such time as the
Applicants' base rates are adjusted through a general base rate filing. Mr.
Crosslin testified that
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Staff also recommends hold harmless conditions to ensure that the ratepayers are
shielded from unknown and unintended consequences. Attachment B, of Jimmy D.
Crosslin's December 19, 1998 Testimony, provides Staff's overall regulatory plan
recommendations.
Mr. Crosslin testified the Applicants propose that merger savings be
credited against regulatory assets. However, Staff notes that PSO's regulatory
assets were definitively addressed in PSO's last rate proceeding, Cause No. PUD
960000214. Next, the Applicants propose the merger savings be applied to
depreciation expense to provide the benefit of a lower ratebase for distribution
facilities. Mr. Crosslin testified that Staff cannot support the Applicants'
proposal since it does not provide meaningful benefits to customers.
Mr. Crosslin testified as to the Applicants' retail market power study and
the load flow study. Mr. Crosslin testified that the proposed merger
substantially lessens competition in a retail access environment. He stated that
the Applicants propose market power mitigation measures in order to gain
regulatory approval of their proposed merger. Mr. Crosslin further testified
that the issue of market power becomes a major and vital concern as the State of
Oklahoma moves toward allowing competition for electric utility services.
Mr. Crosslin testified that the proposed merger creates market barriers on
the transmission system. The proposed merger contemplates transactions from the
AEP service territory to CSW. Historically, there have been no trading
transactions between the merging parties. Mr. Crosslin testified that the
proposed merger seeks to combine separate, distinct, geographic markets through
a 250 MW transmission service reservation. Mr. Crosslin testified that the
Applicants' reservation for transmission service results in additional
congestion on the regional transmission grid. Mr. Crosslin testified that the
Applicants' transmission reservation limits market participants' ability to
enter the Oklahoma market, which has an impact on the
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competitiveness of the market. Staff's specific recommendations regarding the
market power issues and hold harmless conditions are provided in the
recommendation portion of Mr. Crosslin's testimony.
Furthermore, 17 O.S. Section 191.5 provides that the merger may be
disallowed if the Commission finds:
the effect of the merger or other acquisition or control would be
substantially to lessen competition in the furnishing of public utility
service in this state;
Mr. Crosslin testified that the proposed merger presents competitive
concerns in a retail access environment. Staff recommended the following
changes to the Applicants' market power mitigation proposal:
1. The Applicants shall divest generation assets as necessary to
address horizontal and vertical market power concerns.
2. The Applicants must provide meaningful hold harmless provisions to
ensure that the customer is not negatively impacted by the merger.
To date, the Applicants have not provided a meaningful hold harmless
mechanism to evaluate the opportunity cost of the customers
resulting from diverting cheap generation as part of the interim and
divestiture market power mitigation sale.
3. The Applicants shall hold the customers harmless for the cost
differential of coal versus natural gas generation resulting from
the market power mitigation plan. The Applicants propose to divest
coal generation capacity instead of natural gas. Staff recommends
the customer be insulated from the adverse effect that might result
from the __________.
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4. plan for sharing the generation divestiture gains with the
ratepayers.
5. Applicants should agree to a 75% - 25% sharing of the interim
generation sale margins.
6. The Applicants load flow study of the transmission system identifies
the congestion areas, which has an impact on the performance of
Oklahoma transmission systems. Staff recommends the Applicants bear
the cost of upgrading the Fort Smith transformers.
7. Finally, Staff recommends the Applicants join an ISO by a date
certain to ensure that the transmission system is operated.
Mr. Crosslin's prefiled testimony was accepted into the record as
Exhibit Numbers 56, 112 and 172, without objection. Mr. Crosslin testified,
under cross-examination, that it was his understanding that his testimony
should be deemed conformed to be in compliance with the stipulation entered
into on April 19, 1999. Mr. Crosslin further testified under
cross-examination that an Independent System Operator ("ISO") could identify
and take remedial action to remove transmission congestion and constraints
through regional transmission planning [p. 84 ls. 16-21], and further stated
that PSO, in the offered stipulation, agrees to participate in an ISO
pursuant to the Stipulation at page 11, paragraph 17 (Exhibit 209 attached
hereto). Mr. Crosslin further testified it was his understanding that the
PSO customers will receive 100 percent of the jurisdictional fuel and
purchase power savings resulting from the merger. Mr. Crosslin testified
that the upgrade to the transformer at the Fort Smith junction is required by
the Public Utility Holding Company Act, under the interconnection
requirement. Therefore, the expense to upgrade the transformer is an
appropriate merger cost. Mr. Crosslin testified that the upgrade is
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necessary to ensure the parties are returned to pre-merger condition [p.86 ls.
12-17]. Mr. Crosslin testified that this is a traditional issue, because
ideally, the members of an ISO would pay proportionately for this benefit, but
he admitted "we are not there" [p.87 ls. 18-24]. He also testified that the
reason the upgrade is needed is the merger transaction [p.87 ls. 24 and 25 and
p. 88 l. 1) [See also p. 88 ls. 23-25 and p. 89 ls. 1-3].
Mr. Crosslin was aware that a firm reservation of 250 MW had not been
made for the summer of 1999, and therefore there was not a requirement to
resolve this issue immediately [p. 89, ls. 4-14].
Mr. Crosslin further reiterated his recommendation was that the
Applicants be required to have the Southwest Power Pool perform a regional
study to identify whether the merger would cause transmission constraints
that may have a negative impact on Oklahoma utilities. The second
recommendation was for the Applicants to be required to join an ISO. [p. 90,
ls. 1-5 ]
It was Mr. Crosslin's opinion that this issue would be resolved if the
Southwest Power Pool would in fact do the study, determine if the 250 MW
transfer can be performed and determine what the impact was on Oklahoma
utilities. The parties should be required to accept the decision rendered by the
Southwest Power Pool in this regard [p. 90, ls. 7-12].
Mr. Crosslin was also aware that PSO could accept the position taken by
the Staff [p. 90, ls. 13-15].
Mr. Crosslin was also aware that the State of Arkansas in their
approval of the merger had made as a condition that if SWEPCO intended on
leaving the Southwest Power Pool they would come back and request the
Arkansas Public Service Commission for approval [p. 90, ls. 17-22].
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KENNETH R. ZIMMERMAN
Kenneth R. Zimmerman, Ph.D., Tariff & Cost of Service Coordinator for PUD,
testified on behalf of Staff. Dr. Zimmerman testified that this application has
been evaluated by Staff in terms of the criteria contained in 17 O.S., Section
191.5, as well as the general definitions and standards in Sections 191.1
through 191.13. Section 191.5(A), provides:
The Corporation Commission shall approve any merger or other acquisition
of control referred to in Section 2 of this act unless, after a public
hearing thereon, it finds that one or more of the following conditions
will exist if such merger or other acquisition of control is consummated,
in which event it shall disapprove such merger or acquisition of control
and the same shall not be consummated.
The specific criteria in Section 191.5 are:
1. The acquisition of control would adversely affect the contractual
obligations of the domestic public utility or of any person controlling
such domestic public utility, or its ability or commitment to continue to
render the same level of service to its customers that the domestic public
utility is currently rendering;
2. The effect of the merger or other acquisition of control would be
substantially to lessen competition in the furnishing of public utility
service in this state;
3. The financial condition of any acquiring party is such as might
jeopardize the financial stability of the domestic public utility or any
person controlling such domestic public utility or otherwise prejudice the
interest of the domestic public utility's customers;
4. The plans or proposals which an acquiring party has to liquidate the
public utility or any such controlling person, sell its assets, or a
substantial part thereof, or consolidate or merge it with any person, or
to make any other material change in its investment policy, business or
corporate structure or management, would be detrimental to the customers
of the domestic public utility and not in the public interest; or
5. The competence, experience and integrity of those persons who would
control the operation of the domestic public utility are such that it
would not be in the interest of its customers and the public to permit the
merger or other acquisition of control.
Dr. Zimmerman testified that his testimony concerns two criteria in the
review Staff performed in assessing the impact of the proposed merger. In
addressing these criteria, Dr. Zimmerman testified that he focused on the
following:
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1. The PROMOD analyses performed by the applicants to assess the
operational costs and characteristics of the combined AEP/CSW generation
and transmission systems; and,
2. The economic impact of the proposed merger on the Tulsa Metropolitan
Statistical Area (MSA) economy and the Oklahoma economy.
Based on its review of the data and information provided by the Applicants
and independent analysis, Dr. Zimmerman testified that Staff has reached the
following overall conclusions:
1. The PROMOD analyses prepared by the Applicants indicate that the AEP
and CSW generation and transmission systems can be operated in combination
without significant negative impact on either the reliability or cost of
power for the customers of PSO;
2. The PROMOD analyses prepared by the Applicants do not investigate how
the AEP and CSW generation and transmission systems might be operated so
as to minimize the cost of power to PSO's customers;
3. The economic impact of the proposed merger on the economy of the Tulsa
MSA and the economy of the State of Oklahoma is unknown at this time, and
for the next 3-5 years; and,
4. An appropriate and acceptable estimate of the impact of the proposed
merger on the economy of the Tulsa MSA and the economy of the State of
Oklahoma can be made by either the University of Oklahoma or Oklahoma
State University, using state level economic modeling tools already
available to those institutions.
Based on these conclusions, Dr. Zimmerman testified that Staff recommends
the Commission approve the proposed merger only if the hold harmless provisions
outlined in Mr. Crosslin's testimony are agreed to by the Applicants. Dr.
Zimmerman testified that these hold harmless provisions are essential to protect
the public interest relative to a proposed merger that has so many uncertainties
and potential impacts for Oklahoma. In addition, Staff recommends that the
Commission order the Applicants to:
1. Perform more extensive PROMOD analyses to assess any possible
operational benefits of the merger for PSO's customers; and,
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2. Perform ongoing analyses to assess the impact of the merger on the
economy of Tulsa MSA and the State, in conjunction with the University of
Oklahoma or Oklahoma State University if possible.
Dr. Zimmerman testified in an in camera proceeding on April 21, 1999, that
the Applicants voluntarily had Oklahoma State University perform an analysis to
assess the impact of the merger on the economy of Tulsa County, Oklahoma. He
further testified regarding the results of the analysis. Dr. Zimmerman's
testimony presented in the in camera proceeding on April 21, 1999, is under
seal. His conclusions, however, are that additional PROMOD analyses are not
needed due to information received in discovery. The economic impact of the
merger is not fully known at this time. However, even a worst case scenario
would not be a significant adverse economic impact on Tulsa County, considering
the size of Tulsa County economy. Dr. Zimmerman's pre-filed testimony was
accepted into the record as Exhibit Number 59 without objection or
cross-examination.
FINDINGS OF FACT AND CONCLUSIONS OF LAW
The ALJ finds that this Commission has jurisdiction over the merger
pursuant to 17 O.S. Section 191.1 et seq. and OAC 165:5-7-57. Further, the ALJ
finds this Commission has jurisdiction over Public Service Company of Oklahoma
regarding retail rates and the effect that the merger might have on those rates
pursuant to 17 O.S. Section 152, 153 and Okla. Const. Art. 9, Section 18.
The conditions for disapproval of a merger are set forth at 17 O.S.
Section 191.5, and require the merger be approved unless one of the conditions
contained within the statute would exist if the merger is consummated. The
Stipulation reached by the Joint Applicants, Staff, CSD, and the AG, which sets
forth various hold harmless provisions, guaranteed rate reductions, guaranteed a
base rate increase moratorium, quality of service standards and a most favored
nations clause, satisfies the majority of the statutory standards. The primary
areas of inquiry raised by Intervenor OG&E and others, relating to whether the
merger would lessen competition
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in the furnishing of public utility service in the state, is negated by the
Joint Applicants' commitment to engage in joint planning and the involvement of
the Southwest Power Pool.
The evidence tends to show that market power will indeed be impacted in
Oklahoma and competition harmed because of the impact of the merger on the
transmission system at the Ft. Smith transformer which may result in line losses
and congestion.
The evidence also tends to show that the Southwest Power Pool did not list
this area of transmission (OG&E's Ft. Smith transformer) as a problem in its
seasonal studies and OG&E has no plans for any upgrades for the next five years.
The ALJ further finds that the Commission should direct PSO and OG&E to
request the Southwest Power Pool to evaluate and identify the impact on the
transmission import capability into Oklahoma at the Ft. Smith 161/500 MCA
Transformer of the 250 MW transfer of power from AEP to CSW across the Ameren
system and to identify what, if any, corrective action should be taken to return
the Oklahoma transmission system to pre-merger condition.
The ALJ further finds that the Commission should require that, after the
Southwest Power Pool has made its determination, the Joint Applicants be
required to reimburse OG&E for the proportionate share that the Joint Applicants
contribute to any problem found to exist on the Oklahoma transmission system by
making such transfers recognizing that some part of the problems caused by the
merger already exist at the Ft. Smith substation that has resulted in outages
and congestion.
The ALJ further finds that authority over the alleged line loss issue lies
with the Federal Energy Regulatory Commission.
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RECOMMENDATION
After careful consideration of the testimony and the Stipulation, the ALJ
recommends that the Commission issue an order approving the merger based upon
the conditions set forth herein:
The ALJ further recommends that the Commission issue an order approving
the Stipulation as being fair, just and reasonable.
The ALJ further recommends that the Commission direct PSO and OG&E to
request the Southwest Power Pool to evaluate the impact on OG&E's Fort Smith
161/500 MVA transformer of a 250 MW transfer of power from AEP to CSW across the
Ameren system and identify what, if any, corrective action should be taken.
The ALJ further recommends that the Commission require that, after the
Southwest Power Pool has made its determination, the Joint Applicants be
required to reimburse OG&E for the proportionate share that the Joint Applicants
contribute to any problem found to exist at the Fort Smith substation by making
such transfers, recognizing that a problem already exists at the Fort Smith
substation that has resulted in outages and congestion.
The ALJ further recommends that the Commission direct the Joint Applicants
to report the results of the Southwest Power Pool evaluation to the Director of
the Public Utility Division of the Oklahoma Corporation Commission no later than
June 14, 1999.
The ALJ further recommends that the Commission issue an order stating that
the Commission lacks jurisdiction to address the question of line loss
reimbursement based upon the facts presented in this Cause.
71
<PAGE> 80
DATED this 4th day of May, 1999
/s/ ROBERT E. GOLDFIELD
Administrative Law Judge
72
<PAGE> 81
BEFORE THE CORPORATION COMMISSION OF THE STATE OF OKLAHOMA
JOINT APPLICATION OF AMERICAN )
ELECTRIC POWER COMPANY, INC., )
PUBLIC SERVICE COMPANY OF ) CAUSE NO. PUD 980000444
OKLAHOMA AND CENTRAL AND SOUTH )
WEST CORPORATION REGARDING )
PROPOSED MERGER )
STIPULATION
The parties to this Stipulation, dated as of April 16, 1999, are the
Public Utility Division (Staff) and the Consumer Services Division (CSD) of the
Oklahoma Corporation Commission (OCC or Commission); American Electric Power
Company, Inc. (AEP); Central and South West Corporation (CSW); Public Service
Company of Oklahoma or any successor (PSO); and, the Attorney General of the
State of Oklahoma (Attorney General). The foregoing parties to this cause shall
be referred to individually either as a Signatory or by the acronym assigned
above, and collectively as the Signatories. The Signatories submit this
Stipulation to the Commission as representing a just and reasonable disposition
of the issues addressed in this Stipulation; the Signatories request approval of
this Stipulation and entry of an order consistent with this Stipulation.
The Signatories stipulate and agree as follows:
STATEMENT OF SIGNATORIES' INTENT
The purpose of the plan is to distribute net merger savings through a
credit rider to retail ratepayers. The minimum life of the credit rider is five
years. It is the intention of the Signatories to this Stipulation that, at a
minimum, a five-year plan be implemented. The costs to achieve the merger
incurred prior to the end of the first two years after the effective date of the
merger will be deferred and amortized. These costs are to be amortized during
the five-year period after the
<PAGE> 82
effective date of the merger. If a general rate change proceeding changes PSO's
base rates within the first five years after the effective date of the merger,
the shareholder savings imputation shall be used and the credit rider will
continue regardless of any changes to base rates. If a general rate change
proceeding changes PSO's base rates after the first five years after the
effective date of the merger, no shareholder savings imputations or deferred
costs to achieve amortization shall be used and the credit rider shall terminate
upon the implementation of new base rates. The Applicants commit to hold PSO
Oklahoma retail customers harmless from adverse impacts of the merger. PSO
commits not to seek a general base rate change prior to January 1, 2003. If PSO
seeks a general rate change from January 1, 2003 through the fifth year
anniversary of the effective date of the merger, the Applicants agree to a
$5,000,000 reduction to PSO's revenue requirement as otherwise determined by the
Commission. The parties acknowledge that there may be changes in the number of
Central and South West Services, Inc. (CSWS) or PSO employees located within
Oklahoma as a result of this merger and the level of such changes have not been
finally determined. The economic impacts of this merger are not addressed in
this partial Stipulation and remain unresolved. It is the intent of the
Signatories that all five attachments to this Stipulation be incorporated as if
set forth fully herein.
SECTION 1. NON-OPPOSITION TO MERGER.
Both the Staff and the Attorney General acknowledge that they will not
oppose the merger as to the issues stipulated herein before the Federal Energy
Regulatory Commission (FERC). Further, the Staff recommends that the Commission
file a position statement in consolidated FERC Docket Nos. EC98-40-000;
ER98-2770-000; and ER98-2786-000 indicating that it does not oppose the merger.
The Staff reserves the right to litigate before FERC the impact of the merger
upon the transmission system in Oklahoma, which includes the impact of the
merger upon other
2
<PAGE> 83
Oklahoma jurisdictional utilities and also includes the impact of potential line
losses and potential increased congestion within Oklahoma.
SECTION 2. THE PROPOSED PLAN.
This Stipulation has been developed to ensure that Oklahoma retail
customers of PSO receive the benefits of the merger. The proposed plan set forth
below is reasonable and in the public interest.
SECTION 3. SHARING OF NET NON-FUEL AND NON-PURCHASED POWER OPERATION
AND MAINTENANCE EXPENSE SAVINGS.
(a) PSO will implement a net merger savings (net of costs to achieve
the merger as defined in Section 3(b)) rider in Oklahoma that will reduce rates
to customers by the annual amount shown in Attachment 1 beginning with the first
revenue month after the effective date of the merger. Each individual year's
rate reduction will apply for a twelve month period as presented in Attachment
1, with a $9,409,000 annual reduction to be applied in each of the years
following the end of the fifth year until new base rates for PSO become
effective pursuant to a general rate change proceeding.(1) At the end of the
five-year period, deferred costs to achieve amortization and shareholder savings
imputations as addressed in Section 3(c) shall terminate.
(b) Costs to achieve the merger ("costs to achieve") are those costs
reasonably and prudently incurred within the first two years after the effective
date of the close of the merger in order 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; systems integration costs;
operations integration costs including
- ----------
(1) The Signatories' understanding for the purpose of this Stipulation of what
constitutes a general rate change proceeding is one in which the overall
non-fuel base revenue requirements of the company are revised.
3
<PAGE> 84
telecommunication costs; and facilities consolidation costs. The costs to
achieve are to be recovered through merger savings. For Oklahoma retail
jurisdictional ratemaking purposes, PSO will defer the lesser of estimated or
actual costs to achieve incurred prior to the end of two years after the
effective date of the merger. These deferred costs will be amortized over a
five-year period beginning with the effective date of the merger. The amortized
costs for each year shall be proportionate to the aggregate estimated merger
savings for the corresponding year as seen in Attachment 1.
Applicants shall credit the customer via an allocation methodology that
allocates the net merger savings according to Attachment 2.
(c) If changes in base rates of PSO, pursuant to a general rate change
proceeding, occur within the first five years after the effective date of the
merger, the following rate treatments shall be reflected:
(1) Estimated non-fuel operation and maintenance expense merger
savings net of 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.
(2) Amortization of 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. The
unamortized balance of costs to achieve will not be included
in rate base and no return will be allowed on the unamortized
balance of costs to achieve.
(3) The merger savings rate reduction rider as described in
Paragraph (a) above shall continue.
(4) The Applicants shall have the burden of proof to show that
they have substantially achieved the estimated level of merger
savings as shown in Attachment 1. If the Applicants cannot
demonstrate in any general rate change proceeding initiated
within the first five years after the effective date of the
merger, that they have substantially achieved the estimated
merger savings, then the shareholders' portion of net merger
savings (as shown in Attachment 1) shall not be included as a
cost of service expense.
(5) Attachment 3 is an example of the retail base rate treatment
described in this subsection.
4
<PAGE> 85
(d) For each year following the end of the fifth year after the
effective date of the merger, a $9,409,000 annual reduction will be reflected in
the net merger savings rate reduction rider. In any retail base rate change
proceeding after the fifth year after the effective date of the merger, the
following rate treatments will be reflected:
(1) No estimated non-fuel operation and maintenance expense merger
savings will be included in cost of service as an allowable
expense.
(2) No amortization of costs to achieve will be included as an
allowable expense.
(3) The merger savings rate reduction rider will cease upon the
effective date of the new base rates.
(e) In the event the electric utility industry in Oklahoma is
restructured prior to the end of the fifth year after the effective date of the
merger, the then effective rider benefits, as described above in Section 3, and
costs to achieve amortization pursuant to Section 3(b) shall be deemed
applicable in their entirety to the rates of the unbundled services that remain
regulated by the Commission. The costs to achieve amortization and rider
benefits shall continue in full, and remain unaltered, for the five-year term,
except in the case of a general rate change proceeding initiated by a party
other than PSO.
(f) In the event of any general rate change proceeding initiated by a
party other than PSO subsequent to industry restructuring and prior to the end
of the fifth year, the rider benefits, cost amortization, and shareholder net
savings imputation shall be reduced proportionate to the rates of regulated
unbundled services. It is the intent of the Signatories that the cost
amortization, net merger savings rider, and shareholder savings amputations
continue for the five-year term for those services subject to continued
regulation by the State of Oklahoma. It is also the intent of the Signatories
that the benefits would continue for the period of time in which the net merger
savings rider set forth in Section 3 above remains in effect for those services
subject to continued regulation by the State of Oklahoma.
5
<PAGE> 86
SECTION 4. SHARING OF FUEL AND PURCHASED POWER EXPENSE SAVINGS.
After the effective date of the merger, all jurisdictional fuel and
purchased power expense savings resulting from the merger shall accrue to the
benefit of the retail customers through the existing fuel cost recovery
mechanism.
SECTION 5. ACCESS TO BOOKS AND RECORDS.
The Applicants agree that subject to regulatory authority, the OCC and
Attorney General will either have access in Oklahoma to copies of 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 or AEP will pay reasonable and prudently
incurred travel expenses to conduct on-site review of books and records. The OCC
and Attorney General will have access to the books and records of PSO to the
degree required to fully audit, examine, or otherwise investigate transactions
between PSO and AEP affiliates.
SECTION 6. AGREEMENT REGARDING STRANDED INVESTMENT.
The Applicants commit and agree that stranded costs, if any, that PSO
may seek to recover will be on a stand-alone basis, and will be limited to the
ownership-interest of PSO's assets and obligations. PSO does not have any
stranded costs under current Oklahoma regulation. The merger by itself does not
create stranded costs.
SECTION 7. MITIGATION.
To mitigate any perceived impacts of the merger on the Applicants'
market power, the Applicants have proposed in their FERC merger application a
mitigation plan which includes the following:
(1) Divestiture of 300 megawatts of coal-fired generating capacity
at the Northeastern generating plant after such plant is no
longer required to meet PSO's native load demand requirements
subsequent to industry restructuring in Oklahoma.
6
<PAGE> 87
(2) Sale of 300 megawatts per hour of energy on an interim basis
prior to the divestiture of the Northeastern capacity.
(3) Waiver of PSO's priority to the use of CSW interfaces with
other transmission systems to import centrally dispatched
energy from the existing AEP system in excess of 250
megawatts.
(4) Waiver of PSO's priority to the use of CSW interfaces to
import non-firm energy from non-affiliates.
(5) Schedule CSW's use of the two high voltage direct current
(HVDC) ties between ERCOT and the SPP on a first-in-time basis
for certain transactions.
The Applicants commit to hold PSO Oklahoma retail customers harmless
from adverse impacts from these transactions. Attachment 4 to this agreement
describes the methodology that the Applicants will follow in order to hold PSO
Oklahoma retail customers harmless from adverse effects of the interim
mitigation sale.
The Applicants' market power mitigation plan is reasonable and is
subject to approval at the FERC. To the extent that the market power mitigation
plan is modified by a final order of the FERC, the Applicants will inform the
Commission and the Attorney General of such modifications. The Applicants shall
make a filing with the Commission to address such modification, so as to ensure
that Oklahoma PSO retail customers are held harmless from adverse effects of
such plan, and quantify and determine the regulatory treatment of gains, if any.
SECTION 8. BASE RATE MORATORIUM.
Applicants will commit not to seek a base rate increase over base rates
as of the date of this Stipulation, subject to major Force Majeure provisions
set forth below, which would become effective prior to January 1, 2003. If a
rate review is sought by the Applicants after January 1, 2003 through the end of
the fifth year after the effective date of the merger, the Applicants shall make
a $5,000,000 reduction to the revenue requirement otherwise determined by the
Commission to be reasonable.
7
<PAGE> 88
SECTION 9. FORCE MAJEURE.
Prior to January 1, 2003, if Force Majeure or events beyond the
influence and/or control of PSO occur, including Oklahoma legislative action
regarding industry restructuring or unbundling, PSO shall be entitled to file
for a general rate review pursuant to OAC 165:70 and in such case, PSO will have
the burden of proving (1) that its request for relief is a good faith request,
(2) that the event or occurrence was not directly or indirectly caused by PSO,
(3) the event or occurrence has at least an annual impact of $6,000,000 and (4)
that PSO had no direct or indirect control over the event or occurrence. The
Signatories will have the right to challenge PSO's request for rate relief. In
any rate proceeding pursuant to this Section, merger costs and savings will be
treated in accordance with Section 3.
SECTION 10. REGULATORY AUTHORITY.
Applicants agree not to assert in proceedings before this Commission,
or in court proceedings related to this Commission, that the authority of the
Securities and Exchange Commission ("SEC") as interpreted in Ohio Power v. FERC,
554 F.2d 779 (D.C. Cir. 1992.) cert. denied, 498 U.S. 73 (1992) impairs the
Oklahoma Corporation Commission's ability to examine the reasonableness of
non-power affiliate costs to be passed to PSO's retail customers. The parties
agree that the Ohio Power waiver does not include waiver of any arguments that
AEP/CSW may have with respect to the reasonableness of SEC approved cost
allocations, as opposed to the reasonableness of the costs themselves.
SECTION 11. CAPITAL COSTS.
The Applicants commit and agree that the cost of capital as reflected
in PSO's rates shall not be adversely affected by the result of AEP's
acquisition of CSW. The Applicants al so agree that subsequent to the completion
of the merger, the cost of capital from PSO should be set commensurate with the
risk of PSO and should not be affected by the merger. Applicants agree
8
<PAGE> 89
that they will not oppose, in either a regulatory proceeding or an appeal of a
decision by the OCC, the application of the principal that the determination of
the cost of capital can be based on the risk attendant to the regulated
operations of PSO.
SECTION 12. QUALITY OF SERVICE.
The Applicants agree to the quality of service standards set forth in
Attachment 5.
SECTION 13. MOST FAVORED NATIONS.
The Applicants 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 customers of any jurisdiction or imposing any conditions on Applicants that
would benefit the customers of any jurisdiction, such net benefits and
conditions will be extended to PSO Oklahoma retail customers to the extent
necessary to achieve equivalent net benefits and conditions to the Oklahoma PSO
retail customers, provided the proposed merger is ultimately consummated. Joint
Applicants will provide to the director of the Public Utility Division and the
Attorney General any final and non-appealable order from the FERC, SEC, or any
state or federal commission addressing the merger, through stipulation or
otherwise.
SECTION 14. MERGER SAVINGS HOLD HARMLESS CONDITIONS.
The Applicants agree to hold harmless the retail customers of PSO from
unforeseen events that materially diminish the estimated benefits of the merger
and from major deviations from the Applicants' stated representations of
estimated merger benefits as reflected in Column 5 of Attachment 1 in
calculating the benefits to flow to retail customers.
SECTION 15. COST RECOVERY.
If the merger is not consummated, the Applicants commit and agree not
to seek to recover transition or transaction costs, or termination fees,
including but not limited to the "Out of Pocket"
9
<PAGE> 90
and "Topping Out" fees associated with the merger described in Sections 9.5 and
9.6 of the Agreement and Plan of Merger By and Among American Electric Power
Company, Inc., Augusta Acquisition Corporation and Central and South West
Corporation dated December 21, 1997 (Merger Agreement) and further commit and
agree not to seek to recover fees related to the merger that may be charged by
Morgan Stanley.
SECTION 16. NON-RECOURSE PROVISION.
A PSO affiliate may not incur debt or pledge the stock of PSO in a
manner that, on the affiliate's default, would permit a creditor to have
recourse against the regulated assets of PSO.
SECTION 17. REGIONAL TRANSMISSION ORGANIZATION.
The Applicants offer the following as a condition to approval of the
merger:
Prior to the later of six months prior to retail customer choice, or
December 31, 2001, the Applicants agree that AEP will file with the FERC an
unconditional application to, consistent with the RTO agreement, transfer the
operational control of bulk transmission facilities owned, controlled and/or
operated by AEP currently located in the Southwest Power Pool to a FERC-approved
Regional Transmission Organization directly interconnected with the AEP
transmission facilities. The above date shall be extended, if necessary, to 75
days after FERC issues the order on an RTO to which AEP is a signatory that is
filed before June 30, 2001. Notwithstanding any other provision of this
agreement, the Joint Applicants will not be precluded from seeking recovery of
costs required to implement a Regional Transmission Organization.
SECTION 18. NOTICE OF CLOSING.
AEP shall notify the parties of the date the merger closes promptly
after the closing occurs. This notice shall be sent to the parties in care of
their respective attorneys of record at the addresses shown on the service list
in this docket.
10
<PAGE> 91
SECTION 19. SUPPORT OF STIPULATION AND EFFECT OF MODIFICATION OF
STIPULATION.
The Signatories shall recommend that the Commission enter an order
consistent with this stipulation in all material respects. If the Commission
enters an order inconsistent with this stipulation, any Signatory may withdraw
its consent to this Stipulation, and the withdrawing Signatory's agreement to
this Stipulation shall be extinguished. The withdrawing Signatory shall not be
deemed to have in any way waived or compromised any right to urge that a
different result, methodology, or position be required by law or the facts.
The Signatories agree that the provisions of this Stipulation are the
result of extensive negotiations and that the terms and conditions of this
Stipulation are interdependent. The Signatories agree that settling the issues
in this Stipulation is in the public interest, and, for this reason, they have
entered into this Stipulation to resolve among themselves the issues in this
Stipulation. This Stipulation is a compromise and settlement among the
Signatories, and no Signatory is bound beyond its obligation to support this
Stipulation. This Stipulation shall not constitute nor be cited as precedent or
deemed an admission by any Signatory in any other proceeding except as necessary
to enforce its terms before the Commission or any state court of competent
jurisdiction. The Commission's decision, if it enters an order consistent with
this Stipulation, will be binding as to the matters decided regarding the issues
described in this Stipulation, but the decision will not be binding with respect
to similar merger plans that might arise in other proceedings. A Signatory's
support of this Stipulation may differ from its position or testimony in other
causes. To the extent there is a difference, the Signatories are not waiving
their positions in other causes. Because this is a stipulated agreement, the
Signatories are under no obligation to take the same positions as set out in
this Stipulation in other dockets.
11
<PAGE> 92
Fully and duly authorized representatives of the Signatories have
signed this Stipulation as of the date first set forth above.
GENERAL COUNSEL FOR THE PUBLIC UTILITY
DIVISION OF THE OKLAHOMA CORPORATION
COMMISSION
By: /s/ Deborah Jacobson
COUNSEL FOR THE CONSUMER SERVICES DIVISION
OF THE OKLAHOMA CORPORATION COMMISSION
By: /s/ Marchi McCartney
COUNSEL FOR THE OFFICE OF THE ATTORNEY
GENERAL OF THE STATE OF OKLAHOMA
By: /s/ Deborah R. Morgan
COUNSEL FOR AMERICAN ELECTRIC POWER COMPANY,
INC.
By: /s/ Cody L. Graves
COUNSEL FOR CENTRAL AND SOUTH WEST
CORPORATION AND PUBLIC SERVICE COMPANY OF
OKLAHOMA
By: /s/ Jack P. Fite
12
<PAGE> 93
Attachment 1
AEP/CSW MERGER
NET ANNUAL MERGER SAVINGS
AND OKLAHOMA CUSTOMER RATE REDUCTIONS ($000)
<TABLE>
<CAPTION>
(1) (2) (3) (4) (5) (6)
Costs to
Gross Merger Achieve Net Merger Customer Rate Shareholder
Period Savings the Merger Savings Reduction* Savings
------ ------- ---------- ------- ---------- -------
<S> <C> <C> <C> <C> <C>
Year 1..................... 8,255 2,524 5,731 3,179 2,552
Year 2..................... 12,648 3,868 8,780 4,871 3,909
Year 3..................... 15,264 4,668 10,596 5,878 4,718
Year 4..................... 17,355 5,307 12,048 6,684 5,364
Year 5..................... 18,817 5,754 13,063 7,247 5,816
72,339 22,121 50,218 27,859 22,359
Percent of Net Savings..... 55.5% 44.5%
</TABLE>
- -------------
* The amount of customer rate reduction to be used after Year 5 and which
will continue until the effective date of the first base rate change
after Year 5 is $9,409.
1
<PAGE> 94
Attachment 2
PUBLIC SERVICE COMPANY OF OKLAHOMA
Net Merger Savings Rate Reduction
Percentage Allocation of Merger Savings to Rate Class
<TABLE>
<CAPTION>
OCC PUD
960000214
PROPOSED BASE % OF CLASS SAVINGS
RATE CODE NON-FUEL REVENUES NON-FUEL REV SPREAD
----------------
<S> <C> <C> <C> <C> <C>
RESIDENTIAL
1 Residential LURS 120 $5,885,299 3.420% 1.710%
2 Residential GCLURS 125 319,841 0.186% 0.093%
3 Residential RS 140 151,429,153 88.002% 44.001%
4 Residential GCRS 150 14,439,411 8.391% 4.196%
------------------------------------------------------- --------------------- ----------------- --------------
5 TOTAL RESIDENTIAL 172,073,704 100.000% 50.000%
------------------------------------------------------- --------------------- ----------------- --------------
COMMERCIAL & INDUSTRIAL SER. LEVEL 5
6 C & I SL5 LUGS 575, 675, 676 33,019,230 29.439% 8.243%
7 C & I SL5 GS 5 680, 651, 685, 686, 2660 65,581,934 58,471% 16.372%
8 C & I SL5 PL5 550, 560, 650, 651, 655, 656, 2650 12,453,658 11.103% 3.109%
9 C & I SL5 GSTOD 750 157,856 0.141% 0.039%
10 C & I SL5 MP 835, 836, 837 592,526 0.528% 0.148%
11 C & I SL5 UMS 435, 436, 444 356,569 0.318% 0.069%
------------------------------------------------------- --------------------- ----------------- --------------
12 TOTAL COMMERCIAL & INDUSTRIAL SER. 112,161,773 100.000% 28.000%
LEVEL 5
------------------------------------------------------- --------------------- ----------------- --------------
COMMERCIAL & INDUSTRIAL SER. LEVEL 4
13 C & I SL4 GS 680 3,493,596 58.842% 0.941%
14 C & I SL4 PL 640 2,337,453 39.370% 0.630%
15 C & I SL4 LUGS 574, 674 106,151 1.788% 0.029%
16 C & I SL4 GS TOD 740 0 0.000% 0.000%
------------------------------------------------------- --------------------- ----------------- --------------
17 TOTAL COMMERCIAL & INDUSTRIAL SER. 5,937,200 100.000% 1.600%
LEVEL 4
------------------------------------------------------- --------------------- ----------------- --------------
COMMERCIAL & INDUSTRIAL SER. LEVEL 3
------------------------------------------------------- --------------------- ----------------- --------------
18 C & I SL 3 LPL 630, 632, 635, 637, 2630, 2635 25,665,299 100.000% 8.000%
------------------------------------------------------- --------------------- ----------------- --------------
COMMERCIAL & INDUSTRIAL SER. LEVEL 2
------------------------------------------------------- --------------------- ----------------- --------------
19 C & I SL2 LPL 620, 625, 2620, 2625 22,875,147 100.000% 10.000%
------------------------------------------------------- --------------------- ----------------- --------------
COMMERCIAL & INDUSTRIAL SER. LEVEL 1
------------------------------------------------------- --------------------- ----------------- --------------
20 C & I SL1 LPL 612, 617, 2612 2617 3,559,629 100.000% 1.800%
------------------------------------------------------- --------------------- ----------------- --------------
LIGHTING
21 Lighting GSL 833-834 4,660 0.078% 0.000%
22 Lighting OL 320-325 334,335 5.631% 0.034%
23 Lighting SL 310, 311, 330, 340, 360 4,838,557 81.498% 0.489%
24 Lighting MSL 830-832 759,466 12,792% 0.077%
------------------------------------------------------- --------------------- ----------------- --------------
25 TOTAL LIGHTING 5,937,018 100.000% 0.600%
------------------------------------------------------- --------------------- ----------------- --------------
------------------------------------------------------- --------------------- ----------------- --------------
26 TOTAL RETAIL 348,209,770 100.000%
------------------------------------------------------- --------------------- ----------------- --------------
</TABLE>
1
<PAGE> 95
PUBLIC SERVICE COMPANY OF OKLAHOMA
Net Merger Savings Rate Reduction
Percentage Allocation of Merger Savings to Rate Class
<TABLE>
<CAPTION>
Year 1 Year 2 Year 3 Year 4
---------------- --------------- ---------------- ----------------
Annual Savings Annual Savings Annual Savings Annual Savings
Rate Code $3,179,000 $4,871,000 $6,878,000 $6,664,000
----------------
<S> <C> <C> <C> <C> <C> <C>
RESIDENTIAL
1 Residential LURS 120 $ 54,364 $ 83,299 $ 100,520 $ 114,384
2 Residential GCLURS 125 2,954 4,527 5,463 6,212
3 Residential RS 140 1,398,800 2,143,301 2,506,393 2,941,043
4 Residential GCRS 150 133,381 264,373 246,624 200,441
---------------------------------------- ---------------- --------------- ---------------- ----------------
5 TOTAL RESIDENTIAL 1,589,500 2,435,500 2,939,000 3,342,000
---------------------------------------- ---------------- --------------- ---------------- ----------------
COMMERCIAL & INDUSTRIAL SER. LEVEL 5
6 C & I SL5 LUGS 575, 675, 676, 262,842 401,512 484,518 550,956
680
7 C & I SL5 GS 5 681, 685, 686.
2660 520,441 797,472 962,337 1,094,294
8 C & I SL5 PL5 550, 560, 650,
651, 655, 656, 98,833 151,436 183,743 207,800
2650
9 C & I SL5 GSTOD 750 1,253 1,920 2,316 2,634
10 C & I SL5 MP 835, 836, 837 4,702 7,203 8,095 9,087
11 C & I SL5 UMS 435, 426, 444 2,830 4,336 5,232 5,990
---------------------------------------- ---------------- --------------- ---------------- ----------------
12 TOTAL COMMERCIAL & INDUSTRIAL SER. 80,120 1,363,000 1,645,840 1,871,520
LEVEL 5
---------------------------------------- ---------------- --------------- ---------------- ----------------
COMMERCIAL & INDUSTRIAL SER. LEVEL 4 0 0 0 0
13 C & I SL4 GS 680 29,930 43,859 35,340 62,929
14 C & I SL4 PL 640 20,025 30,083 37,826 42,163
15 C & I SL4 LUGS 574, 674 909 1,393 1,681 1,912
16 C & I SL4 GS TOD 740 0 0 0 0
---------------------------------------- ---------------- --------------- ---------------- ----------------
17 TOTAL COMMERCIAL & INDUSTRIAL SER. 90,864 77,936 94,848 106,944
LEVEL 4
---------------------------------------- ---------------- --------------- ---------------- ----------------
COMMERCIAL & INDUSTRIAL SER. LEVEL 3
---------------------------------------- ---------------- --------------- ---------------- ----------------
18 C & I SL 3 LPL 630, 632, 635,
637, 2630, 2635 234,320 389,600 470,240 534,720
---------------------------------------- ---------------- --------------- ---------------- ----------------
COMMERCIAL & INDUSTRIAL SER. LEVEL 2
---------------------------------------- ---------------- --------------- ---------------- ----------------
19 C & I SL2 LPL 620, 625, 2620,
2625 317,980 487,100 587,800 608,400
---------------------------------------- ---------------- --------------- ---------------- ----------------
COMMERCIAL & INDUSTRIAL SER. LEVEL 1
---------------------------------------- ---------------- --------------- ---------------- ----------------
20 C & I SL1 LPL 617, 617, 2812,
2617 57,222 87,678 105,884 120,312
---------------------------------------- ---------------- --------------- ---------------- ----------------
LIGHTING
21 Lighting GSL 833-834 15 23 28 31
22 Lighting OL 320-325 1,074 1,646 1,986 2,258
23 Lighting SL 310-311, 330, 15,545 23,819 28,743 32,084
340, 360
24 Lighting MSL 830-832 2,440 3,739 4,511 5,130
---------------------------------------- ---------------- --------------- ---------------- ----------------
25 TOTAL LIGHTING 19,074 29,226 35,268 40,104
---------------------------------------- ---------------- --------------- ---------------- ----------------
---------------------------------------- ---------------- --------------- ---------------- ----------------
26 TOTAL RETAIL 3,179,000 4,871,000 5,878,000 6,684,000
---------------------------------------- ---------------- --------------- ---------------- ----------------
Year 5 Total Rev. Year 6
--------------- ---------------- ----------------
Annual Savings 6 Yr Savings Annual Savings
Rate Code $7,247,000 $27,808,000 $9,409,000
----------------
<S> <C> <C> <C> <C> <C>
RESIDENTIAL
1 Residential LURS 120 $ 123,932 $ 476,420 $ 168,984
2 Residential GCLURS 125 6,735 25,891 8,744
3 Residential RS 140 3,196,770 12,298,308 4,140,077
4 Residential GCRS 150 304,863 1,168,882 394,774
---------------------------------------- --------------- ---------------- ----------------
5 TOTAL RESIDENTIAL 3,623,500 13,929,500 4,704,500
---------------------------------------- --------------- ---------------- ----------------
COMMERCIAL & INDUSTRIAL SER. LEVEL 5
6 C & I SL5 LUGS 575, 675, 676, 597,363 2,296,390 775,575
680
7 C & I SL5 GS 5 681, 685, 686.
2660 1,186,467 4,561,000 1,540,426
8 C & I SL5 PL5 550, 560, 650,
651, 655, 656, 225,304 866,115 292,519
2650
9 C & I SL5 GSTOD 750 2,856 10,978 3,706
10 C & I SL5 MP 835, 836, 837 10,720 41,288 13,918
11 C & I SL5 UMS 435, 426, 444 6,451 24,798 8,375
---------------------------------------- --------------- ---------------- ----------------
12 TOTAL COMMERCIAL & INDUSTRIAL SER. 2,829,100 7,800,520 2,634,520
LEVEL 5
---------------------------------------- --------------- ---------------- ----------------
COMMERCIAL & INDUSTRIAL SER. LEVEL 4 0 0 0
13 C & I SL4 GS 680 68,229 262,287 88,504
14 C & I SL4 PL 640 45,658 173,488 99,200
15 C & I SL4 LUGS 574, 674 2,073 7,989 2,002
16 C & I SL4 GS TOD 740 0 0 0
---------------------------------------- --------------- ---------------- ----------------
17 TOTAL COMMERCIAL & INDUSTRIAL SER. 115,952 445,744 150,544
LEVEL 4
---------------------------------------- --------------- ---------------- ----------------
COMMERCIAL & INDUSTRIAL SER. LEVEL 3
---------------------------------------- --------------- ---------------- ----------------
18 C & I SL 3 LPL 630, 632, 635,
637, 2630, 2635 579,760 2,228,720 732,720
---------------------------------------- --------------- ---------------- ----------------
COMMERCIAL & INDUSTRIAL SER. LEVEL 2
---------------------------------------- --------------- ---------------- ----------------
19 C & I SL2 LPL 620, 625, 2620,
2625 724,700 2,785,900 948,980
---------------------------------------- --------------- ---------------- ----------------
COMMERCIAL & INDUSTRIAL SER. LEVEL 1
---------------------------------------- --------------- ---------------- ----------------
20 C & I SL1 LPL 617, 617, 2812,
2617 130,446 501,462 109,362
---------------------------------------- --------------- ---------------- ----------------
LIGHTING
21 Lighting GSL 833-834 34 131 44
22 Lighting OL 320-325 2,449 9,413 3,179
23 Lighting SL 310-311, 330, 35,437 136,227 46,009
340, 360
24 Lighting MSL 830-832 5,562 21,382 7,222
---------------------------------------- --------------- ---------------- ----------------
25 TOTAL LIGHTING 43,482 167,154 56,454
---------------------------------------- --------------- ---------------- ----------------
---------------------------------------- --------------- ---------------- ----------------
26 TOTAL RETAIL 7,247,000 27,859,000 9,409,000
---------------------------------------- --------------- ---------------- ----------------
</TABLE>
2
<PAGE> 96
Attachment 3
AEP/CSW MERGER
EXAMPLE OF BASE RATE CASE TREATMENT
BASED ON YEAR 3 ($000)
<TABLE>
<CAPTION>
<S> <C> <C> <C>
CREDIT PER RIDER CONTINUES (5,878)
INCLUDED IN TEST YEAR:
GROSS MERGER SAVINGS (15,264)
CHANGE IN CONTROL AMORTIZATION 1,160
OTHER CTA AMORTIZATION 3,508
----------------
TOTAL CTA AMORTIZATION 4,668
-----------------
NET MERGER SAVINGS IN TEST YEAR (10,596)
ADD BACK TO TEST YEAR COST OF SERVICE:
CUSTOMER SHARE (Attachment A1- Year 3, Col. 5) 5,878
SHAREHOLDER PORTION (Attachment A1- Year 3, Col. 6) 4,718
----------------
10,596
-----------------
NET RATE REDUCTION 0
---------------
OKLAHOMA CUSTOMER RATE REDUCTION (5,878)
===============
</TABLE>
1
<PAGE> 97
Attachment 4
MITIGATION SALE HOLD HARMLESS METHODOLOGY
The following describes the methodology proposed by the Applicants to account
for the margins from the Market Mitigation Sale in order to meet the Hold
Harmless provisions of the agreements between the Applicants and the Arkansas,
Louisiana and Oklahoma commissions.
Applicants will do an "after the fact" calculation, using actual hourly data, to
reconstruct the dispatch and determine margins from the mitigation sale. This
calculation will be referred to as the Regulatory Mitigation Reconstruction
(RMR). The RMR will not alter the methodology currently used by CSW under the
CSW Operating Agreement to account for transactions by and between the CSW
Operating Companies. The RMR will be used to determine if the mitigation sale
resulted in negative margins, which should not be included in the retail
customer eligible fuel and provide the mechanism by which the Applicants will
ensure that retail customers are held harmless from this sale. The RMR will
calculate the margins on a monthly basis, and any margins above credits to
eligible fuel will be calculated and deferred monthly and refunded annually such
that customers are protected from any negative margins on an annual basis.
The RMR will reconstruct the dispatch on a hourly basis using the installed
generation capacity owned by the CSW Operating Companies (both off-line and
on-line) plus the firm annual purchases included in CSW's CDR. The purchases
will be used as dispatchable resources at the price incurred in that hour. (Firm
annual purchases will be modeled as a reduction in load. Because the purchase
expense and the MW amount are held constant in both production cost cases, the
model ignores the purchase price for the firm annual purchases.) The generation
resources will be economically dispatched to serve the actual hourly load
included in the CSW Internal Economy dispatch level of the CSW Interchange Cost
Reconstruction (ICR). The program will determine the cost of production for the
level of dispatch referred as the Own Load Production Cost. The Mitigation Sale
(scheduled in that hour) will then be added to the load and the dispatch
performed again. The resulting production costs are referred to as the Total
Production Cost. The difference between Total Production Cost and the Own Load
Production Cost is the Mitigation Production Cost.
The energy revenues from the sale (S14/MWh) minus Mitigation Production Cost and
the costs of hedges to manage fuel cost risks and any expenses due to the buy
back provisions of the sale equals the Mitigation Margin. If the Mitigation
Margin is positive then the margin would be treated in the same manner as any
other off-system sales margin. The revenues received from the mitigation sale
auction are referred to as the Mitigation Reservation Margin. These margins will
be used to offset any negative Mitigation Margin calculated above. The
Mitigation Margins will be deferred on a monthly basis and all gains and losses
will be accumulated annually and flowed through 30 days after the end of a
calendar year. Alternatively, if the Mitigation Margin is positive, the
Mitigation Reservation Margin will be treated in the same manner as any other
off-system sales margin. When the Mitigation Margin is negative for the month,
then the Mitigation
1
<PAGE> 98
Attachment 4
MITIGATION SALE HOLD HARMLESS METHODOLOGY
Reservation Margin (calculated on an monthly basis) will be credited in an
amount necessary to make the Mitigation Margin zero. If the Mitigation Margin is
still negative, after giving full credit for the Mitigation Reservation Margin,
this amount determines the monthly Hold Harmless credit applied to eligible
fuel. The positive or negative monthly Mitigation Margin will be accrued
monthly, and the Hold Harmless credits in a month may be reversed if Mitigation
Reservation Margin is available in a succeeding month.
The expenses and revenues associated with the Mitigation Margin will be
allocated to the CSW Operating Companies based on the relative participation of
their units in the sale as determined in RMR.
The following is the RMR algorithm:
OWN LOAD - the sum of the CSW Operating Companies native load plus firm purchase
and sale obligations.
OWN LOAD PRODUCTION COST (OLPC) - The cost of production to serve CSW Own Load
requirement plus daily regulating and operating reserves. This is the Internal
Economy dispatch level of ICR.
TOTAL PRODUCTION COST (TPC) - The cost of production to serve CSW Own Load
requirements plus daily regulating and operating reserves plus the Mitigation
Sale.
MITIGATION ENERGY SALES REVENUE (MESR) - The revenue associated with the
Mitigation Energy, at $14/MWh.
MITIGATION PRODUCTION COST (MPC) - the cost or producing the energy to supply
the Mitigation Sale.
MITIGATION MARGIN (MM) - Margin resulting from the mitigation sale.
MITIGATION RESERVATION MARGIN (MRM) - The annual revenue from the reservation
fees determined in the mitigation auction. The annual revenue is divided by 12
to determine a monthly MRM.
ENERGY RECALL EXPENSE (ERE) - The payments made to the Mitigation Sale
purchasers when CSW recalls the energy in order to serve firm native load. These
payments will be calculated on an hourly basis.
MPC = TPC - OLPC
MM = MESR - MPC - ERE
If MM is negative, an amount of M4RM will be added in an amount to make MM
positive. If MM is still negative, MM equals the Hold Harmless Credit.
2
<PAGE> 99
Attachment 4
MITIGATION SALE HOLD HARMLESS METHODOLOGY
Following are two examples: one representing a Summer load case and the other
representing a Spring/Fall load case. In each example, it is assumed that the
MRM value = $10,512,000/12 = $876,000.
SUMMER LOAD CASE
<TABLE>
<CAPTION>
Operating Company Load Generation Production Cost $/MWh
- ----------------- ---- ---------- --------------- -----
<S> <C> <C> <C> <C>
CPL 3500 MW 3709 MW $57,455.55 15.49
PSO 3000 MW 2999 MW $48,015.25 16.02
SWEPCO 3500 MW 3432 MW $43,621.21 12.71
WTU 1000 MW 861 MW $20,018.25 23.25
CSW 11000 MW 11000 MW $169,110.26 15.37
Own Load Production Cost = $169,110.26
Add 300 MW Mitigation Sale:
CPL 3500 MW 3709 MW $57,455.55 15.49
PSO 3000 MW 3098 MW $49,905.25 16.11
SWEPCO 3500 MW 3632 MW $47,361.21 13.03
WTU 1000 MW 861 MW $20,018.25 23.25
CSW 11000 MW 11300 MW $174,740.26 15.46
</TABLE>
TOTAL PRODUCTION COST = $174,740.26
WC = TPC - OLPC $174,740.26 - 169,110.26 = $5,630.00
MITIGATION PRODUCTION COST = $5,630.00 $5630/300 MWh = $18.77/MWh
MM = MESR - MPC - ERE MM = $4,200.00 - $5,630.00 - 0
MM = -$1430.00 If MM is negative for the month, MRM is added as
needed.
Assuming MM is the same for every hour of the month (30 days x 24 hours), MM
would equal 720 x -$1430 = -$1,029,600.
MRM = $876,000 MM = -$1,029,600 + $876,000 = -$153,600 The whole monthly amount
of MRM was applied.
THE MONTHLY HOLD HARMLESS CREDIT = -$153,600
3
<PAGE> 100
Attachment 4
MITIGATION SALE HOLD HARMLESS METHODOLOGY
SPRING/FALL LOAD CASE
<TABLE>
<CAPTION>
Operating Company Load Generation Production Cost $/MWh
- ------------------ ---- ---------- --------------- -----
<S> <C> <C> <C> <C>
CPL 3000 MW 3 100 MW $45,767.23 14.76
PSO 2300 MW 2250 MW $32,358.25 14.38
SWEPCO 2750 MW 2800 MW $40,010.00 14.29
WTU 845 MW 745 MW $11,735.45 15.75
CSW 8895 MW 8895 MW $129,970.93 14.60
Own Load Production Cost =
$129,870.93
Add 300 MW mitigation sale
CPL 3000 MW 310OMW $45,767.23 14.76
PSO 2300 MW 2375 MW $34,203.25 14.40
SWEPCO 2750 MW 2975 MW $42,582.50 14.31
WTU 845 MW 745 MW $11,735.45 15.75
CSW 8895 MW 9195 MW $134,288.43 14.60
</TABLE>
TOTAL PRODUCTION COST - $134,288.43
WC = TPC - OLPC $134,288.43 - 129,870.93 = $4,417.50
MITIGATION PRODUCTION COST = $4,417.50 $4417.5/300 MW = $14.73/MWh
MM = MESR - MPC - ERE $4,200.00 - $4,417.50 - 0 = -$217.50
MM = -$217.50 If MM is negative for the month, MRM is added as needed.
Assuming MM is the same for every hour of the month (30 days x 24 hours), MM
would equal 720 x -$217.50 = -$156,600.
MRM = $876,000
$156,600 of MRM is credited to MM
MM = $0.00 The remaining $719,400 of MRM is treated as normal off-system sales
margin.
THE MONTHLY HOLD HARMLESS CREDIT = $0.00
4
<PAGE> 101
Attachment 5
CAUSE NO. PUD 980000444
PROPOSED QUALITY OF SERVICE STANDARDS
AMERICAN ELECTRIC POWER COMPANY, INC., AND CENTRAL AND SOUTH WEST CORPORATION
Standards related to the Company's customer service center calls:
- - On an annual basis, the customer call center's average answer time for
customer calls shall not exceed fifty-five seconds.
- - As used in this paragraph, "answer" means the operator, service
representative, or automated system is ready to render assistance and/or
accept the information necessary to process the call.
- - Answer time shall be measured from the first ring at the call enter or at
the point the customer begins to wait in queue, whichever comes first.
- - If AEP/CSW utilizes a menu driven, automated, interactive answering, the
initial recorded message presented by the system to the customer shall only
identify the Company and the general options available to the customer,
including the option of being transferred to a live attendant. At any time
during the call, the customer shall be transferred to a live attendant if
the customer fails to interact with the system for a period of ten seconds
following any prompt.
- - Customers shall not be delayed from reaching the queue by any promotional
or merchandising material not selected by the customer.
- - Performance data during a "major event" or comparable term as such is used
by the electric distribution company in its emergency plan, and subject to
review and acceptance by the Commission shall be excluded from the
calculation of monthly minimum service values pursuant to the paragraphs
above. If the Company and the Commission cannot agree on the definition of
a "major event" or comparable term, Staff and /or the Company may apply,
within forty-five days after the submission of the Company's proposal, to
the Commission for a hearing, file a written report and/or recommendations.
Standards related to the Company's response to requests for service:
- - Ninety-five percent (95%) of the Company's application for new electric
service, not involving a line extension or new facilities, shall be filled
by the end of the next business day after the customer's location is ready
for service and the customer submits a service request, excluding those
orders where a later date was specifically requested by the customer.
- - The Company will notify customers two days before non-emergency, temporary
service interruptions required to improve or maintain performance of the
Company's system, and shall meet its commitment in ninety-five percent
(95%) of such instances.
- - The Company shall comply with the deadlines established for meter testing,
written reports on meter testing, and reconnection of service, in OAC
165:35 and any amendments thereto.
1
<PAGE> 102
Standard related to the Company's Billing Adjustments:
- - The Company shall maintain its infrastructure and customer service in such
a manner that the average monthly rate of actual customer over-billing
errors per 1,000 customers does not exceed ten. Estimated billings due to
inclement weather, lack of access to customer premises, damaged metering
equipment, and errors due to erroneous information provided from customers
shall be excluded from this measurement.
All of the above standards and measurements are on a PSO Company-wide, 12-month
basis. The customer service standards established under this agreement shall
remain in effect for a period of no more than three years following the
effective date of the merger. In the event the OCC changes any of its rules
concerning customer service standards, such changes shall automatically be
incorporated in this agreement. Additionally, these standards can be changed
during the three-year period to reflect any performance-based ratemaking plans
or rules for PSO and/or the electric industry.
Standard related to Customer Satisfaction:
- - PSO shall provide a Customer Satisfaction Index Report to the OCC on an
annual basis. This report will provide at a minimum data on: a.) the
fairness and reasonableness of rates; b.) reliability/high quality service;
c.) courteous and understanding employees; and, d.) quick service
restoration after an outage. In addition, if a decline in the trend in the
categories noted above is reported, PSO shall provide information to the
OCC as to the actions being taken in order to correct such decline(s). The
data to be provided in conjunction with this paragraph shall be provided
(and maintained by the OCC) on a confidential basis.
Standards related to Company's Reliability Performance:
The merged company, AEP and CSW, commits to maintain its reliability performance
for its Oklahoma retail customers as determined by the System Average
Interruption Frequency Index (SAIFI) and the System Average Interruption
Duration Index (SAIDI) within the range experienced during the period 1997
through 1999 (inclusive), absent a major outage event beyond the scope of any
the PSO system experienced during the same period. The SAIFI and SAIDI indices
are defined as shown below.
PSO will provide information/substantiation of its performance for each of these
measures on an annual basis by the end of May of the year following the year in
question.
<TABLE>
<CAPTION>
Year 97 98 99#
---- -- -- ---
<S> <C> <C> <C> <C>
SAIFI 1.59 1.54
SAIDI* 158 178
</TABLE>
* These numbers reflect minutes.
# These numbers will be available by the time the merger is consummated.
AEP/CSW 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:
2
<PAGE> 103
SAIFI = number of customers interrupted
number of customers served
2) System Average Interruption Duration Index (SAIDI) is defined as the
number of customer minutes of interruption divided by the number of
customers served. It is calculated by the equation:
SAIDI = sum of all customer minutes of interruption
-------------------------------------------
number of customers served
<PAGE> 1
Exhibit D-5.3
SOAH DOCKET NO. 473-98-0839
PUC DOCKET NO. 19265
APPLICATION OF CENTRAL AND BEFORE THE
SOUTH WEST CORPORATION AND
AMERICAN ELECTRIC POWER PUBLIC UTILITY COMMISSION
COMPANY, INC. REGARDING
PROPOSED BUSINESS COMBINATION OF TEXAS
MOTION TO IMPLEMENT SETTLEMENT
Now come the Signatories to the attached Integrated Stipulation and
Agreement, Applicants American Electric Power Company, Inc. ("AEP") and Central
and South West Corporation ("CSW"), the General Counsel of the Public Utility
Commission of Texas, the Office of Public Utility Counsel, certain Cities served
by CSW, Texas Industrial Energy Consumers, the State of Texas, and the
Low-Income Intervenors, and request that the ALJ and the Commission approve and
implement the Integrated Stipulation and Agreement in this Docket.
I.
Summary of Integrated Stipulation and Agreement
The Agreement provides for the following:
* Rate reductions: Total rate reductions of $221,000,000 by the CSW Texas
operating companies over a period of six years, broken down as follows:
- CPL: $142,840,000
- SWEPCO: $ 42,080,000
- WTU: $ 36,080,000
The Signatories agree that these rate reductions are in addition to any
rate reduction provided for in legislation and will be implemented
regardless of any changes to the current regulatory structure in Texas
or implementation of a legislatively-mandated rate freeze.
<PAGE> 2
* Low-income program: An expanded Low-Income Program.
* Customer Education Plan: Implementation of a Customer Education Plan in
the event of electric industry restructuring legislation.
* ECOM amortization: An additional commitment by CPL to amortize
$60,000,000 of ECOM over six years ($20,000,000 in 2000 and 2001 and
$5,000,000 per year in 2002-2005).
* Rate moratorium: Applicants agree to a rate moratorium until January 1,
2003, subject to certain force majeure provisions. Other Signatories
(except General Counsel) agree not to initiate a base rate proceeding
against the CSW Texas operating companies that would result in a change
in base rates prior to January 1, 2001.
* Off-system sales margins: A sharing of off-system sales margins in
excess of historical levels.
* Jurisdictional issues: Preservation of status quo concerning CSW
operating companies' relationship with ERCOT and the SPP, absent prior
Commission authorization for a change.
* Affiliate standards: Applicants agree to abide by affiliate standards
set out in the Agreement until new standards are enacted by rule or
legislation. The standards in the Agreement include financial policies
and guidelines for transactions between AEP operating companies, access
to books and records, restrictions on extension of credit to
affiliates, requirements for separation of employees and facilities,
restrictions on information exchange, comparability requirements,
provisions governing transfer of utility assets, and a requirements for
biennial audits.
* Market power mitigation plan: A market power mitigation plan that
provides, subject to Commission approval, for divestiture of 250 MW
from CSWE's Frontera Plant and 1354 MW from CPL plants, subject to
certain recall provisions if necessary to supply CPL's native load and
existing firm wholesale contracts. In addition, the Applicants have
agreed to divest 300 MW in the SPP.
* Customer service standards: Customer service standards, including
service quality standards (service turn-on and upgrade, light
replacement, telephone response, reporting requirements), reliability
standards and financial guarantees to meet those standards, and
provisions for an Office of Consumer Protection audit of service
quality.
2
<PAGE> 3
II.
Request for Establishment of Procedures
The Signatories also request that the ALJ expeditiously schedule a
prehearing conference to establish a new procedural schedule for consideration
of the Integrated Stipulation and Agreement. The Signatories propose the
following schedule:
Supplemental Testimony in Support of the Stipulation May 21
Discovery on Supplemental Testimony Ends June 11
Testimony of Non-Signatory Parties June 25
Motions to Strike Direct Testimony of All Parties July 2
Discovery on Testimony of Non-Signatory Parties Ends July 9
Responses to Motions to Strike Direct Testimony July 9
Rebuttal Testimony July 9
Motions to Strike Rebuttal Testimony July 15
Discovery on Rebuttal Testimony Ends July 16
Responses to Motions to Strike Rebuttal Testimony July 19
Hearing on the Merits July 19
Discovery Response Times:
Signatories' Testimony on Stipulation Ten Working Days
Non-Signatory Testimony Ten Working Days
Signatories' Rebuttal Testimony Five Working Days
Time for Filing Objections to RFIs on the Following Testimony:
Signatories' Testimony on the Stipulation Five Working Days
Non-Signatory Testimony Five Working Days
Signatories' Rebuttal Testimony Three Working Days
Time from Receipt of Objections for Filing Motions to Compel and Responses to
Motions to Compel on Objections to the Following Testimony:
Signatories' Testimony on the Stipulation Five Working Days
Non-Signatory Testimony Three Workings Days
Signatories' Rebuttal Testimony Two Working Days
Wherefore, the Signatories request that the ALJ and the Commission
grant the relief requested herein.
3
<PAGE> 4
Respectfully submitted,
CLARK, THOMAS & WINTERS BRACEWELL & PATTERSON, L.L.P.
A Professional Corporation
By: /s/ Philip F. Ricketts
----------------------
By: /s/ Walter Demond Philip F. Ricketts
-----------------
Walter Demond 111 Congress Avenue, Suite 2300
P.O. Box 1148 Austin, TX 78701
Austin, TX 78767 (512) 472-7800
(512) 472-8800 (512) 472-9123 Fax
(512) 474-1129 Fax
BROYLES & PRATT
ATTORNEYS FOR AMERICAN ELECTRIC A Professional Corporation
POWER COMPANY, INC. One Northpoint Centre, Suite 250
6836 Austin Center Boulevard
BUTLER, PORTER, GAY & DAY Austin, TX 78731
(512) 794-2100
Geoffrey M. Gay (512) 794-2111 Fax
1600 Shoal Creek Blvd., Suite 302
Austin, TX 78701
(512) 474-7475 ATTORNEYS FOR CENTRAL
(512) 474-7443 Fax AND SOUTH WEST CORPORATION
MAYOR, DAY, CALDWELL & KEETON,
ATTORNEYS FOR CITIES OF ABILENE, L.L.P.
CORPUS CHRISTI, MCALLEN, VICTORIA,
BIG LAKE, VERNON AND PADUCAH Rex D. VanMiddlesworth
C. Lane Mears
LOW INCOME INTERVENORS 100 Congress Avenue, Suite 1500
Austin, TX 78701
Neish A. Carroll (512) 320-9200
Texas Legal Services Center (512) 320-9292 Fax
815 Brazos, Suite 1100
Austin, TX 78701 ATTORNEYS FOR TEXAS INDUSTRIAL
(512) 477-6000 ENERGY CONSUMERS
(512) 477-6576 Fax
4
<PAGE> 5
OFFICE OF PUBLIC UTILITY COUNSEL STATE OF TEXAS
James K. Rourke, Jr. Bryan L. Baker, Ass't Attorney General
Assistant Public Counsel Consumer Protection Division
1701 North Congress Avenue 300 West 15th St., 9th Floor
Austin, TX 78701 Austin, TX 78701
(512) 936-7500 (512) 475-4237
(512) 936-7520 (512) 322-9114 Fax
PUBLIC UTILITY COMMISSION OF
TEXAS
Bret J. Slocum
Director-Legal Division
Russell Trifovesti
Assistant Director - Legal Division
Thomas S. Hunter
Assistant General Counsel
Christopher Green
Assistant General Counsel
1701 North Congress Avenue
(512) 936-7272
(512) 936-7268 Fax
CERTIFICATE OF SERVICE
I certify that a copy of this document was served on all parties of
record in this proceeding on this 4th day of May, 1999, by facsimile,
first-class mail or hand delivery.
/s/ Walter Demond
-----------------
Walter Demond
5
<PAGE> 6
INTEGRATED
STIPULATION AND AGREEMENT
This Integrated Stipulation and Agreement ("Agreement") is
made and entered into by and among American Electric Power Company, Inc. ("AEP")
and Central and South West corporation ("CSW"), referred to jointly as
"Applicants," and other entities whose authorized representatives have signed
it. Applicants and such other signatories are at times referred to jointly
herein as the "Signatories" (also referred to individually as "Signatory").
WHEREAS, on April 30, 1998, AEP and CSW filed an Application
with the Public Utility Commission of Texas ("PUCT") pursuant to Section 14.101
of the Public Utility Regulatory Act ("PURA"), requesting that the PUCT find
their proposal to combine their systems ("merger") to be consistent with the
public interest ("Application");
WHEREAS, notice of the filing of the Application and the
Commission's proceeding to evaluate it was published once each week for four
consecutive weeks in newspapers of general circulation in each Texas county
served by Central Power and Light Company ("CPL"), West Texas Utilities Company
("WTU") and Southwestern Electric Power Company ("SWEPCO"), the electric utility
operating company subsidiaries owned by CSW. In addition, individual notice was
given by mail to each Texas customer of CPL, WTU and SWEPCO and supplemental
notice was given in accordance with Order Nos. 43 and 45;
WHEREAS, the Signatories desire to resolve all outstanding
merger-related issues among them;
WHEREAS, this Agreement involves all issues in this proceeding
in a manner the Signatories believe is consistent with the public interest, and
the Signatories, along with the non-signatory parties who do not oppose the
Agreement, represent diverse interests;
WHEREAS, the Signatories believe that fully contested hearings
in this case would be time-consuming and expensive for all parties and that the
public interest will be served by adoption of an order consistent with this
Stipulation;
WHEREAS, the WTU rate freeze expired in October 1998;
WHEREAS, there are currently pending in the Texas courts
appeals of prior PUCT Docket Nos. 14965 and 17460 concerning CPL and SWEPCO,
respectively;
WHEREAS, the Signatories desire to resolve all issues in
Docket No. 17460 and certain issues in Docket No. 14965 as part of this
Agreement;
WHEREAS, the PUCT is currently considering adoption of an
affiliate code of conduct and has recently considered reliability and service
quality issues in several proceeding;
<PAGE> 7
WHEREAS, the Signatories desire to address affiliate code of
conduct and service quality issues in response to the PUCT's stated concerns;
WHEREAS, AEP and CSW previously entered into a Stipulation and
Agreement with the Office of Public Utility Counsel and certain Cities served by
CSW;
WHEREAS, the parties to the previous Stipulation and Agreement
have now reached agreement with additional parties, including the General
Counsel of the Public Utility Commission of Texas, Texas Industrial Energy
Consumers, the State of Texas, and the Low-Income Intervenors;
WHEREAS, this subsequent agreement accomplishes the
Signatories' desire to resolve as many pending and potential issues and disputes
existing among them as possible; and
WHEREAS, the Signatories wish to consolidate the terms of this
subsequent agreement with the terms of the previous Stipulation and Agreement to
produce this Integrated Stipulation and Agreement.
NOW, THEREFORE, in consideration of the mutual agreements and
covenants herein, the Signatories, through their undersigned representatives,
agree to and recommend for PUCT approval the following provisions of this
Agreement as a means of fully resolving the issues among them in Docket No.
19265 and other proceedings referenced in this Agreement:
1. Definitions
The term "Merged Company" refers to post-merger AEP and its
successors in interest.
"Texas operating company" refers to either CPL, WTU or SWEPCO,
and their respective successors in interest. "Texas operating companies" refers
collectively to CPL, WTU, SWEPCO and their respective successors in interest.
The term "actual native load requirements" refers to firm
wholesale contractual load requirements existing as of the date of this
Agreement and load requirements of firm retail customers.
The term "effective date of the merger" refers to the "closing
date" as defined in Annex A to the Agreement and Plan of Merger attached to
Thomas V. Shockley's testimony as Exhibit TVS-4.
References to CPL, WTU or SWEPCO include their respective
successors in interest.
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2. Support For the Merger
A. The signatories hereby stipulate and agree, and urge the PUCT
to issue a Final Order finding, that the Application in Docket
No. 19265, as modified and contained in this Agreement, is in
the public interest and otherwise consistent with the
requirements of Section 14.101 of PURA.
B. All Signatories agree to fully support this Agreement in all
respects and to use all reasonable efforts to obtain prompt
adoption of a final order in Docket No. 19265 based upon this
Agreement. Further, all Signatories agree to defend the terms
of this Agreement.
3. Regulatory Plan
A. Texas Retail Rate Reductions.
The Texas operating companies will implement net merger
savings rate reduction riders which will reduce rates to
customers by the annual amounts shown in Attachment A
beginning with the first revenue month after the effective
date of the merger. The annual rate reduction amounts shown in
Attachment A will be allocated to rate classes based 50% upon
a total revenues factor and 50% upon a year-end customer
factor, as shown on Attachment A. Table A-1. Each individual
year's rate reduction will apply for a twelve month period
with the last reduction continuing to apply in years following
the end of year six until base rates for the Texas operating
company are changed. Notwithstanding any base rate proceeding
during the six year period after the effective date of the
merger, the annual amounts shown in Attachment A will remain
in effect.
B. The annual base rate reduction amounts are net "bottom-line"
amounts not subject to any offset.
C. The Texas operating companies agree to implement the above
rate reductions in the manner and amounts described above
notwithstanding any changes to the current regulatory
structure in Texas or implementation of a
legislatively-mandated rate freeze. In the event that retail
electric restructuring legislation is implemented in Texas
including any divestiture, unbundling or restructuring, the
Texas operating companies agree to apply the regulatory plan's
provisions to regulated rates of their customers.
D. The Signatories agree that any legislatively mandated
reductions or credits to base rates that are part of any
retail electric restructuring legislation implemented in Texas
shall not diminish or offset, but shall be in addition to, the
base rate reductions established in this proceeding.
E. The Merged Company and Texas operating companies agree not to
request under currently existing law any new resource
surcharge or Power Cost Recovery Factor
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("PCRF") for increase in any existing resource surcharge or
PCRF that would become effective within a period of six years
after the effective date of the merger or until retail
electric restructuring legislation is implemented in Texas,
whichever first occurs. Notwithstanding the previous sentence,
the Merged Company or a Texas operating company may request a
new or increased surcharge or PCRF if the requested surcharge
or PCRF was authorized in Docket Nos. 18041 or 18845 or is to
provide for recovery of fuel and purchased power energy
savings resulting from demand-side management ("DSM") as
required by the preliminary integrated source plan in Docket
No. 16995.
In addition, the Merged Company or a Texas operating company
may request a surcharge or PCRF related to acquisition of
additional short-term capacity or DSM resources required to
meet the load requirements specified in subparagraphs (1) and
(2) below. The following provisions will apply to any such
request made by the Texas operating companies:
(1) for amounts of short-term capacity or DSM resources
required to meet a reserve margin based upon actual
native loan requirements plus a 15% reserve margin
during each annual period, the Merged Company and
Texas operating companies agree that the costs which
may be requested in a surcharge or PCRF will be
limited to the cost of the short-term capacity or DSM
less the amount of production capacity costs per
kilowatt embedded in current base rates times the
kilowatts of short-term capacity of DSM required to
meet the actual native load requirements and 15%
reserve margin.
(2) For amounts of short-term capacity or DSM resources
required by the PUCT to be purchased in excess of
actual native load requirements plus a 15% reserve
margin during each annual period, the Merged Company
and Texas operating companies agree that the costs
which may be requested in a surcharge or PCRF will be
limited to the cost of the short-term capacity or
DSM.
Any PCRF implemented pursuant to this section is not subject
to adjustment pursuant to Section 3.F.(3) below. The Merged
Company's request for recovery of any surcharge or purchased
power costs pursuant to this Section 3.E. will not be
considered a base rate case and will not trigger any rate
treatments illustrated on Attachment F, and the Attachments A
and H rate credits will remain in place. This Agreement does
not prevent any Signatory from opposing any request referenced
in this Section 3.E.
F. (1) Subject to subparagraph F.(3), in a proceeding to
change base rates of a Texas operating company to
become effective prior to the end of the six year
period after the effective date of the merger, a "net
merger savings" expense item, the purpose of which is
to prevent ratepayers from receiving their share of
merger savings twice and to ensure that the
shareholders
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retain their share of net merger savings attributable
to the Texas operating company, will be reflected as
reasonable and necessary operating expenses in the
calculation of cost of service. The annual amounts of
the net merger savings expense item for each of the
Texas operating companies are included in Attachment
B. The amount to be included in cost of service shall
be based upon the test year period.
(2) The Merged Company and Texas operating companies will
defer and amortize their merger related
costs-to-achieve over a six year period following the
effective date of the merger. 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. Subject to subparagraph F. (3),
in any proceeding to change base rates of a Texas
operation company to become effective prior to the
end of the six year period after the effective date
of the merger and that is not initiated to implement
electric industry restructuring legislation, the
annual amount of amortization of costs to achieve the
merger included in Attachment C will be reflected as
a reasonable and necessary expense included in the
calculation of cost of service.
(3) In any proceeding initiated by a Texas operation
company requesting an increase to overall base rate
revenues to become effective prior to end of the six
year period after the effective date of the merger:
(a) The net merger savings expense item and
annual amount of amortization of costs to
achieve the merger will not be included in
the calculation of the cost of service
unless the Texas operating company
demonstrates:
(i) that the proposed rate increase
results from circumstances not
directly or indirectly related to
the merger; and
(ii) that the full level of achieved
merger savings for the applicable
year as reflected in Attachment D
have been achieved; and
(b) The revenue requirements otherwise
determined to be reasonable and necessary
will be reduced by the annual amounts
included in Attachment E.
(4) The Merged Company and the Texas operating companies,
subject to the following force majeure provisions,
agree not to initiate a base rate
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proceeding seeking an overall base rate revenue
increase to be effective prior to January 1, 2003 or
three years from the effective date of the merger,
whichever is later (the "rate moratorium"):
(a) Changes in statutory Federal income tax
provisions which result in a material known
and measurable increase of tax expense of
the Texas operating company initiating the
proceeding;
(b) Legislative or governmental regulatory
action, other than loss of load resulting
from electric industry restructuring, which
has a material direct impact on the Texas
operating company's non-fuel cost of
providing service;
(c) Other material increases in a Texas
operating company's known and measurable
annual non-fuel operating expenses which are
outside its control; and
(d) A review of the Texas operating company's
rates instituted and allowed to proceed
under PURA Section 36.151.
For purposes of this force majeure provision, the
annual levels of materiality for each Texas operating
company on a Texas retail basis shall be 5% of
normalized base revenues for the previous year. For
example, for a force majeure event occurring in 2001,
the annual level of materiality would be 5% of the
normalized base revenues for the year 2000.
(5) Subject to the limitations in Sections 3.B, 3.C and
3.D above, during the rate moratorium the Texas
operating companies may request and support any
changes to rates that they believe appropriate or
desirable in connection with any filings required to
implement any regulatory or legislatively-imposed
restructuring or unbundling of services provided by
electric companies.
(6) The Texas operating companies may make filings during
the rate moratorium which either: (1) modify tariffs,
riders, or terms and conditions while not increasing
aggregate base revenues for major rate classes
(residential, commercial, industrial, municipal and
lighting) or (2) add tariffs, riders, or terms and
conditions to address competitive conditions or
secure additional load that will not shift allocable
costs under such tariffs, riders, or terms or
conditions to other major rate classes.
(7) The rate moratorium does not preclude the
implementation of any surcharge or other rate
mechanism found appropriate as a result of a remand
to the PUCT from a court proceeding.
(8) An illustration of the impact of this Agreement on
the revenue requirements of each Texas operating
company in the event a base rate
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proceeding is initiated during the six-year period
after the effective date of the merger is included as
Attachment F. In the event of any request to change
rates under subparagraph (5), (6) or (7), above, the
annual rate credits shown in Attachments A and H will
remain in effect.
G. Off-System Sales Margins.
(1) CPL off-system sales margins up to $1.75 million
shall be credited to customers. For any CPL
off-system sales margins between $1.75 million and
$2.62 million, 85% shall be credited to customers and
15% of such margins shall be retained by the
shareholders. For any CPL off-system sales margins
above $2.62 million, 50% of such margins shall be
credited to customers and 50% of such margins shall
be retained by the shareholders.
(2) SWEPCO off-system sales margins up to $1.35 million
shall be credited to customers. For any SWEPCO
off-system sales margins between $1.35 million and
$2.03 million, 85% of such margins shall be credited
to customers and 15% of such margins shall be
retained by the shareholders. For any SWEPCO
off-system sales margins above $2.03 million, 50% of
such margins shall be credited to customers and 50%
of such margins shall be retained by the
shareholders.
(3) WTU off-system sales margins up to $900,000 shall be
credited to customers. For any WTU off-system sales
margins between $900,000 and $1.35 million, 85% of
such margins shall be retained by the shareholders.
For any WTU off-system sales margins above $1.35
million, 50% of such margins shall be credited to
customers and 50% of such margins shall be retained
by the shareholders.
(4) The provisions as to off-system sales margins shall
be in effect for a period of five years from the
effective date of the merger.
(5) The dollar figures shall apply on a calendar-year
basis.
(6) Off-system sales margins to be credited to customers
under this subsection shall be made in the form of
revenue credits in fuel reconciliation proceedings.
H. Fuel Savings.
All reconcilable fuel and purchased power savings shall be
passed through to customers in accordance with PUCT rules and
proceedings for fuel factor adjustments and fuel
reconciliation (consistent with the proposal of the
Applicants).
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4. Regulatory Jurisdiction
A. The Merged Company and the Texas operating companies commit
and agree that they will not contend in any forum that the
jurisdiction of the PUCT over any Texas operating company is
changed as a result of the merger.
B. The Merged Company commits to file any allocation of the cost
of the new generation of transmission facilities with the
Federal Energy Regulatory Commission ("FERC") and to notify
the PUCT of any such filings at the time they are made.
C. The Merged Company agrees not to assist in proceedings before
the PUCT or in appeals of PUCT orders that the authority of
the Securities and Exchange Commission ("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 PUCT to
examine and determine the reasonableness and necessity of
non-power affiliate transaction costs of the Texas operating
companies. The Signatories agree that this agreement does not
include a waiver of any arguments that the Merged Company may
have with respect to the reasonableness of SEC approved costs
allocations, as opposed to the reasonableness of the costs
themselves.
D. The Merged Company will not seek recovery of AEP mine-closing
costs except to the extent that such closing costs are
reflected as a component of AEP fueled costs utilized for
economy energy sales under the Systems Integration Agreement.
Economy energy sales will only be made under the Systems
Integration Agreement when both the East and West zones will
achieve coast savings.
E. The Merged Company commits and agrees that any stranded costs
that CPL, SWEPCO or WTU may seek to recover will be on a
stand-alone basis, and will be limited to the
ownership-interest of CPL, SEPCO or WTU in its respective
assets and obligations. The Merged Company agrees not to seek
or recover any stranded costs associated with the existing AEP
system from Texas customers. The Signatories agree not to
propose the allocation of any stranded costs associated with
the CSW system to customers of the existing AEP operating
companies. STP will be used only to serve Texas customers.
F. The Merged Company will provide the PUCT with notice of
filings which propose new allocation factors with the SEC or
FERC. The notice will include a description of the proposed
factors.
G. The Merged Company agrees not to implement further connection
between the Electric Reliability Council of Texas ("ERCOT")
and the Southwest Power Pool ("SPP") or the Western Systems
Coordinating Council ("WSCC") without providing prior notice
to the PUCT and all members of ERCOT and without first
obtaining a Section 211 order from the FERC. Any such
interconnect proposed will comply with legal and current
contractual requirements for making such interconnections.
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H. Subject to due process rights to a public hearing and
opportunity to present evidence in support of their position,
CPL and WTU agree not to terminate their membership in ERCOT
without the prior written approval of the PUCT. The Merged
Company will not include CPL and the ERCOT portion of WTU in
an Independent System Operator ("ISO") outside ERCOT without
the prior written approval of the PUCT, with CPL and WTU
afforded the right to seek this determination through the
PUCT's contested case hearing process. SWEPCO will not
withdraw from the SPP without first seeking approval from the
PUCT.
I. CPL and WTU will continue to file rates for transmission
services at the FERC in accordance with ERCOT regional pricing
and terms and conditions as established by the PUCT so long as
CPL and WTU are members of ERCOT or until such time as ERCOT
is no longer subject to the jurisdiction of the PUCT. CPL and
WTU will comply with all Texas transmission statutes and
rules, including Transmission Cost of Service ("TCOS")
allocations. CPL and WTU commit to make TCOS filings with the
PUCT in accordance with PUCT rules and procedures. The PUCT
will determine CPL's and WTU's transmission costs in
accordance with the PUCT's transmission rules. CPL and WTU
will submit and support the results of the PUCT orders
concerning TCOS for CPL and WTU in FERC transmission rate
filings for intra-ERCOT transmission service.
J. The Merged Company agrees that it should not double recover
Direct Current ("DC") tie costs and will make all necessary or
appropriate adjustments to prevent double recovery, including,
but not limited to, removal of any DC tie costs included in
CPL, WTU and TCOS.
K. The Merged Company will comply with any Texas legislation or
administrative order providing for direct retail access. This
requires complying with all conditions governing such
legislation and/or order, including conditions related to the
recovery and quantification of stranded costs, if any.
Notwithstanding the foregoing, the Merged Company does not
waive any rights which it may have to challenge the legality
of any legislation or administrative orders.
L. The Merged Company will abide by the ultimate resolution of
affiliate allocation issues in the Docket No. 14965 appeal,
i.e, whether the PUCT may determine that the Company applied
the wrong SEC factor to an affiliate expense.
5. Affiliate Standards
The Merged Company agrees to comply with affiliate rules adopted in
either restructuring legislation or in PUCT rules. The Merged Company
also agrees to comply with all existing statutes and PUCT rules
pertaining to affiliate transactions. Until a statute or rule governing
affiliate transactions is adopted, the Merged Company agrees to comply
with the affiliate standards set forth below. The following affiliate
standards shall apply from the effective date of merger until the new
affiliate standards imposed by state legislation or PUCT rule become
effective.
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A. The terms "exempt wholesale generator" and "power marketer"
are defined in PURA Section 31.002.
B. 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
non-utility affiliates or its utility affiliates.
(2) An AEP operating company's costs for jurisdiction
rate purposes shall reflect only those costs
attributable to its jurisdiction customers.
(3) The principals set forth in subparagraphs (1) and
(2), above, shall be applied to prevent costs found
to be just and reasonable for ratemaking purposes by
the affected state commission being left unallocated
or stranded between various regulatory jurisdictions,
resulting in the failure of the opportunity of 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 which are sufficient
to identify and appropriately allocate costs between
the operating company and its affiliates, consistent
with these cross-subsidization principles and the
financial policies and guidelines set out in this
subparagraph B.
C. The PUCT and other municipal regulatory authorities under PURA
shall have access to the books and records of any affiliate of
a Texas operating company to the same extent and in like
manner that the PUCT has over a public utility operating
company if the affiliate has had direct or indirect
transactions with the Texas operating company. The access
shall be sufficient to enable the PUCT or other regulatory
authority to conduct a complete analysis and make appropriate
determinations under PURA Section 36.058. Upon request of the
PUCT, such employees, officers, books and records will be made
available in Austin, Texas to the PUCT. 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 be raised before the PUCT
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 rules and
regulations of the PUCT and the Texas Public Information Act.
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D. 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. Asset transfers from an
AEP operating company to a non-utility affiliate and asset
transfers from a non-utility affiliate to an AEP operating
company shall be at fully distributed costs for book purposes
in accord with current SEC requirements or other statutory
requirements of the SEC have no jurisdiction.
E. 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:
(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 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, endorse,
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.
An AEP operating company may not incur debt in a manner that, on its
default, would permit a creditor to have recourse against the assets of
another AEP operating company.
Transactions between AEP operating companies and affiliates
involving a money pool for financing the short-term funding
requirements or transactions between AEP operating companies
and special purpose financing entities used solely for the
purpose of financing utility assets are exempt from the
requirements of this paragraph. Further, provisions of this
paragraph would not preclude the AEP operating companies from
issuing securities or assuming obligations related to their
coal subsidiaries.
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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, upon request, make available for inspection in Austin,
Texas by the PUCT, copies of each billing statement, contract
and arrangement between the operating company and its
non-utility affiliates that relates to the provision of such
goods and services in accordance with applicable PUCT document
retention requirements.
G. Employees responsible for the day to day operations of the AEP
operating companies and those of affiliated exempt wholesale
generators or affiliated power marketers shall operate
independently of one another. AEP shall track and document all
employee movement between and among all affiliates. Such
information shall be made available to the PUCT and consumer
advocates upon request. Employees may transfer from one
function to the other so long as the transfer does not create
any unfair competitive advantage to the AEP operating company
or the affiliated exempt wholesale generator or affiliated
power marketer.
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. An affiliate may use an AEP operating company's name or logo
only if, in connection with such use, 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.
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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. The 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 M, an AEP operating company
may only make a product or service available to an affiliate
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
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,
in a central location for review by the PUCT and municipal
regulatory authorities.
Q. Except as provided in the Public Utility Regulatory Act,
including, but not limited to Subchapter B of Chapter 35, all
transfers of utility property with a net book value of more
than $1 million to unregulated affiliates must be valued at
the higher of net book value or market value for ratemaking
purposes, and all transfers of affiliate property with a net
book value of more than $1 million to regulated utilities must
be valued at the lesser of net book value or market value for
ratemaking purposes. This provision shall not apply to sales
of accounts receivable.
R. Transfers of generation, transmission, and fuel regulated
assets allowed by applicable utility industry restructuring
legislation or regulatory requirements are not subject to
subparagraph Q. For retail rate-making purposes, the cost
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characteristics of such generation, transmission or fuel
related assets shall be preserved for the duration of cost
based regulation of such transferred assets. Treatment of any
loss or gain from the sale of such assets will be subject to
applicable accounting, regulatory and statutory requirements.
S. AEP shall designate an employee who will act as a contact for
the PUCT and consumer advocates seeking data and information
regarding affiliate transactions and personnel transfers. Such
employee shall be responsible for providing data and
information requested by the PUCT for any affiliate
transactions and personnel transfers which involve a
jurisdictional operating company, regardless of the
affiliate(s), subsidiary(is), associate(s) or AEP operating
company from which the information is sought.
T. AEP shall designate an employee or agent within Texas who will
act as a contact for retail consumers 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.
U. AEP shall provide the PUCT a current list of employees or
agents that are designated to work with the PUCT concerning
state regulatory matters, including, but not limited to, rate
cases and retail competition issues.
V. Prior to filing any affiliate contract (including service
agreements) with the SEC or the FERC, and AEP operating
company shall submit to the PUCT a copy of the proposed
filing.
W. Any violation of the provisions of these affiliate standards
is subject to the enforcement powers and penalties of the
PUCT.
X. 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
audit shall be filed with the PUCT. Prior to the initial
audit, AEP will conduct an informational meeting with the PUCT
regarding how its affiliates and affiliate transactions will
or have changed as a result of the proposed merger.
7. Market Power Mitigation
A. System Integration Agreements. To mitigate any perceived
impacts of the merger on the Merged Company's market power,
the Applicants have proposed in their FERC Merger Application
a mitigation plan. To protect Texas retail customers, the
Merged Company agrees to hold harmless the retail customers of
the Texas operating companies from adverse net costs impacts
arising from the mitigation plan, as measured on a calendar
year basis.
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B. The Merged Company agrees to divest 1604 megawatts ("MW") of
generation capacity in ERCOT (Lon Hill Units 1-4 (CPL) - 546
MW, Nueces Bay Plan (CPL) - 559 MW, Joslin Unit 1 (CPL) - 249
MW, and Frontera Plan (CSW Energy) - 250 MW (as included in
Applicants' FERC mitigation plan). The divestiture shall be
timed so as not to violate the criteria for pooling of
interests accounting. Following execution of the Agreement,
Applicants and General Counsel shall jointly seek written
guidance (including appeals to the SEC, if available) from the
SEC or other entity authorized by the SEC to rule on this
matter, including, but not limited to, the Office of Chief
Accountant, on whether the divestiture of assets before two
years after consummation of the merger as proposed herein will
prevent pooling of interests accounting treatment for the
AEP/CSW merger.
Absent the Stipulation, General Counsel would have advocated,
and believed the PUCT would have ordered both the level and
the timing of the divestiture included within this
Stipulation.
Affiliates shall be ineligible to directly purchase divested
capacity, but may engage in non-firm energy transactions with
parties who purchase the capacity. The Signatories agree not
to oppose, consistent with any applicable electric industry
restructuring legislation, inclusion of these amounts of
divested capacity for purposes of compliance with future
statutes or rules requiring capacity auction or divestiture.
C. General Counsel and Applicants believe that current SEC
guidance allows the divestiture event to begin as soon as
possible after the effective date of the merger if the Merged
Company can demonstrate that the divestiture was required by
the PUCT and would have been ordered to occur in less than two
years if not for this settlement. The Merged Company agrees to
advocate this position in any meeting or proceeding before the
SEC in which the pooling of interests issue is considered. If
it is determined that divestiture can proceed immediately
without jeopardizing pooling of interests accounting treatment
for the merger, the divestiture shall begin no later than 90
days after the effective date of the merger. The Merged
Company further agrees to provide regular status reports to
the PUCT and all Signatory parties of the status of SEC
considerations of the merger, including, but not limited to,
the pooling of interests issue. If the SEC, through the
issuance of a final, non-appealable order or other final,
non-appealable ruling determines that the divestiture would be
a pooling violation, the auction will be scheduled consistent
with meeting SEC pooling of interests requirements. If the
final ruling from SEC will allow the divestiture of some of
the units within two years after the effective date of the
merger, the General Counsel and the Merged Company will work
together to determine the sequence of divestiture of those
units. If the General Counsel and the Merged Company are
unable to agree on the sequence of divestiture they will
submit the issue to the PUCT.
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<PAGE> 21
D. The terms of the divestiture will detail the right of CPL to
recall up to 1354 MWs of the divested capacity in accordance
with the following terms:
(1) CPL may recall the capacity anytime during May
through September;
(2) Any recall of capacity must be pre-scheduled at least
24 hours in advance with specific hours and MWs
nominated;
(3) Hours nominated may not exceed 20% of the hours in a
year (i.e., 1752 hours); and
(4) A minimum of four consecutive hours shall be
nominated for each day pre-scheduled.
E. If the acquirer of the divested CPL plants has to run the
plant(s) more than the nominated hours on the days in which
CPL preschedules or nominates energy due to operating
requirements, CPL agrees to offer the acquirer the heat rate
times the applicable fuel cost of such plan(s) for energy
received. Such additional hours shall not count toward the
limit of 1752 hours that may be nominated per year.
Alternatively, the acquirer is free to sell power above the
nominated amounts into the marketplace.
F. CPL will pay the acquirer(s) of its divested generation for
capacity during the May through September period at the level
embedded in CPL's current rates less seven months of operation
and maintenance expenses embedded in CPL's current rates. The
Merged Company will pay for nominated energy by multiplying an
agreed daily fuel market index by the heat rate of the
specific plant as agreed in the contract between the
acquirer(s) of the CSW plant(s) and the Merged Company.
G. During the other seven months of the year (i.e., October
through April). CPL may need to purchase power from the market
to replace the divested capacity (up to 1354 MWs). The energy
portion of the purchased power will be included in CPL's
reconcilable fuel expense at a fixed heat rate of 10,000
multiplied by the applicable monthly average price paid by CPL
for natural gas for each month such energy portion was
purchased during the reconciliation period. The cost of
replacement capacity will be subtracted from the reduction in
CPL's base rate revenue requirement due to divestiture in
order to determine the net reduction in revenue requirement
resulting from the divestiture. This amount is identified by
the following formula:
A + B - C + D
where:
A = seven-twelfths of the operation and maintenance
expense of the divested plants, as recorded in the
1998 FERC Form 1 for CPL;
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<PAGE> 22
B = reduction in annual depreciation and pre-tax return
due to reducing the undepreciated balance of STP
plant by the amount of the gain from divestiture;
C = replacement capacity cost for the October through
April period;
D = annual net reduction in base rate revenue
requirement from divestiture.
One-half of any positive annual net reduction in base rate
revenue requirement resulting from divestiture, as "D" is
defined in the above formula, will be used to reduce the
undepreciated balance of South Texas Project ("STP") plant,
and the remainder will be retained by the Merged Company.
H. CPL's recall right will expire once there is no longer an
obligation to serve retail customers in ERCOT. The recall
right will be reduced to the extent that CPL no longer remains
legally obligated to serve any retail customer or group of
retail customers, either existing or prospective. To the
extent that CPL retains the legal obligation to serve any
existing or prospective retail customer or group of retail
customers, the load requirements of those customers shall be
considered in determining whether the right of recall shall be
reduced. An example of how this calculation will be done under
currently proposed deregulation legislation is attached as
Attachment G.
In the event that future statutes require that the PUCT
designate a provider of last resort which must offer service
to all customers within all or designated portions of CPL's
service area, and in the event that CPL affirmatively requests
that it be so designated, the load requirements for those
customers eligible for service from CPL as a provider of last
resort shall not be considered as load requirements of retail
customers for whom CPL retains a legal obligation to serve,
solely for purposes of determining whether the right of recall
shall be reduced. In the event that CPL does not affirmatively
request designation as a provider of last resort within its
service area but is so designated by the PUCT, the load
requirements of retail customers eligible for service from CPL
as a provider of last resort shall be considered as load
requirements of retail customers for whom CPL retains a legal
obligation to service for purposes of determining whether the
right of recall shall be reduced.
I. The Merged Company agrees to divest 300 MW in SPP. No further
SPP divestiture is required.
J. Gains from the sale of the Lon Hill, Nueces Bay and Joslin
plants shall be utilized to reduce STP excess costs over
market ("ECOM"), taking into account the effects of income
taxes and reasonable transaction costs. The amount of such
gains will be deducted from the ECOM asset determined by the
Commission's Final Order on Rehearing in Docket No. 14965. At
the time of CPL's next base rate proceeding, if industry
restructuring legislation has not been adopted, then the
parties agree that the annual amortization of ECOM will be
reduced proportionately. The period over which the remaining
balance of ECOM, if any,
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<PAGE> 23
is to be amortized remains as ordered by the Commission's
Final Order on Rehearing in Docket No. 14965.
K. The Merged Company and Texas operating companies agree that no
ratepayer of a Texas operating company will be charged any new
or increased surcharge or PCRF to recover any capacity cost
resulting from divestiture provided for in Section 6 of this
Agreement. This provision does not prevent the Merged Company
from seeking recovery of capacity costs in accordance with
subparagraph 3.E of this Agreement which may be incurred
regardless of the divestiture of generating capacity required
by this Agreement.
L. Pursuant to the PUCT's statutory authority, CPL will submit
the terms of the divestiture of its plants to the PUCT for
approval.
M. Prior to December 31, 2000, the Applicants agree that AEP will
file with the FERC an unconditional application to, consistent
with the Regional Transmission Organization ("RTO") agreement,
transfer the operational control of bulk transmission
facilities owned, controlled and/or operated by AEP currently
located in the SPP to a FERC-approved RTO directly
interconnected with the AEP transmission facilities. The above
date is extended, if necessary, to 75 days after FERC issues
the order on an RTO to which AEP is a signatory that is filed
before June 30, 2000. Applicants agree to pursue any FERC
filings made pursuant to this paragraph in good faith using
their best efforts to obtain prompt FERC approval.
7. Quality of Service
A. Customer Service Standards.
These guidelines establish customer service performance
standards that should be achieved by the Merged Company. The
Merged Company shall make measurements to determine the level
of service quality for each item included in these guidelines.
The Merged Company shall provide the PUCT with the
measurements and summaries thereof for any of the items
included herein on request of the PUCT. Records of these
measurements and summaries shall be retained by the Merged
Company.
(1) Service Turn On and Upgrades: On a quarterly basis,
the Merged Company shall complete the installation of
new service or upgrade of service as follows:
(a) Ninety-five percent of new service
installations requiring no construction of
electric facilities shall:
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<PAGE> 24
(i) be completed within 24 hours after
the customer's service location is
ready for service and all necessary
tariff requirements have been met;
(ii) be completed by the requested
installation date, when an applicant
requests an installation date more
than 24 hours after the customer's
service location is ready for
service and all necessary tariff
requirements have been met.
(b) Ninety percent of new service installations
requiring construction of electric
facilities, including the setting of the
meter, and ninety percent of service
upgrades, shall:
(i) be completed within 10 business days
after the customer's service
location is ready for service and
all necessary tariff and local
regulation requirements have been
met;
(ii) be completed by the requested
installation date, when an applicant
or customer requests an installation
date more than ten business days
after the customer's service
location is ready for service and
all necessary tariff requirements
have been met;
(iii) provided that this standard shall
not apply to an extension that
involves the construction of
non-standard facilities.
Non-standard conditions for
extension requirements are
characterized by one of the
following factors: (a) the service
installation requires underground
feeder construction of more than
300 feet in length or (b) the
service installation requires
construction of more than 1320 feet
of single phase line in the service
area of WTU, or more than 900 feet
of single phase line in the service
areas of CPL or SWEPCO.
Service installation requiring line
extensions that involve
non-standard facilities shall be
completed within ninety (90) days,
unless circumstances beyond the
Company's control cause unavoidable
delays;
(iv) provided, further, that this
standard will be tolled for all
requests for service for the
duration of any "major event" as
defined in Substantive Rule
25.52(c)(2)(D).
c. If an applicant/customer complies with all
pertinent tariff requirements and the
electric distribution company cannot
complete the requested service installation
or service upgrade as
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<PAGE> 25
set forth above, the company shall promptly
notify the applicant/customer of the delay,
the reasons for the delay, the steps being
taken to complete the work, and the probable
completion date. If such probable completion
date cannot be met, repeat notification
shall be made.
d. Penalty for failure to meet this standard:
the Merged Company will rebate, on a
quarterly basis, via bill credit $40 for
each customer not connected within the time
frames stated above.
(2) Light Replacements. In any distribution substation
service area, 95 percent of all customer reports of
security and streetlight outages shall be corrected
within 72 hours. Light replacement compliance will be
measured on a calendar month basis. This standard
will be tolled for all customer reports for the
duration of any "major event," as defined in
Substantive Rule 25.52(c)(2)(D).
(3) Telephone Response. On an annual basis, the call
center's average answer time for customer calls shall
not exceed sixty seconds.
a. As used in this paragraph, "answer" means
the operator, service representative, or
automated system is ready to render
assistance and/or accept the information
necessary to process the call.
b. Answer time shall be measured from the first
ring at the call center or at the point the
customer begins to wait in queue, whichever
comes first.
c. If the Merged Company utilizes a menu
driven, automated, interactive answering,
the initial recorded message presented by
the system to the customer shall only
identify the company and the general options
available to the customer, including the
option of being transferred to a live
attendant. At any time during the call, the
customer shall be transferred to a live
attendant if the customer fails to interact
with the system for a period of ten seconds
following any prompt.
d. Customers shall not be delayed from reaching
the queue by any promotional or
merchandising material not selected by the
customer.
e. Performance data during a "major event" (as
such term is defined in Substantive Rule
25.52(c)(2)(D)) or comparable term as such
is used by the electric distribution company
in its emergency plan, and subject to review
and acceptance by the PUCT, shall be
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<PAGE> 26
excluded from the calculation of annual
minimum service value pursuant to this
subparagraph (3).
f. Penalty for failure to meet this standard.
The Merged Company will rebate, via a bill
credit, on an annual basis, $20 for each
verifiable customer who does not receive
service within the standard's parameters,
limited to one $20 credit per customer per
month of service. For customers who cannot
be verified, the Merged Company will
contribute the $20 to a fund to benefit
low-income customers.
(4) Reporting requirements.
a. When the Merged Company does not meet any
minimum service standards concerning
Response to Request for Service and Customer
Service Call Center for any two months
within any twelve-month period, the company
shall notify the PUCT Office of Customer
Protection in writing within fifteen days
after internal measurements have disclosed
such failure. The company shall submit a
report of any remedial action taken to the
Office of Customer Protection within an
additional thirty days.
b. The Merged Company shall conduct
statistically valid customer service surveys
of Texas customers annually. The results of
the survey shall be compiled by the utility
and reported to the PUCT Office of Customer
Protection under confidential or other
protected designations if required to
protect sensitive information.
c. The Merged Company shall submit an Annual
Customer Service Report to the PUCT Office
of Consumer Protection that addresses
customer service issues such as number of
customer complaints, performance of the call
center, performance of field personnel,
billing error rates, etc.
d. The Merged Company shall provide an Annual
Utility Scorecard to its customers that
addresses issues such as number of customer
complaints, performance of the call center,
performance of field personnel, billing
error rates, etc.
e. The Merged Company shall maintain records
sufficient to demonstrate compliance with
these standards and shall provide such
records to the PUCT upon request.
B. Reliability. The intent of the reliability provisions set out
below is for the Merged Company to comply with the provisions
of the PUCT rules adopted in Project No. 19198.
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<PAGE> 27
(1) General Provisions.
a. The standards are to be consistent with PUCT
Substantive Rule 25.52 (Reliability and
Continuity of Service).
b. Reporting periods are to be consistent with
PUCT Substantive Rule 25.81 (Service Quality
Reports) and are to coincide with the
Applicants' Electric System Service Quality
Report to the PUCT. Annual evaluations will
be for the 12-month period ending April 30
of each year. Initial evaluation will be for
the reporting period ending April 30, 2001.
c. Reliability indices are calculated for
"forced interruptions" unless otherwise
specified.
d. The standards will be calculated and
evaluated separately for the Texas
operations of each CSW operating company
(CPL, SWEPCO and WTU).
(2) 90% Distribution Feeder Standards. The following
reliability standards for System Average Interruption
Frequency Index ("SAIFI") and System Average
Interruption Duration Index ("SAIDI") shall be
established for distribution feeders for each CSW
operating company:
a. Standards shall be established for the
24-month period ending April 30, 1999. The
standards shall be the average of the 1998
and the 1999 reporting years for each index
at the value represented by the 10% of the
distribution feeders with the highest
values.
b. Reliability of distribution feeders
performing below the standard shall be
improved, resulting in 96% of the feeders
performing at or better than the standard in
the 2001 reporting period.
(3) 2% Distribution Feeder Standards. Each CSW operating
company shall manage its distribution feeders so that
no distribution feeder shall sustain 12-month SAIDI
or SAIFI values that are among the highest (worst)
2.0% of that company's feeders for two or more
consecutive reporting years.
(4) System Standards. System-wide service reliability
standards shall be established for each CSW operating
company as follows:
a. SAIFI Standard - System Average Interruption
Frequency Index Average SAIFI for 3-year
reporting period 5/1/97-4/30/00.
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<PAGE> 28
b. SAIDI Standard - System Average Interruption Duration
Index Average SAIDI for 3-year reporting period
5/1/97-4/30/00.
c. As of April 30, 2001, maintain annual system-wide
SAIFI and SAIDI values at or better than 105% of the
standard.
(5) Guarantees to Meet Reliability Standards.
a. The Annual service reliability guarantees for the CSW
operating companies will be as follows:
<TABLE>
<CAPTION>
Operating Company Dollar Amount % of Total
----------------- ------------- ----------
<S> <C> <C>
CPL $3,000,000 71.4%
SWEPCO 700,000 16.7%
WTU 500,000 11.9%
--------- ---------- -----
Total CSW $4,200,000 100%
</TABLE>
b. The guarantees will be credited to customers based
upon the following priorities:
(i) 90% Distribution Feeder Standards;
(ii) 2% Distribution Feeder Standards;
(iii) System Standards.
c. Terms of Guarantees:
(i) 90% Distribution Feeder Standards
(a) A service reliability credit of $20
shall be made to each customer on
all feeders violating the 96%
provision of the rule. (For
example, if only 95% of the feeders
perform at or better than the 90%
standard, a credit will be made to
customers on 5% of the feeders.) A
separate credit will be made for
each standard violated (SAIDI and
SAIFI) such that a customer on a
feeder violating both standard
would be credited $40. This credit
will not be made for feeders that
perform at the system average times
two. The sum of these credits will
not exceed the maximum amount of
the service reliability guarantees
stated above.
(b) If a CSW operating company achieves
the SAIDI and/or SAIFI 90%
Distribution Feeder Standards for a
reporting period (i.e., 96% of the
feeders perform at or better than
the 90% standard), the
23
<PAGE> 29
total amount of guarantees will be
reduced in the following amounts
for each standard achieved: CPL,
$357,000; SWEPCO, $83,500; and WTU,
$59,500 (which total $500,000)
(such that the amount of the
reduction will be equal to twice
that amount if both standards are
achieved). The reduction of
guarantees will decrease the
exposure the operating company may
have with respect to the 90%
Distribution Feeder Standards, the
2% Distribution Feeder Standards or
the System Standards for that
reporting year.
(ii) 2% Distribution Feeder Standards.
(a) A service reliability credit of $50
shall be made to each customer on a
feeder violating either standard. A
separate credit will be made for
each standard violated (SAIDI
and/or SAIFI) such that a customer
on a feeder violating both
standards would be credited $100.
These credits will be prorated if
the guarantees for this provision
plus the guarantees for the 90%
Distribution Feeder Standard exceed
the total guarantees expressed
above as calculated for each CSW
operating company.
(b) If a CSW operating company achieves
the SAIDI and/or SAIFI 2%
Distribution Feeder Standards for a
reporting period (i.e., no feeders
repeat on the 2% list), the total
amount of guarantees will be
reduced in the following respective
amounts for each standard achieved:
CPL, $357,000; SWEPCO, $83,500; and
WTU, $59,500 (which total $500,000)
(such that the amount of the
reduction will be equal to twice
that amount if both standards are
achieved). The reduction of
guarantees will decrease the
exposure the operating company may
have with respect to the 2%
Distribution Feeder Standards or
the System Standards for the
reporting year.
(iii) System Standards. In the event an operating
company's system SAIDI and/or SAIFI values
exceed the allowable limit of 105% of the
36-month standard described above, the
company shall credit the guarantees
proportionately among all customers on the
company's Texas system as follows:
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<PAGE> 30
(a) SAIDI: The guarantee will be the
numerical difference between the
actual and allowable SAIDI values
(measured in minutes) multiplied by
10,000, up to a maximum of the
lower of (i) the total remaining
guarantee described above for each
operating company or (ii) the
following amounts for each
respective company: CPL, $749,700;
SWEPCO, $175,350; and WTU, $124,950
(which total $1.05 million, or 25%
of the total guarantee described
above).
(b) SAIFI: The guarantee will be the
numerical difference between the
actual and allowable SAIFI values
multiplied by 1 million, up to a
maximum of the lower of (i) the
total remaining guarantee described
above for each operating company or
(ii) the following amounts for each
respective company: CPL, $749,700;
SWEPCO, $175,350; and WTU, $124,950
(which total $1.05 million, or 25%
of the total guarantee described
above).
(c) If a CSW operating company achieves
either the SAIDI or SAIFI System
Standard for a reporting period
(i.e., performance at or below 105%
of the standard), the amount of the
guarantees will be reduced in the
following amounts: CPL, $357,000;
SWEPCO, $83,500; and WTU, $59,500
(which total $500,000). The
reduction of guarantees will
decrease any exposure the operating
company may have with respect to
the other System Standard for that
reporting year.
C. PUCT Office of Customer Protection ("OCP") audit.
Twenty-four months after the customer service objectives and
performance standard levels are implemented by the Merged
Company, and every twenty-four months thereafter, the PUCT
Office of Customer Protection shall conduct an independent
audit to determine whether the proposed performance standards
have been implemented.
The PUCT Office of Customer Protection shall file a report
detailing any areas where the Merged Company did not
accurately report instances where the performance standard
levels were not met, or failed to accurately account for every
penalty required by these guidelines.
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<PAGE> 31
D. Term of Standards.
(1) The customer service standards established under this
agreement shall remain in effect for a period of six
(6) years following the effective date of the merger.
Reporting periods for all standards will coincide
with the Electric System Service Quality Report to
the Commission. The initial evaluation will be for
the reporting period ending April 30, 2001.
(2) Any interested person shall have the right to
petition the Commission to revise the standard and/or
penalties described herein. 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.
8. Low Income Program. The Merged Company commits to the Low-Income
Program described below for six years, until the next base rate case of
each operating company, or until the Low-Income Program is evaluated in
accordance with provisions of restructuring legislation. The PUCT will
have the ability to review the Low-Income Program in accordance with
the next base rate case of each operating company or in accordance with
the provisions of restructuring legislation and may continue such
programs to the extent cost recovery is provided.
A. CPL, SWEPCO and WTU commit to continue funding of low-income
DSM programs at current levels for the full six-year term of
the merger savings sharing plan unless otherwise revised by
the PUCT.
Current HomeSavers program funding commitments:
<TABLE>
<S> <C>
CPL $1,365,000
SWEPCO 400,000
WTU $ 325,000
------------
Total $2,090,000
</TABLE>
Funds not utilized by the HomeSavers program during the
current contract year and in future years shall be carried
forward during the six-year merger savings sharing period.
B. Each operating company shall conduct an annual review meeting
for low-income program expenditures and to recommend any
changes in program design and outreach. Representative of the
PUCT, the Low-Income Intervenors and OPC will participate in
the annual meeting. Interim spending reports for low-income
programs shall be provided on a quarterly basis to PUCT staff,
Low-Income Intervenors and OPC.
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<PAGE> 32
C. CPL, SWEPCO and WTU shall each commit an additional annual
budget of $100,000 to unspecified low-income DSM programs
approved by the Commission. Representatives of the Commission,
Low Income Intervenors and OPC shall be given an opportunity
to participate in formulating a list of low-income DSM
programs recommended for Commission approval. These funds will
be used for DSM programs to benefit low-income customers
living in public housing, Section 8 multifamily housing,
housing funded by Habitat for Humanity, homeless shelters, and
any other energy efficiency programs that benefit low-income
customers.
D. CPL and SWEPCO will continue their Neighbor to Neighbor
programs that provide billing assistance to low-income
customers. WTU shall implement a Neighbor to Neighbor program.
WTU will work with Texas Legal Services Centre to implement
such a program through a third party administrator.
Minimum annual funding for each Neighbor to Neighbor program
shall be as follows:
<TABLE>
<S> <C>
CPL $250,000
SWEPCO $100,000
WTU $100,000
----------
$450,000
</TABLE>
These minimum-funding levels will be in addition to any
customer contributions to the programs.
9. Other Provisions
A. Pending rate litigation will be resolved as provided in
Attachment H. Each individual year's rate reduction will apply
for a twelve month period following the effective date of the
merger with the last decrease continuing to apply in years
following the end of year six until base rates for the Texas
operating company are changed.
B. The Merged Company commits and agrees that:
(i) 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; and
(ii) upon execution of any written agreement settling
merger issues, any of which provide merger benefits
to ratepayers of any jurisdiction or impose merger
conditions on the Merged Company that would benefit
the ratepayers of any jurisdiction, such set benefits
and conditions will be extended to Texas retail
customers to the extent necessary to achieve
equivalent net benefits and conditions to the Texas
retail customers,
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<PAGE> 33
provided the proposed merger is ultimately
consummated. The Merged Company will file with the
PUCT and provide all Signatories a copy of all final
orders from all jurisdictions, and serve all executed
settlement agreements on General Counsel, within 10
days of execution of the same. Any action by a
Signatory to enforce the most favored nations
provision of this stipulation will not trigger any
rate treatments illustrated in Attachment F, and the
Attachments A and H rate credits will remain in
place.
C. Excluding positions at the three divested plants after the
date of divestiture, the Merged Company will freeze operating
company field positions and customer service jobs for eighteen
months from April 1, 1999. The Merged Company will not make
any terminations, layoffs, or reassignments, unless the
reassignment is to Central and South West Services, Inc.
("CSWS") or its successor and the employee performs the same
job as before the reassignment, except for CSWS or its
successor rather than for the operating company.
D. If electric utility restructuring legislation is adopted, the
Merged Company commits to file a one-time customer Education
Program with the PUCT for approval by the OCP within 90 days
of the effective date of the merger or the legislation,
whichever is later. The Customer Education Program will be
designed to provide information about electric industry
restructuring and retail competition. The program will be
designed and implemented for all of the Merged Company's Texas
customers. The program will include, but is not limited to, an
Internet web site, mailers which include information such as
frequently asked questions and answers, newspaper articles,
press releases, and advertisements. The Merged Company should
spend an amount up to $750,000 per year for two years on the
customer Education Program. The Signatories agree not to
oppose, to the extent consistent with any applicable electric
industry restructuring legislation, inclusion of these amounts
of customer education expenditures for purposes of compliance
with future statutes or rules requiring consumer education
advertising.
E. This agreement is binding on the Office of the Attorney
General only in its capacity as a representative of state
agencies as consumers of electric service. By signing this
agreement, the State of Texas is in no way waiving any of its
rights or settling any potential claims pursuant to the Texas
Free Enterprise and Antitrust Act of 1983, TEX. BUS. & COM.
CODE Sections 15.01-.52.
The approval of this Integrated Stipulation and Agreement by
the Steering Committee of the Cities of Corpus Christi,
McAllen, Victoria, Big Lake, Paducah and Vernon is conditioned
to the right of individual cities to reconsider their prior
approval of the November 3, 1998 Stipulation and Agreement and
reject the Integrated Stipulation and Agreement within thirty
(30) days of the execution of this document.
28
<PAGE> 34
F. The Merged Company commits to coordinate transmission and
distribution substation planning with transmission dependent
utilities to provide reliable service, to maximize use of
existing facilities, and to avoid expenditures for duplicative
facilities. The process will include:
(1) Period meetings to discuss requirements for
facilities that are mutually beneficial;,
(2) A commitment by the Merged Company to provide
resources and information to the appropriate regional
ISO or regulatory authority to assist in their
evaluations of facility requirements; and
(3) An opportunity to utilize alternative dispute
resolution processes, as defined either by PUCT rules
(within ERCOT) or SPP tariffs or procedures (within
the SPP) or by the procedures of future entities
which exercise operational control over the
transmission systems.
G. The Merged Company will maintain a bargaining and
decision-making presence in the current CSW region with
authority to negotiate, deal and enter into binding agreements
with its present and potential Texas wholesale and
transmission customers (including interconnection agreements).
The threshold for such authority will be at least $3 million.
H. The Merged Company and the Texas operating companies may
consider increasing the level of contributions to low income
programs so long as the contributions do not adversely affect
the rate credits and reductions agreed to in this proceeding
or result in any new surcharge or PCRF or an increase in any
existing surcharge or PCRF.
I. The Merged Company and Texas operating companies will create
an internal accounting mechanism to reflect AEP use of
existing CSW sulfur dioxide ("SO2") allowances. Such use will
be valued at market value and gains and losses realized in
comparison to original cost of allowances in excess of amounts
included in base rates will be reflected as reconcilable fuel
costs. SO2 allowance transactions among existing AEP operating
companies will be as per existing agreements.
J. The Merged Company commits and agrees that the cost of capital
as reflected in CPL's, WTU's, and SWEPCO's rates shall not be
increased or adversely affected as a result of AEP's
acquisition of CSW. The Merged Company also agrees that
subsequent to the completion of the merger, the cost of
capital for CPL, WTU and SWEPCO should be set commensurate
with the risk of those utilities and should not be affected by
the merger. The Merged Company agrees that it will not oppose,
in either a regulatory proceeding or an appeal, 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 CPL, WTU and SWEPCO.
29
<PAGE> 35
K. The Merged Company has no plans to liquidate, sell, merge, or
consolidate any Texas operating company or to materially
change any Texas operating company's investment policy,
business or corporate structure, or management. The Merged
Company agrees that the Texas operating companies will
continue to operate subject to the jurisdiction and regulation
of the PUCT after closing of the proposed merger. The Merged
Company agrees that the financial stability of the Texas
operating companies will not be impaired or jeopardized by the
merger and the interests of Texas customers will not be
prejudiced as a result of the merger. Nothing in this
agreement shall be construed to limit whatever rights the
Merged Company may have under applicable Texas law to
liquidate, sell, merge, or consolidate any Texas operating
company or to materially change any Texas operating company's
investment policy, business or corporate structure, or
management subject to required regulatory approvals.
L. The Merged Company shall provide written notice on the day of
closing to the Signatories and non-opposing parties that the
merger closing has occurred.
M. Any and all exhibits and testimony submitted by Signatories in
this docket will be offered for the purpose of supporting this
Agreement. Signatories reserve their full rights to challenge
any and all exhibits and testimony offered in this proceeding
by any party for any purpose other than support of this
Agreement. This includes the right to object to the admission
of such evidence and the right of cross-examination.
N. This Agreement is binding on each Signatory only for the
purpose of settling the issues herein and for no other
purpose. The Signatories acknowledge and agree that a
Signatory's support of the matters contained in this Agreement
may differ from its position or testimony in other dockets and
cases not referenced in this Agreement. To the extent that
there is a difference, a Signatory does not waive its position
in such other dockets. Because this is a settlement agreement,
a Signatory is under no obligation to take the same position
as set out in this Agreement in other dockets not referenced
in this Agreement whether those dockets present the same or a
different set of circumstances. The Signatories reserve their
rights in this docket to litigate all issues in this docket
against parties who do not sign this Stipulation.
O. This Agreement represents a compromise, settlement and
accommodation among the Signatories, and all Signatories agree
that the terms and conditions herein are interdependent and no
Signatory shall be bound by any portion of this Agreement
outside the context of the Agreement as a whole. If the PUCT
does not accept this Agreement in any material respect as
issued, the Signatories agree that any Signatory adversely
affected by that material modification or inconsistency has
the right to withdraw its consent from this Agreement, thereby
becoming released from all commitments and obligations, and to
proceed to hearing on all issues, present evidence, and
advance any positions it desires as if it had not been a
Signatory. If the PUCT does not adopt appropriate orders
consistent with the material terms of this Agreement, the
Signatories agree that neither oral nor
30
<PAGE> 36
written statements made during the course of the settlement
negotiations, nor the terms of this Agreement may be used as
an admission or concession of any sort nor as evidence in any
proceeding. This obligation shall continue and be enforceable,
even if this Agreement is terminated.
P. Implementation of the actions contemplated in this Agreement
is subject to PUCT approval of this Agreement and consummation
of the AEP/CSW merger.
Q. This Agreement expires six years from the effective date of
the merger.
R. Nothing in this Agreement shall limit the statutory power of
any regulatory authority to adjudicate a contested case
brought before it.
S. This written agreement contains the entire understanding and
agreement of the Signatories, supersedes all other written and
oral exchanges, or arrangements or negotiations among them or
their representatives with respect to the subjects contained
herein; and neither this Agreement, nor any of the terms of
this Agreement, may be altered, amended, waived, terminated,
discharged or modified, except by a writing properly executed
by the Signatories.
T. The Signatories mutually agree that they enter into this
Agreement for their exclusive benefit and the benefit of their
respective lawful successors. The Signatories agree that
nothing in this Agreement shall be construed to confer any
right, privilege or benefit on any person or entity other than
the Signatories and their respective lawful successors.
U. This Agreement assumes the legality of the treatments and
methodologies set out herein. Should any treatment or
methodology used be declared illegal by either the PUCT or a
court, the Signatories agree to negotiate in good faith to
substitute a treatment or methodology with the same economic
effect of that declared illegal.
V. The titles assigned to each Article are for convenience only,
are not part of this Agreement and shall not be considered in
the resolution of any dispute or question arising with respect
to this Agreement.
W. Each signing representative warrants that he or she is duly
authorized to sign this Agreement on behalf of the Signatory
he or she represents. Facsimile copies of signatories are
valid for purposes of evidencing execution.
X. The Signatories may sign individual signature pages to
facilitate the circulation and filing of the original of this
Agreement.
31
<PAGE> 37
IN WITNESS WHEREOF, this Agreement has been executed, approved and
agreed to by the Signatories hereto in multiple counterparts each of which shall
be deemed an original, on the date indicated below by the Signatories hereto, by
and through their undersigned duly authorized representatives. This Agreement
shall be effective and binding, as to each Signatory, as of the date of
execution of each Signatory.
AMERICAN ELECTRIC POWER GENERAL COUNSEL OF THE PUBLIC
COMPANY INC. UTILITY COMMISSION OF TEXAS
By: /s/ Walter Demond By: /s/ Thomas S. Hunter
------------- ----------------
Walter Demond Thomas S. Hunter
Title: Title: Assistant General Counsel
Date: Date:
CENTRAL AND SOUTH WEST STATE OF TEXAS
CORPORATION
By: /s/ Philip F. Ricketts By: /s/ Bryan Baker
---------------------- ---------------
Philip F. Ricketts Bryan Baker
Title: Title: Assistant Attorney General
Date: Date:
OFFICE OF PUBLIC UTILITY TEXAS INDUSTRIAL ENERGY
COUNSEL CONSUMERS
By: /s/ James K. Rourke, Jr. By: /s/ C. Lane Mears
------------------------ -----------------
James K. Rourke, Jr. C. Lane Mears
Title: Assistant Public Counsel Title:
Date: Date:
32
<PAGE> 38
STEERING COMMITTEE OF THE LOW INCOME INTERVENORS
CITIES OF MCALLEN, CORPUS
CHRISTI, VICTORIA, ABILENE, BIG
LAKE, VERNON, PADUCAH
By: /s/ Geoffrey Gay By: /s/ Neish Carroll
---------------- -----------------
Geoffrey Gay Neish Carroll
Title: Attorney Title: Attorney
Date: Date:
33
<PAGE> 39
Attachment A to
Integrated Stipulation and Agreement
AEP/CSW Merger
Net Merger Savings Rate Reduction Rider(1)
NET MERGER SAVINGS RATE REDUCTION RIDER AMOUNTS
<TABLE>
<CAPTION>
YEAR CPL SWEPCO WTU TOTAL
---- --- ------ --- -----
(Thousands)
<S> <C> <C> <C> <C>
Year 1 $ 3,663 $ 1,127 $ 1,053 $ 5,843
Year 2 6,999 2,107 2,015 11,121
Year 3 8,841 2,670 2,582 14,093
Year 4 10,212 3,110 3,040 16,362
Year 5 11,180 3,417 3,349 17,946
Year 6 11,827 3,639 3,591 19,058
------- ------- ------- -------
Total $52,722 $16,070 $15,630 $84,423
------- ------- ------- -------
</TABLE>
- ------------------
(1) See Attachment J for the total allocation of rate reduction riders set out
in Attachments A and H.
<PAGE> 40
Attachment B to
Integrated Stipulation and Agreement
AEP/CSW Merger
Net Merger Savings Expense Adjustment
For Inclusion in Cost of Service
NET MERGER SAVINGS EXPENSE AMOUNTS
<TABLE>
<CAPTION>
YEAR CPL SWEPCO WTU TOTAL
---- --- ------ --- -----
(Thousands)
<S> <C> <C> <C> <C>
Year 1 $ 5,982 $ 1,844 $ 1,713 $ 9,539
Year 2 12,653 3,806 3,636 20,095
Year 3 16,337 4,931 4,769 26,037
Year 4 19,080 5,811 5,686 30,577
Year 5 21,016 6,424 6,304 33,744
Year 6 22,309 6,868 6,787 35,964
-------- -------- -------- ---------
Total $ 97,377 $ 29,684 $ 28,895 $ 155,956
-------- -------- -------- ---------
</TABLE>
<PAGE> 41
Attachment C to
Integrated Stipulation and Agreement
Page 1 of 2
AEP/CSW Merger
Amortization of Costs to Achieve
TRANSITION AND TRANSACTION COST AMORTIZATION
<TABLE>
<CAPTION>
YEAR CPL SWEPCO WTU TOTAL
---- --- ------ --- -----
(Thousands)
<S> <C> <C> <C> <C>
Year 1 $ 4,832 $ 1,470 $ 1,418 $ 7,720
Year 2 4,832 1,470 1,418 7,720
Year 3 4,832 1,470 1,418 7,720
Year 4 4,832 1,470 1,418 7,720
Year 5 4,832 1,470 1,418 7,720
Year 6 4,832 1,470 1,418 7,720
-------- ------- ------- --------
Total $ 28,992 $ 8,820 $ 8,508 $ 46,320
-------- ------- ------- --------
</TABLE>
CHANGE-IN-CONTROL AMORTIZATION
<TABLE>
<CAPTION>
YEAR CPL SWEPCO WTU TOTAL
---- --- ------ --- -----
(Thousands)
<S> <C> <C> <C> <C>
Year 1 $1,334 $ 409 $ 394 $ 2,147
Year 2 1,334 409 394 2,147
Year 3 1,334 409 394 2,147
Year 4 1,334 409 394 2,147
Year 5 1,334 409 394 2,147
Year 6 1,334 409 394 2,147
------ ------- ------- --------
Total $8,064 $ 2,454 $ 2,364 $ 12,882
------ ------- ------- --------
</TABLE>
<PAGE> 42
Attachment C to
Integrated Stipulation and Agreement
Page 2 of 2
TOTAL COST TO ACHIEVE AMORTIZATION
<TABLE>
<CAPTION>
YEAR CPL SWEPCO WTU TOTAL
---- --- ------ --- -----
(Thousands)
<S> <C> <C> <C> <C>
Year 1 $ 6,176 $ 1,879 $ 1,812 $ 9,867
Year 2 6,176 1,879 1,812 9,867
Year 3 6,176 1,879 1,812 9,867
Year 4 6,176 1,879 1,812 9,867
Year 5 6,176 1,879 1,812 9,867
Year 6 6,176 1,879 1,812 9,867
-------- -------- -------- --------
Total $ 37,056 $ 11,274 $ 10,872 $ 59,202
-------- -------- -------- --------
</TABLE>
<PAGE> 43
Attachment E to
Integrated Stipulation and Agreement
AEP/CSW Merger
REVENUE REQUIREMENTS CREDIT
<TABLE>
<CAPTION>
YEAR CPL SWEPCO WTU TOTAL
---- --- ------ --- -----
(Thousands)
<S> <C> <C> <C> <C>
Year 1 $ 2,319 $ 718 $ 659 $ 3,696
Year 2 5,654 1,698 1,621 8,973
Year 3 7,496 2,261 2,187 11,944
Year 4 2,554 779 771 4,104
Year 5 3,038 932 926 4,896
Year 6 3,361 1,043 1,046 5,450
-------- ------- ------- --------
Total $ 24,422 $ 7,431 $ 7,210 $ 39,063
-------- ------- ------- --------
</TABLE>
<PAGE> 44
Attachment D to
Integrated Stipulation and Agreement
American Electric Power Company, Inc.
and Central and South West Corporation
Texas Retail Gross Merger Savings
Source: Roberson Exhibit MDR-1 Converted to Calendar Year
Amounts in Dollars
<TABLE>
<CAPTION>
Year CPL SWEPCO WTU
---- --- ------ ---
<S> <C> <C> <C>
Year 1 12,158,351 3,722,895 3,524,846
Year 2 18,829,238 5,684,479 5,448,585
Year 3 22,513,700 6,809,739 6,581,266
Year 4 25,256,296 7,689,677 7,498,009
Year 5 27,192,785 8,303,151 8,115,701
Year 6 28,485,394 8,747,580 8,598,207
Year 7 29,580,313 9,116,169 8,967,591
Year 8 30,061,345 9,318,729 9,189,807
Year 9 30,895,061 9,608,775 9,455,822
Year 10 31,651,550 9,880,562 9,718,245
----------- ---------- ----------
Total 256,624,032 78,881,755 77,098,137
----------- ---------- ----------
</TABLE>
<PAGE> 45
<TABLE>
<CAPTION>
AEP/CSW Merger Attachment F to
Example of Application of Rate Integrated Stipulation and Agreement
Treatment of Merger Savings and Expense Page 1 of 3
Central Power and Light Company
Rate Case Initiated By The Company
Revenue Requirements Impact
------------------------------------------------------------------------------------------------
Net Merger
Savings Net Merger Amortization Net Revenue Net
Rate Savings Of Costs Revenue Requirements Base Rate
Rider Achieved Expense Adj. To Achieve Requirements Credit Impact
Year (Attach. A) Savings (a) (Attach. B) (Attach. C) (2)-(3)-(4) (Attach. E) (5)-(6)
---- ----------- ----------- ----------- ----------- ----------- ----------- -------
(1) (2) (3) (4) (5) (6) (7)
<S> <C> <C> <C> <C> <C> <C>
Year 1 $ (3,663)
Year 2 (6,999) Not applicable due to rate cap unless a force majeure proceeding is initiated under Sec. 3. F.
Year 3 (8,841)
Year 4 (10,212) (25,256) 19,080 6,176 - 2,554 (2,554)
Year 5 (11,180) (27,193) 21,016 6,176 - 3,038 (3,038)
Year 6 (11,827) (28,486) 22,309 6,176 - 3,361 (3,361)
----------- ------------- ------------- ------------ ------------- ------------
Total $ (52,722) $ (80,934) $ 62,405 $ 18,529 - $ 8,952 $ (8,952)
----------- ------------- ------------- ------------ ------------- ------------ ------------
</TABLE>
<TABLE>
<CAPTION>
Revenue Requirements Impact
---------------------------------------------
Rate Rate Total
Reduction Reduction Rate
Rider Rider Impact
Year (Table H-1) (Table H-2) (1)+(7)+(8)+(9)
---- ----------- ----------- ---------------
(8) (9) (10)
<S> <C> <C> <C>
Year 1 $ (15,337) $ (4,807) $ (23,807)
Year 2 (12,001) (4,807) (23,807)
Year 3 (10,159) (4,807) (23,807)
Year 4 - (4,807) (17,573)
Year 5 - (4,807) (19,025)
Year 6 - (4,807) (19,995)
------------ ------------ ------------
Total $ (37,497) $ (28,842) $ (128,014)
------------ ------------ ------------
</TABLE>
Rate Case Initiated By A Signatory Other Than The Company
<TABLE>
<CAPTION>
Revenue Requirements Impact
---------------------------------------------------------------------------------------------
Merger
Savings Net Merger Amortization Net Revenue Net
Rate Savings Of Costs Revenue Requirements Base Rate
Rider Achieved Expense Adj. To Achieve Requirements Credit Impact
Year (Attach. A) Savings (a) (Attach. B) (Attach. C) (2)-(3)-(4) (Attach. E) (5)-(6)
---- ----------- ----------- ----------- ----------- ----------- ----------- -------
(1) (2) (3) (4) (5) (6) (7)
<S> <C> <C> <C> <C> <C> <C> <C>
Year 1 $ (3,663)
Year 2 (6,999) Not applicable due to rate freeze.
Year 3 (8,841) (22,514) 16,337 6,176 - - -
Year 4 (10,212) (25,256) 19,080 6,176 - - -
Year 5 (11,180) (27,193) 21,016 6,176 - - -
Year 6 (11,827) (28,486) 22,309 6,176 - - -
----------- ------------- ------------- ------------ ------------- ------------ ------------
Total $ (52,722) $ (103,448) $ 78,742 $ 24,705 - $ - $ -
----------- ------------- ------------- ------------ ------------- ------------ ------------
</TABLE>
<TABLE>
<CAPTION>
Revenue Requirements Impact
---------------------------------------------
Rate Rate Total
Reduction Reduction Rate
Rider Rider Impact
Year (Table H-1) (Table H-2) (1)+(7)+(8)+(9)
---- ----------- ----------- ---------------
(8) (9) (10)
<S> <C> <C> <C>
Year 1 $ (15,337) $ (4,807) $ (23,807)
Year 2 (12,001) (4,807) (23,807)
Year 3 (10,159) (4,807) (23,807)
Year 4 (8,788) (4,807) (23,807)
Year 5 (7,820) (4,807) (23,807)
Year 6 (7,173) (4,807) (23,807)
------------ ------------ ------------
Total $ (61,278) $ (28,842) $ (142,842)
------------ ------------ ------------
</TABLE>
Note (a) Achieved savings are the reduction in cost of service from gross merger
savings as shown in Roberson Exhibit MDR-1.
<PAGE> 46
<TABLE>
<CAPTION>
AEP/CSW Merger Attachment F to
Example of Application of Rate Integrated Stipulation and Agreement
Treatment of Merger Savings and Expense Page 2 of 3
Southwestern Electric Power Company
Rate Case Initiated By The Company
Revenue Requirements Impact
-----------------------------------------------------------------------------------------------
Net Merger
Savings Net Merger Amortization Net Revenue Net
Rate Savings Of Costs Revenue Requirements Base Rate
Rider Achieved Expense Adj. To Achieve Requirements Credit Impact
Year (Attach. A) Savings (a) (Attach. B) (Attach. C) (2)-(3)-(4) (Attach. E) (5)-(6)
---- ----------- ----------- ----------- ----------- ----------- ----------- -------
(1) (2) (3) (4) (5) (6) (7)
<S> <C> <C> <C> <C> <C> <C> <C>
Year 1 $ (1,127)
Year 2 (2,107) Not applicable due to rate cap unless a force majeure proceeding is initiated under Sec. 3.
F. (4).
Year 3 (2,670)
Year 4 (3,110) (7,690) 5,811 1,879 - 779 (779)
Year 5 (3,417) (8,303) 6,424 1,879 - 932 (932)
Year 6 (3,639) (8,747) 6,868 1,879 - 1,043 (1,043)
----------- ------------- ------------- ------------ ------------- ------------ ------------
Total $ (16,070) $ (24,740) $ 19,104 $ 5,637 - $ 2,753 $ (2,753)
----------- ------------- ------------- ------------ ------------- ------------ ------------
</TABLE>
<TABLE>
<CAPTION>
Revenue Requirements Impact
---------------------------------------------
Rate Rate Total
Reduction Reduction Rate
Rider Rider Impact
Year (Table H-1) (Table H-2) (1)+(7)+(8)+(9)
---- ----------- ----------- ---------------
(8) (9) (10)
<S> <C> <C> <C>
Year 1 $ (4,873) $ (1,013) $ (7,013)
Year 2 (3,893) (1,013) (7,013)
Year 3 (3,330) (1,013) (7,013)
Year 4 - (1,013) (4,902)
Year 5 - (1,013) (5,362)
Year 6 - (1,013) (5,695)
------------ ------------ ------------
Total $ (12,096) $ (6,080) $ (36,999)
------------ ------------ ------------
</TABLE>
Rate Case Initiated By A Signatory Other Than The Company
<TABLE>
<CAPTION>
Revenue Requirements Impact
----------------------------------------------------------------------------------------------
Merger
Savings Net Merger Amortization Net Revenue Net
Rate Savings Of Costs Revenue Requirements Base Rate
Rider Achieved Expense Adj. To Achieve Requirements Credit Impact
Year (Attach. A) Savings (a) (Attach. B) (Attach. C) (2)-(3)-(4) (Attach. E) (5)-(6)
---- ----------- ----------- ----------- ----------- ----------- ----------- -------
(1) (2) (3) (4) (5) (6) (7)
<S> <C> <C> <C> <C> <C> <C> <C>
Year 1 $ (1,127)
Year 2 (2,107) Not applicable due to rate freeze.
Year 3 (2,670) (6,810) 4,931 1,879 - - -
Year 4 (3,110) (7,690) 5,811 1,879 - - -
Year 5 (3,417) (8,303) 6,424 1,879 - - -
Year 6 (3,639) (8,747) 6,868 1,879 - - -
----------- ------------- ------------- ------------ ------------- ------------ ------------
Total $ (16,070) $ (31,550) $ 24,035 $ 7,515 - $ - $ -
----------- ------------- ------------- ------------ ------------- ------------ ------------
</TABLE>
<TABLE>
<CAPTION>
Revenue Requirements Impact
---------------------------------------------
Rate Rate Total
Reduction Reduction Rate
Rider Rider Impact
Year (Table H-1) (Table H-2) (1)+(7)+(8)+(9)
---- ----------- ----------- ---------------
(8) (9) (10)
<S> <C> <C> <C>
Year 1 $ (4,873) $ (1,013) $ (7,013)
Year 2 (3,893) (1,013) (7,013)
Year 3 (3,330) (1,013) (7,013)
Year 4 (2,890) (1,013) (7,013)
Year 5 (2,583) (1,013) (7,013)
Year 6 (2,361) (1,013) (7,013)
------------ ------------ ------------
Total $ (19,931) $ (6,080) $ (42,080)
------------ ------------ ------------
</TABLE>
Note (a) Achieved savings are the reduction in cost of service from gross merger
savings as shown in Roberson Exhibit MDR-1.
<PAGE> 47
<TABLE>
<CAPTION>
AEP/CSW Merger Attachment F to
Example of Application of Rate Integrated Stipulation and Agreement
Treatment of Merger Savings and Expense Page 3 of 3
West Texas Utilities Company
Rate Case Initiated By The Company
Revenue Requirements Impact
------------------------------------------------------------------------------------------------
Net Merger
Savings Net Merger Amortization Net Revenue Net
Rate Savings Of Costs Revenue Requirements Base Rate
Rider Achieved Expense Adj. To Achieve Requirements Credit Impact
Year (Attach. A) Savings (a) (Attach. B) (Attach. C) (2)-(3)-(4) (Attach. E) (5)-(6)
---- ----------- ----------- ----------- ----------- ----------- ----------- -------
(1) (2) (3) (4) (5) (6) (7)
<S> <C> <C> <C> <C> <C> <C> <C>
Year 1 $ (1,053)
Year 2 (2,015) Not applicable due to rate cap unless a force majeure proceeding is initiated under Sec. 3.
F. (4).
Year 3 (2,582)
Year 4 (3,040) (7,498) 5,686 1,812 - 771 (771)
Year 5 (3,349) (8,116) 6,304 1,812 - 926 (926)
Year 6 (3,592) (8,599) 6,787 1,812 - 1,046 (1,046)
----------- ------------- ------------- ------------ ------------- ------------ ------------
Total $ (15,631) $ (24,212) $ 18,776 $ 5,436 - $ 2,743 $ (2,743)
----------- ------------- ------------- ------------ ------------- ------------ ------------
</TABLE>
<TABLE>
<CAPTION>
Revenue Requirements Impact
---------------------------------------------
Rate Rate Total
Reduction Reduction Rate
Rider Rider Impact
Year (Table H-1) (Table H-2) (1)+(7)+(8)+(9)
---- ----------- ----------- ---------------
(8) (9) (10)
<S> <C> <C> <C>
Year 1 $ (3,947) $ (1,013) $ (6,013)
Year 2 (2,985) (1,013) (6,013)
Year 3 (2,418) (1,013) (6,013)
Year 4 - (1,013) (4,825)
Year 5 - (1,013) (5,288)
Year 6 - (1,013) (5,652)
------------ ------------ ------------
Total $ (9,350) $ (6,080) $ (33,804)
------------ ------------ ------------
</TABLE>
Rate Case Initiated By A Signatory Other Than The Company
<TABLE>
<CAPTION>
Revenue Requirements Impact
--------------------------------------------------------------------------------------------
Merger
Savings Net Merger Amortization Net Revenue Net
Rate Savings Of Costs Revenue Requirements Base Rate
Rider Achieved Expense Adj. To Achieve Requirements Credit Impact
Year (Attach. A) Savings (a) (Attach. B) (Attach. C) (2)-(3)-(4) (Attach. E) (5)-(6)
---- ----------- ----------- ----------- ----------- ----------- ----------- -------
(1) (2) (3) (4) (5) (6) (7)
<S> <C> <C> <C> <C> <C> <C> <C>
Year 1 $ (1,053)
Year 2 (2,015) Not applicable due to rate freeze.
Year 3 (2,582) (6,581) 4,769 1,812 - - -
Year 4 (3,040) (7,498) 5,686 1,812 - - -
Year 5 (3,349) (8,116) 6,304 1,812 - - -
Year 6 (3,592) (8,599) 6,787 1,812 - - -
----------- ------------- ------------- ------------ ------------- ------------ ------------
Total $ (15,631) $ (30,793) $ 23,545 $ 7,248 - $ - $ -
----------- ------------- ------------- ------------ ------------- ------------ ------------
</TABLE>
<TABLE>
<CAPTION>
Revenue Requirements Impact
---------------------------------------------
Rate Rate Total
Reduction Reduction Rate
Rider Rider Impact
Year (Table H-1) (Table H-2) (1)+(7)+(8)+(9)
---- ----------- ----------- ---------------
(8) (9) (10)
<S> <C> <C> <C>
Year 1 $ (3,947) $ (1,013) $ (6,013)
Year 2 (2,985) (1,013) (6,013)
Year 3 (2,418) (1,013) (6,013)
Year 4 (1,960) (1,013) (6,013)
Year 5 (1,651) (1,013) (6,013)
Year 6 (1,410) (1,013) (6,016)
------------ ------------ ------------
Total $ (14,370) $ (6,080) $ (36,081)
------------ ------------ ------------
</TABLE>
Note (a) Achieved savings are the reduction in cost of service from gross merger
savings as shown in Roberson Exhibit MDR-1.
<PAGE> 48
Attachment G to
Integrated Stipulation and Agreement
In the event that future statutes provide that, upon the commencement
to customer choice, CPL is not required to serve large commercial and industrial
customers having loads above 1000 KW (which at the current time constitutes 550
MW of load), that amount would be deducted from CPL's recall right of 1354 MW on
the date customer choice begins. Assuming CPL's large commercial and industrial
load does not change, CPL's buyback rights would be 804 MW (1354 MW - 550 MW).
However, if CPL is involuntarily designated as a provider of last resort and
under the new statute must offer a provider of last resort service to large
commercial and industrial customers, its recall rights would not be diminished
because it retains the legal obligation to serve those customers.
<PAGE> 49
Attachment H to
Integrated Stipulation and Agreement
Page 1 of 3
Settlement of Pending and Potential Rate Litigation
1. Additional rate decreases. In addition to the merger related rate
reduction riders and in consideration for the partial settlement of the
currently pending appeal of the CPL rate order and in consideration for
the full settlement of the currently pending appeal of the SWEPCO fuel
reconciliation proceeding and to recognize that the WTU rate freeze
expired in October 1998, the Merged Company agrees to implement rate
reduction riders which reflect the rate reductions on Page 3 of this
Attachment beginning on the first revenue month after the effective
date of the merger. Each rate decrease amount shown in Table H-1 on
page 3 of this Attachment will be allocated to customer classes based
upon base rate revenues and will be credited to customers based upon a
percentage of monthly base rate charges as shown in H-1a. Each rate
decrease amount shown in Table H-2 on page 3 of this Attachment will be
allocated to customer classes as shown on Table H-2a. The rate
reduction rider (Table H-1 of Attachment H) for each Texas operating
company will cease upon the effective date of new base rates for such
company established pursuant to Section 36.151 or Section 36.101,
PURA. In the absence of the establishment of new base rates for a
Texas Operating Company during the six year period, the rate reduction
rider (Table H-1) for each Texas Operating will continue to apply in
the years following the end of year six until new base rates for such
Texas Operating Company are established. The supplemental rate
reduction rider (Table H-2 of Attachment H) will remain in effect
notwithstanding any base rate proceeding during the six year period
after the effective date of the merger and will continue to apply in
the years following the end of year six until base rates for the Texas
Operating Company are changed.
All rate reduction riders will be credited to customers in accordance with
Attachment I.
2. Within 30 days of the effective date of the merger, SWEPCO will withdraw
its pending appeal of its fuel reconciliation proceeding in Docket No.
17460 pursuant to the following provisions:
a. Approval by the PUCT of the settlement of Docket No. 19265
including all material provisions of the regulatory plan
consistent with Section 9.0. of the Stipulation;
b. Agreement by all Signatories to this Agreement except General
Counsel that they will not initiate a base rate proceeding
against SWEPCO which would result in a change in base rates
prior to January 1, 2001; and
c. Agreement by all Signatories to this Agreement that
transmission equalization payments and receipts for intra-CSW
System transactions will be treated as base rate items in
future proceedings for all Texas operating companies.
<PAGE> 50
3. Within 30 days of the effective date of the merger, CPL will withdraw from
its pending appeal of Docket No. 14965 all issues which pertain to Points
of Error Nos. 15 and 16 in CPL's Third Motion of Rehearing filed with the
PUCT (related to the lawfulness of the mandated glide path rate reductions
in 1998 and 1999) pursuant to the following provisions:
a. Approval by the PUCT of the settlement of Docket No. 19265
including all material provisions of the regulatory plan
consistent with Section 9.0. of the Stipulation;
b. Agreement by all Signatories to this Agreement except General
Counsel that they will not initiate a base rate proceeding
against CPL which would result in the change in base rates
prior to January 1, 2001;
c. CPL will have the right to continue to litigate all issues in
its appeal other than those related to the mandated glide path
rate reductions; and
d. In consideration for the commitments made in this Attachment
H, CPL will extend the terms of the Docket No. 12820
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.
4. All Signatories to this Agreement except General Counsel agree that they
will not initiate a base rate proceeding against WTU which would result in
a change in base rates to be effective prior to January 1, 2001.
5. The annual base rate reduction amounts are net, "bottom-line" amounts not
subject to any offset.
6. The Texas operating companies agree to implement the above rate
decreases in the manner and amounts described above notwithstanding any
changes to the current regulatory structure in Texas or implementation
of a legislatively-mandated rate freeze. In the event the retail
electric restructuring deregulation legislation is implemented in Texas
including any required divestiture, unbundling or restructuring, the
Texas operating companies agree to apply the regulatory plan's
provisions to regulated rates of their customers.
7. The Signatories agree that any legislatively mandated reductions or
credits to base rates that are part of any retail electric deregulation
legislation implemented in Texas shall not diminish or offset but shall be
in addition to the base rate reductions established in this proceeding.
8. In the event that future statutes provide that, upon the commencement
to customer choice. CPL is not required to serve large commercial and
industrial customers having loads above 1000 KW (which at the current
time constitutes 550 MW of load), that amount would be deducted from
CPL's recall right of 1354 MW on the date customer choice begins.
Assuming CPL's large commercial and industrial load does not change,
<PAGE> 51
CPL's buyback rights would be 804 MW (1354 MW - 550 MW). However, if
CPL is involuntarily designated as a provider of last resort and under
the new statute must offer provider of last resort service to large
commercial and industrial customers, its recall rights would not be
diminished because it retains the legal obligation to serve those
customers.
<PAGE> 52
Attachment H to
Integrated Stipulation and Agreement
Page 3 of 3
AEP/CSW Merger
Revenue Requirements Credit
Table H-1
Rate Reduction Rider Amounts
<TABLE>
<CAPTION>
Year CPL SWEPCO WTU Total
- ---- --- ------ --- -----
(Thousands)
<S> <C> <C> <C> <C>
Year 1 $15,337 $ 4,873 $ 3,947 $24,157
Year 2 12,001 3,893 2,985 18,879
Year 3 10,159 3,330 2,418 15,907
Year 4 8,788 2,890 1,960 13,638
Year 5 7,820 2,583 1,651 12,054
Year 6 7,173 2,361 1,409 10,943
------- ------- ------- -------
Total $61,278 $19,930 $14,370 $95,578
------- ------- ------- -------
</TABLE>
Table H-2
Supplemental Rate Reduction Rider Amounts
<TABLE>
<CAPTION>
Year CPL SWEPCO WTU Total
---- --- ------ --- -----
<S> <C> <C> <C> <C>
Year 1 $ 4,806,667 $ 1,013,334 $ 1,013,333 $ 6,833,334
Year 2 $ 4,806,667 $ 1,013,334 $ 1,013,333 $ 6,833,334
Year 3 $ 4,806,667 $ 1,013,333 $ 1,013,333 $ 6,833,333
Year 4 $ 4,806,667 $ 1,013,333 $ 1,013,333 $ 6,833,333
Year 5 $ 4,806,666 $ 1,013,333 $ 1,013,334 $ 6,833,333
Year 6 $ 4,806,666 $ 1,013,333 $ 1,013,334 $ 6,833,333
----------- ----------- ----------- -----------
Total $28,840,000 $ 6,080,000 $ 6,080,000 $41,000,000
----------- ----------- ----------- -----------
</TABLE>
<PAGE> 53
Attachment J to
Integrated Stipulation and Agreement
AEP/CSW Merger
Allocation of Combined Attachment A and Attachment H
Rate Reduction Riders
<TABLE>
<CAPTION>
Central Power and Light
Company
Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total
- ----------------------------- ----------- ----------- ----------- ----------- ----------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Residential $10,213,347 $10,870,000 $11,233,975 $11,504,214 $11,695,018 $11,822,546 $ 67,340,000
Commercial & Small Industrial 10,733,270 10,215,576 9,907,640 9,678,443 9,516,615 9,408,456 59,500,000
Large Industrial 2,149,572 2,106,448 2,082,635 2,052,399 2,052,399 9,408,456 12,500,000
Lighting 670,478 613,743 582,417 559,098 542,634 531,630 3,500,000
----------- ----------- ----------- ----------- ----------- ----------- ------------
Total 23,806,667 23,806,667 23,806,667 23,806,667 23,806,666 23,806,666 142,840,000
----------- ----------- ----------- ----------- ----------- ----------- ------------
</TABLE>
<TABLE>
<CAPTION>
Southwestern Electric Power
Company
Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total
- ----------------------------- ----------- ----------- ----------- ----------- ----------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Residential $ 2,686,497 $ 2,870,327 $ 2,975,942 $ 3,058,470 $ 3,116,063 $ 3,157,701 $ 17,865,000
Commercial & Small Industrial 2,655,165 2,557,145 2,500,834 2,456,825 2,426,117 2,403,914 15,000,000
Industrial 1,439,959 1,372,602 1,333,899 1,303,667 1,282,564 1,267,309 8,000,000
Municipal 66,342 62,863 60,863 59,300 58,210 57,422 365,000
Lighting 165,371 150,397 141,795 135,071 130,379 126,987 850,000
----------- ----------- ----------- ----------- ----------- ----------- ------------
Total 7,013,334 7,013,334 7,013,333 7,013,333 7,013,333 7,013,333 42,080,000
----------- ----------- ----------- ----------- ----------- ----------- ------------
</TABLE>
<TABLE>
<CAPTION>
West Texas Utilities Company
Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total
- ----------------------------- ----------- ----------- ----------- ----------- ----------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Residential $ 2,859,319 $ 2,987,880 $ 3,063,422 $ 3,165,611 $ 3,165,611 $ 3,199,327 $ 18,400,000
Commercial & Small Industrial 2,109,592 2,041,488 2,001,488 1,969,229 1,947,440 1,930,736 12,000,000
Industrial 719,716 686.782 667,419 651,777 641,228 633,078 4,000,000
Municipal 209,687 193,339 183,715 175,939 170,696 166,624 1,100,000
Lighting 115,019 103,844 97,262 91,947 88,359 83,569 580,000
----------- ----------- ----------- ----------- ----------- ----------- ------------
Total 6,013,333 6,013,333 6,013,333 6,013,333 6,013,334 6,013,334 36,080,000
----------- ----------- ----------- ----------- ----------- ----------- ------------
</TABLE>
<TABLE>
<CAPTION>
Texas Operating Companies
Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total
- ----------------------------- ----------- ----------- ----------- ----------- ----------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Residential $15,759,163 $16,729,107 $17,273,339 $17,687,125 $17,976,692 $18,179,574 $103,605,000
Commercial & Small Industrial 15,538,027 14,814,209 14,409,989 14,104,497 13,890,172 13,743,106 86,500,000
Industrial 4,309,247 4,165,832 4,083,953 4,020,356 3,976,191 3,944,421 24,500,000
Municipal 276,029 256,202 244,578 235,239 228,906 224,046 1,465,000
Lighting 950,868 867,984 821,474 786,116 761,372 742,186 4,930,000
----------- ----------- ----------- ----------- ----------- ----------- ------------
Total 36,833,334 36,833,334 36,833,333 36,833,333 36,833,333 36,833,333 221,000,000
----------- ----------- ----------- ----------- ----------- ----------- ------------
</TABLE>
<PAGE> 54
Table A-1
AEP/CSW Merger
Allocation of Attachment A Net Merger Savings Rate Reduction Rider
<TABLE>
<CAPTION>
Central Power and Light
Company
Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total
- ----------------------------- ---------- ---------- ---------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Residential $2,306,088 $4,406,307 $5,565,959 $ 6,429,090 $ 7,038,508 $ 7,445,832 $33,191,784
Commercial & Small Industrial 1,044,736 1,996,209 2,521,574 2,912,601 3,188,687 3,373,223 15,037,030
Large Industrial 261,472 499,603 631,088 728,953 798,051 844,235 3,763,402
Lighting 50,704 96,881 122,379 141,356 154,754 163,710 729,784
---------- ---------- ---------- ----------- ----------- ----------- -----------
Total 3,663,000 6,999,000 8,841,000 10,212,000 11,180,000 11,827,000 52,722,000
---------- ---------- ---------- ----------- ----------- ----------- -----------
</TABLE>
<TABLE>
<CAPTION>
Southwestern Electric Power
Company
Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total
- ----------------------------- ---------- ---------- ---------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Residential $ 650,519 $1,216,188 $1,541,165 $ 1,795,133 $ 1,972,341 $ 2,100,477 $ 9,275,823
Commercial & Small Industrial 308,428 576,628 730,707 851,123 935,139 995,896 4,397,921
Large Industrial 147,622 275,982 349,719 407,359 447,569 476,650 2,104,901
Municipal 9,100 17,015 21,561 25,113 27,592 29,385 129,766
Lighting 11,331 21,187 26,848 31,272 34,359 36,592 161,589
---------- ---------- ---------- ----------- ----------- ----------- -----------
Total 1,127,000 2,107,000 2,670,000 3,110,000 3,417,000 3,639,000 16,070,000
---------- ---------- ---------- ----------- ----------- ----------- -----------
</TABLE>
<TABLE>
<CAPTION>
West Texas Utilities Company
Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total
- ----------------------------- ---------- ---------- ---------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Residential $ 640,381 $1,226,171 $1,571,205 $ 1,849,909 $ 2,037,941 $ 2,186,204 $ 9,511,811
Commercial & Small Industrial 297,969 569,646 729,938 859,416 946,769 1,015,183 4,418,921
Large Industrial 86,521 165,407 211,948 249,543 274,911 294,776 1,283,106
Municipal 20,142 38,507 49,343 58,095 64,001 68,625 298,713
Lighting 7,987 15,269 19,566 23,037 25,378 26,212 117,449
---------- ---------- ---------- ----------- ----------- ----------- -----------
Total 1,053,000 2,015,000 2,582,000 3,040,000 3,349,000 3,591,000 15,630,000
---------- ---------- ---------- ----------- ----------- ----------- -----------
</TABLE>
<PAGE> 55
Table H-1a
AEP/CSW Merger
Allocation of Table H-1 Rate Reduction Rider
<TABLE>
<CAPTION>
Central Power and Light
Company
Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total
- ----------------------------- ----------- ----------- ----------- ---------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Residential $ 6,632,530 $ 5,189,865 $ 4,393,288 $3,800,396 $3,381,782 $3,101,986 $26,499,847
Commercial & Small Industrial 6,938,284 5,429,117 4,595,816 3,975,591 3,537,678 3,244,983 27,721,469
Large Industrial 1,293,050 1,011,795 856,497 740,909 659,298 604,749 5,166,298
Lighting 473,136 370,223 313,399 271,104 241,242 221,282 1,890,386
----------- ----------- ----------- ---------- ---------- ---------- -----------
Total 15,337,000 12,001,000 10,159,000 8,788,000 7,820,000 7,173,000 61,278,000
----------- ----------- ----------- ---------- ---------- ---------- -----------
</TABLE>
<TABLE>
<CAPTION>
Southwestern Electric Power
Company
Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total
- ----------------------------- ----------- ----------- ----------- ---------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Residential $ 1,898,672 $ 1,516,833 $ 1,297,472 $1,126,032 $1,006,417 $ 919,919 $ 7,765,345
Commercial & Small Industrial 1,821,012 1,454,792 1,244,402 1,079,976 965,252 882,292 7,447,726
Large Industrial 973,198 777,481 665,041 577,170 515,857 471,521 3,980,268
Municipal 56,657 45,263 38,717 33,602 30,032 27,451 231,722
Lighting 123,461 98,631 84,368 73,220 65,442 59,817 504,939
----------- ----------- ----------- ---------- ---------- ---------- -----------
Total 4,873,000 3,893,000 3,330,000 2,890,000 2,583,000 2,361,000 19,930,000
----------- ----------- ----------- ---------- ---------- ---------- -----------
</TABLE>
<TABLE>
<CAPTION>
West Texas Utilities Company
Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total
- ----------------------------- ----------- ----------- ----------- ---------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Residential $ 1,875,981 $ 1,418,752 $ 1,149,260 $ 931,574 $ 784,712 $ 670,165 $ 6,830,441
Commercial & General Service 1,394,083 1,054,302 854,037 692,274 583,132 498,013 5,075,841
Industrial 458,784 346,964 281,060 227,823 191,906 163,892 1,670,429
Municipal 142,424 107,711 70,724 59,574 50,878 518,562 87,251
Lighting 75,728 57,271 46,392 37,605 31,676 28,052 274,724
----------- ----------- ----------- ---------- ---------- ---------- -----------
Total 3,947,000 2,985,000 2,418,000 1,960,000 1,651,000 1,409,000 14,370,000
----------- ----------- ----------- ---------- ---------- ---------- -----------
</TABLE>
<PAGE> 56
Table H-2a
AEP/CSW Merger
Allocation of Table H-2 Supplemental Rate Reduction Rider
<TABLE>
<CAPTION>
Central Power and Light
Company
Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total
- ----------------------------- ---------- ---------- ---------- ---------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Residential $1,274,729 $1,274,728 $1,274,728 $1,274,728 $1,274,728 $1,274,728 $ 7,648,369
Commercial & Small Industrial 2,790,250 2,790,250 2,790,250 2,790,251 2,790,250 2,790,250 16,741,501
Large Industrial 595,050 595,050 595,050 595,050 595,050 595,050 3,570,300
Lighting 146,638 146,639 146,639 146,638 146,638 146,638 879,830
---------- ---------- ---------- ---------- ---------- ---------- -----------
Total 4,806,667 4,806,667 4,806,667 4,806,667 4,806,666 4,806,666 28,840,000
---------- ---------- ---------- ---------- ---------- ---------- -----------
</TABLE>
<TABLE>
<CAPTION>
Southwestern Electric Power
Company
Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total
- ----------------------------- ---------- ---------- ---------- ---------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Residential $ 137,306 $ 137,306 $ 137,305 $ 137,305 $ 137,305 $ 137,305 $ 823,832
Commercial & Small Industrial 525,725 525,725 525,725 525,726 525,726 525,726 3,154,353
Large Industrial 319,139 319,139 319,139 319,138 319,138 319,138 1,914,831
Municipal 585 585 585 586 586 586 3,512
Lighting 30,579 30,579 30,579 30,578 30,578 30,579 183,472
---------- ---------- ---------- ---------- ---------- ---------- -----------
Total 1,013,334 1,013,334 1,013,333 1,013,333 1,013,333 1,013,333 6,080,000
---------- ---------- ---------- ---------- ---------- ---------- -----------
</TABLE>
<TABLE>
<CAPTION>
West Texas Utilities Company
Major Rate Class Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Total
- ----------------------------- ---------- ---------- ---------- ---------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Residential $ 342,957 $ 342,957 $ 342,957 $ 342,958 $ 342,958 $ 342,958 $ 2,057,745
Commercial & General Service 417,540 417,540 417,540 417,539 417,539 417,540 2,505,238
Industrial 174,411 174,411 174,411 174,411 174,411 174,410 1,046,465
Municipal 47,121 47,121 47,121 47,120 47,121 47,121 282,725
Lighting 31,304 31,304 31,304 31,305 31,305 31,305 187,827
---------- ---------- ---------- ---------- ---------- ---------- -----------
Total 1,013,333 1,013,333 1,013,333 1,013,333 1,013,334 1,013,334 6,080,000
---------- ---------- ---------- ---------- ---------- ---------- -----------
</TABLE>
<PAGE> 57
Attachment I to
Integrated Stipulation and Agreement Page 1 of 2
Principles for Texas Merger Retail Decrease Implementation
1. Riders for each Company will be implemented annually to refund the
negotiated decrease amounts to major rate classes through a credit to
individual customers bills based on projections of base rate revenues for
each individual rate class.
2. The negotiated decrease amounts (merger and rate reduction) by major rate
class will be allocated to the individual rate classes within each major
rate class based upon projected base rate revenues. The resulting base
rate revenue credits will be an equal percentage of projected base rate
revenues for individual rate classes within a major rate class.
3. Projected base rate revenues will include all retail base rate revenues
with the exception of revenues associated with miscellaneous services,
fees and facility rentals. Projected base rate revenues for each
individual rate class will be based upon consecutive twelve month periods,
not necessarily a calendar year.
4. The individual rate class refund factors will be calculated by dividing
the base rate revenue credits assigned to that rate class, determined in
#2 above, by the corresponding annual projected base revenue for that rate
class.
5. The year one refund factors will be filed with the PUCT 30 days prior to
the anticipated effective date of the merger. These factors will be
implemented as of the first day of the first billing month after the
effective date of the merger and will be applicable for the initial 12
month period. The approval of this settlement by the PUCT will establish
the refund methodology and all other compliance filings for annual refund
factors will be administrative in nature.
6. No less than 60 days prior to the expiration of the current refund
factors, each Texas operating Company will make compliance filings to
implement new refund factors for the upcoming 12 month period. These
factors will be based on the refund amounts for the upcoming year plus any
true-up amounts from the prior 12 month period.
7. Due to the timing of these compliance filings, the exact amount of the
current 12 month's over/under refund balance (true-up) will not be
known at the time the next 12 month's refund factors are calculated.
Estimates will need to be made for any periods (possibly two or three
months) for which actual data is not available for the purposes of
determining the amount of over/under refund balance to be included in
the design of the net 12 month's refund factors. The annual true-up of
the refund amount, plus interest calculated in conformance with the
provisions of the PUCT's fuel rule governing reconciliation proceedings
(PUCT Substantive Rule 23.23(b)), will continue until such
<PAGE> 58
time as the refund factor is no longer applicable. At such time that the
refund factors are no longer applicable, each Texas operating Company will
true-up the over/under refund balance for any prior outstanding months
which were estimated.
8. For purposes of the calculation of over/under refund balances each Texas
operating Company will keep the balances of the refunds by individual rate
class and any over/under balances will be included in the calculation of
the next 12 month's refund factor for that individual rate class.
9. 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 PUCT 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.
<PAGE> 1
Exhibit D-6.2
7590-01-P
UNITED STATES OF AMERICA
NUCLEAR REGULATORY COMMISSION
In the Matter of
HOUSTON LIGHTING & POWER COMPANY ) Docket Nos. 50-498
CITY PUBLIC SERVICE BOARD OF ) and 50-499
SAN ANTONIO )
CENTRAL POWER AND LIGHT COMPANY )
CITY OF AUSTIN, TEXAS )
STP NUCLEAR OPERATING COMPANY )
)
(South Texas Project, Units 1 and 2 )
ORDER APPROVING APPLICATION REGARDING PROPOSED CORPORATE
MERGER OF CENTRAL AND SOUTH WEST CORPORATION
AND AMERICAN ELECTRIC POWER COMPANY, INC.
I.
Houston Lighting & Power Company; City Public Service Board of San
Antonio; Central Power and Light Company (CPL): City of Austin, Texas; and STP
Nuclear Operating Company are holders of Facility Operating Licenses Nos. NPF-76
and NPF-80, issued on March 22, 1988, and March 28, 1989, respectively. Facility
Operating Licenses Nos. NPF-76 and NPF-80 authorize the holders to possess the
South Texas Project, Units 1 and 2 (STP), and authorize STP Nuclear Operating
Company to use and operate STP in accordance with the procedures and limitations
set forth in the operating licenses. The Nuclear Regulatory Commission (NRC)
issued Licenses Nos. NPF-76 and NPF-80 on March 22, 1988, and March 28, 1989,
respectively, pursuant to Part 50 of Title 10 of the Code of Federal Regulations
(10 CFR Part 50). The facility is located in Matagorda County, Texas.
II.
Under cover of a letter dated June 19, 1998, CPL submitted an application
dated June 16, 1998, for consent under 10 CFR 50.80 to allow the indirect
transfer of CPL's interest in STP that would occur in connection with a proposed
merger of Central and South West Corporation (CSW, the parent holding company of
CPL) and American Electric Power, Inc. (AEP). Under the proposed merger, CSW
would become a wholly-owned subsidiary of AEP, with CPL remaining a wholly-owned
subsidiary of CSW. Houston Lighting & Power Company; City Public Service Board
of San Antonio; City of Austin, Texas; and
<PAGE> 2
STP Nuclear Operating Company are not involved in the merger. The application
was supplemented by a letter dated June 23, 1998, and enclosures thereto.
CPL and the other current licensees would continue to hold the licenses,
and no direct transfer of the licenses would result from the merger. On August
5, 1998, a Notice of Consideration of Approval of Application Regarding Proposed
Merger was published in the Federal Register (63 FR 41876). An Environmental
Assessment and Finding of No Significant Impact was published in the Federal
Register on September 28, 1998 (63 FR 51629).
Under 10 CFR 50.80, no license shall be transferred, directly or
indirectly, through transfer of control of the license, unless the Commission
gives its consent in writing. Upon review of the information contained in the
application dated June 16, 1998, and enclosures to the letter dated June 23,
1998, the NRC staff has determined that the proposed merger will not affect the
qualifications of CPL as holder of Facility Operating Licenses Nos. NPF-76 and
NPF-80, and that the transfer of control of the licenses, to the extent effected
by the proposed merger, is otherwise consistent with applicable provisions of
law, regulations, and orders issued by the Commission, subject to the conditions
set forth herein. These findings are supported by a safety evaluation dated
November 5, 1998.
III.
Accordingly, pursuant to Sections 161b, 161i, 161o, and 184 of the Atomic Energy
Act of 1954, as amended; 42 U.S.C. Sections 2201(b), 2201(i), 2201(o), and
2234; and 10 CFR 50.80, IT IS HEREBY ORDERED that the Commission approves the
application regarding the merger agreement between CSW and AEP subject to the
following: (1) CPL shall provide the Director of the Office of Nuclear Reactor
Regulation with a copy of any application, at the time it is filed, to transfer
(excluding grants of security interests or liens) from CPL to its proposed
parents, or to any other affiliated company, facilities for the production,
transmission, or distribution of electric energy having a depreciated book value
exceeding 10 percent of CPL's consolidated net utility plant, as recorded on its
books of account, and (2) should the merger not be completed by December 31,
1999, this Order shall become null and void, unless upon application and for
good cause shown this date is extended.
This Order is effective upon issuance.
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IV.
By December 14, 1998, any person adversely affected by this Order may file
a request for a hearing with respect to issuance of the Order. Any person
requesting a hearing shall set forth with particularity how such person's
interest is adversely affected by this Order and shall address the criteria set
forth in 10 CFR 2.714(d).
If a hearing is to be held, the Commission will issue an order designating
the time and place of such hearing.
The issue to be considered at any such hearing shall be whether this Order
should be sustained.
Any request for a hearing must be filed with the Secretary of the
Commission, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001,
Attention: Rulemakings and Adjudications Staff, or may be delivered to the
Commission's Public Document Room, the Gelman Building, 2120 L Street, NW,
Washington DC 20555-0001, by the above date. Copies should also be sent to the
Office of the General Counsel and to the Director, Office of Nuclear Reactor
Regulation, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, and
to John O'Neill, Jr., Shaw, Pittman, Potts & Trowbridge, 2300 N Street, NW.,
Washington, DC 20037-1128, counsel for CPL.
For further detailed with respect to this action, see the application from
CPL dated June 16, 1998, submitted under cover of a letter dated June 19, 1998,
from Shaw, Pittman, Potts and Trowbridge, counsel for CPL, supplemental letter
dated June 23, 1998, and enclosures thereto, and the safety evaluation dated
November 5, 1998, which are available for public inspection at the Commission's
Public Document Room, the Gelman Building, 2120 L Street, NW, Washington, DC
20555-0001, and at the local public document room located at the Wharton County
Junior College, J.M. Hodges Learning Center, 911 Boling Highway, Wharton, TX
77488.
FOR THE NUCLEAR REGULATORY COMMISSION
/s/ Samuel J. Collins, Director
Office of Nuclear Reactor Regulation
Dated at Rockville, Maryland,
This 5th Day of November, 1998
3
<PAGE> 4
UNITED STATES
NUCLEAR REGULATORY COMMISSION
WASHINGTON, D.C. 20555-0001
SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION
REGARDING PROPOSED MERGER
CENTRAL POWER AND LIGHT COMPANY
DOCKET NOS. 50-498 AND 50-499
SOUTH TEXAS PROJECT, UNITS 1 AND 2
1.0 INTRODUCTION
Pursuant to 10 CFR 50.80, Central Power and Light Company (CPL) submitted an
application dated June 16, 1998, under cover of a letter dated June 19, 1998,
and additional supporting material under cover of a letter dated June 23, 1998,
describing the proposed merger of Central and South West Corporation (CSW), the
parent holding company of CPL) and American Electric Power Company, Inc. (AEP).
The application requests the consent of the Nuclear Regulatory Commission (NRC)
to allow the indirect transfer of CPL's interest in STP that will occur under
the proposed merger of CSW and AEP.
CPL, as a wholly-owned subsidiary of CSW, owns a 25.2 percent interest in South
Texas Project, Units 1 and 2 (STP). Upon completion of the merger, CSW will
become a wholly-owned subsidiary of AEP, with CPL remaining a wholly-owned
subsidiary of CSW.
The merger will result in an indirect transfer of CPL's interest in the licenses
for STP to AEP, and approval for this indirect transfer is being sought from the
NRC pursuant to 10 CFR 50.80. Houston Lighting & Power Company, City Public
Service Board of San Antonio, and City of Austin, Texas, are the other owners of
STP, and the proposed merger does not involve any of them. The STP Nuclear
Operating Company (STPNOC) is a holder of the STP licenses and is the licensed
operator of STP, but STPNOC is not impacted by the merger. STPNOC holds no
ownership interest in either unit.
Pursuant to 10 CFR 50.80, the NRC may approve the transfer of the control of a
license, after notice to interested persons. Such action is contingent upon the
NRC's determination that the holder of the license following the transfer of
control is qualified to hold the license and the transfer is otherwise
consistent with applicable provisions of law, regulations, and orders of the
Commission.
In the application for approval dated June 16, 1998, the applicant states on
page 7:
The purpose of the merger is to achieve benefits for AEP's and CSW's
shareholders, customers and communities that would not be achievable if
they were to remain separate companies. The potential net non-fuel cost
savings related to the merger are approximately $2 billion over the first
ten years following the merger. The savings will come from the elimination
of duplicative activities, improved operating efficiencies, lower capital
costs, and the combination of the companies' work forces. In addition, it
is anticipated that there will be reduced fuel costs.
2.0 FINANCIAL QUALIFICATIONS
According to CPL's application, following the proposed merger, CPL will continue
to own its 25.2 percent interest in both Units 1 and 2 and will remain an
electric utility as defined in 10 CFR 50.2, engaged in the generation,
transmission, and distribution of electric energy through rates authorized by
the Public Utility
<PAGE> 5
Commission of Texas for retail purposes and by the Federal Energy Regulatory
Commission for wholesale transactions. As an electric utility, CPL is exempt
from further financial qualifications review, pursuant to 10 CFR 50.33(f).
However, in view of the NRC's concern that restructuring can lead to a
diminution of assets necessary for the safe operation and decommissioning of a
licensee's nuclear power plant, the NRC's practice has been to condition license
transfer approvals upon a requirement that the licensee not transfer significant
assets from the licensee to an affiliate without first notifying the NRC. This
requirement assists the NRC in assuring that a licensee will continue to
maintain adequate resources to contribute to the safe operation and
decommissioning of its facility. With regard to this requirement, CPL has agreed
on page 4 of its June 16, 1998, application:
To provide the Director of the Office of Nuclear Reactor Regulation a copy
of any application, at the time it is filed, to transfer (excluding grants
of security interests or liens) from CPL to its proposed parents, or to
any other affiliated company, facilities for the production, transmission
or distribution of electric energy having a depreciated book value
exceeding ten percent of CPL's consolidated net utility plant, as recorded
on its books of account.
With the foregoing a condition of the Order approving the application regarding
the proposed merger, and abased on the above information, the staff finds that
CPL will remain financially qualified to hold the STP licenses following the
proposed merger.
3.0 TECHNICAL QUALIFICATIONS
STP Nuclear Operating Company, the only licensee of STP authorized to operate
and maintain the facility, is not involved in the proposed merger. CPL has
stated in its application that the proposed merger involves no change to either
the management organization or technical personnel of STP Nuclear Operating
Company. Accordingly, the proposed merger does not raise any problematic
technical qualifications issues.
4.0 ANTITRUST REVIEW
Section 105 of the Atomic Energy Act of 1954, as amended (the Act), requires the
NRC to conduct an antitrust review in connection with an application for a
license to construct or operate a facility under Section 103. Although AEP may
become the holding company of CSW, which in turn is the holding company of CPL
(a licensee for STP), i.e., may indirectly acquire control of the licenses, AEP
will not be performing activities for which a license is needed. Since approval
of the application would not involve issuance of a license and since CPL as the
existing licensee will remain the licensee, the procedures under Section 105
regarding antitrust reviews do not apply, including the making of any
"significant changes" determination.
5.0 FOREIGN OWNERSHIP, CONTROL, OR DOMINATION
CPL indicated in its application that it is now, and will be after the merger, a
corporation organized and existing under the laws of the State of Texas. All of
its directors and principal officers are citizens of the United States. The
application also indicated that after the merger is implemented, CPL will be an
indirect wholly-owned subsidiary of AEP. Subsequent to the merger, the Board of
Directors of AEP will be composed of 15 members, to include all then current
board members of AEP, the Chairman of CSW, and four additional outside directors
of CSW to be nominated by AEP. The current directors of AEP and the Chairman and
outside directors of CSW are U.S. citizens according the application. Nothing in
the application indicates that there will be any known changes in the
memberships of these boards occurring prior to the proposed merger. Counsel for
CPL confirmed on October 29, 1998, during a telephone conversation with Steven
R. Hom of the Office of the General Counsel, that there are no board elections
scheduled to occur prior to the merger, there is no present plan to change any
current board member prior to the
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merger, and it is intended that all AEP board members following the merger will
be U.S. citizens. The application declares that following the proposed merger,
CPL will not be owned, controlled or dominated by an alien, foreign corporation,
or foreign government. The staff does not know or have reason to believe
otherwise.
6.0 CONCLUSIONS
In view of the foregoing, the staff concludes that the proposed merger of CSW
into AEP as a wholly-owned subsidiary of AEP will not adversely affect the
financial qualifications of CPL with respect to the operation and
decommissioning of STP. Also, there do not appear to be any problematic
antitrust or foreign ownership considerations related to the STP licenses that
would result from the proposed merger. Thus, the proposed merger will not affect
the qualifications of CPL as a holder of the licenses, and the transfer of
control of the licenses, to the extent effected by the proposed merger, is
otherwise consistent with applicable provisions of law, regulations, and orders
issued by the Commission pursuant thereto. Accordingly, the NRC should approve
the application regarding the proposed merger, subject to the condition
discussed above concerning significant asset transfers.
Principal Contributor: A. McKeigney
Date: November 5, 1998
3
<PAGE> 1
Exhibit D-7.1
COMMONWEALTH OF KENTUCKY
BEFORE THE PUBLIC SERVICE COMMISSION
In the Matter of:
JOINT APPLICATION OF KENTUCKY POWER)
COMPANY, AMERICAN ELECTRIC POWER ) CASE NO. 99-149
COMPANY, INC. AND CENTRAL AND )
SOUTH WEST CORPORATION REGARDING )
A PROPOSED MERGER )
O R D E R
On April 15, 1999, Kentucky Power Company d/b/a American Electric Power
("Kentucky Power"), American Electric Power Company, Inc. ("AEP"), and Central
and South West Corporation ("CSW") (collectively, the "Joint Applicants")
applied to the Commission for an Order: (1) declaring that the merger of CSW and
AEP, with AEP being the surviving entity, may be consummated without Commission
approval or, alternatively, approving pursuant to KRS 278.020(4) and 278.020(5),
the proposed regulatory plan and authorizing other steps necessary to implement
the regulatory plan; (2) approving a tariff providing a net merger savings
credit for Kentucky Power customers; and (3) making certain findings concerning
the deferral of certain merger-related expenses in conformity with SFAS 71.
On April 20, 1999, the Commission established a procedural schedule
that provided for discovery, an evidentiary hearing, and an opportunity for
parties to file briefs. The Commission granted full intervention to the
following entities: Attorney General's Office of Rate Intervention ("AG",
Kentucky Industrial Utility Customers ("KIUC"), and Kentucky Electric Steel
Corporation (collectively, the "Intervenors"). Following several conferences
held under the Commission's auspices, the parties resolved all disputed issues
and executed a "Stipulation and Settlement Agreement" which they filed with the
Commission on May 24, 1999. The
<PAGE> 2
Commission held a public hearing in this matter on May 28, 1999, at the
Commission's offices in Frankfort, Kentucky.
OVERVIEW OF THE TRANSACTION
Kentucky Power. a Kentucky corporation, owns and operates facilities
engaged in the generation, transmission, distribution and sale of electricity.
It serves approximately 170,000 customers in the eastern Kentucky counties of
Boyd, Breathitt, Carter, Clay, Elliott, Floyd, Greenup, Johnson, Knott,
Lawrence, Leslie, Letcher, Lewis, Magoffin, Martin, Morgan, Owsley, Perry, Pike,
and Rowan. It also supplies electricity to public utilities and municipalities
in Kentucky for resale. Kentucky Power is a utility subject to Commission
jurisdiction. KRS 278.010(3)(a).
AEP, a New York corporation, is a holding company registered under the
Public Utility Holding Company Act of 1935.(1) It owns, directly or indirectly,
all of the outstanding common stock of seven domestic electric utility operating
subsidiaries: Appalachian Power Company, Columbus Southern Power company,
Indiana Michigan Power Company, Kentucky Power, Kingsport Power Company, Ohio
Power Company and Wheeling Power Company. Its subsidiaries provide electricity
to over 3 million customers in Kentucky, Indiana, Michigan, Ohio, Tennessee,
Virginia, and West Virginia.
CSW, a Delaware corporation, is a holding company registered under the
Public Utility Holding Company Act of 1935. It owns all of the outstanding
common stock of four domestic electric utility operating subsidiaries: Central
Power and Light Company, Public Service Company of Oklahoma, Southwestern
Electric Power Company and West Texas Utilities
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(1) 15 U.S.C. Section 79 et seq.
2
<PAGE> 3
Company. These subsidiaries provide electricity to over 1.7 million customers in
areas of Texas, Oklahoma, Arkansas and Louisiana.
On December 21, 1997, AEP and CSW, with the approval of their
respective Boards of Directors, executed a merger agreement. Under the terms of
this agreement, shareholders of CSW will receive .6 of a share of AEP stock for
each share of CSW common stock, resulting in CSW shareholders acquiring 40
percent of AEP's common stock. The four CSW domestic utility subsidiaries will
become AEP subsidiaries. AEP's Board of Directors will be expanded from 12 to 15
members, with two AEP board members retiring. Five directors, formerly on the
CSW Board of Directors, will be selected to serve upon AEP's Board.
The Joint Applicants estimate that the proposed merger will produce
approximately $2.4 billion in non-fuel savings over a 10-year period. After
considering the cost to achieve these savings and pre-merger initiatives, the
proposed merger is estimated to produce net merger savings of $1.965 billion. Of
this amount, Kentucky Power will be allocated $73.8 million. These savings are
expected to result from the elimination of duplicative functions and positions
and greater economies of scale the merger is expected to produce.
Because of the geographical area served by the Joint Applicants and
their affiliates and the nature of their operations, the utility regulatory
commissions of six states,(2) the Federal Energy Regulatory Commission ("FERC"),
the Securities and Exchange Commission ("SEC"), the Federal Trade Commission
("FTC"), the United States Department of Justice ("DOJ"), and the Nuclear
Regulatory Commission ("NRC") must approve the proposed merger. As of
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(2) Arkansas, Louisiana, Oklahoma, Texas, Indiana, and Kentucky. See Joint
Applicants' Response to the Commission's Order of April 28, 1999, Item 2.
3
<PAGE> 4
May 28, 1999, the NRC, Arkansas Public Service Commission, Indiana Utility
Regulatory Commission, and Oklahoma Corporation Commission have granted their
approval.
STIPULATION AND SETTLEMENT AGREEMENT
On May 24, 1999, the parties filed a "Stipulation and Settlement Agreement"
("Settlement Agreement") with the Commission. The most significant features of
the Settlement Agreement are described below.
Merger Savings. The Settlement Agreement provides for the implementation of
a Net Merger Savings Credit ("Merger Credit") tariff that will reduce customers'
bills beginning in the first full billing month 30 days after the consummation
of the merger. The Merger Credit will appear on each customer's monthly bill and
will be based upon kWh consumption. The Merger Credit reflects non-fuel related
merger savings and the associated merger costs based on estimated values
included in AEP's merger filing with the FERC. Although the amounts are only
estimates, the Joint Applicants have committed to guarantee their estimate of
not merger savings. Associated merger costs have been classified by AEP as
either "Cost to Achieve" or "Change in Control Payments."(3)
The Merger Credit will be in effect for an initial eight-year period,
with all associated merger costs amortized over the same eight years. The Cost
to Achieve the merger will be shared by both customers and shareholders of AEP,
while the Change in Control Payments will be borne solely by AEP shareholders.
At the completion of the initial eight years, customers will
- ----------------------
(3) The Change in Control Payments relate to a special incentive plan adopted by
CSW for 16 key employees in October 1996. See Joint Applicants' Response to
Commission Staff's Information Request (requested at the informal conference of
April 22, 1999), Item 4 at 61.
4
<PAGE> 5
have received 55 percent, or $28.365 million, of the total net merger savings
for the period.(4) The Merger Credit will continue beyond the initial eight-year
period, reflecting the gross merger savings estimated for the eighth year, and
will be allocated between customers and shareholders in the same manner as was
utilized during the initial eight-year period. This annual amount of customer
savings will be $5.243 million and will continue until Kentucky Power's next
base rate case which will allocate total gross merger savings to customers.
Should Kentucky Power file a base rate case during the initial eight-year
period, the Merger Credit will remain in effect. Any legislatively mandated
rates that are part of any legislation enacted to deregulate the electric
industry in Kentucky will not diminish or offset, but will be in addition to,
the bill reductions established in the Settlement Agreement.
Rate Moratorium. The Settlement Agreement provides that Kentucky Power
will not request a general increase in its existing base rates and charges that
will be effective prior to January 1, 2003, or three years from the effective
date of the merger, whichever is later. Kentucky Power's fuel adjustment clause,
environmental surcharge, demand side management adjustment clause and system
sales tracker are not included in this rate moratorium. Kentucky Power,
moreover, may seek a general rate adjustment during the moratorium period if,
after a public evidentiary hearing, the Commission determines that events
constituting a force majeure as defined in the Settlement Agreement have
occurred. The Intervenors have agreed not to Seek a reduction in base rates
during the rate moratorium period. The Settlement Agreement does not preclude
the Commission from initiating proceedings to investigate Kentucky Power's rates
should it find that circumstances warrant such proceedings.
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(4) See Settlement Agreement, Attachment A. The annual Merger Credit amount
ranges from $1.464 million to $4.626 million during the initial eight-year
period.
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<PAGE> 6
Fuel Savings. The Settlement Agreement provides that all savings of
fuel and purchase power expenses that result from the proposed merger will flow
directly to Kentucky Power's retail customers through its existing fuel
adjustment clause mechanism. AEP further agrees to hold Kentucky Power's native
load customers harmless from higher replacement power costs of foregone revenues
caused by current AEP operating companies supplying power to the service area of
the CSW operating companies.
Environmental Surcharge Litigation. The Settlement Agreement seeks to
resolve all outstanding matters involving Kentucky Power's environmental
surcharge mechanism. It requires the dismissal of all appeals,(5) including the
Commission's, now before the Kentucky Court of Appeals involving the
Commission's Orders in Case No. 96-489.(6) All parties will dismiss their
appeals without prejudice. The Settlement Agreement further provides that
Kentucky Power may, beginning January 1, 2000, recover through its environmental
surcharge mechanism the costs associated with the low NOx burners for Big Sandy
Generating Units No. 1 and No. 2. Kentucky Power will forego any recovery of
costs eligible for recovery prior to January 1, 2000.(7) The Settlement
Agreement also provides that the Commission's most recent review(8) of Kentucky
Power's environmental surcharge be closed without further adjustment.
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(5) Kentucky Power Company d/b/a American Electric Power v. Kentucky Public
Service Commission, et al., No. 1998-CA-001337 (filed July 25, 1998); Com. of
Ky., ex rel., A.B. Chandler, III, Attorney General v. Kentucky Public Service
Commission, et al, No. 1998-CA-001344 (filed July 28, 1998); Kentucky Industrial
Utility Customers, Inc. v. Com. of Ky., ex rel., A.B. Chandler, III, Attorney
General, No. 1998-CA-001417 (filed July 25, 1998); Kentucky Public Service
Commission v. Com. of Ky., ex rel., A.B. Chandler, III, Attorney General, No.
1998-CA-001455 (filed July 27, 1998); Kentucky Power Company v. Kentucky Public
Service Commission, et al., 1998-CA-002476 (filed Oct. 1, 1998).
(6) Case No. 96-489, Application of Kentucky Power Company d/b/a American
Electric Power to Assess a Surcharge under KRS 278.183 to Recover Costs of
Compliance with the Clear Air Act and Those Environmental Requirements Which
Apply to Coal Combustion Waste and By-Products.
(7) In Commonwealth of Kentucky ex rel. Chandler v. Kentucky Public Service
Commission, Nos. 97-CI-01138, 97-CI-01144, 97-CI-01319 (Ky. Franklin Cir. Ct.
May 14, 1998), the Franklin Circuit Court
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<PAGE> 7
Affiliated Standards. The Settlement Agreement provides for affiliate
standards and guidelines that will apply to transactions between AEP operating
companies and their affiliates. These standards will take effect upon the
consummation of the merger and remain in effect "until new affiliate standards
imposed by either the Commission or by the General Assembly."(9)
Quality of Service. The Settlement Agreement requires Kentucky Power
and AEP to maintain service quality and reliability at existing levels. Kentucky
Power and AEP agree to provide annually service reliability reports addressing
the duration and frequency of customer disruptions and annual Call Center
performance measures for those centers that handle Kentucky customer calls. They
also commit to compile outage data detailing each circuit's reliability
performance to identify and resolve reliability problems.
Most Favored Nations Provisions. The Joint Applicants agree that if, in
connection with the proposed merger, any state or federal regulatory commission
imposes conditions on AEP that would benefit ratepayers in one jurisdiction,
equivalent net benefits and conditions will be extended to Kentucky retail
customers.
COMMISSION FINDINGS
Having thoroughly reviewed the Settlement Agreement, the Commission
finds that the Settlement Agreement represents a reasonable resolution to the
issues surrounding the proposed merger and should be approved. The Settlement
Agreement allows for a fair and equitable
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reversed in part the Commission's Order of May 27, 1997 and directed the
Commission to permit Kentucky Power's recovery of low Nox burner costs incurred
after May 19, 1997.
(8) Case No. 98-624. An Examination By The Public Service Commission of The
Environmental Surcharge Mechanism of Kentucky Power Company d/b/a American
Electric Power As Billed From January 1, 1998 to June 30, 1998.
(9) Settlement Agreement at 6.
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<PAGE> 8
distribution of the merger benefits between ratepayers and shareholders and
protects Kentucky Power ratepayers from many of the potential risks posed by the
merger.
The Commission notes that the Settlement Agreement imposes new
reporting requirements on Kentucky Power in the areas of service quality and
reliability. While we recognize the difficulties presented by the terrain and
topography in portions of Kentucky Power's service territory, the Commission
reminds Kentucky Power that its top priority must be service quality and
reliability. In the event that Kentucky Power's quality of service experiences a
decline, the Commission is prepared to require additional measures be taken.
The Commission also notes that the Settlement Agreement will end the
lengthy and extensive litigation surrounding Kentucky Power's environmental
surcharge mechanism. By this Order, we approve in principle those provisions and
authorize our legal counsel to take all actions necessary to implement the
Settlement Agreement's provisions and to dismiss all outstanding appeals pending
before the Kentucky Court of Appeals. Because the issues dealing with Kentucky
Power's environmental surcharge mechanism are addressed in other Commission
proceedings that have not been consolidated with this proceeding, however. the
Commission must implement certain of the provisions related to that mechanism
through Orders in those proceedings. The Commission will issue those Orders as
soon as possible.(10)
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(10) Within the next few days, the Commission will issue an Order in Case No.
98-624 to close Kentucky Power's current environmental surcharge proceedings.
Implementing the provisions related to the recovery of the costs associated with
the low NOx burners for Big Sandy Generating Units No. 1 and No. 2 will require
the issuance of an Order in Case No. 96-489. That action will occur upon
dismissal of all outstanding appeals.
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<PAGE> 9
REPORTING REQUIREMENTS
In previous cases,(11) the Commission has determined that to
effectively monitor the activities of the jurisdictional utility, its parent
company and related subsidiaries, and to protect ratepayers, certain additional
reports should be furnished by the jurisdictional utility to the Commission on
an annual, periodic, or other basis as appropriate. The Commission finds that
similar requirements are appropriate in this case as well. (12)
Periodic Reports
The annual financial statements of AEP should be furnished, including
consolidating adjustments of AEP and its subsidiaries with a brief explanation
of each adjustment and all periodic reports filed with the SEC. (13) All
subsidiaries should prepare and have available monthly and annual financial
information required to compile financial statements and to comply with other
reporting requirements. The financial statements for any non-consolidated
subsidiaries of AEP should be furnished to the Commission.
AEP should also furnish the following reports on an annual basis:
1. A general description of the nature of intercompany transactions
with specific identification of major transactions, and a description of the
basis upon which cost allocations
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(11) See, e.g., Case No. 10296, The Application of Kentucky Utilities Company to
Enter Into an Agreement and Plan of Exchange and to Carry Out Certain
Transactions in Connection Therewith (Oct. 6, 1988); Case No. 89-374,
Application of Louisville Gas and Electric Company for an Order Approving an
Agreement and Plan of Exchange and to Carry Out Certain Transactions in
Connection Therewith (May 25, 1990); Case No. 94-104, Application of the
Cincinnati Gas & Electric Company and CINergy Corp. for Approval of the
Acquisition of Control of The Union Light, Heat & Power Company by CINergy Corp.
(May 13, 1994); Case No. 97-300, Joint Application of Louisville Gas and
Electric Company and Kentucky Utilities Company for Approval of Merger (Sept.
12, 1997).
(12) The imposition of these requirements is consistent with KRS 278.020(5), KRS
278.230 and Paragraph 8 of the Stipulation and Settlement Agreement.
(13) The requested SEC reports include, but are not limited to, the U5S and
U-13-60 reports.
9
<PAGE> 10
and transfer pricing have been established. This report should discuss the use
of the cost or market standard for the sale or transfer of assets, the
allocation factors used, and the procedures used to determine these factors if
they are different from the procedures used in prior years.
2. A report that identifies professional personnel transferred from
Kentucky Power to AEP or any of the non-utility subsidiaries and describes the
duties performed by each employee while employed by Kentucky Power and to be
performed subsequent to transfer.
AEP should file on a quarterly basis, a report detailing Kentucky
Power's proportionate share of AEP's total operating, revenues, operating and
maintenance expenses, and number of employees.
Special Reports
Other special reports should be furnished to the Commission as
necessary. In anticipation that transfers of utility assets and investments by
AEP will occur in the future, AEP should file any contracts or other agreements
concerning the transfer of such assets or the pricing of intercompany
transactions with the Commission at the time the transfer occurs.
AEP should also file the following information:
1. A quarterly report of the number of employees of AEP and each
subsidiary on the basis of payroll assignment.
2. An annual report containing the years of service at Kentucky Power
and the salaries of professional employees transferred from Kentucky Power to
AEP or its subsidiaries filed in conjunction with the annual transfer of
employees report.
3. An annual report of cost allocation factors in use, supplemented
upon significant change.
4. Summaries of any cost allocation studies when conducted and the
basis for the methods used to determine the cost allocation in effect.
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5. An annual report of the methods used to update or revise the cost
allocation factors in use, supplemented upon significant change.
6. Current Articles of Incorporation and bylaws of affiliated companies
in businesses related to the electric industry or that would be doing business
with AEP.
7. Current Articles of Incorporation of affiliated companies involved
in non-related business.
After consummation of the merger, AEP will remain a registered holding
company under the Public Utility Holding Company Act of 1935 and under the
oversight of several regulatory bodies. Where the same information sought in
these reports has been filed with the SEC, FERC, or another state regulatory
commission, AEP may provide copies of that filing rather than prepare separate
reports. Further, AEP may request the Commission to review these reporting
requirements after the merger is completed to determine if the documentation
being provided is either excessive or redundant.
The Commission recognizes that the proposed merger has not yet received
all necessary regulatory approvals. Consequently, the form or substance of the
anticipated benefits of the merger might ultimately vary from those reviewed in
this case. To the extent that the merger is subject to conditions or changes not
reviewed in this case, the Joint Applicants should amend their filing to allow
the Commission and all parties an opportunity to review the revisions to ensure
that Kentucky Power and its customers are not adversely affected and that any
additional benefits flow through the favored nations clause.
MOTION FOR REHEARING
The Kentucky Association of Plumbing-Heating-Cooling Contractors, Inc.
and Kentucky Propane Gas Association (collectively "Contractors") have moved
for reconsideration of the
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Commission's Order of May 20, 1999 in which we denied their application for full
intervention. In support of their motion, the Contractors state that they have
an interest in this proceeding as the Joint Applicants have not expressly
precluded the possibility of competing with their members or to refrain such
competition pending completion of Administrative Case No. 369.(14)
Having considered the motion, the Commission does not find good cause
to modify its May 20, 1999 Order. While the Commission acknowledges the
Contractors' concerns regarding utility affiliate transactions, these concerns
are more appropriately addressed in Administrative Case No. 369, which was
initiated specifically to review these issues as they relate to all regulated
utilities. Moreover, Commission approval of the Settlement Agreement neither
binds nor limits our ability to deal with the issue of affiliated transactions.
The Settlement Agreement contains no provision limiting the scope of our
discretion in this area. It specifically provides that its affiliate standards
"apply from the date of closing of the merger until new affiliate standards
imposed by state legislation or State Commission action become effective."
Settlement Agreement at 6.
SUMMARY
After consideration of the evidence and being otherwise sufficiently
advised, the Commission finds that:
1. The proposed merger of AEP and CSW will result in an indirect change
in control of Kentucky Power and therefore requires prior Commission approval.
KRS 278.020(4) and (5).
- -------------
(14) The Administrative Case No. 369, An Investigation of The Need For Affiliate
Transaction Rules and Cost Allocation Requirements For All Jurisdictional
Utilities.
12
<PAGE> 13
2. The proposed merger of AEP and CSW and the resulting indirect change
in control of Kentucky Power is in accordance with law, for a proper purpose,
and with the conditions and assurances established herein consistent with the
public interest.
3. AEP and Kentucky Power have and, upon completion of the proposed
merger, will retain the financial, managerial and technical abilities to provide
reasonable utility service.
4. The "Stipulation and Settlement Agreement," appended hereto, is
reasonable, does not conflict with any regulatory principle and should be
approved.
5. The Contractor's Motion for Reconsideration should be denied.
6. AEP and Kentucky Power should file the reports and other information
as specifically set out in this Order.
7. The Joint Applicants should submit copies of final approval received
from the FERC, SEC, FTC, DOJ, and all state regulatory commissions to the extent
that these documents have not been provided. With each submittal, the Joint
Applicants shall further state whether Paragraph 10 of the Settlement Agreement
requires changes to the regulatory plan approved herein.
IT IS THEREFORE ORDERED that:
1. The Joint Applicants' Application for an Order declaring that the
merger of AEP and CSW is not subject to approval pursuant to KRS 278.020(4) or
(5) is denied.
2. The terms and conditions set forth in the Settlement Agreement, a
copy of which is appended hereto, are adopted and approved and are incorporated
into this Order as if fully set forth herein.
13
<PAGE> 14
3. The proposed merger transaction and resulting indirect transfer of
control are approved, subject to additional review in the event that the merger
or the anticipated benefits are changed or modified as a result of action by
other regulatory agencies.
4. The proposed Net Merger Savings Credit Tariff is approved.
5. Within 20 days of the date of this Order, Kentucky Power shall file
revised tariff sheets reflecting the approved Net Merger Savings Credit Tariff.
6. AEP and Kentucky Power shall comply with all reporting requirements
described herein.
7. The Kentucky retail jurisdictional share of the estimated
transaction, regulatory processing and transition costs incurred to merge and
combine AEP and CSW shall be deferred and amortized for recovery over eight
years. This amortization shall begin with the date of the combination and shall
continue for eight years on a straight-line basis.
8. The Joint Applicants shall within five days of the consummation of
the proposed merger file a written notice setting forth the date of merger and
the effective date of the Net Merger Saving Credit Tariff.
9. The proposed settlement of outstanding litigation involving Kentucky
Power's environmental surcharge mechanism, as set forth in the Settlement
Agreement, is approved. Commission counsel is authorized to execute all
necessary documents to dismiss all appeals identified in Footnote 6 of this
Order.
10. The Contractors' Motion for Reconsideration is denied.
Done at Frankfort, Kentucky, this 14th day of June, 1999.
By the Commission
14
<PAGE> 15
ATTEST:
/s/ Helen C. Helton
Executive Director
15
<PAGE> 16
APPENDIX
AN APPENDIX TO AN ORDER OF THE KENTUCKY PUBLIC SERVICE
COMMISSION IN CASE NO. 99-149 DATED 6/14/99
<PAGE> 17
COMMONWEALTH OF KENTUCKY
BEFORE THE
PUBLIC SERVICE COMMISSION OF KENTUCKY
IN THE MATTER OF:
JOINT APPLICATION OF KENTUCKY POWER COMPANY )
AMERICAN ELECTRIC POWER COMPANY, INC. )
AND CENTRAL AND SOUTH WEST CORPORATION ) CASE NO. 99-149
REGARDING A PROPOSED MERGER )
STIPULATION AND SETTLEMENT AGREEMENT
On February 17, 1999 the Staff of the Public Service Commission of Kentucky
("Commission") issued a letter stating staff's belief that the Commission has
jurisdiction under KRS 278.020(5) to review the proposed merger of Central and
South West Corporation ("CSW") into American Electric Power Company, Inc.
("AEP") and requested that Kentucky Power Company ("Kentucky Power", "KPCO" or
the "Company") advise in writing by March 8, 1999 of the date AEP would file an
application for Commission approval of "the indirect change in control of
Kentucky Power Company." On March 5, 1999 the Company issued a letter notifying
the Commission that it would file the requested application by April 15, 1999.
The letter also indicated that the Company expected to provide the Staff and the
Commission with sufficient information to enable the Commission to approve its
application within the sixty (60) day period prescribed by the statute. The
letter further preserved the Company's legal arguments regarding the application
of KRS 278.020 (5) to this merger.
On April 15, 1999 the Company, AEP and CSW filed a Joint Application with
supporting testimony and workpapers. The proceeding was designated P.S.C. Case
No. 99-149. On April 22, 1999 the Commission issued a letter indicating that the
Commission staff had reviewed the Company's application and found that it met
the minimum filing requirements.
On May 4, 1999 the Attorney General, Office of the Rate Intervention ("Attorney
General"), and Kentucky Electric Steel, Inc. ("KESI") were granted full
intervention in Case No. 99-149. On May 11, 1999 Kentucky Industrial Utility
Customers Inc. ("KIUC"), was also granted full intervention in Case No. 99-149.
These parties will be referred to herein collectively as the "Intervenors".
On April 22, 1999 a Technical Conference was held at the Commission's offices.
On May 4, May 11, May 17, and May 20, 1999 settlement conferences were held at
the Commission's offices. Present were the Staff and counsel for the
Intervenors, as well as Company representatives.
<PAGE> 18
Solely for the purposes of compromise and settlement of the issues in this
proceeding, Central and South West Corporation, American Electric Power Company,
Inc., Kentucky Power Company, which does business in Kentucky as American
Electric Power, the Attorney General, Kentucky Industrial Utility Customers,
Inc. and Kentucky Electric Steel, Inc. (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 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 the Parties have met and explored 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 the Parties 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; and
WHEREAS, the Parties agree as follows:
That AEP, KPCO and the Intervenors will recommend to the Commission 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 Parties:
1. Will not oppose the proposed merger pending before the Federal Energy
Regulatory Commission ("FERC").
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.
<PAGE> 19
AEP, or Kentucky Power Company, conditional on merger consummation will:
1. REGULATORY PLAN. KPCO will implement a Net Merger Savings Credit tariff that
will reduce bills to customers by the annual amounts shown in Attachment A
beginning with the first full billing month available following thirty days from
the consummation of the merger. The annual bill reduction amounts shown in
Attachment A will be refunded to customers based upon kwh consumption. Each
individual year's bill reduction will apply for a twelve month period. A
Balancing Adjustment Factor (B.A.F.) per Kwh will be included for the second
through the twelfth month of the current distribution year which will reconcile
any over- or under-distribution of the net savings from prior years.
The merger savings and costs are based on estimated values included in AEP's
filing with the Federal Energy Regulatory Commission ("FERC") in Docket No.
EC98-40-000.
Absent a force majeure, KPCO will not file a petition, 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,
2003 or three years from the effective date of the merger, whichever is later
(the "rate moratorium"), and the Intervenors agree not to seek a reduction in
base rates during the rate moratorium. During this period, the fuel adjustment
clause, the environmental surcharge, the demand side management adjustment and
the system sales tracker shall continue in force and shall not be subject to any
freeze. During the rate moratorium period, and not withstanding any force
majeure event, any discount, including but not limited to, operating reserve and
interruptible discounts contained in special contracts as currently approved by
the Commission, shall remain in force and shall not be changed for any customer
receiving the discount.
The Parties and the Commission will dismiss the appeals and cross-appeals in
Case Nos. 98 CA 00137, 98 CA 001344, 98 CA 001417, 98 CA 001455 and 98 CA
002476. The dismissal shall be without prejudice in any other action with
respect to the positions taken by the parties in dismissed litigation.
Effective January 1, 2000, KPCO shall begin collecting the environmental
surcharge, including the costs of the Low Nox burners for the Big Sandy
generating plant's Unit No. 1 and Unit No. 2, in accordance with the decisions
of the Franklin Circuit Court Opinion and Order dated April 30, 1998 and its
Amended Opinion and Order dated May 14, 1998 in Consolidated Case Nos.
97-CI-01138, 97-CI-01144 and 97-CI-00137 (except those portions of the decision
allowing retroactive recovery of the surcharge).
The parties further agree that there shall be no adjustment to the environmental
surcharge as a result of the six month review in P.S.C. Case No. 98-624.
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. After the eight year period and absent a base rate proceeding, the
Company will continue through the Net Merger Savings Credit to reduce bills to
customers by the annual amount shown on Attachment
<PAGE> 20
A which is the customers' portion of the net savings without the amortization of
the costs to achieve during the eighth year after the consummation of the
merger.
KPCO must implement the above rate reductions in the manner and amounts
described above notwithstanding any changes to the current regulatory structure
in Kentucky. In the event that retail electric deregulation legislation is
implemented in Kentucky or if there is any unbundling or restructuring, KPCO
shall continue to apply the regulatory plan's provisions to regulated rates of
its Kentucky retail jurisdictional customers.
Any legislatively mandated adjustments to base rates, of any kind, that are part
of any retail electric deregulation legislation implemented in Kentucky shall
not diminish or offset, but shall be in addition to, the bill reductions
established in this proceeding.
Subject to this agreement, AEP and KPCO will defer and amortize their Kentucky
retail jurisdictional estimated merger related 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. The Commission will issue accounting orders or
other orders necessary to authorize the deferral and amortization of merger
costs.
If the merger is not consummated, the Company commits and agrees not to seek to
recover termination fees, the "Out of Pocket" and "Topping Out" fees associated
with the merger as described in Sections 9.5 and 9.6 of the Agreement and Plan
of Merger By and Among American Electric Power Company, Inc., Augusta
Acquisition Corporation and Central and South West Corporation dated December
21, 1997 (Merger Agreement); and further commit and agree not to seek to recover
the fee that may be charged by Morgan Stanley.
In any proceeding to change base rates for KPCO 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).
In any base rate proceeding after the eight year period, neither the merger
savings credit rider nor the expense adjustments described in A. and B. above
will be reflected in the test year.
<PAGE> 21
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 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.
3. For purposes of this Settlement Agreement, force majeure shall mean
circumstances that cause any of the following to occur: a) the bond rating for
Kentucky Power Company to fall below an investment grade rating of Baa3
(Moody's) or BBB- (Standard & Poor's), or b) an increase in the federal and/or
state income taxes of KPCO, which increase is the result of changes in federal
or state income tax provisions, or c) an increase in KPCO's total electric
operating expenses, excluding fuel and purchased power, due to circumstances
beyond its control, and further excluding the costs of compliance with federal,
state or local environmental requirements which apply to coal combustion wastes
and by-products from facilities utilized for production of energy from coal.
For purposes of this force majeure provision, an increase is defined as an
increase in expense in an annualized amount greater than five percent (5%) of
AEP's Kentucky jurisdictional net revenues (i.e., operating revenues less fuel
and purchased power) for the preceding twelve months.
A force majeure may only exist under the terms of this Settlement Agreement if
the Commission finds in a rate application filed by the Company that the
circumstances allowed for under this Settlement Agreement are a force majeure,
as defined in this Agreement, after a public evidentiary hearing in which al the
Parties may participate.
4. 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.
5. 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.
6. 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
<PAGE> 22
company requests a change in its basic rates and charges, or in any other
proceeding where so ordered by the State 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 facilities whose costs will be subject to the System
Integration Agreement or the System Transmission Agreement with the FERC and to
notify each State Commission of any such filing at the time it is made.
Notification to each State 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
State Commission an explanation of the circumstances causing the AEP operating
company to make the purchase in question.
7. 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 a State Commission based on the
assertion that the authority of the Securities and Exchange Commission 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 State Commission's ability to examine 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 each State
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 filing but shall include, to the extent information is available, a
description of the proposed factors and the reasons supporting such factors. AEP
and State Commission Staff will make a good faith attempt to resolve their
differences, if any, in advance of a filing being made at the SEC.
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 State 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
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. These principles shall be applied to avoid costs
found to be just and reasonable for ratemaking
purposes by the affected State Commission being left
unallocated or stranded between various regulatory
jurisdictions,
<PAGE> 23
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. Each State 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 each such State Commission has over a public
utility operating within the state in which such State
Commission exercises its regulatory authority 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 a State Commission, then upon request of a State
Commission, the AEP operating company shall, in accordance
with state reimbursement rules, reimburse the State 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 be raised before the
State 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
each State Commission's rules and regulations.
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. Asset transfers from an
AEP operating company to a non-utility affiliate and asset
transfers from a non-utility affiliate to an AEP operating
company shall be at fully distributed costs in accordance with
current Securities and Exchange Commission (SEC) issued
requirements or other statutory requirements if the SEC has no
jurisdiction.
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 that
operating company's State Commission:
<PAGE> 24
1. An 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 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 with respect to 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 existing
coal subsidiaries.
E. An 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 State Commission copies
of each billing statement, contract and arrangement between
the AEP operating company or affiliated service company and
its affiliates that relates 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 State Commission copies
of each billing statement, contract and arrangement between
the operating company
<PAGE> 25
and its non-utility affiliates that relates to the provision
of such goods and services in accordance with applicable State
Commission retention requirements.
G. Employees responsible for the day to day operations of the AEP
operating 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 each State Commission and consumer
advocate 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 an 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, 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 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
<PAGE> 26
transfer or 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
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 State Commissions in accordance with Paragraph
B, above.
Q. AEP shall designate an employee who will act as a contact for
State Commissions and consumer advocates seeking data and
information regarding affiliate transactions and personnel
transfers. Such employee shall be responsible for providing
data and information requested by a State 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 each signatory
state who will act as a contact for retail consumers 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 each signatory state a current list of
employees or agents that are designated to work with each
State Commission and consumer advocate 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 each affected State
Commission a copy of the proposed filing.
<PAGE> 27
U. Any violation of the provisions of these affiliate standards
are subject to the enforcement powers and penalties at the
State Commissions.
V. AEP shall contract with an independent auditor who shall
conduct biennial audits for ten years after merger
consummation of affiliated transactions to determine
compliance with these affiliate standards. The results of such
audits shall be filed with the State Commissions. Prior to the
initial audit, AEP will conduct an informational meeting with
State Commissions 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 State Commissions to
ensure that AEP continues to furnish the State Commission with
the appropriate information to regulate its jurisdictional AEP
operation company. The State 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. See Attachment C for the
AEP/KENTUCKY POWER SERVICE QUALITY PROGRAM that has been agreed to by the
parties.
10. STATUTORY AND OTHER ISSUES. Provided the 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. Nothing in this Agreement is intended to preclude
the Commission and its staff from addressing in a manner not inconsistent with
this Agreement issues raised in the FERC Docket No. 98-40-000.
12. ENFORCEABILITY. AEP and KPCO will not assert in any action to enforce an
order approving this Agreement that the Commission lacks the authority to have
the provisions of this Agreement enforced under Kentucky law.
DEFINITIONS
1. "AEP zone" means either the area comprising the AEP operating companies
providing service in Indiana, 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.
<PAGE> 28
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. "Consumer advocate" means an agency of the state government designated as a
representative of consumers in matters involving utility companies before the
applicable State Commission.
5. "Entity" means a corporation or a natural person.
6. "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 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.
7. "FERC" means the Federal Energy Regulatory Commission, or any successor
governmental agency.
8. "Non-Utility Affiliate" means an Affiliate which is not a domestic public
utility. Non-utility affiliate includes a foreign affiliate.
9. "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.
10. "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.
11. "SEC" means the United States Securities and Exchange Commission, or any
successor governmental agency.
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.
<PAGE> 29
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. The Parties shall move for the admission of this Agreement into evidence at
the hearing scheduled for May 28, 1999, or such earlier time as the Commission
may establish and sponsor evidence including testimony and exhibits as may be
required to support Commission approval of this Agreement.
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, 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 evidence in this Case constitutes substantial evidence sufficient to
support the Agreement and provides an adequate evidentiary basis upon which the
Commission can make any finding of fact and conclusions of law necessary for the
approval of the Agreement, as filed.
3. The issuance of the Final Order shall terminate any further proceedings in
this Case.
4. In the event this Case is required to be litigated, the Parties expressly
reserve all of their rights to make objections and motions to strike with
respect to all testimony and exhibits and their right to cross-examine the
witnesses presenting such testimony and exhibits.
<PAGE> 30
5. The undersigned have represented and agreed that they are fully authorized to
execute this Agreement on behalf of their designated clients who will be bound
thereby.
6. The Parties to this Agreement shall not appeal the agreed Final Order or any
other Commission order 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.
7. 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 24th day of May, 1999.
Central and South West Corporation
By: /s/ Mark R. Overstreet
-----------------------------
Kentucky Power Company
By: /s/ Mark R. Overstreet
-----------------------------
Mark R. Overstreet
Sites and Harbison
<PAGE> 31
AEP
By: /s/ Richard E. Munczinski
------------------------------------
Richard E. Munczinski
Senior Vice President
American Electric Power
Service Corporation
Attorney General
By: /s/ Elizabeth E. Blackford
------------------------------------
Elizabeth E. Blackford
Assistant Attorney General
Attorney General, Office of Rate
Intervention
Kentucky Industrial Utility Customers, Inc.
By: /s/ David F. Boehm
------------------------------------
David F. Boehm
Boehm, Kurtz & Lowry
Kentucky Electric Steel, Inc.
By: /s/ William H. Jones, Jr.
------------------------------------
William H. Jones, Jr.
VanAntwerp, Monge, Jones & Edwards, LLP
<PAGE> 32
ATTACHMENT A
Page 1 of 1
AEP/CSW MERGER
NET ANNUAL MERGER SAVINGS
AND KENTUCKY CUSTOMER BILL REDUCTIONS ($000)
<TABLE>
<CAPTION>
(1) (2) (3) (4)
RATE NET CUSTOMER BILL SHAREHOLDER
YEAR MERGER SAVINGS REDUCTION @ 55% NET SAVINGS @ 45%
------ -------------- --------------- -----------------
<S> <C> <C> <C>
Year 1 2,469 1,464 1,005
Year 2 4,551 2,554 1,997
Year 3 5,757 3,185 2,572
Year 4 6,732 3,695 3,037
Year 5 7,385 4,037 3,348
Year 6 7,887 4,299 3,588
Year 7 8,279 4,505 3,774
Year 8 8,511 4,626 3,885
------ ------ ------
51,571 28,355 23,206
====== ====== ======
</TABLE>
Note: Annual Customer Bill Reduction after year 8 until next base rate case is
$5,242,785.
<PAGE> 33
ATTACHMENT B
Page 1 of 3
AEP/CSW MERGER
EXAMPLE OF BASE RATE CASE TREATMENT
BASED ON YEAR 3 ($000)
<TABLE>
<S> <C> <C> <C>
CREDIT PER RIDER CONTINUES (3,184)
INCLUDED IN TEST YEAR
GROSS MERGER SAVINGS (7,262)
CHANGE IN CONTROL AMORTIZATION 328
OTHER CTA AMORTIZATION 1,178
----------------
TOTAL CTA/CIC AMORTIZATION 1,506
-------------------
NET MERGER SAVINGS IN TEST YEAR (5,756)
ADD BACK TO TEST YEAR COST OF SERVICE
CUSTOMER SHARE 3,184
SHAREHOLDER PORTION 2,572
----------------
5,756
-------------------
NET BASE REDUCTION 0
--------
KENTUCKY CUSTOMER RATE REDUCTION (3,184)
========
</TABLE>
<PAGE> 34
ATTACHMENT B
Page 2 of 3
AEP/CSW MERGER
BASE RATE CASE TREATMENT
FOR INCLUSION IN COST OF SERVICE ($000)
<TABLE>
<CAPTION>
Add Back to Test Year Cost of Service
-------------------------------------
RATE CUSTOMER SHAREHOLDER
YEAR NET SAVINGS NET SAVINGS
---- ----------- -----------
<S> <C> <C> <C>
Year 1 1,464 1,005
Year 2 2,554 1,997
Year 3 3,185 2,572
Year 4 3,695 3,037
Year 5 4,037 3,348
Year 6 4,299 3,588
Year 7 4,505 3,774
Year 8 4,626 3,885
------ ------
28,365 23,206
====== ======
</TABLE>
<PAGE> 35
ATTACHMENT B
Page 3 of 3
AEP/CSW MERGER
AMORTIZATION OF ESTIMATED
COSTS TO ACHIEVE*
<TABLE>
<CAPTION>
RATE
YEAR AMOUNT
---- ------
<S> <C> <C>
Year 1 1,505,502
Year 2 1,505,502
Year 3 1,505,502
Year 4 1,505,502
Year 5 1,505,502
Year 6 1,505,502
Year 7 1,505,502
Year 8 1,505,501
----------
TOTAL 12,044,015 **
==========
</TABLE>
* Includes change in control payments.
** May not add due to roundings.
<PAGE> 36
AEP/KENTUCKY POWER SERVICE QUALITY
Attachment C
Page 1 of 5
AEP/Kentucky Power (the Company) has as one of its highest priorities a desire
to maintain and improve the quality and reliability of service to its customers.
The Company commits that current levels of customer service and service
reliability shall not degrade as a result of the merger and that it shall
undertake all reasonable efforts to improve the quality and reliability of its
service. In order to assure the Commission and Kentucky customers of continued
excellent service quality in the post-merger environment, the Company commits
and agrees to do the following:
1. To maintain the overall quality and reliability of its electric service at
levels no less than it has achieved in the calendar years 1995-1998. The Company
will provide service reliability reports annually indicating its calendar year
Kentucky Customer Average Interruption Duration Index (CAIDI) and Kentucky
System Average Interruption Frequency Index (SAIFI). These indices shall be
determined and reported, including all storms. Definitions for these measures
are included on page 3. On page 5 are listed Kentucky Power's annual SAIFI and
CAIDI performance for the years 1995 through 1998.
2. To provide annual Call Center performance measures for those centers which
handle Kentucky customer calls. These will include the Call Center Average Speed
of Answer (ASA), Abandonment Rate, and Call Blockage. Definitions for these
measures are also included on page 4.
a) The performance measures described in paragraphs 1 and 2 above
shall be provided by the end of May of the year following the
calendar year in question.
3. Will continue to completely inspect its Kentucky electric facilities every
two years and perform tree trimming, lightning arrest or replacement, animal
guarding and pole and cross arm replacements.
4. AEP/Kentucky Power management will compile outage data detailing each
circuit's reliability performance. In addition, by monitoring repeated outages
on a regular basis, the Company will identify and resolve reliability problems
which may go unnoticed by using CAIDI and SAIFI results. This data will be
coupled with feedback from district field personnel and supervision and
management concerning other locations and situations where the impact of outages
are quantified. This process will be used to develop a comprehensive work plan
each year which focuses efforts to improve service reliability. The Company will
undertake all reasonable expenditures to achieve the goal of limiting customer
outages.
5. Plans to continue to maintain a high quality workforce to meet its customers
needs.
6. Shall designate an employee or agent within Kentucky who will act as a
contact for retail consumers regarding service and reliability concerns and to
provide a contact for retail consumers for information, questions and
assistance. Such AEP/Kentucky Power representative shall be able to deal with
billing, maintenance and service reliability issues.
<PAGE> 37
AEP/KENTUCKY POWER SERVICE QUALITY
Attachment C
Page 2 of 5
a) The company further commits to maintain in Kentucky a
sufficient management team to ensure that safe, reliable and
efficient electric service is provided and to respond to the
needs and inquiries of its Kentucky customers.
7. In the event the Commission adopts industry generic rules concerning customer
service standards, AEP/Kentucky Power shall have at its option, the right to
incorporate them into this agreement.
a) AEP/Kentucky Power will have the opportunity to revisit with
the Commission the agreed upon measure(s) should the Company
wish to propose a specific performance-based ratemaking
proposal provided the proposal either includes a reliability
measure(s) and/or a customer satisfaction survey measure that
contains service reliability as a component.
b) These standards can be changed during the term of this
agreement to reflect any performance-based ratemaking plans or
rules which the Commission adopts either for AEP/Kentucky
Power and/or generically for the electric utility industry.
8. If retail access is mandated by the Kentucky General Assembly and/or the
Commission and/or by federal legislation, AEP/Kentucky Power shall have the
right to petition the Commission for modifications to this service quality
agreement that are made necessary by the mandating of retail access.
a) Any such petition must establish the necessity of the proposed
modifications and provide appropriate protections to ensure
that AEP/Kentucky Power's quality of service will not decline.
The Commission will act upon the petition within 90 days or
the petition will be deemed to be automatically approved.
9. All prudent costs incurred to comply with the items contained in this
Agreement, once incurred, will constitute known and measurable expenses that
Kentucky Power shall have an opportunity to recover in accordance with
traditional ratemaking principles, through recognition of these costs in its
revenue requirement in future rate review.
2
<PAGE> 38
AEP/KENTUCKY POWER SERVICE QUALITY
Attachment C
Page 3 of 5
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
<PAGE> 39
AEP/KENTUCKY POWER SERVICE QUALITY
Attachment C
Page 4 of 5
AEP CALL CENTER MEASURES
1) Average Speed of Answer (ASA) is defined as the average 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 = Time for all calls between call answer and
(seconds) 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 = {Total number of callers who hang up}
(percent) ----------------------------------------------- x 100
{Total number of calls made to the Call Center}
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:
<TABLE>
<S> <C>
Call Blockage = {Total number of non-outage calls that do not get connected}
(percent) ------------------------------------------------------------ x 100
{Total number of non-outage calls made to the Call Center}
</TABLE>
<PAGE> 40
AEP/KENTUCKY POWER SERVICE QUALITY
Attachment C
Page 5 of 5
AEP/KENTUCKY POWER RELIABILITY PERFORMANCE
(INCLUDES ALL STORMS)
<TABLE>
<CAPTION>
Year SAIFI CAIDI
---- ----- -----
<S> <C> <C> <C>
1995 1.794 4.12
1996 1.530 3.10
1997 1.343 3.04
1998 1.519 5.96
</TABLE>
<PAGE> 41
EXHIBIT 1
ATTACHMENT D
COMMONWEALTH OF KENTUCKY
BEFORE THE
PUBLIC SERVICE COMMISSION OF KENTUCKY
IN THE MATTER OF:
JOINT APPLICATION OF KENTUCKY POWER COMPANY, )
AMERICAN ELECTRIC POWER COMPANY, INC. )
AND CENTRAL AND SOUTH WEST CORPORATION ) CASE NO. 99-149
REGARDING A PROPOSED MERGER )
On February 17, 1999, the Staff of the Public Service Commission of
Kentucky ("Commission") issued a letter stating staff's belief that the
Commission has jurisdiction under KRS 278.020 (5) to review the proposed merger
of Central and South West Corporation ("CSW") into American Electric Power
Company, Inc. ("AEP") and requested that Kentucky Power Company ("Kentucky
Power", "KPCO" or the "Company") advise in writing by March 8, 1999 of the date
AEP would file an application for Commission approval of "the indirect change in
control of Kentucky Power Company." On March 5, 1999 the Company issued a letter
notifying the Commission that it would file the requested application by April
15, 1999. The letter also indicated that the Company expected to provide the
Staff and the Commission with sufficient information to enable the Commission to
approve its application within the sixty (60) day period prescribed by the
statute. The letter further preserved the Company's legal arguments regarding
the application of KRS 278.020 to this merger.
On April 15, 1999, the Company, AEP and CSW filed a Joint Application
with supporting testimony and work papers. The proceeding was designated P.S.C.
Case No. 99-149. On April 22, 1999, the Commission issued a letter indicating
that the Commission staff had reviewed the Company's application and found that
it met the minimum filing requirements.
<PAGE> 42
On May 4, 1999, the Attorney General, Office of the Rate Intervention
("Attorney General"), and Kentucky Electric Steel, Inc. ("KESI") were granted
full intervention in Case No. 99-149. On May 11, 1999, Kentucky Industrial
Utility Customers, Inc. ("KIUC"), was also granted full intervention in Case No.
99-149. These parties will be referred to herein collectively as the
"Intervenors."
On April 22, 1999, a Technical Conference was held at the Commission's
offices. On May 4, 1999, May 11, 1999, May 17, 1999 and May 20, 1999 settlement
conferences were held at the Commission's offices. All parties to the proceeding
and the Commission staff were present and participated in the settlement
conferences.
Having considered the evidence and being duly advised, the Commission
now finds:
1. Notice and Jurisdiction. Due and timely notice of the hearing to
consider the settlement proposed by the parties was given. Kentucky Power is a
"utility" within the meaning of that term in KRS 278.010(3)(a) and is subject to
the jurisdiction of the Commission in the manner and to the extent provided by
the laws of the Commonwealth of Kentucky.
2. The Settlement Agreement. As described in the Settlement Agreement,
a copy of which is attached hereto as Exhibit A and incorporated herein by
reference, the Settlement Agreement contains, among other things, provisions
regarding (a) net non-fuel merger savings; (b) fuel and purchased power merger
savings; (c) limitation on requests for stranded cost recovery; (d) allocation
of proceeds from the sale of facilities; (e) system integration agreements; (f)
Ohio Power waiver; (g) affiliate standards; (h) maintenance and enhancement of
the adequacy and reliability of retail electric service, including certain
reporting requirements; (i) settlement of the existing environmental surcharge
litigation (Kentucky Court of Appeal Case No. 98-CA-00137, 98-CA-01344,
98-CA-01417, 98-CA-01455); and (j) settlement of the pending six month
2
<PAGE> 43
review of KPCO's environmental surcharge in P.S.C. Case No. 98-624. The
Settlement Agreement was agreed to by all parties to this proceeding.
The Settlement Agreement further provides that if the 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.
The Settlement Agreement also provides that, upon approval by the
Commission, the Intervenors, the Commission and its Staff shall not oppose the
proposed merger before FERC or oppose AEP's previously made merger-related
filings with the Securities and Exchange Commission.
The Settlement Agreement further states that it 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 on these particular issues. The
Settlement Agreement provides that it is solely the result of compromise in the
settlement process, shall not constitute a concession of subject matter
jurisdiction, and except as expressly provided therein, is without prejudice to
and shall not constitute a waiver of any position that any of the parties
thereto may take with respect to any or all of the items resolved therein in any
future regulatory or other proceedings.
The Settlement Agreement states that if the Commission does not approve
the Settlement Agreement in its entirety, it shall be null and void and deemed
withdrawn, unless such change is approved by the parties.
3
<PAGE> 44
At a hearing held May 28, 1999, Richard E. Munczinski, Senior Vice
President-Corporate Planning and Budgeting of American Electric Power Service
Corporation, the service corporation subsidiary of AEP, and Errol K. Wagner,
Director of Regulatory Affairs for Kentucky Power testified in support of
Commission approval of the Settlement Agreement. Mr. Munczinski discussed the
negotiating process which resulted in the Settlement Agreement and the public
benefits that would result from its approval. Mr. Wagner testified regarding the
mechanism by which the bill reductions will be implemented by Kentucky Power.
During the course of this proceeding information about the proposed
merger was requested from and provided by Kentucky Power, AEP and CSW.
Additional information about the proposed merger has since been developed in the
course of FERC proceedings and proceedings before other state commissions. After
lengthy and detailed negotiations, Kentucky Power, CSW, AEP, the Attorney
General, Office for Rate Intervention, Kentucky Industrial Consumers, Inc. and
Kentucky Electric Steel have reached a unanimous agreement on terms and
conditions that help ensure that Kentucky consumers will fairly share in the
benefits achieved by the merger and that Kentucky consumers will be protected
against any detrimental effects. The Parties recommend that the Commission
approve the Settlement Agreement as a fair and just settlement of differences
regarding merger-related issues.
Having reviewed the Settlement Agreement and the evidence relating
thereto, the Commission finds that the recommendation of the Parties should be
approved. The Commission further finds that the Settlement Agreement is a fair
and reasonable resolution of the merger-related issues of concern to the
Commission and the Intervenors and should be approved in its entirety without
modification.
4
<PAGE> 45
The Commission finds that AEP and Kentucky Power have and will retain
the financial, technical and managerial abilities to provide reasonable service.
The Commission further finds that the proposed merger of AEP and CSW is
in accordance with the law, for a proper purpose and is consistent with the
public interest.
IT IS THEREFORE ORDERED BY THE PUBLIC SERVICE COMMISSION OF KENTUCKY
that:
1. The Settlement Agreement shall be and hereby is approved in its
entirely without modification and that the merger of AEP and CSW is approved
pursuant to KRS 278.020(4) and KRS 278.020(5).
2. Kentucky Power shall implement the Net Merger Savings Credit Tariff
in the amounts shown in the tariff filed as Exhibit 2 to this Order, which
tariff is approved.
3. American Electric Power, Inc. and Central and South West Corporation
will incur transaction, regulatory processing and transition costs to merge the
two companies. The Commission orders that the Kentucky retail jurisdictional
share of the estimated merger costs be deferred and amortized for recovery over
eight years. The amortization should begin with the date of the combination and
continue for eight years on a straight-line basis.
4. The proposed regulatory plan is approved as are the steps necessary
to implement it, specifically:
a. the regulatory treatment of the fuel saving arising from
the integrated operations of AEP, CSW and Kentucky Power as set forth in the
Settlement Agreement;
b. Kentucky Power is authorized to include as an allowable
expense in cost of service the non-fuel merger savings, net of cost to achieve
and amortization of estimated costs to achieve as set forth in Attachment B to
the Settlement Agreement.
5
<PAGE> 46
5. Effective January 1, 2000, KPCO shall begin collecting the
environmental surcharge, including the costs of the Low Nox burners for the Big
Sandy generating plant's Unit No. 1 and Unit No. 2, in accordance with the
Opinion and Order of the Franklin Circuit Court dated April 30, 1998, as amended
by Opinion and Order dated May 14, 1998 in Consolidated Case Nos. 97-CI-00137,
97-CI-01138, 97-CI-01144 (except those portions of the decisions allowing
retroactive recovery of the surcharge).
6. The Commission approves the settlement of the environmental
surcharge litigation (Kentucky Court of Appeals Case Nos. 98-CA-00137,
98-CA-01344, 98-CA-01417, 98-CA-01455 and 98 CA 002476) as described in the
Settlement Agreement and authorizes its counsel to execute the necessary
documents to dismiss the appeals and cross-appeals therein.
7. The pending review of KPCO's environmental surcharge in P.S.C. Case
No. 98-624 shall be terminated and that proceeding is ordered closed without
adjustment to the surcharge.
8. This Order shall be effective on and after the date of its approval.
______________________
By the Commission
6
<PAGE> 47
EXHIBIT 1
STIPULATION AND
SETTLEMENT AGREEMENT
<PAGE> 48
EXHIBIT 2
AMERICAN ELECTRIC POWER ORIGINAL SHEET NO. 25-1
CANCELING________ SHEET NO.____________
P.S.C. ELECTRIC NO. 7
NET MERGER SAVINGS CREDIT (N.M.S.C.)
APPLICABLE
To Tariffs R.S, R.S.-L.M.-T.O.D., Experimental R.S.-T.O.D., S.G.S.,
M.G.S., Experimental M.G.S.-T.O.D., L.G.S. Q.P., C.I.P., T.O.D., C.S.-I.R.P.,
M.W., O.L. and S.L.
RATE
The Net Merger Savings Credit shall provide for a monthly adjustment to
base rates on a rate per kWH of monthly consumption. The Net Merger Savings
Credit shall be calculated according to the following formula:
Net Merger Savings Credit = M.S.F. - B.A.F.
Where
(M.S.F.) is the Merger Savings Factor per KWH which is based on the
total Company net savings that are to be distributed to the Company's
Kentucky retail jurisdictional customers in each 12 month period.
<TABLE>
<CAPTION>
Net Savings Merger Savings
to be Factor
Distributed (M.S.F.)
----------- --------
<S> <C> <C>
Year 1* $1,463,815 .021(cent)per Kwh
Year 2 2,553,660 .037(cent)per Kwh
Year 3 3,184,645 .045(cent)per Kwh
Year 4 3,695,003 .051(cent)per Kwh
Year 5 4,037,167 .055(cent)per Kwh
Year 6 4,229,432 .057(cent)per Kwh
Year 7 4,504,920 .059(cent)per Kwh
Year 8 4,626,369 .059(cent)per Kwh
Year 9 5,242,785 .066(cent)per Kwh
</TABLE>
* The Net Merger Savings Credit will begin in the
first full billing month available following
thirty days from the consummation of the merger
and will continue until the effective date of a
Commission order changing the Company's base rates
after Year 8 of this tariff.
(B.A.F.) is the Balancing Adjustment Factor per KW for the
second through the twelfth months of the current distribution
year which reconciles any over- or under-distribution of the
net savings from prior periods. The B.A.F. will be determined
by dividing the difference between amounts which were expected
to be distributed and the amounts actually distributed from
the application of the Net Merger Savings Credit from the
previous year by the expected Kentucky retail jurisdictional
KWH. The final B.A.F. will be applied to customer billings in
the second month following the effective date of a Commission
order changing the Company's base rates after Year 8 of this
tariff.
TERMS OF DISTRIBUTION
1. The total distribution to the Company's customers will, in no
case, be less than the sum of the amounts shown for the first
eight years above.
2. On or before the 21st of the first month of each distribution
year following Year 1, the Company will file with the
Commission a status report of the Net Merger Savings Credit.
Such report shall include a statement showing the amounts
which were expected to be distributed and the amounts actually
distributed in previous periods, along with a calculation of
the B.A.F. which will be implemented with customer billings in
the second month of that distribution year to reconcile any
previous over- or under-distributions.
3. The Net Merger Savings Credit shall be applied to the
customer's bill following the rates and charges for electric
service, but before application of the school tax, the
franchise fee, sales tax or similar items.
DATE OF ISSUE:_____________ DATE EFFECTIVE __________________________________
ISSUED BY: E.K. WAGNER ______ DIRECTOR OF REGULATORY AFFAIRS ASHLAND, KENTUCKY
<PAGE> 1
Exhibit D-8.1
STATE OF INDIANA
INDIANA UTILITY REGULATORY COMMISSION
IN THE MATTER OF THE INVESTIGATION )
ON THE COMMISSION'S OWN MOTION )
INTO ANY AND ALL MATTERS RELATING ) CAUSE NO. 41210
TO THE MERGER OF AMERICAN )
ELECTRICAL POWER, INC., AND CENTRAL ) APPROVED:
AND SOUTH WEST CORPORATION ) APR 26, 1999
BY THE COMMISSION:
Camie J. Swanson-Hull, Commissioner
David E. Ziegner, Commissioner
Claudia J. Earls, Administrative Law Judge
On June 29, 1998, the Commission on its own motion indicated an
investigation regarding the proposed merger of American Electric Power Company,
Inc. ("AEP") and Central and South West Corporation ("CSW"). AEP is the parent
company of Indiana Michigan Power Company ("I&M") which provides electric
utility service in the State of Indiana. The Order noted that AEP and CSW had
filed an application with the Federal Energy Regulatory Commission ("FERC") for
approval of the merger under Section 203 of the Federal Power Act.
Petitions to intervene in this matter were filed by the Citizens Action
Coalition of Indiana, Inc. ("CAC"), Indiana Consumers For Fair Utility Rates (an
ad hoc group of industrial companies) ("ICFUR"), PSI Energy, Inc. ("PSI") and
Steel Dynamics, Inc.(1) These petitions were granted and these entities were
made parties to this proceeding. The Office of Utility Consumer Counselor
("OUCC") also participated in this proceeding.
After receiving written comments of the parties on certain issues
relating to the proposed merger and after holding a preliminary hearing on
August 4, 1998, the Commissioner on September 2, 1998, issued an Order
appointing a negotiating team of members of the Commission Staff (the "Staff
Negotiating Team") to attempt to negotiate a settlement of the issues present in
this matter.
By docket entries, I&M was directed to respond to various data requests
seeking information about the proposed merger and to provide to the Commission,
the Staff Negotiating Team and the other parties certain documents relating
thereto. I&M responded to the requests by providing voluminous information and
documents.
During the course of this proceeding, status hearings were held at
which time the Staff Negotiating Team submitted reports regarding the process of
negotiations. On April 9, 1999, I&M and the Staff Negotiating Team submitted to
the Commission and
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(1) SDI subsequently withdrew from the proceeding.
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recommended for approval a Stipulation and Settlement Agreement (the "Settlement
Agreement") executed by I&M, AEP and the Staff Negotiating Team.
On April 14, 1999, the parties to the Settlement Agreement prefiled
with the Commission prepared testimony and evidence in support of the Settlement
Agreement. A public evidentiary hearing on the Settlement Agreement was held on
April 19, 1999, at 10:00 a.m. in Room TC10 of the Indiana Government Center
South, Indianapolis, Indiana. At that time, the Settlement Agreement and
evidence relating thereto were accepted into the record.
Based upon the applicable law and evidence herein, the Commission now
finds:
(1) NOTICE AND JURISDICTION. Due legal and timely notice of the
settlement hearing was given and published as required by law. I&M is a "public
utility" within the meaning of that term in IC 8-1-2-1 and is subject to the
jurisdiction of the Commission in the manner and to the extent provided by the
laws of the State of Indiana. At the conclusion of the evidentiary hearing held
in this cause, CAC stated three bases for this Commission to determine that it
did not have the authority to approve the tendered Settlement Agreement. On
April 19, 1999, CAC filed a "Motion for Ruling in the Nature of a Judgment on
the Evidence." The three arguments raised by CAC are as follows:
(1) The Commission lacks subject matter jurisdiction to approve the
"Regulatory Plan" proposed in the Settlement Agreement.
(2) The Commission lacks jurisdiction to approve the "Regulatory Plan"
because I&M's customers have not received adequate notice that their
future rates could be adjudicated in this proceeding.
(3) Even if the Commission has the general subject matter jurisdiction and
jurisdiction in this particular case to approve the proposed
"Regulatory Plan," the rate-making treatment proposed in the Plan is
contrary to law.
On April 21, 1999, I&M filed its response. We will first discuss CAC's
arguments regarding the notice given to the public in this cause and then
address the arguments regarding the Commission's authority to grant the relief
requested in the Settlement Agreement.
a. Notice of the scope of the proceeding. CAC contends that customers
did not receive adequate notice that future rates could be adjudicated in this
proceeding. Specifically, CAC argues that there is no reference to "rates" in
the public notice provided in this cause and secondly, that even the active
parties to this proceeding understood that the intended purpose of the
Commission investigation was to gather information for the purposes of
formulation of the Commission's position before the Federal Energy Regulatory
Commission, not to adjudicate issues as the regulator of I&M's retail rates and
charges.
Indiana law clearly states that the IURC must have flexibility in
determining the appropriate content of public notices. "The complexity and
varied nature of regulatory
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proceedings militate against the adoption of a more particularistic notice
standard; the Commission's Rule 8(b) provides the flexibility necessary for
case-by-case determinations of the appropriate content of the public notice to
be published." City of Evansville v. Southern Ind. Gas & Elec. Co., 339 N.E.2d
562, 578 (Ind. Ct. App. 1975). Our administrative code requires the caption of a
petition to describe in general terms all the relief being sought in the
petition, 170 IAC 1-1-8(b) (emphasis added). In this proceeding, customers were
given notice that "any and all matters relating to the merger" were subject to
the investigation. This broad notice certainly contemplates that issues
including but not limited to merger savings, merger cost allocation, and impact
on jurisdictional customers of the merged utility would be considered. We find
that the public notice issued in this proceeding was sufficient to notify
customers that the investigation may reach the issue of rate treatment. We also
note that, even where a public utility makes a complaint as to any matter
affecting its own rates or service, only reasonable notice is required, and
there is no necessity for specific public notice of all regulatory issues whose
ultimate resolution might independently affect an increase in a utility's rates.
See, e.g., City of Evansville v. Southern Ind. Gas & Electric Co., 339 N.E.2d
562, 578-579.
The notice provided in this case stated that this was a Commission
investigation. Under the Commission's investigatory powers, the Commission has
the power and authority to issue orders consistent with its broad grant of power
from the legislature which is necessary to effectuate the regulatory scheme.
See, N. Ind. Pub. Serv. V. Citizens act. Coal., 548 N.E.2d 153 (Ind. 1989). In
its "Memorandum of Law in Support of Motion for Ruling in the Nature of Judgment
on the Evidence," CAC argues that "even the active parties to this proceeding
understood that the intended purpose of the Commission investigation was to
gather information...." p.7. The Commission's September 2, 1998 Order provided
notice to the parties that the Commission was moving from an informal
investigation pursuant to IC 8-1-2-58 to a formal adjudication pursuant to IC
8-1-2-59. The Commission had previously described the issues before it to
include "how the risks, costs and benefits of the merger should be shared among
the stockholders and the customers, both wholesale and retail, of AEP." Order,
June 29, 1998, Exhibit A, p.4, Item 4. CAC participates in the process. As Staff
witness Glazier stated at the hearing held in this Cause, "We are negotiating on
behalf of the almost six million people who we work for, Mr. Muller. And as you
know, you were part of the negotiation discussions." To have participated in the
settlement negotiations and then allege that the parties were unaware of the
scope of the proceedings is puzzling to the Commission.
CAC also makes mention of the fact that I&M did not provide notice to
its customers of the potential rate impact of the Commission's investigation.
Yet, nowhere in its legal memorandum does CAC cite any authority that confers
upon I&M an affirmative duty to provide such notice. In addition, the Commission
would note that CAC has waived any such challenge to our jurisdiction. As the
Indiana Supreme Court found in City of New Haven v. Indiana Suburban Sewers,
Inc., (1972) 277 N.E.2d 361:
If the notice prescribed is prerequisite to jurisdiction of
the subject matter of the proceedings, the rule is otherwise,
as the right to challenge such jurisdiction can never be lost
or waived. Appellant has correctly stated such rule and
supported it with good authority, but we believe the
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question here is not one of jurisdiction over the subject
matter of the proceedings. Such jurisdiction was established
when notice of the time and place of public hearing was given
more than ten (10) days prior to the date set for the hearing
as prescribed by the statue, Indiana Acts 1957, ch. 313,
Section 2, 1969 Supp. Burns Ind. Stat. Ann. Section 54-601c,IC
1971, 8-1-289. Having been thusly established, such
jurisdiction continued throughout the proceedings, including
the rehearing, and we believe that the ends of justice would
not be served by faulting proceedings by reason of a defect in
the form of notice, if such defect did in fact exist, when the
complaining party attended and participated therein. Clearly
the notice which Appellant insists should have been given
would not have benefited it and its omission did it no harm.
Id., at p. 362-3.
CAC also argues that it did not have full rights of discovery. It never
raised this concern throughout the investigation. All parties were invited to
submit proposed discovery requests to the Commission. The Commission then issued
data requests akin to discovery requests including data requests propounded by
CAC. At no time did CAC object in this procedure. On November 30, 1998, the
Commission issued a docket entry stating that it had reviewed AEP's responses to
its data requests, and giving all parties an opportunity to submit additional
data requests to the Commission for consideration. CAC provided no new data
requests. In addition, CAC is a party to the FERC action and was a party to the
FAC 40 S i subdocket before this Commission. CAC has had available to it all
discovery processes in both of those proceedings. This argument appears as
devoid of merit as the argument that CAC was without notice of the scope of the
proceeding.
Having considered the arguments of the parties the Commission finds
that the public received proper notice of the proceedings held in this Cause and
that the Commission has complied with the applicable authority regarding the
procedural conduct of this proceeding.
b. Commission's Jurisdiction to grant the requested relief. Throughout
CAC's "Memorandum" it argues that I&M is "recovering through rates" shareholder
savings. CAC's argument is misguided. I&M has agreed in the Settlement Agreement
to pass through 55% of the net merger savings immediately and automatically upon
consummation of the merger. Without this agreement, I&M could have maintained
its existing rates until either it successfully petitioned the Commission for a
change in its base rates or the Commission initiated either on its own or at the
request of another party and concluded an investigation into the reasonableness
of I&M's base rates.
CAC also argues that the Settlement Agreement's allowances of the
referral and amortization over the eight-year period of the merger costs is
allowing the inclusion in customer rates of expenses based upon contingencies
that have not yet occurred. To support its proposition, CAC cites Citizens
Action Coalition v. Public Serv. Co. (Ind.
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App. 1993) 612 N.E. 2d 199, 201. That case is readily distinguishable from this
case insomuch as that case dealt with the Commission's speculation regarding the
probability of passage of acid rain legislation. In the instant case, the
contingent event is the consummation of the merger. If there is no merger, there
is no effect of the Settlement Agreement. In this case, there is no speculation.
If the merger occurs, I&M is allowed to amortize the expenses associated with
the merger. If the merger does not occur, there will be no allocation of those
expenses and no rate impact. To adopt CAC's position would be to call into
question every municipal rate order this Commission has issued in the recent
past which allows for an increase in rates premised upon an increase in debt
service in anticipation of the issuance of bonds to fund a capital improvement
project. Generally the bonds have not been issued when the municipality
petitions for rate relief. Thus, the Commission in granting the rate relief is
premising the relief on the issuance of the bonds, a future contingency. Orders
on proposed but unconsummated transactions have occurred in the merger and/or
take-over context as well. For example, in our order in Cause No. 37962, issued
May 29, 1986, in a case involving the acquisition of the Zionsville waterworks
system by Zionsville Water Corporation, a subsidiary of Indianapolis Water
Company, the Commission approved the accounting methodology to be utilized upon
consummation of the transaction for the recording of the purchase, including an
acquisition adjustment. The transaction had not been consummated, and yet the
accounting treatment was approved. In addition, the Commission approved the
amortization of the acquisition adjustment as an "above-the-line" operating
expense recoverable through rates. Order, p.19. The Commission noted that such
treatment was consistent with a previous order involving Indiana Cities Water
Corporation, Cause No. 37579, Order issued June 12, 1985. In addition, in
several cases, future rate-making treatments were approved in advance of the
closing of the transaction, and in many of the cases, pre-approval of the
rate-making treatment was a condition for closing. See e.g., Indianapolis Gas
Co. and Westport Net Gas Corp., Cause No. 38302 issued January 20, 1988; West
Lafayette Water CO. and Green Meadows Util., Cause Nos. 39417, 38902 and 39166-U
issued September 23, 1962; and Indiana American Water Co. and Farmington
Utilities, Inc., Cause No. 40442, issued October 2, 1996.
The final argument that CAC presents against the Settlement Agreement
is that it attempts to "bind" future Commissions with respect to various
expenses. As Indiana courts have stated on numerous occasions, the rate-making
process is a legislative not an adjudicatory process. See, e.g. Office of
Utility Consumer Counselor v. Public Service Company, 463 N.E.2d 499 (Ind. App.
3 Dist. 1984). There is no precedent set in one case for use in a subsequent
case. Res judicata principles apply when an administrative agency acts in a
judicial capacity, but do not apply when the agency acts in a legislative
capacity. See, Indiana Gas v. Utility Consumer Counselor, 610 N.E.2d 865 (Ind.
App. 5 Dist. 1993). In this case, the Settlement Agreement requests that the
Commission allow I&M to book certain expenditures. In any rate proceeding, the
Commission is allowed to presume a utility's costs are prudently incurred. See,
Anaheim v. Federal Energy Regulatory Commission, (D.C. Circuit, 1981) 669 F.2d
799). However, where a participant in a proceeding creates a doubt as to the
reasonableness of the expenditure, the burden of dispelling these doubts and of
proving the questioned expenditure falls to the utility. Id. Obviously, if the
Commission approves the Settlement Agreement and I&M is allowed to book certain
expenditures, any party to any subsequent proceeding may question the
reasonableness of any such expenses. CAC argues that by adopting our Staff's
recommendation to approve the Settlement Agreement, the Commission will be
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mystically transformed into a proponent of the accounting treatment afforded the
expenditures in any subsequent rate proceeding. The adoption of a Staff
recommendation, however, does not transform the Commission into a proponent. As
the Appellate Court held in Board of Directors for Utilities v. Office of Util.
Consumer Counselor.
The statute does not limit the use of these reports by the
Commission and to the extent that they become a part of the
record and their contents may be utilized by the Commission,
they are evidence. Reliance on the reports does not
automatically transform the Commission into a proponent or
opponent in the proceedings. To hold otherwise would place
I.C. 8-1-1-5(a) in direct conflict with subsection (b), an
illogical result clearly not intended by the legislature. . .
. The reports are merely an additional tool to aid the
assimilation of factually complex and technical information.
c. Conclusion. Having considered the arguments raised by CAC, the
Commission finds that due, legal and proper notice of this proceeding was given
as provided by law and that this Commission has jurisdiction over Petitioner and
the subject matter of this cause and has authority to approve the Settlement
Agreement if it is found o be in the public interest.
(4) PROVISIONS OF THE SETTLEMENT AGREEMENT. As described in
the Settlement Agreement, a copy of which is attached hereto as Exhibit
A, and incorporated herein by reference, the Settlement Agreement
contains, among other things: (a) net non-fuel merger savings; (b) fuel
and purchase power merger savings; (c) limitation on requests for
stranded cost recover; (d) allocation of proceeds from the sale of
facilities; (e) system integration agreements; (f) Ohio Power waiver;
(g) regional transmission organization commitments; (h) affiliate
standards; and (i) maintenance and enhancement of the adequacy and
reliability of retail electric service, including certain reporting
requirements.
The Settlement Agreement further provides that if any other state
commission or any federal commission issues a final and non-appealable order
addressing the merger that provides benefits or imposes conditions that would
benefit ratepayers of another jurisdiction, AEP will extend equivalent net
benefits and conditions to all AEP retail customers.
The Settlement Agreement also provides that, upon approval by the
Commission, neither the Commission nor its Staff shall oppose the proposed
merger before FERC or oppose AEP's previously made merger-related filings with
the Securities and Exchange Commission.
The Settlement Agreement also states that it shall not constitute nor
be cited as precedent or deemed an admission by any party in any other
proceeding except as
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necessary to enforce its terms before the Commission, or any State Court of
competent jurisdiction on these particular issues. The Settlement Agreement
provides that it is solely the result of compromise in the settlement process,
shall not constitute a concession of subject matter jurisdiction, and except as
expressly provided therein, is without prejudice to and shall not constitute a
waiver of any position that any of the parties thereto may take with respect to
any or all of the items resolved therein in any future regulatory or other
proceedings.
The Settlement Agreement states that if the Commission does not approve
the Settlement Agreement in its entirety, it shall be null and void and deemed
withdrawn, unless such change is approved by the parties. However, the
Settlement Agreement does provide the Commission with the authority to address
matters ancillary or incidental to the agreement.
At the settlement hearing, Robert C. Glazier, Director of Utilities for
the Indiana Utility Regulatory Commission, Richard E. Munczinski, Senior Vice
President-Corporate Planning and Budgeting of American Electric Power Service
Corporation, the service corporation subsidiary of AEP, and Kent D. Curry,
Director of Regulatory Affairs for I&M, testified in support of Commission
approval of the Settlement Agreement. Mr. Glazier and Mr. Munczinski discussed
the negotiating process which resulted in the Settlement Agreement and the
benefits that they believe would result from its approval. Mr. Curry testified
regarding the mechanism by which the bill reductions would be implemented by
I&M.
(5) COMMISSION FINDINGS. In our Order dated June 29, 1998, the
Commission stated this investigation was commenced because the
Commission believed that the proposed merger of AEP and CSW could have
significant impact on the electric industry and customers in Indiana
and across the region and the Commission was concerned about the
proposed merger's effect on reliability of service and the development
of independent system operators. During the course of this proceeding
considerable information about the proposed merger was requested from
and provided by I&M. Additional information about the proposed merger
has been developed in the course of FERC proceedings and proceedings
before other state commissions. After lengthy and detailed
negotiations, I&M, AEP and the Staff Negotiating Team have reached
agreement on terms and conditions which they allege will help ensure
that Indiana consumers will fairly share in the benefits achieved by
the merger and that Indiana consumers will be protected against any
detrimental effects arising from the merger. The Staff Negotiating Team
recommended that the Commission approve the Settlement Agreement as a
fair and just settlement of differences regarding merger-related
issues.
At the hearing held in this cause, various parties expressed concern
regarding various aspects of the Settlement Agreement. Those concerns included:
(a) the mechanism for sharing of non-fuel merger savings; (b) the accounting
methodology to be used to allocate the merger costs and projected savings; (c)
the mechanism for the pass-through of fuel merger savings; (d) the assurances in
the Settlement Agreement that AEP will join a Regional Transmission Organization
("RTO"); (e) the affiliated standards; (f) the adequacy and reliability of AEP's
electric service; and (g) the public interest issues raised by the proposed
merger.
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The Commission will address each of these concerns individually.
(a) Non-fuel merger savings tracker mechanism. CAC raised a concern
regarding the implementation of the Regulatory Plan, contained in the Settlement
Agreement and explained in more detail in the pre-filed testimony of AEP Witness
Curry. This Plan is used to pass certain non-fuel merger savings on to the
ratepayers of AEP. The procedural mechanism proposed to be used by AEP in this
Commission's 30-day filing procedure, an administrative procedure routinely used
to "track" expenses or savings back to the ratepayer. We note that as the 30-day
filing procedure is an informal process, it may need some enhancement to
alleviate some of the concern raised by CAC. We therefore find that in addition
to complying with the normal 30-day filing procedure, each filing made to track
the non-fuel merger savings should be accompanied by a verified statement
indicating that the facts contained in the filing are true to the best of AEP's
knowledge and that a copy of the 30-day filing has been served on each party to
this Cause. Our 30-day filing process includes an option for the Commission to
deny approval of any filing. The proponent of the filing may then petition the
Commission for approval of the requested relief at which time the Commission
would set any request for hearing. Nothing in this Order should be read to
preclude any party from objecting to any future 30-day filings by AEP. With
these safeguards, the Commission finds that the rider mechanism is acceptable to
implement the sharing of the non-fuel merger savings.
(b) Accounting Methodology. As discussed in Finding No. 1(b)
hereinabove, the Settlement Agreement contemplates the Commission issuing an
Order in this cause approving the proposed accounting treatment of the merger
expenses and merger savings. Mr. Munczinski testified that the merger expenses
are currently accruing on the parents' books and that upon consummation of the
merger, the costs will be allocated to the operating companies' books. Pursuant
to the terms of the Settlement Agreement, these costs are to be included in
AEP's future FAC proceedings for purposes of determining whether I&M has
complied with the "earnings test" contained in I.C. 8-1-2-42(d)(3)("d(3) test")
In addition, for purposes of the return allowed in the d(3) test, the portion of
merger savings allocated to shareholders will be utilized in essence to increase
the allowable return.
The Commission notes that these provisions will be of no consequence
unless at some point in the future, I&M is otherwise earning in excess of its
allowable return in a future FAC proceeding. In addition, the same treatment is
to be utilized should I&M file a base rate case. Pursuant to the terms of the
Settlement Agreement I&M may not file a base rate case with an effective date
prior to January 1, 2005. Considering the probability of either of these events
occurring, and consistent with the Commission's reasoning in Finding 1(b)
hereinabove, the Commission finds that the accounting methodology contained in
the Settlement Agreement should be approved.
(c) Fuel Energy Savings Reflected Through the FAC (Fuel Adjustments
Clause). The Settlement Agreement states that fuel savings will be passed
through the fuel adjustment clause proceeding. In each future quarterly FAC
filing, AEP is to calculate the difference between the fixed fuel rate (9.2
mills per kWh) found in the Stipulation and Settlement Agreement in Cause No.
38702-FAC40-S1 and the actual incurred fuel cost, in mills. If the weighted
average of actual fuel costs are less than the
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fixed fuel costs during the period of April 1, 1999 through December 31, 2003,
then that difference will be credited to customers, based on total kWh consumed,
as soon as possible after December 31, 2003. In this way, the fuel savings will
be passed along to the consumers upon the reconciliation contemplated in the FAC
40 S, 1 Order.
(d) Regional Transmission Organization. The Indiana Utility Regulatory
Commission has consistently advocated the establishment of Regional Transmission
Operators (RTOs), such as Independent System Operators (ISOs), as a means of
mitigating the inherent market power of transmission owners and to foster a more
efficient and competitive wholesale power market. The mitigation of market power
by AEP's membership in an RTO is exceedingly important.
To mitigate market power concerns and achieve greater reliability and
economic efficiency, the IURC has been supportive of efforts to form RTOs. While
we have been supporters of the Midwest Independent System Operator (MISO), we
have urged the FERC to make modifications to the MISO including, among other
things, to:
(1) Establish Power Exchanges (PXs) that would either be
(a) separate organizations that coordinated with the RTO, or
(b) a part of the RTO;
(2) vest the RTO with considerable authority over more of the traditional
control area responsibilities;
(3) ensure that coordination among RTOs, including pricing of services and
information protocols, are as efficient as possible.
While the IURC recognizes many positive aspects of the MISO, the IURC,
in this cause as articulated by Staff Witness Glazier and in Commission
statements to the FERC, continues to express its concern that more progress is
needed to ensure independence, reliability and economic efficiency. One of the
most immediate concerns is the need to require participation of all transmission
owners in an RTO. To this end, the IURC has urged the FERC to use its authority
under the Federal Power Act (FPA) to mandate the participation of all
transmission owning utilities in an RTO. The IURC has also urged the FERC to
allow a certain amount of time for the industry to establish appropriate
boundaries for RTOs. If the industry can not agree on the appropriate boundaries
for any given RTO by a date certain, the IURC has suggested the FERC use its
authority to draw those boundaries.
In previous testimony before the FERC and in this instant case, AEP's
position has been very similar to that espoused by the IURC. By way of example,
both AEP and the IURC have recognized the need for power exchanges. AEP has
suggested that RTOs assume greater authority over many traditional control area
responsibilities. AEP has also been a forceful advocate for large regional RTOs.
Counsel Ronald Brothers, on behalf of intervenor CINergy in this cause,
sought to clarify the reasons for AEP's unwillingness to join the MISO. During
the course of the cross-examination, it became clear to the IURC that AEP and
CINergy are in agreement in many many respects. It does not seem that the areas
of disagreement are
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insurmountable. By way of example, both CINergy and AEP agree that RTOs should
be as large as possible to provide greater reliability and efficiency. In this
regard, they both agree that an RTO could be as large as the entire eastern
interconnection. CINergy and AEP agree that gaps in the membership pose
significant problems. CINergy and AEP also both profess a sense of urgency.
It is against this backdrop that the IURC has evaluated this Settlement
Agreement. Certainly, getting AEP to commit to joining an RTO is a major
accomplishment and AEP and other parties should be commended for their strides
in this regard. The IURC will be assertive before the FERC to ensure that AEP
joins an RTO and, to the maximum extent possible, that the RTO satisfies the
conditions espoused by the IURC. The IURC is satisfied that nothing in this
agreement prevents the IURC from advocating these concerns to the FERC, or
advocating these positions in any other forum, or assisting the parties in
bridging the remaining differences.
(e) Affiliate Standards. Paragraph 8 of the Stipulation and Settlement Agreement
provides for Affiliate Standards between the regulated and non-regulated
affiliates of the merged company. Specific provisions of the Affiliate Standards
include:
(1) Principles for preventing cross-subsidization and/or cost shifting
among the regulated and non-regulated affiliates and among the various
regulatory jurisdictions in which the merged company will operate.
(2) Guaranteed Commission access to employees, officers, books and records
of any affiliate of the jurisdictional AEP operating company.
(3) 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.
(4) 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 agreement. Contracts between the AEP operating company and
non-utility affiliates must be filed with the Commission.
(5) The clear division of AEP operating company personnel, facilities and
information from affiliated non-regulated wholesale generating or
marketing personnel, facilities and information.
(6) AEP will designate an employee who will act as a contact for the State
Commission and consumer advocates seeking data and information
regarding affiliate transactions and personnel transfers.
(7) AEP will designate an employee who will act as a contact for retail
consumers for information, questions and assistance.
(8) AEP will inform the State Commission at least thirty days before making
a filing at the FERC or SEC.
(9) Violations of the provisions of the Affiliate Standards are subject to
the enforcement powers and penalties at the State Commissions.
(10) AEP will contact with an independent auditor who will conduct biennial
audits for eight years after merger consummation of affiliated
transactions to determine compliance with these affiliate standards.
The results of such audits will be filed with the State Commissions.
Prior to the initial audit, AEP will conduct an
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informational meeting with State Commissions regarding how its
affiliates and affiliate transactions will have changed as a result of
the proposed merger.
(11) If the Public Utility Holding Company Act of 1935 ("PUHCA") 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 State Commissions to ensure that AEP continues to
furnish the State Commission with the appropriate information to
regulate its jurisdictional AEP operating company.
During the Commission hearing AEP witness Richard E. Munczinski and
Staff Negotiating Team witness Robert C. Glazier were questioned on the various
provisions of the Affiliate Standards. Both witnesses were asked why the
definition of affiliate in the Stipulation and Settlement Agreement differed
from the definition contained in I.C. 8-1-2-49. Both witnesses responded that
the difference was unintentional and not designed to circumvent any Commission
rule or standard.
Mr. Munczinski was asked a number of questions during the hearing
designed to clarify various provisions of the Affiliate Standards section of the
Stipulation and Settlement Agreement. Subsection A3 of the Affiliate Standards
addresses the recovery of just and reasonable costs from the various regulatory
jurisdictions. Mr. Munczinski explained that this provision protected AEP from
just and reasonable costs being left unallocated or stranded. Mr. Munczinski
testified that these costs would include "particularly those [costs] that apply
to affiliated transactions, so that the parties have agreed that what should be
included in the cost of service would be those affiliated transaction costs that
meet the guidelines that are in this agreement, that the company should be made
whole. . ." In return, AEP pledges that no more than one hundred percent of the
cost will be allocated on an aggregate basis to the various regulatory
jurisdictions. Further, Mr. Munczinski committed that if a State Commission
failed to allow the recovery of just and reasonable affiliated transaction
costs, AEP would not seek recovery of those stranded costs from other
jurisdictions.
Counsel for CAC questioned Mr. Munczinski on the terms and requirements
of the independent audit addressed in Section V of the Affiliate Standards. Mr.
Munczinski explained that the audit would be designed to test each provision of
the Affiliate Standards to ensure AEP compliance. Further, that prior to the
initial audit, AEP would conduct informational meetings with the affected State
Commission to allow them to input on the audit requirements. AEP also pledged to
file an audit plan with each State Commission prior to the commencement of the
independent audit.
Questions from the bench regarding Section W of the Affiliate Standards
clarified that if PUCHA were repealed, AEP would continue to meet all
appropriate reporting requirements. AEP committed to work with the State
Commissions to determine what information would be reported to the Commission,
including an allocation of jurisdictional costs. Mr. Munczinski assured the
Commission that it was not AEP's intention to circumvent any Commission laws or
requirements upon the repeal of PUCHA.
Having reviewed the Affiliated Standards the Commission finds that they
are reasonable and should provide more protection to AEP's Indiana customers
than the current state of regulation. AEP should be advised that in determining
an "affiliate" it
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should use the definition contained in Indiana Code. AEP should also file an
audit plan with the Commission five days prior to commencing the independent
audit.
(f) Reliability of Service. This Commission is very concerned that the
reliability, quality and adequacy of electric service provided by AEP not
deteriorate as a result of this merger. The Settlement Agreement addresses these
concerns on page 11, rhetorical paragraph 9 and through the reporting
requirements contained in Attachment C to the Settlement Agreement. The
reporting requirements consist of annual reports on two reliability measures,
known as SAIFI (System Average Interruption Frequency Index) and CAIDI (Customer
Average Interruption Duration Index), and three call center measures, delineated
as Average Speed of Answer, Abandonment Rate, and Call Blockage. These reports
are to be provided to the IURC by the end of May for the preceding calendar
year. These reports will provide an indication of AEP's ongoing reliability,
quality and adequacy of electric service.
This Commission was troubled by the lack of quantification of any
benchmark against which to assess these measures to see if reliability, quality
and adequacy of electric service is being maintained or enhanced. Attachment C
of the Settlement Agreement indicated only that "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." Responding to questions from
the bench, both AEP witnesses Munczinski and Curry testified that AEP would be
willing to file with the Commission the historical reliability and call center
measures, in a form essentially similar to that contained in Attachment C for
the last ten years, provided that such data exists. We find that AEP shall file
all such historical data that exists with the Commission's Engineering Division
within ninety (90) days of the date of this October.
(g) Public Interest. The theory of law creating the Commission is that
"it shall be conscientiously and impartially administered by a body composed of
a personnel especially qualified by knowledge, training and experience
pertaining to the subject-matter committed to it . . . consonant with reasonable
fairness and substantial justice according to legislative mandate, and the
circumstances shown relative to its effect in the future on the utility's
ability to serve the interest and convenience of the public, the cost and
expense to the parties interested being an element for consideration." In re
Northwestern Indiana Tel. Co., 201 Ind. 667 (1929), at p. 674-5. When asked by
counsel for CAC for a definition of "public interest," Staff witness Glazier
stated that it was the balancing of the interests of economic development,
employment and the effectiveness of regulation. Case law has stated that the
Commission is to balance the interests of the affected utility and the public.
In Mr. Glazier's Staff Report admitted into the record of this cause he
stated that "[I]t appears that employment in Indiana will not be negatively
impacted as a result of the proposed merger." Report, p.11. At the hearing held
in this cause, Mr. Munczinski stated that "if there are affected employees [in
Indiana], they would be at the management level in the service corporation or at
the highest level of management in Indiana Michigan Company. What we have
excluded would be the field personnel. I think we're pretty sure that in Indiana
it would be all the IBEW workers, union workers, customer service
representatives, things like that. But I couldn't, for instance, guarantee the
legal positions or the rates director position." Later in Mr. Munczinski's
testimony, he referred
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to Mr. Flaherty's testimony in the Texas Docket. In that Docket, as Mr.
Glazier's staff report alludes to, Mr. Flaherty stated that there "are no
current plans to close any facilities in Indiana as a result of the AEP/CSW
merger." Report, p.11. The representation by AEP that no facilities will be
closed in Indiana and that no IBEW worker, union worker, or customer service
representative will lose their job, is critical to this Commission's
consideration of this merger.
The Settlement Agreement left at least two critical terms undefined.
One undefined term is "bulk transmission facilities." The other is "consummation
of the merger." The Commission is aware of the difficulties in defining the term
"bulk transmission facilities." As was explained at the hearing, there is a
potential conflict between the states and FERC regarding the definition of
transmission facilities giving rise to a conflict regarding jurisdiction of the
transfer of those assets. AEP should be aware that this Commission intends to
actively participate in FERC proceedings and this Commission will not readily
cede its control over the transfer of transmission facilities. In our opinion,
IC 8-1-2-83 is applicable to the transfer of assets. This Commission intends, as
we previously stated herein, to be assertive before the FERC to ensure that AEP
joins a FERC-approved RTO. We do not anticipate that the failure to define the
term "bulk transmission facilities" will be utilized by AEP to thwart in any way
the effort to establish a regional RTO. "Consummation of the merger" shall be
defined as the day on which CSW shares are converted to AEP shares. AEP should
immediately notify the Commission of this occurrence.
Given our task of balancing the interests of all of Indiana, the
Commission finds that approval of the Settlement Agreement is in the public
interest. Approval serves the interest and convenience of the public, and the
enormous cost in both time and money to continue litigating this matter on the
state and federal level will be diminished.
(h) Conclusion. At the conclusion of the hearing held in this cause,
the OUCC's counsel made the following statement, "We are very appreciative of
all the efforts that the Commission staff put into this negotiation. I know it
is a very complex and arduous task for them, and they did a good job, and
although the OUCC did not sign off on the agreement, it does not take away from
our belief that the Commission staff did everything they could to reach an
agreement that they thought was the best for the ratepayers of I&M." We join in
the OUCC's recognition of the efforts made by the Commission 's Staff
negotiating team and by AEP to reach a settlement that resolved many of the
complex issues arising from this merger. It is the Commission's belief that
whole no party is ever 100 percent satisfied by the results of a settlement, the
negotiating process presents opportunities to raise issues which might otherwise
remain unaddressed in a litigated proceeding.
Having reviewed the Settlement Agreement and the evidence relating
thereto and having considered all evidence submitted in this cause, the
Commission finds that the recommendation of the Staff Negotiating Team should be
approved. The Commission further finds that the Settlement Agreement is a fair
and reasonable resolution of the merger-related issues of concern to the
Commission and should be approved consistent with the findings herein which
approve the Settlement Agreement while also addressing matters incidental or
ancillary thereto.
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<PAGE> 14
IT IS THEREFORE ORDERED BY THE INDIANA UTILITY REGULATORY COMMISSION THAT:
1. The Settlement Agreement shall be and hereby is approved consistent
with the findings herein.
2. I&M shall implement the bill reductions as set forth in the
Agreement upon consummation of the merger as defined herein.
3. Upon consummation of the merger as defined herein, I&M shall be and
hereby is authorized to defer and amortize its Indiana jurisdictional estimated
merger-related cross-to-achieve savings over an eight-year period, as set forth
in the Agreement consistent with finding 3(b) herein.
4. The investigation in this cause commenced by our Order dated June
29, 1998 is hereby terminated.
5. This Order shall be effective on and after the date of its approval.
MCCARTY, KLEIN, RIPLEY, SWANSON-HULL AND ZIEGNER CONCUR:
APPROVED:
I hereby certify that the above is a true and correct copy of the Order as
approved.
/s/ Joseph M. Sutherland
- ----------------------------------------
Joseph M. Sutherland,
Secretary to the Commission
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<PAGE> 15
EXHIBIT A
STIPULATION AND SETTLEMENT AGREEMENT
<PAGE> 16
STATE OF INDIANA
INDIANA UTILITY REGULATORY COMMISSION
IN THE MATTER OF THE INVESTIGATION )
ON THE COMMISSION'S OWN MOTION )
INTO ANY AND ALL MATTERS RELATING ) CAUSE NO. 41210
TO THE MERGER OF AMERICAN )
ELECTRIC POWER, INC. AND CENTRAL )
AND SOUTH WEST CORPORATION )
STIPULATION AND SETTLEMENT AGREEMENT
On June 29, 1998, the Indiana Utility Regulatory Commission ("IURC" or
"Commission") initiated this investigation 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").
On September 2, 1998, the Commission appointed a Staff Negotiating Team "to
attempt to negotiate a settlement of the issues presented in this cause." In a
Docket Entry dated November 30, 1998 the presiding officers directed that "any
negotiated settlement resolving the issues presented in this Cause should be
filed with the Commission on or before March 5, 1999....." The Commission
extended that deadline at the request of the Staff Negotiating Team eventually
to April 12, 1999.
Solely for the purposes of compromise and settlement of the issues in this
proceeding, Indiana Michigan Power Company, which does business in Indiana as
American Electric Power and the Staff Negotiating Team (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 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 Staff Negotiating Team 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 Staff Negotiating Team recognize the costs and
uncertainty of litigation and the desirability of consensual voluntary
resolution of their differences and the legitimate interest and good faith of
each of the parties in achieving the objectives each desires to achieve, and
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WHEREAS the Staff Negotiating Team is authorized to make recommendations to the
IURC regarding a fair and just settlement of differences in the public interest,
The Parties agree as follows:
The Staff Negotiating Team will recommend to the IURC 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 IURC and STAFF:
1. Will not oppose the proposed merger pending before the Federal Energy
Regulatory Commission ("FERC").
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 its Indiana jurisdictional AEP operating company, conditional on merger
consummation will:
1. REGULATORY PLAN. 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 bill reduction amounts shown in Attachment A will be allocated to rate
classes based upon total revenues, 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 bill 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.
I&M must implement the above bill reductions in the manner and amounts described
above notwithstanding any changes to the current regulatory structure in
Indiana. In the event that retail electric deregulation legislation is
implemented in Indiana, or if there is any unbundling or restructuring, I&M
shall continue to apply the regulatory plan's provisions to regulated rates of
its Indiana customers.
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Any legislatively mandated adjustments to base rates, of any kind, that are part
of any retail electric deregulation legislation implemented in Indiana shall not
diminish or offset, but shall be in addition to, the bill reductions established
in this proceeding.
Subject to this agreement, AEP and I&M will defer and amortize their Indiana
jurisdictional estimated merger related 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 retaining costs; and facilities
consolidation costs. The IURC 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)
In addition, the net merger savings allocated to the shareholders will be
excluded from the earnings test in determining I&M's compliance with the
provisions of I.C. 8-1-2-42(d)(2) and (3).
To mitigate potential stranded investment, I&M will increase the funding for the
provision of paragraph 21 of the settlement agreement approved by the Commission
in Cause No. 38702-FAC40-S1 in the additional amount of $5.5 million annually
starting January 1, 2001 for a three-year period ending December 31, 2003. The
rate filing limitation in paragraph 8 of that settlement agreement is extended
by one year to January 1, 2005. In addition, I&M will abide by the provisions of
paragraphs 8, 9 and 10 of that settlement agreement, regardless of the outcome
of litigation in that cause.
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 AEP zone are supplying power to the
other AEP zone, and as a
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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.
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.
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 State 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 facilities whose costs will be subject to the System
Integration Agreement or the System Transmission Agreement with the FERC and to
notify each State Commission of any such filing at the time it is made.
Notification to each State 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
State 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 a State Commission based on the
assertion that the authority of the Securities and Exchange Commission 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 State Commission's ability to examine 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 approval cost allocations. AEP will provide each State
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 State Commission Staff will make a good-faith attempt to resolve their
differences, if any, in advance of a filing being made at the SEC.
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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 FERC-approved Regional Transmission
Organization directly interconnected with AEP transmission
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 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 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, which
have control of the dispatch of generation facilities, taking
service from these RTO(s) and shall be subject to appropriate
confidentiality provisions.
D. AEP believes that its RTO commitment, as defined in this
document, is in keeping with its goal of achieving a large,
economically efficient RTO in the Eastern Interconnection.
E. 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 State 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:
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1. An AEP operating company's retail customers shall not
subsidize the activities of the operating company's
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. These principles shall be applied to avoid costs found to be
just and reasonable for rate-making purposes by the affected
State 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. Each State 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 each such State Commission has over a public
utility operating within the state in which such State
Commission exercises its regulatory authority 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 a State Commission, then upon request of a State
Commission, the AEP operating company shall, in accordance
with state reimbursements rules, reimburse the State
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 be raised before the State 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 each State Commission's
rules and regulations.
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. Asset transfers from an
AEP operating company to a non-utility affiliate and asset
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transfers from a non-utility affiliate to an AEP operating
company shall be at fully distributed costs in accordance with
current Securities and Exchange Commission (SEC) issued
requirements or other statutory requirements if the SEC has no
jurisdiction.
D. An AEP operating company shall not allow a non-utility 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 affiliate are subject to the following
restrictions unless otherwise approved by that operating
company's State 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 an investment in a
non-utility affiliate under circumstances 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 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
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inspection by the State 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 State 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 State Commission retention
requirements.
G. Employees responsible for the day-to-day operations of the AEP
operating 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 each State Commission and consumer
advocate 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, 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.
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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 another safeguards are in place to
ensure full compliance with these affiliate rules.
N. An AEP operating company 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 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
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 regulated and
non-regulated services or products. Such documentation shall
be available, subject to requests for confidential treatment,
for review by State Commission in accordance with Paragraph B
above.
Q. AEP shall designate an employee who will act as a contact for
State Commissions and consumer advocates seeking data and
information regarding affiliate transactions and personnel
transfers. Such employee shall be responsible for providing
data and information requested by a State 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 each signatory
state who will act as a contact for retail consumers 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 each signatory state a current list of
employees or agents that are designated to work with each
State Commission and consumer advocate
9
<PAGE> 25
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 each affected State
Commission a copy of the proposed filing.
U. Any violation of the provisions of these affiliate standards
are subject to the enforcement powers and penalties at the
State Commissions.
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 State Commissions. Prior to the
initial audit, AEP will conduct an informational meeting with
the State Commissions 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 State Commissions to
ensure that AEP continues to furnish the State Commission with
the appropriate information to regulate its jurisdictional AEP
operating company. The State 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
State Commissions participating in this Agreement in the format described in
Attachment C to this Agreement.
10. STATUTORY AND OTHER ISSUES. Provided the 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. Nothing in this Agreement is intended to preclude
the Commission and its staff from addressing in a manner not inconsistent with
this Agreement issues raised in FERC Docket No. EC98-40-000.
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 to have
the provisions of this Agreement enforced under Indiana law.
10
<PAGE> 26
DEFINITIONS
1. "AEP zone" means either the area comprising the AEP operating companies
providing service in Indiana, 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. "Consumer advocate" means an agency of the state government designated as a
representative of consumers in matters involving utility companies before the
applicable State Commission.
5. "Entity" means a corporation or a natural person.
6. "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 transmission of electricity,
other than an essential interconnecting transmission facility
necessary to effect 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.
7. "FERC" means the Federal Energy Regulatory Commission, or any successor
governmental agency.
8. "Non-Utility Affiliate" means an Affiliate which is not a domestic public
utility. Non-utility affiliate includes a foreign affiliate.
9. "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.
10. "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;
11
<PAGE> 27
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.
11. "Regional Transmission Organization" (RTO) means an organization that
operates electric transmission equipment and facilities on a regional basis.
12. "SEC" means the United States Securities and Exchange Commission, or any
successor governmental agency.
13. "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.
14. "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.
15. "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.
16. "Subsidiary" means any corporation 10 percent or more of whose voting
capital stock is controlled by another Entity.
17. "Utility Affiliate" means an affiliate of a utility operating company that
is also a public utility.
Presentation of Agreement to the Commission
1. The Parties shall move for the admission of this Agreement into evidence at
the hearing scheduled for April 19, 1999 and sponsor evidence including
testimony and exhibits as may be required to support Commission approval of this
Agreement.
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 or 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
12
<PAGE> 28
jurisdiction and, except as expressly provided herein, 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 evidence in this cause constitutes substantial evidence sufficient to
support the Agreement and provides an adequate evidentiary basis upon which the
Commission can make any finding of fact and conclusions of law necessary for the
approval of the Agreement, as filed.
3. The issuance of the Final Order shall terminate any further proceedings in
this cause.
4. In the event this cause is required to be litigated, the Parties expressly
reserve all of their rights to make objections and motions to strike with
respect to all testimony and exhibits and their right to cross-examine the
witnesses presenting such testimony and exhibits.
5. The undersigned have represented and agreed that they are fully authorized to
execute this Agreement on behalf of their designated clients who will be bound
thereby.
6. The Parties to this Agreement shall not appeal the agreed Final Order or any
other Commission order 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.
7. 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 12th day of April 1999.
Indiana Michigan Power Company
By: /s/ Marc E. Lewis
---------------------------
Marc E. Lewis
Senior Attorney
13
<PAGE> 29
AEP
By: /s/ Richard E. Munczinski
---------------------------
Richard E. Munczinski
Senior Vice President
American Electric Power
Service Corporation
IURC Staff Negotiating Team
By: /s/ Robert C. Glazier
---------------------------
Robert C. Glazier
Director of Utilities
By: /s/ Abby R. Gray
---------------------------
Abby R. Gray
Special Counsel to the
Staff Negotiating Team
14
<PAGE> 30
Attachment A
Page 1 of 1
AEP/CSW MERGER
NET ANNUAL MERGER SAVINGS
AND INDIANA CUSTOMER BILL REDUCTIONS ($000)
<TABLE>
<CAPTION>
(1) (2) (3) (4)
Net Customer Shareholder
Period Merger Savings Bill Reduction Savings
------ -------------- --------------- -----------
<S> <C> <C> <C>
Year 1 5,591 3,306 2,286
Year 2 10,633 5,927 4,706
Year 3 13,531 7,434 6,097
Year 4 15,903 8,668 7,235
Year 5 17,437 9,465 7,972
Year 6 18,606 10,073 8,533
Year 7 19,515 10,546 8,969
Year 8 20,039 10,818 9,221
121,255 66,238 55,017
</TABLE>
<PAGE> 31
Attachment B
Page 1 of 3
AEP/CSW MERGER
EXAMPLE OF BASE RATE CASE TREATMENT
BASED ON YEAR 3 ($000)
<TABLE>
<S> <C> <C> <C>
CREDIT PER RIDER CONTINUES (7,434)
INCLUDED IN TEST YEAR:
GROSS MERGER SAVINGS (17,048)
CHANGE IN CONTROL AMORTIZATION 768
OTHER CTA AMORTIZATION 2,751
-----
TOTAL CTA AMORTIZATION 3,517
------
NET MERGER SAVINGS IN TEST YEAR (13,531)
ADD BACK TO TEST YEAR COST OF SERVICE:
CUSTOMER SHARE (Attachment A, Col. 3, Year 3) 7,434
SHAREHOLDER PORTION (Attachment A, Col. 4, Year 3) 6,097
-----
13,531
------
NET BASE RATE REDUCTION 0
------
INDIANA CUSTOMER RATE REDUCTION (7,434)
======
</TABLE>
<PAGE> 32
Attachment B
Page 2 of 3
AEP/CSW MERGER
BASE RATE CASE TREATMENT
FOR INCLUSION IN COST OF SERVICE ($000)
<TABLE>
<CAPTION>
Add Back to Test Year Cost of Service
-------------------------------------
Customer Shareholder
Net Savings Net Savings
----------- -----------
<S> <C> <C>
YEAR 1 3,306 2,286
YEAR 2 5,927 4,706
YEAR 3 7,434 6,097
YEAR 4 8,668 7,235
YEAR 5 9,465 7,972
YEAR 6 10,073 8,533
YEAR 7 10,546 8,969
YEAR 8 10,818 9,221
</TABLE>
<PAGE> 33
Attachment B
Page 3 of 3
AEP/CSW MERGER
AMORTIZATION OF ESTIMATED
COST TO ACHIEVE
<TABLE>
<CAPTION>
AMOUNT
---------
<S> <C>
YEAR 1 3,517,436
YEAR 2 3,517,436
YEAR 3 3,517,436
YEAR 4 3,517,436
YEAR 5 3,517,436
YEAR 6 3,517,436
YEAR 7 3,517,436
YEAR 8 3,517,436
TOTAL 28,139,494*
</TABLE>
- -----------------
* May not add due to rounding
<PAGE> 34
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 Indiana Customer Average Interruption
Duration Index (CAIDI) and Indiana System Average Interruption Frequency Index
(SAIFI). These indices shall be determined 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 Indiana customer calls. These will
include the Call Center Average Speed of Answer (ASA), Abandonment Rate, and
Call Blockage. Definition 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 in question.
<PAGE> 35
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 customers hours of interruption
------------------------------------------
number of customers interrupted
<PAGE> 36
AEP Call Center Measures
1. Average Speed of Answer (ASA) is defined as the average 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:
<TABLE>
<S> <C>
Average Speed of Answer = time for all calls between call answer and CSR/IVR connection
-------------------------------------------------------------
(seconds) total number of calls made to the Call Center
</TABLE>
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:
<TABLE>
<S> <C>
Abandonment Rate = {total number of callers who hang up}
--------------------------------------------- x 100
(percent) total number of calls made to the Call Center
</TABLE>
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:
<TABLE>
<S> <C>
Call Blockage = {total number of non-outage calls that do not get connected}
------------------------------------------------------------ x 100
(percent) total number of non-outage calls made to the Call Center
</TABLE>
<PAGE> 37
STATE OF INDIANA
INDIANA UTILITY REGULATORY COMMISSION
IN THE MATTER OF THE INVESTIGATION )
ON THE COMMISSION'S OWN MOTION )
INTO ANY AND ALL MATTERS RELATING ) CAUSE NO. 41210
TO THE MERGER OF AMERICAN )
ELECTRIC POWER, INC. AND CENTRAL ) APPROVED:
AND SOUTH WEST CORPORATION )
CORPORATION
BY THE COMMISSION:
David E. Ziegner, Commissioner
Camie J. Swanson-Hull, Commissioner
Claudia J. Earls, Administrative Law Judge
On June 29, 1998, the Commission on its own motion initiated
an investigation regarding the proposed merger of American Electric Power
Company, Inc. ("AEP") and Central and South West Corporation ("CSW"). AEP is the
parent company of Indiana Michigan Power Company ("I&M") which provides electric
utility service in the State of Indiana. The Order noted that AEP and CSW had
filed an application with the Federal Energy Regulatory Commission ("FERC") for
approval of the merger under Section 203 of the Federal Power Act.
Petitions to intervene in this matter were filed by the
Citizens Action Coalition of Indiana, Inc., Indiana Consumers For Fair Utility
Rates run ad hoc group of industrial companies), PSI Energy, Inc. and Steel
Dynamics, Inc.(1) These petitions were granted and these persons were made
parties to this proceeding. The Office of Utility Consumer Counselor also
participated in this proceeding.
After receiving written comments of the parties on certain
issues relating to the proposed merger and after holding a preliminary hearing
on August 4, 1998, the Commission on September 2, 1998, issued an Order
appointing a negotiating team of members of the Commission Staff (the "Staff
Negotiating Team") to attempt to negotiate a settlement of the issues presented
in this matter.
By docket entries, I&M was directed to respond to various data
requests seeking information about the proposed merger and to provide to the
Commission, the Staff Negotiating Team and the other parties certain documents
relating thereto. I&M responded to the requests by providing the requested
information and documents.
During the course of this proceeding, status hearings were
held at which time the Staff Negotiating Team submitted reports regarding the
progress of negotiations. On April 9, 1999, I&M and the Staff Negotiating Team
submitted to the Commission and recommended for approval a Stipulation and
Settlement Agreement (the "Settlement
(1) SDI subsequently withdrew from the proceeding.
<PAGE> 38
Agreement") executed by I&M, AEP and the Staff Negotiating Team.
On April 15, 1999, the parties to the Settlement Agreement
prefiled with the Commission prepared testimony and evidence in support of the
Settlement Agreement. Pursuant to notice of hearing given as provided by law, a
public evidentiary hearing on the Settlement Agreement was held on April 19,
1999, at 10:00 a.m. in Room TC10 of the Indiana Government Center South,
Indianapolis, Indiana. At that time, the Settlement Agreement and evidence
relating thereto were accepted into the record.
Having considered the evidence and being duly advised, the
Commission now finds:
1. Notice and Jurisdiction. Due legal and timely notice of the settlement
hearing was given and published as required by law. I&M is a "public utility"
within the meaning of that term in IC 8-1-2-1 and is subject to the jurisdiction
of the Commission in the manner and to the extent provided by the laws of the
State of Indiana.
2. The Settlement Agreement. As described in the Settlement Agreement, a
copy of which is attached hereto as Exhibit A and incorporated herein by
reference, the Settlement Agreement contains, among other things, provisions
regarding (a) net non-fuel merger savings; (b) fuel and purchased power merger
savings; (c) limitation on requests for stranded cost recovery; (d) allocation
of proceeds from the sale of facilities; (e) system integration agreements; (f)
Ohio Power waiver; (g) regional transmission organization commitments; (h)
affiliate standards; and (i) maintenance and enhancement of the adequacy and
reliability of retail electric service, including certain reporting
requirements.
The Settlement Agreement further provides that if any other
state commission or any federal commission issues a final and non-appealable
order addressing the merger that provides benefits or imposes conditions that
would benefit ratepayers of another jurisdiction. AEP will extend equivalent net
benefits and conditions to all AEP retail customers.
The Settlement Agreement also provides that, upon approval by
the Commission, neither the commission nor its Staff shall oppose the proposed
merger before FERC or oppose AEP's previously made merger-related filings with
the Securities and Exchange Commission.
The Settlement Agreement also states that it 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 on these particular issues. The
Settlement Agreement provides that it is solely the result of compromise in the
settlement process, shall not constitute a concession of subject matter
jurisdiction, and except as expressly provided therein, is without prejudice to
and shall not constitute a waiver of any position that any of the parties
thereto may take with respect to any or all of the items resolved therein in any
future regulatory or other proceedings.
The Settlement Agreement states that if the Commission does
not approve the Settlement Agreement in its entirety, it shall be null and void
and deemed withdrawn, unless such change is approved by the parties.
<PAGE> 39
At the settlement hearing, Robert C. Glazier, Director of Utilities for the
Indiana Utility Regulatory Commission, Richard E. Munczinski, Senior Vice
President-Corporate Planning and Budgeting of American Electric Power Service
Corporation, the service corporation subsidiary of AEP, and Kent D. Curry,
Director of Regulatory Affairs for I&M, testified in support of Commission
approval of the Settlement Agreement. Mr. Glazier and Mr. Munczinski discussed
the negotiating process which resulted in the Settlement Agreement and the
public benefits that would result from its approval. Mr. Curry testified
regarding the mechanism by which the bill reductions will be implemented by I&M.
3. Commission Findings. In our Order dated June 29, 1998, the Commission
stated that this investigation was commenced because the Commission believed
that the proposed merger of AEP and CSW could have a significant impact on the
electric industry and customers in Indiana and across the region and the
Commission was concerned about the proposed merger's effect on the reliability
of service and the development of independent system operators. During the
course of this proceeding considerable information about the proposed merger was
requested from and provided by I&M. Additional information about the proposed
merger has since been developed in the course of FERC proceedings and
proceedings before other state commissions. After lengthy and detailed
negotiations. I&M, AEP and Staff Negotiating Team have reached agreement on
terms and conditions which help ensure that Indiana consumers will fairly share
in the benefits achieved by the merger and that Indiana consumers will be
protected against any detrimental effects. The Staff Negotiating Team recommends
that the Commission approve the Settlement Agreement as a fair and just
settlement of differences regarding merger-related issues. Having reviewed the
Settlement Agreement and the evidence relating thereto, the Commission finds
that the recommendation of the Staff Negotiating Team should be approved. The
Commission further finds that the Settlement Agreement is a fair and reasonable
resolution of the merger-relating issues of concern to the Commission and should
be approved in its entirety without modification.
IT IS THEREFORE ORDERED BY THE INDIANA UTILITY REGULATORY COMMISSION THAT:
1. The Settlement Agreement shall be and hereby is approved in its
entirety without modification.
2. I&M shall implement the bill reductions as set forth in the
Agreement.
3. I&M shall be and hereby is authorize to defer and amortize its
Indiana jurisdictional estimated merger-related costs-to-achieve savings over an
eight-year period, as set forth in the Agreement.
4. The investigation in this Cause commenced by our Order dated June
29, 1998 is hereby terminated.
5. This Order shall be effective on and after the date of its approval.
<PAGE> 40
McCARTY, KLEIN, RIPLEY, SWANSON-HULL AND ZIEGNER CONCUR:
APPROVED:
I hereby certify that the above is a true and correct copy of the Order as
approved.
- -----------------------------------
Joseph M. Sutherland, Secretary to the Commission
<PAGE> 1
Exhibit K
AGREEMENT
This Agreement is by and between American Electric Power ("AEP") and
Central and South West Corporation ("CSW") (jointly referred to as "the
Companies"), and the International Brotherhood of Electrical Workers, Local
Union 329, 386, 696, 738, 876, 934, 978, 981, 1002, 1392 and 1466 ("IBEW"). The
Companies and IBEW are sometimes referred to jointly herein as the
"Signatories." This Agreement addresses issues affecting the Signatories in all
jurisdictions served by the Companies. The Signatories agree as follows:
I. Workforce
A. The Companies agree not to eliminate any current IBEW employee
as a direct result of the proposed merger between the
Companies. As used in this Agreement, the term "direct result
of the merger" shall mean the result of synergies identified
at the time the merger was announced.
B. The Companies agree that any IBEW represented employee whose
position is eliminated as a direct result of the sale of
ownership interests in the Northeast Station, Oolagah,
Oklahoma, will be provided with another employment opportunity
within the bargaining unit.
II. Cook Negotiations
The Signatories agree that normal negotiations will proceed to
resolution at Cook Plant.
III. Successorship
<PAGE> 2
The Companies agree to include the recognition of existing labor
agreements as a condition of the sale, divestiture or transfer of any
facility subject to a collective bargaining agreement.
(See Exhibit A)
IV. Organizing Conduct
The Signatories agree that, in the event IBEW engages in organizing
efforts among AEP and/or CSW unrepresented employees, neither party
shall coerce or intimidate employees during the course of an organizing
campaign. The Companies agree to refrain from negative public
statements concerning IBEW and any IBEW officer, representative or
member. IBEW, its officers, representatives and employees agree not to
publicly express negative comments concerning the Companies' integrity
or motives including the integrity or motives of the Companies'
officers, directors, agents or employees. The Signatories agree that
all oral or written statements made during the course of an organizing
campaign shall be factual.
V. Union Security
The Companies will, as soon as possible after the effective date of
their merger, include in all IBEW contracts an "Agency Shop" provision
covering employees hired after the effective date of the merger. The
Companies will also, at the same time, include "Maintenance of
Membership" language in all IBEW contracts. Such provision will cover
all employees hired prior to the merger who are or become members of
their respective local IBEW unions. The Companies also agree to a dues
checkoff provision that shall be irrevocable by the employee for
successive periods of one year from the date of signing or expiration
of the agreement, whichever occurs sooner. (See Exhibit B)
2
<PAGE> 3
VI. Unit Clarification
For a period of five (5) years following the effective date of this
Agreement, the Companies will not remove any working foreman or
electric system operator positions at PSO or any senior lineman
positions at Southwestern Electric Power Company ("SWEPCO") from the
bargaining unit without agreement of the respective unions.
VII. Leave of Absence
The Companies will, upon request of the respective local IBEW unions,
institute in all existing contracts Leave of Absence provisions for
union business. (See Exhibit C)
VIII. Service Quality
Signatories agree to cooperate to establish reasonable Service Quality
Standards in all jurisdictions served.
IX. Other Provisions
A. Upon execution of this Agreement, IBEW agrees that it will
immediately cease all activities in opposition to the merger,
withdraw all objections to the merger, and not file future
objections to the merger.
B. The Companies and IBEW agree to make a good faith effort to
settle unfair labor practice complaints issued by the National
Labor Relations Board.
C. The Companies will reimburse IBEW up to $73,000 for costs
incurred in its intervention up to the effective date of this
Agreement.
D. Facsimile copies of signatures are valid for purposes of
evidencing execution.
X. Effective Date
The provisions contained in Sections II, IV, VI, VII, VIII, and IX of
this Agreement will be effective upon execution of this Agreement by
the last Local Union to execute this
3
<PAGE> 4
Agreement. The provisions contained in Sections I, III and V of the
Agreement will be effective upon completion of the merger between the
Companies.
EFFECTIVE DATE: _____________
INTERNATIONAL BROTHERHOOD OF INTERNATIONAL BROTHERHOOD OF
ELECTRICAL WORKERS LOCAL UNION 329 ELECTRICAL WORKERS LOCAL UNION 386
By: __________________________ By: __________________________
INTERNATIONAL BROTHERHOOD OF INTERNATIONAL BROTHERHOOD OF
ELECTRICAL WORKERS LOCAL UNION 696 ELECTRICAL WORKERS LOCAL UNION 738
By: __________________________ By: __________________________
INTERNATIONAL BROTHERHOOD OF INTERNATIONAL BROTHERHOOD OF
ELECTRICAL WORKERS LOCAL UNION 876 ELECTRICAL WORKERS LOCAL UNION 934
By: __________________________ By: __________________________
INTERNATIONAL BROTHERHOOD OF INTERNATIONAL BROTHERHOOD OF
ELECTRICAL WORKERS LOCAL UNION 978 ELECTRICAL WORKERS LOCAL UNION 981
By: __________________________ By: __________________________
INTERNATIONAL BROTHERHOOD OF INTERNATIONAL BROTHERHOOD OF
ELECTRICAL WORKERS LOCAL UNION 1002 ELECTRICAL WORKERS LOCAL UNION 1392
By: __________________________ By: __________________________
INTERNATIONAL BROTHERHOOD OF
ELECTRICAL WORKERS LOCAL UNION 1446
By: __________________________
AMERICAN ELECTRIC POWER CENTRAL AND SOUTH WEST CORPORATION
By: ________________________ By: ____________________________
4
<PAGE> 5
EXHIBIT A
Successorship:
The Company agrees that the adoption of this Agreement will be
a condition of the sale, divestiture or transfer of any facility covered by this
Agreement. When the sale, divestiture or transfer is publicly disclosed, the
Company will provide the Union with relevant information concerning such
transaction upon request.
<PAGE> 6
EXHIBIT B
Union Security:
Section 1. Maintenance of Membership Provision
In order that employees do their part in assisting the Union
to meet its obligations as a party to this Agreement, an employee hired before
the effective "date" of the merger) who on or after (the effective "date" of the
merger) personally pays Union dues or authorizes Union dues deduction, may only
discontinue such payments or revoke a prior authorization within the 10 day
calendar period preceding (the expiration "date" of the Agreement). Such
revocation must be in writing and must be delivered to the Union and the
Company.
Section 2. Agency Fee Provision
In order that employees do their part in assisting the Union
to meet its obligations as a party to this Agreement, an employee hired on or
after (the effective "date" of the merger) shall either personally pay Union
dues or authorize Union dues deductions.
Section 3. Failure to Pay Required Union Fees or Dues
Should an employee covered under Section 1 above or Section 2
above fail to pay the dues or fees required as a condition of employment, the
employee shall be terminated.
Dues Membership:
The Company agrees to deduct once each month from the pay of
each employee who executes a written authorization, an amount equal to the
current Union
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dues as set forth in the Local Union By-Laws and the Constitution of the
International Brotherhood of Electrical Workers. The amount of these deductions
will be paid to the Financial Secretary of the Local Union. The deduction will
be renewed for successive periods of one year unless revoked by written notice
by certified mail to the Company and the Union within ten days prior to the
anniversary date of the authorization or the expiration of the Agreement. The
Union shall notify the Company of any changes in the dues amounts to be
deducted.
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Exhibit C
Leave of absence for Union Officials
A maximum of two employees elected or appointed to full-time
union positions shall be granted leaves of absence for the period of such
election or appointment. The employees shall continue to accrue seniority during
such leaves, and upon termination of the leaves of absence, shall be reinstated
to their former positions (or the equivalent if such former positions no longer
exist) provided the employees are qualified to return to work.
