<PAGE>
As filed with the Securities and Exchange Commission on October 31, 1996
File No. _____
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
-----------------------------
FORM U-1
APPLICATION/DECLARATION
UNDER
THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
-----------------------------
Ameren Corporation
1901 Chouteau Avenue
St. Louis, Missouri 63103
(Name of company filing this statement
and address of principal executive offices)
None
(Name of top registered holding company)
William E. Jaudes
Registered Agent
Ameren Corporation
1901 Chouteau Avenue
St. Louis, Missouri 63103
(Names and addresses of agents of service)
The Commission is requested to send copies of all notices, orders and
communications in connection with this Application to:
James J. Cook William J. Harmon
Union Electric Company Thomas D. Brooks
1901 Chouteau Avenue Jones, Day, Reavis & Pogue
P.O. Box 149 77 West Wacker, Suite 3500
St. Louis, Missouri 63166 Chicago, Illinois 60601-1692
<PAGE>
Table of Contents
<TABLE>
<CAPTION>
Page
----
<S> <C>
Item 1. Description of Proposed Transaction........................... 1
A. Introduction.................................................. 1
1. General Request........................................... 2
2. Overview of the Transaction............................... 3
B. Description of the Parties to the Transaction................. 4
1. General Description....................................... 4
a. UE.................................................... 4
b. CIPSCO and CIPS....................................... 6
c. Ameren and Arch Merger................................ 8
i. Ameren......................................... 8
ii. Arch Merger.................................... 8
d. Ameren Services....................................... 8
2. Description of Energy Sales, Facilities and Fuel.......... 9
a. UE.................................................... 9
i. General......................................... 9
ii. Electric Generating Facilities.................. 9
iii. Electric Transmission and Other Facilities...... 11
iv. Fuel Sources.................................... 12
v. Gas Facilities.................................. 13
b. CIPSCO and CIPS....................................... 13
i. General......................................... 13
ii. Electric Generating Facilities.................. 13
iii. Electric Transmission and Other Facilities...... 14
iv. Fuel Sources.................................... 15
v. Gas Facilities.................................. 15
c. Transferred Utility Facilities........................ 16
3. Nonutility Interests of UE and CIPSCO..................... 16
a. UE.................................................... 16
b. CIPSCO................................................ 16
4. Present Electric Coordination............................. 17
5. Present Gas Coordination.................................. 18
C. Description of Transaction and Statement as to Consideration.. 19
1. Background................................................ 19
2. Benefits of the Transaction............................... 24
3. Merger Agreement.......................................... 26
a. Consideration......................................... 26
b. Other Terms........................................... 27
c. Management Following the Mergers...................... 27
4. Related Agreements........................................ 27
D. Dividend Reinvestment Plan and Employee Benefits Plans........ 27
1. Sources of Common Stock and Use of Proceeds............... 28
2. Dividend Reinvestment Plan................................ 28
3. Employee Benefit Plans.................................... 29
</TABLE>
i
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
a. Long Term Incentive Plan.............................. 29
b. Savings Plans......................................... 30
4. Solicitation of Proxies................................... 30
Item 2. Fees, Commissions and Expenses................................ 30
Item 3. Applicable Statutory Provisions............................... 31
A. Analysis of Transaction....................................... 33
1. Section 10(b)............................................. 35
a. Section 10(b)(1)...................................... 35
i. Interlocking Relationships..................... 35
ii. Concentration of Control....................... 36
b. Section 10(b)(2)--Fairness of Consideration........... 40
i. Reasonableness of Consideration................ 40
ii. Reasonableness of Fees......................... 41
c. Section 10(b)(3)--Capital Structure; Not Detrimental
to Public Interest.................................... 43
2. Section 10(c)............................................. 46
a. Section 10(c)(1)...................................... 46
i. Retention of Gas Operations.................... 47
(A) Ameren Satisfies the Traditional "ABC"
Test...................................... 48
(1) Clause (A)........................... 48
(2) Clauses (B) and (C) of Section
11(b)(1) are Satisfied............... 51
(B) The Commission Should Not Require
Ameren to Satisfy the Traditional "ABC"
Test...................................... 52
(1) The Act Does Not Prohibit
Combination Companies................ 52
(2) The Commission's Interpretation
of the Act........................... 53
(3) The Commission Should Revise
Its Interpretation of The Act........ 54
(4) UE's and CIPS' Combination
Systems Are Not
Prohibited by State Law.............. 63
ii. Other Businesses............................... 64
b. Section 10(c)(2)...................................... 74
i. Efficiencies and Economies..................... 74
ii. Integrated Public Utility System............... 78
(A) Electric Utility System................... 78
(B) Gas Utility System........................ 81
3. Section 10(f)--Compliance with State Law.................. 83
4. Section 9(a)(1)........................................... 84
5. Other Applicable Provisions--Sections 6, 7, 12 and 13..... 84
B. Intra-system Financing........................................ 85
</TABLE>
ii
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
C. Ameren Services............................................... 86
D. Other Services................................................ 88
Item 4. Regulatory Approvals.......................................... 88
A. Antitrust..................................................... 88
B. Federal Power Act............................................. 88
C. State Public Utility Regulation............................... 89
D. Nuclear Regulatory Commission................................. 92
Item 5. Procedure..................................................... 92
Item 6. Exhibits and Financial Statements............................. 92
A. Exhibits...................................................... 92
B. Financial Statements.......................................... 94
Item 7. Information as to Environmental Effects....................... 94
</TABLE>
iii
<PAGE>
Item 1. Description of Proposed Transaction
A. Introduction
This Application/Declaration seeks approvals relating to the proposed
business combination transaction among Ameren Corporation ("Ameren"), Union
Electric Company ("UE") and CIPSCO Incorporated ("CIPSCO"), by which UE and
CIPSCO's utility subsidiary, Central Illinois Public Service Company ("CIPS"),
will become wholly owned subsidiaries of Ameren, a new Missouri holding company
(the "Transaction"). Following the consummation of the Transaction, Ameren will
register with the Securities and Exchange Commission (the "Commission") as a
holding company under the Public Utility Holding Company Act of 1935 (the
"Act").
UE is an electric and gas utility company operating in Missouri and
Illinois. CIPS is an electric and gas utility company operating in Illinois.
CIPSCO and UE are each exempt holding companies pursuant to orders of the
Commission. CIPS is an exempt holding company pursuant to Section 3(a)(2) of the
Act and Rule 2 thereunder. See Item 1.B.1.a. and b. below.
The Transaction is expected to produce substantial benefits to the public,
investors and consumers and meets all applicable standards of the Act. Among
other things, UE and CIPSCO believe that the Transaction will allow the
shareholders of each of the companies to participate in a larger, financially
stronger company, and, through a pooling of their equity, management, human
resources and technical expertise, and increased coordination of use of their
facilities, enable the companies to achieve benefits of increased financial
stability and strength, greater opportunities for earnings and dividend growth,
improved creditworthiness, unified management, reduction of operating costs,
efficiencies of operation, better use of facilities for the benefit of
customers, improved ability to use new technologies, greater industrial sales
diversity and improved capability to make wholesale power purchases and sales.
In this regard, UE and CIPSCO believe that synergies created by the Transaction
will generate substantial cost savings which would not be available absent the
Transaction. UE and CIPSCO have estimated the dollar value of synergies from the
Transaction to be approximately $686 million over the 10-year period from 1997
to 2006. The expected benefits of the Transaction are discussed in further
detail in Item 3.A.2.b.i. below.
The Transaction was approved by the shareholders of UE and CIPSCO at
special meetings held December 20, 1995. Approvals are required from the
Missouri Public Service Commission ("MPSC"), the Illinois Commerce Commission
("ICC"), the Federal Energy Regulatory Commission ("FERC") and the Nuclear
Regulatory Commission ("NRC"). The Transaction is also subject to the expiration
of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of
1976, as amended (the "HSR Act"), without adverse action by the Antitrust
Division of the U.S. Department of Justice ("DOJ") or the Federal Trade
Commission ("FTC"). Apart from the approval of the Commission under the Act, the
foregoing approvals are the only approvals required for the consummation of the
Transaction. In order to permit timely consummation of the Transaction and the
realization of the substantial benefits it is expected to produce, Ameren
requests that the Commission's review of this Application/Declaration commence
and proceed as expeditiously as practicable.
<PAGE>
1. General Request
Pursuant to Sections 9(a)(2) and 10 of the Act, Ameren hereby requests
authorization and approval of the Commission to acquire, by means of the mergers
described below, all of the issued and outstanding common stock of UE and CIPSCO
and the indirect acquisition of 60% of the outstanding common stock of Electric
Energy, Inc. ("EEI") as described below. Ameren also hereby requests that the
Commission approve:
(i) the establishment of Ameren Services Corp. ("Ameren Services")
(described in Item 3.C below) in accordance with Rule 88 under the Act and
the acquisition by Ameren of all of the outstanding voting securities of
Ameren Services;
(ii) the General Services Agreement (defined below), a form of
which is filed as Exhibit B-4 hereto;
(iii) the issuance of Ameren Common Stock (as defined below) in
connection with the Transaction;
(iv) the issuance by Ameren (and/or the acquisition by or on behalf
of Ameren in open market transactions) of up to 19 million shares of Ameren
Common Stock, over the period ending five years after the date of the
Commission's approving order in this docket, for purposes of certain
employee benefit and dividend reinvestment plans of UE, CIPSCO, CIPS and
Ameren;
(v) the solicitation of proxies from the holders of Ameren Common
Stock for approvals deemed necessary or desirable in connection with the
establishment or amendment of employee benefit plans referred to in (iv);
(vi) the acquisition by Ameren of all of the outstanding voting
securities of CIPSCO Investment Company (currently a wholly owned
subsidiary of CIPSCO) ("CIPSCO Investment"), which serves as a holding
company for certain nonutility investments;
(vii) the retention by Ameren of the gas properties of UE and CIPS
and the continued operation of UE and CIPS as combination utilities;
(viii) the retention by Ameren of the nonutility activities,
businesses and investments of UE and CIPSCO Investment and the making of
certain similar investments over a period ending five years after the date
of the Commission's approving order in this docket;
(ix) the continuation of all outstanding intrasystem debt, equity
and guaranties; and
(x) the transfer by UE to CIPS of the Transferred Utility
Facilities (defined below) located in Illinois.
2
<PAGE>
2. Overview of the Transaction
Under the Agreement and Plan of Merger executed by CIPSCO and UE on August
11, 1995 (the "Merger Agreement"), CIPSCO and UE have organized a new Missouri
corporation, Ameren, to serve as the eventual holding company for CIPS and UE as
well as for CIPSCO Investment. Ameren has, in turn, organized a wholly-owned
Missouri subsidiary, Arch Merger, Inc. ("Arch Merger"). Upon receipt of all
necessary approvals, the Transaction will be consummated by merging CIPSCO into
Ameren, with Ameren as the surviving corporation, and by merging UE with Arch
Merger, with UE as the surviving corporation (collectively, the "Mergers"). A
copy of the Merger Agreement, filed as Exhibit B-1 hereto, is incorporated by
reference.
After the Transaction is effective, Ameren will own 100% of the common
stock of two combination public utility subsidiaries, UE and CIPS, as well as
100% of the common stock of CIPSCO Investment. UE will continue to own 40% of
the common stock of EEI and 100% of the common stock of Union Electric
Development Corporation ("UEDC"), which is engaged principally in unregulated
nonutility investments. CIPS will continue to own 20% of the common stock of
EEI, and CIPSCO Investment will continue to own 100% of the capital stock of
those subsidiaries engaged in the unregulated nonutility investment business of
CIPSCO. Thus, EEI will be an affiliate and subsidiary of Ameren.
The transaction calls for a tax-free exchange of CIPSCO common stock and UE
common stock. Pursuant to the Merger Agreement, each outstanding share of CIPSCO
common stock will be converted into the right to receive 1.03 shares (the
"CIPSCO Ratio") of Ameren Common Stock, par value $.01 per share ("Ameren Common
Stock"), and each outstanding share of UE common stock will be converted into
the right to receive one share (the "UE Ratio") of Ameren Common Stock. The
outstanding UE and CIPS preferred stock will not be affected in the Transaction.
Ameren is expected to have a total of 137,215,462 shares of Ameren Common Stock
outstanding. It is anticipated that Ameren will adopt UE's per share dividend
payment level as of the effective time of the Mergers.
Following consummation of the Transaction, the headquarters of Ameren will
be in St. Louis, Missouri. The headquarters of the two utility subsidiaries will
remain in their current locations, UE's in St. Louis, Missouri, and CIPS' in
Springfield, Illinois. Ameren Services will maintain offices in St. Louis and
Springfield. Ameren's utility subsidiaries will serve 1,451,005 electric
customers and 285,403 natural gas customers in portions of Missouri and
Illinois. Pursuant to the Merger Agreement, UE expects to transfer its retail
electric and gas distribution utility assets located in Illinois (the
"Transferred Utility Facilities") to CIPS. As a result, after consummation of
the Transaction, CIPS is expected to begin providing service to the
approximately 63,000 electric customers and 18,000 gas customers currently
served by UE in Illinois.
3
<PAGE>
B. Description of the Parties to the Transaction
1. General Description
a. UE
UE is a Missouri corporation also authorized to do business in Illinois and
is a public utility company. The principal business of UE is to provide electric
energy to customers in a 24,500 square mile area of Missouri and Illinois. UE's
Missouri electric service area includes the City of St. Louis and St. Louis
County, and all or portions of 65 other counties. Its Illinois service area
includes the cities of East St. Louis and Alton. In addition to the retail
electric business, UE serves 18 wholesale electric customers, all of which are
located in Missouri. UE also provides natural gas service to customers in 23
Missouri counties and two Illinois counties and provides steam service in
Jefferson City, Missouri. Maps of UE's electric and gas service territories are
attached as Exhibits E-4 and E-5 respectively.
As of June 30, 1996, UE provided retail electric service to approximately
1,069,000 customers in Missouri and 63,000 in Illinois. UE provides natural gas
service to approximately 102,000 customers in Missouri and 18,000 customers in
Illinois. As of June 30, 1996, UE had 6,167 employees in its two-state
operations.
There are two other interests which are held by UE and operated through
subsidiary corporations. UE is the sole stockholder of Union Electric
Development Corporation ("UEDC") (formerly known as Union Colliery Company), and
UE owns 40 percent of the common stock of EEI. UEDC is used principally to own
and invest in energy related or civic and community development related
investments in the UE service area. EEI was formed in the early 1950s to provide
electric energy to a uranium enrichment plant located near Paducah, Kentucky.
The enrichment plant was originally operated by the Atomic Energy Commission and
the Department of Energy and is operated today by the United States Enrichment
Corporation. EEI owns the Joppa Plant, a 1,015 mW coal-fired electric generating
plant located near Joppa, Illinois, and six 161 kV transmission lines which
transmit power from the Joppa Plant to the Paducah enrichment plant. EEI's
common stock is held by four utility companies: UE, 40%; CIPS, 20%; and two
unaffiliated utilities, Kentucky Utilities Company, 20%; and Illinois Power
Company, 20%. EEI sells electricity to its sponsoring utilities for resale. The
uranium enrichment facility is EEI's only end-user customer. SEE CENTRAL
ILLINOIS PUBLIC SERVICE CO., 32 S.E.C. 202 (Jan. 15, 1951); ELECTRIC ENERGY,
INC., 32 S.E.C. 495 (June 26, 1951); ELECTRIC ENERGY, INC., Rel. No. 35-13312
(Nov. 19, 1956); and ELECTRIC ENERGY, INC., 38 S.E.C. 658 (Nov. 28, 1958) for
more information concerning EEI.
UE is an exempt public utility holding company pursuant to an order of the
Commission under Section 3(a)(2) of the Act. SEE IN RE UNION ELECTRIC CO., 40
SEC 1072
4
<PAGE>
(Apr. 2, 1962) and IN RE UNION ELECTRIC CO., Rel. No. 18368 (Apr. 10, 1974).
With respect to UE's ownership of EEI, SEE UNION ELECTRIC, CO., 40 SEC 1072
(Apr. 2, 1962)./1/
As a "public utility" under the laws of Missouri, UE is regulated by the
MPSC as to its retail rates, services, accounts, depreciation, issuance of
securities, and certain utility property transactions, and in other respects as
provided by Missouri law. UE is also subject to regulation by the FERC with
respect to borrowings and the issuance of securities not regulated by the MPSC,
the classification of accounts, rates to wholesale customers, interconnection
agreements, and acquisitions and sales of certain utility properties as provided
by federal laws.
As a "public utility" under the laws of Illinois, UE is regulated by the
ICC as to its retail rates, services, accounts, depreciation, issuance of
securities, certain utility property transactions, transactions with "affiliated
interests" and in other respects as provided by Illinois law. Under Illinois
law, the ICC has jurisdiction over a "reorganization" such as the Transaction
and must find that the Transaction satisfies certain specific requirements
designed to protect consumers and preserve effective regulation by the ICC. See
Item 4.C below.
In addition, UE is subject to regulation by the NRC in connection with its
ownership and operation of the Callaway nuclear generating facility, a 1,100 mW
facility 100% owned by UE.
UE's retail electric, natural gas and steam operations in Missouri are
regulated by the MPSC. Its electric and natural gas operations in Illinois are
regulated by the ICC. Its wholesale electric sales are regulated by the FERC.
The common stock, par value of $5.00 per share, of UE ("UE Common Stock")
is listed on the New York Stock Exchange ("NYSE"). As of June 30, 1996, there
were
- ----------------
/1/ On July 28, 1975, UE registered under and pursuant to the provisions of
Section 5(a) of the Act for the sole and limited purpose of subjecting
itself to the provisions of Section 11(b)(2) of the Act in order that it
might obtain the approval and enforcement of a plan (the "Plan") to
eliminate the publicly-held minority interest in the common stock of
Missouri Utilities Company, as required by the Commission. The exchange
transaction proposed and provided for in the Plan has been carried out in
accordance with the terms and conditions of the Plan. The United States
District Court, having jurisdiction over the Plan's enforcement, has
ordered the Plan terminated and has relieved UE of any further obligation.
UE's limited purpose for registering as a holding company having been
fulfilled, it has returned to its status as an exempt holding company and
this Commission should so find. The necessity to notify the Commission of
changes affecting UE's relationship with or interest in EEI, or any changes
in EEI's contract with the United States Enrichment Corporation or in the
ownership of EEI's securities, should cease upon conclusion of this
proceeding, since the circumstances under which these requirements arose
are no longer relevant.
5
<PAGE>
102,123,834 shares of UE Common Stock and 3,434,336 shares of UE cumulative
preferred stock outstanding. UE's principal executive office is located at 1901
Chouteau Avenue, St. Louis, Missouri 63103. A copy of the Restated Articles of
Incorporation of UE, filed herewith as Exhibit A-2, is incorporated by
reference.
For the 12 months ended June 30, 1996, UE's operating revenues were
approximately $2.1 billion, as follows:
<TABLE>
<CAPTION>
<S> <C>
Electric $2.016 billion
Gas $94.7 million
Steam $452 thousand
</TABLE>
Total net assets of UE at June 30, 1996 were approximately $6.9 billion,
consisting of approximately $5.3 billion in electric utility property, plant and
equipment; $125 million in gas utility property, plant and equipment; and $1.4
billion in other corporate assets.
More detailed information concerning UE and its subsidiaries is contained
in UE's Annual Report on Form 10-K for the year ended December 31, 1995 (which
incorporates certain portions of its Annual Report to Shareholders which is
incorporated herein by reference as Exhibit I-3), a copy of which is
incorporated by reference as Exhibit I-1 and its Quarterly Reports on Form 10-Q
for the quarters ended March 31, 1996 and June 30, 1996, which are incorporated
by reference as Exhibit I-5.
b. CIPSCO and CIPS
CIPSCO, incorporated under the laws of the State of Illinois in 1986, is an
exempt public utility holding company pursuant to an order of the Commission
under Section 3(a)(1) of the Act. SEE CIPSCO INCORPORATED, 47 SEC Docket 174
(Sept. 18, 1990).
CIPSCO owns all of the issued and outstanding common stock of CIPS. CIPS,
an Illinois corporation organized in 1902, supplies electricity and natural gas
services in a 20,000 square mile region of central and southern Illinois,
rendering service to approximately 319,000 retail electric customers in 557
communities and distributing natural gas to approximately 167,000 customers in
267 communities. CIPS' utility service territory has an estimated population of
820,000 (about seven percent of Illinois' population) and contains about 35% of
the surface area of Illinois. In addition, CIPS sells electricity in the
wholesale and interchange markets to such entities as Soyland Electric
Cooperative, Illinois Municipal Electric Agency, Wabash Valley Power
Association, Inc., Mt. Carmel Public Utility Company, individual municipal
electric systems and other public- and investor-owned electric systems. As
noted, CIPS owns 20% of the common stock of EEI. At June 30, 1996, CIPS had
approximately 2,360 employees. A map of CIPS' electric and gas service
territories is attached as Exhibit E-3.
CIPS is an exempt holding company pursuant to Section 3(a)(2) of the Act
and Rule 2 thereunder. Pursuant to Rule 2, CIPS has filed a statement with the
Commission on Form
6
<PAGE>
U-3A-2 dated February 28, 1996 a copy of which is incorporated by reference as
Exhibit I-4 hereto. With respect to CIPS' ownership of EEI, see CENTRAL ILLINOIS
PUBLIC SERVICE CO., 32 S.E.C. 202 (Jan. 15, 1951).
As a "public utility" under the laws of Illinois, CIPS is regulated by the
ICC as to its retail rates, services, accounts, depreciation, issuance of
securities, certain utility property transactions, transactions with "affiliated
interests" and in other respects as provided by Illinois law. CIPS is also
subject to regulation by the FERC with respect to borrowings and the issuance of
securities not regulated by the ICC, the classification of accounts, rates to
wholesale customers, interconnection agreements, and acquisitions and sales of
certain utility properties as provided by federal laws. Under Illinois law, the
ICC has jurisdiction over a "reorganization" such as the Transaction and must
find that the Transaction satisfies certain specific requirements designed to
protect consumers and preserve effective regulation by the ICC. See Item 4.C.
below.
CIPSCO conducts its nonutility businesses through its subsidiary, CIPSCO
Investment. CIPSCO Investment manages CIPSCO's nonutility investments, including
leveraged leases, marketable securities and investments in energy projects.
CIPSCO Investment was organized on October 2, 1990. CIPSCO Investment has four
first-tier subsidiaries: CIPSCO Securities Company, which manages a portfolio of
equities and other marketable securities; CIPSCO Leasing Company, which manages
long-term leveraged leases for various equipment and real estate; CIPSCO Energy
Company, which manages electric generation projects under leveraged leases and a
limited partnership; and CIPSCO Venture Company, which makes investments in the
CIPS service territory. CIPSCO Investment will be wholly owned by Ameren, and
current expectations are that, following consummation of the Transaction, CIPSCO
Investment will continue to operate much as it does today.
The common stock of CIPSCO (the "CIPSCO Common Stock") is listed on the
NYSE and the Chicago Stock Exchange ("CSE"). As of June 30, 1996, there were
34,069,542 shares of CIPSCO Common Stock outstanding. CIPSCO has no preferred
stock outstanding. CIPS has 800,000 shares of Cumulative Preferred Stock
outstanding. CIPSCO's principal executive office is located at 607 East Adams
Street, Springfield, Illinois. Copies of the Amended and Restated Articles of
Incorporation of CIPSCO and the Restated Articles of Incorporation of CIPS are
incorporated by reference as Exhibits A-3 and A-4.
On a consolidated basis, CIPSCO's operating revenues for the 12 months
ended June 30, 1996 were approximately $879.5 million, broken down as follows:
<TABLE>
<CAPTION>
<S> <C>
Electric $728 million
Gas $141 million
Other $ 11 million
</TABLE>
Consolidated net assets of CIPSCO at June 30, 1996 were approximately $1.8
billion, consisting of $1.1 billion in electric utility plant, property and
equipment; $135 million in gas utility property, plant and equipment; and $597
million in other assets.
7
<PAGE>
More detailed information concerning CIPSCO and CIPS is contained in the
Annual Report of CIPSCO and CIPS on Form 10-K for the year ended December 31,
1995, which is incorporated by reference as Exhibit I-2; the Quarterly Reports
of CIPSCO and CIPS on Form 10-Q for the quarters ended March 31, 1996 and June
30, 1996, which are incorporated by reference as Exhibit I-6; and CIPS'
Statement on Form U-3A-2 for the year ended December 31, 1995, which is
incorporated by reference as Exhibit I-4.
c. Ameren and Arch Merger
i. Ameren
Ameren was incorporated under the laws of the State of Missouri on August
7, 1995 as Arch Holding Corp. to become a holding company for UE and CIPS
following the Transaction and for the purpose of facilitating the Transaction.
Its name was changed to Ameren Corporation on October 19, 1995. Ameren has, and
prior to the consummation of the Transaction will have, no operations other than
those contemplated by the Merger Agreement to accomplish the Transaction. The
authorized capital stock of Ameren consists of 400,000,000 shares of Ameren
Common Stock and 100,000,000 shares of preferred stock, par value $.01 per share
("Ameren Preferred Stock"). Upon consummation of the Transaction, Ameren will be
a public utility holding company and will own all of the issued and outstanding
common stock of UE, CIPS and CIPSCO Investment. At present, the common stock of
Ameren is owned 50% by UE and 50% by CIPSCO. No shares of Ameren Preferred Stock
have been issued. A copy of the Restated Articles of Incorporation of Ameren is
attached as Exhibit A-1.
ii. Arch Merger
Solely for the purpose of facilitating the Transaction proposed herein,
Arch Merger was incorporated under the laws of the State of Missouri on August
7, 1995. The authorized capital stock of Arch Merger consists of 100 shares of
common stock, par value $.01 per share ("Arch Merger Common Stock"). Arch Merger
has, and prior to the closing of the Transaction will have, no operations other
than the activities contemplated by the Merger Agreement necessary to accomplish
the combination of Arch Merger and UE as herein described.
d. Ameren Services
Prior to the consummation of the Transaction, Ameren Services will be
incorporated in Missouri to serve as the service company for the Ameren system
after the consummation of the Transaction. Ameren Services will provide UE and
CIPS, and the other companies of the Ameren system, with a variety of
administrative, management and support services.
The authorized capital stock of Ameren Services will consist of 1,000
shares of common stock, par value $.01 per share. Upon consummation of the
Transaction, all issued and outstanding shares of Ameren Services will be held
by Ameren.
8
<PAGE>
Ameren Services will enter into a general services agreement with Ameren,
UE, CIPS and CIPSCO Investment (the "General Services Agreement"). (A copy of
the form of General Services Agreement is filed as Exhibit B-4.)
2. Description of Energy Sales, Facilities and Fuel
a. UE
i. General
For the 12 months ended June 30, 1996, UE sold the following amount of
electric energy (at retail or wholesale) and sold and transported the following
amount of natural gas at retail:
<TABLE>
<CAPTION>
<S> <C>
UE
kWh of electric energy sold............................ 34,469,818,152
(including amounts delivered in interchange)
Mcf of gas distributed at retail....................... 20,615,638
(including transportation of customer owned gas)
</TABLE>
ii. Electric Generating Facilities
UE's generating facilities as of June 30, 1996, all of which are 100% owned
by UE, were as follows:
9
<PAGE>
GENERATING CAPABILITY
Union Electric Company
<TABLE>
<CAPTION>
Net Capability-mW
-----------------
Station Name & Unit No. Unit Type Summer Winter Fuel Type
- ------------------------- ----------- -------- ------- ---------
<S> <C> <C> <C> <C>
Callaway Nuclear 1125 1177 Uranium
Canton Diesels Internal
Combustion 4 4 Oil
Fairgrounds Combustion Combustion
Turbine Turbine 55 61 Oil
Howard Bend Combustion Jet
Turbine Engine 43 47 Oil
Keokuk Hydro 125 126 Water
Kirksville Combustion Combustion
Turbine Turbine 13 14 Gas
Labadie 1 Steam 573 575 Coal
Labadie 2 Steam 573 575 Coal
Labadie 3 Steam 575 577 Coal
Labadie 4 Steam 575 577 Coal
Meramec 1 Steam 131 134 Coal/Gas
Meramec 2 Steam 131 134 Coal/Gas
Meramec 3 Steam 278 280 Coal/Gas
Meramec 4 Steam 333 342 Coal
Meramec Combustion Combustion
Turbine Turbine 55 61 Oil
Mexico Combustion Combustion
Turbine Turbine 55 61 Oil
Moberly Combustion Combustion
Turbine Turbine 55 61 Oil
Moreau Combustion Combustion
Turbine Turbine 55 61 Oil
Osage Hydro 212 208 Water
Portable Diesel Internal
Combustion 1 1 Oil
Rush Island 1 Steam 583 584 Coal
</TABLE>
10
<PAGE>
<TABLE>
<CAPTION>
Net Capability-mW
-----------------
Station Name & Unit No. Unit Type Summer Winter Fuel Type
- ----------------------- ----------- -------- ------- ---------
<S> <C> <C> <C> <C>
Rush Island 2 Steam 583 584 Coal
Sioux 1 Steam 470 477 Coal
Sioux 2 Steam 470 477 Coal
Taum Sauk Pumped 350 275 Water
Storage
Venice Steam 429 439 Gas/Oil
Venice Combustion Combustion
Turbine Turbine 25 30 Oil
Viaduct Combustion Combustion
Turbine Turbine 25 30 Gas
----- -----
TOTAL 7,902 7,972
</TABLE>
As of June 30, 1996, UE had a total net generating capability of 7,972 mW
available.
During 1995, 70.6% of the electricity generated by units owned by UE was
produced by coal-fired generating units, 24.5% by a nuclear generating unit, and
4.9% by other types of generating units.
UE's 1995 summer peak load, which occurred on August 18, 1995, was 7,965 mW
and its 1995 winter peak load, which occurred on February 2, 1996, was 6,480 mW,
exclusive of off-system transactions.
iii. Electric Transmission and Other Facilities
As of December 31, 1995, UE's transmission system included 898 circuit
miles of 345 kV line, 90 circuit miles of 230 kV line, 726 circuit miles of 161
kV line, 1,408 circuit miles of 138 kV line, and 143 circuit miles of 110 kV
line.
The bulk of UE's high voltage transmission system is located in the State
of Missouri. As of December 31, 1995, UE's transformer capacity in transmission
substations totaled 22,133,000 kVA and its transformer capacity in distribution
substations totaled 22,856,000 kVA. See also Item 1.B.2.b.iii. infra. A map of
UE's major transmission lines is filed as Exhibit E-4.
UE's steam heating property at June 30, 1996 consisted of facilities used
to provide steam for heating to the Missouri State Capitol complex in Jefferson
City, Missouri. The facilities have a net book value of $400,000. Steam is
supplied from boilers installed at the
11
<PAGE>
plant. The boilers have a capability of 27,600 pounds of steam per hour under
sustained load.
Other assets owned by UE include an electric distribution system located
throughout its service area, and property, plant and equipment supporting its
electric and gas utility functions.
iv. Fuel Sources
UE's electric generation by fuel type for each of the last five calendar
years, and the average cost of such fuels to UE per kWh generated, are set forth
below :
<TABLE>
<CAPTION>
% of Net Generation
--------------------
Fuel Cost
Year Nuclear Coal Other (Cents per kWh)
- ---- ------- ---- ----- ---------------
<S> <C> <C> <C> <C>
1995 24.5 70.5 5.0 1.068
1994 29.7 65.0 5.3 1.064
1993 28.0 65.3 6.7 1.331
1992 26.2 69.1 4.7 1.310
1991 30.0 66.7 3.3 1.348
</TABLE>
COAL. Because of uncertainties of supply due to potential work stoppages,
equipment breakdowns and other factors, UE has a policy of maintaining a coal
inventory of 75 days, based on normal annual burn practices.
NUCLEAR. The components of the nuclear fuel cycle required for nuclear
generating units are as follows: (1) uranium; (2) conversion of uranium into
uranium hexafluoride; (3) enrichment of uranium hexafluoride; (4) conversion of
enriched uranium hexafluoride into uranium dioxide and the fabrication into
nuclear fuel assemblies; and (5) disposal and/or reprocessing of spent nuclear
fuel.
UE has agreements to fulfill its needs for uranium, enrichment, and
fabrication services through 1999. UE's agreements for conversion services are
sufficient to supply the Callaway Plant through 1997. Additional contracts will
have to be entered into in order to supply nuclear fuel during the remainder of
the life of the Callaway Plant, at prices which cannot now be accurately
predicted. The Callaway Plant normally requires re-fueling at 18-month intervals
and re-fuelings are presently scheduled for the fall of 1996 and the spring of
1998.
Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy
("DOE") is responsible for the permanent storage and disposal of spent nuclear
fuel. DOE currently charges one mill per kilowatt-hour sold for future disposal
of spent fuel. Electric rates charged to customers provide for recovery of such
costs. DOE is not expected to have
12
<PAGE>
its permanent storage facility for spent fuel available until at least 2015. UE
has sufficient storage capacity at the Callaway Plant site until 2004 and has
viable storage alternatives under consideration. Each alternative will likely
require NRC approval and may require other regulatory approvals. The delayed
availability of DOE's disposal facility is not expected to adversely affect the
continued operation of the Callaway Plant.
OIL AND GAS. The actual and prospective use of such fuels is minimal, and
UE has not experienced and does not expect to experience difficulty in obtaining
adequate supplies.
v. Gas Facilities
UE serves approximately 120,000 gas customers. About 18,000 of these
customers are in Illinois, in the Alton area ("Alton System"). The remainder of
UE's customers are in Central, Eastern and Southeastern Missouri. UE also buys
gas for two of its baseload electric generating plants, Meramec and Venice, and
for two of its combustion turbine units. UE's gas system is connected to four
interstate pipelines (Panhandle Eastern Pipe Line Company ("PEPL"), Texas
Eastern Transmission Corporation ("TETCO"), Natural Gas Pipeline Company of
America ("NGPL") and Mississippi River Transmission Corporation ("MRTC")) and to
two intrastate pipelines, Illini Pipeline ("IP") and Missouri Pipeline Company
("MPC"). MRTC, IP and, indirectly, NGPL serve the Alton System. UE purchases all
of its gas supply from producers, gatherers and marketers, and transports it on
one or more of the connected pipelines. UE has no on-system storage capability.
UE currently is operating three propane air facilities, one of which is in
Illinois. UE's peak day firm gas load is approximately 190,000 MCF with an
annual retail sales throughput of 16 BCF. SEE ALSO Item 1.B.2.b.v. infra.
b. CIPSCO and CIPS
i. General
For the 12 months ended June 30, 1996, CIPS sold the following amount of
electric energy (at retail or wholesale) and sold and transported the following
amount of gas at retail:
<TABLE>
<S> <C>
kWh of electric energy sold
(including amounts delivered in interchange) 13,988,215,722
Mcf of gas distributed at retail
(including transportation of customer owned gas) 25,196,065
</TABLE>
ii. Electric Generating Facilities
CIPS's generating facilities as of June 30, 1996, all of which are 100%
owned by CIPS, were as follows:
13
<PAGE>
GENERATING CAPABILITY
Central Illinois Public Service Company
<TABLE>
<CAPTION>
Net Capability-mW
-----------------
Station Name & Unit No. Unit Type Summer Winter Fuel Type
- ----------------------- --------- ------- ------ ---------
<S> <C> <C> <C> <C>
Coffeen 1 Steam 340 340 Coal
Coffeen 2 Steam 560 560 Coal
Grand Tower 3 Steam 82 82 Coal
Grand Tower 4 Steam 104 104 Coal
Hutsonville 3 Steam 76 77 Coal
Hutsonville 4 Steam 77 79 Coal
Hutsonville Internal
Diesel Combustion 3 3 Oil
Meredosia 1 Steam 62 64 Coal
Meredosia 2 Steam 62 64 Coal
Meredosia 3 Steam 215 215 Coal
Meredosia 4 Steam 168 174 Oil
Newton 1 Steam 555 554 Coal
Newton 2 Steam 555 555 Coal
----- -----
TOTAL 2,859 2,871
</TABLE>
As of June 30, 1996, CIPS had a total generating capability of 2,871 mW.
CIPS' 1995 summer peak load, which occurred on August 14, 1995, was 2,319
mW and its 1995 winter peak load, which occurred on February 2, 1996, was 1,978
mW, exclusive of off-system transactions. For the year ended December 31, 1995,
approximately 99% of CIPS' kWh production was obtained from coal-fired
generation and approximately 1% from oil-fired generation.
iii. Electric Transmission and Other Facilities
As of December 31, 1995, the CIPS transmission system consisted of 290
circuit miles of 345 kV lines, 48 circuit miles of 230 kV lines, 58 circuit
miles of 161 kV lines and 1,477 circuit miles of 138 kV lines. As of the same
date, CIPS's transmission substations had a combined capacity of 16,187,643 kVA
and the distribution substations had a combined capacity of 3,032,360 kVA. All
of these facilities are located within the state of Illinois. A map of CIPS's
major transmission lines is attached as Exhibit E-6.
14
<PAGE>
CIPS also owns or leases other physical properties, including real
property, and other facilities necessary or appropriate to conduct its
operations.
iv. Fuel Sources
CIPS's electric generation by fuel type for each of the last five calendar
years, as well as the average cost to CIPS of these fuels per kWh generated, are
set forth below:
<TABLE>
<CAPTION>
% of Net Generation
--------------------------
Fuel Cost
Year Coal Oil (Cents per kWh)
---- ---- --- ---------------
<S> <C> <C> <C>
1995 99+ (less than)1 1.798
1994 99+ (less than)1 1.750
1993 99+ (less than)1 1.727
1992 99+ (less than)1 1.787
1991 99+ (less than)1 1.778
</TABLE>
The amount of coal supplies on hand at the generating stations of CIPS
varies from time to time. CIPS generally attempts to maintain a 65-day supply.
Currently, approximately 75% of the annual coal requirements of the generating
facilities of CIPS are being met by long-term coal contracts expiring at various
dates from 1997 to 2010. As contracts approach their expiration, or when
appropriate, CIPS evaluates alternative supply arrangements based on then
current and expected market conditions for coal. CIPS believes there are
adequate supplies of coal reasonably available to supply its existing generating
units with the quantity and quality of coal required for the foreseeable future.
The actual and prospective use of oil as fuel is minimal and CIPS has not
experienced and does not expect to experience difficulty in obtaining adequate
supplies.
v. Gas Facilities
CIPS serves approximately 167,000 gas customers in 267 communities
throughout Central and Southern Illinois. CIPS' gas system is connected to six
interstate pipelines, three of which also serve UE: PEPL, TETCO, NGPL,
Trunkline Gas Company ("TRKL"), Texas Gas Transmission Corporation ("TGT"), and
Midwestern Gas Transmission Company ("MW"). CIPS is also connected with two
other Illinois gas distribution utilities: Northern Illinois Gas Company
("NIGAS") and Central Illinois Light Company ("CILCO"). CIPS purchases over 99%
of its gas supply from producers, gatherers and marketers and transports it on
one or more of the connecting pipelines. CIPS has four active on-system storage
fields: Ashmore, Sciota, Johnston City and Belle Gent. CIPS also has one
propane-air facility at Quincy. CIPS' peak day firm gas load is approximately
300,000 MCF with an annual retail sales throughput of approximately 23 BCF.
15
<PAGE>
c. Transferred Utility Facilities
As part of the Transaction, UE expects to transfer to CIPS the Transferred
Utility Facilities subject to approval of the ICC and MPSC. The transfer will
include all of UE's electric and gas facilities used to provide retail service
in Illinois. It does not include any generation or transmission facilities.
The electric facilities to be transferred include electric substations in
East St. Louis and Alton, Illinois, plus attendant equipment. In terms of gas
facilities to be transferred, UE's Alton System is basically contiguous to the
southern end of CIPS' Western Division gas system. The Alton System is served by
two pipelines, MRTC and IP. CIPS has significant transportation capacity on
NGPL, which is the pipeline through which gas flows into IP. MRTC is also
interconnected with TRKL, another pipeline on which CIPS holds significant
capacity, and with NGPL. Thus, the Alton System can easily be integrated into
CIPS' existing gas supply and operations. Subject to obtaining any necessary
consents, UE will transfer to CIPS the MRTC, IP and NGPL transportation and
storage contracts that UE has acquired to serve its Illinois gas customers that
are in effect at the time of the Mergers. UE's current supply agreements expire
prior to the expected date for consummation of the Transaction, but any existing
supply agreements in effect at that time will be transferred to CIPS.
Currently, UE provides approximately 500 mW of firm power and 70 mW of
interruptible power to its Illinois customers. After the Transaction, UE expects
to provide to CIPS, through a System Support Agreement, the same amount of power
it currently provides to its Illinois retail customers. This power will be
priced to CIPS at a rate which will recover the same amount of UE's power costs
which is now being recovered from UE's Illinois customers. The System Support
Agreement is subject to approval by the FERC.
3. Nonutility Interests of UE and CIPSCO
a. UE
UE's only nonutility subsidiary is UEDC, which constituted less than 1/4 of
1% of UE's assets at June 30, 1996 and provided less than 1/4 of 1% of UE's
revenues in 1994, 1995 and the 12 months ended June 30, 1996. At June 30, 1996,
UEDC had assets of $10,278,477.
A corporate chart of UE and its subsidiaries, showing their nonutility
interests, is filed as Exhibit E-8.
b. CIPSCO
CIPSCO conducts its unregulated nonutility businesses through CIPSCO
Investment. CIPSCO Investment was formed for the purpose of managing nonutility
investments and providing investment management services to CIPSCO and its
affiliates. CIPSCO Investment's investment portfolio principally includes money-
market investments, common stocks, mutual funds, hedged preferred stocks, hedged
common stocks, and equity interests
16
<PAGE>
in lease transactions and energy related projects. Investments are held in the
four subsidiaries of CIPSCO Investment: CIPSCO Securities Company, CIPSCO
Leasing Company, CIPSCO Energy Company and CIPSCO Venture Company. CIPSCO
Securities Company invests in marketable securities, CIPSCO Leasing Company
invests in leveraged leases for various equipment and real estate, CIPSCO Energy
Company invests in electric generation projects under leveraged leases and a
limited partnership, and CIPSCO Venture Company makes investments within the
CIPS utility service territory.
Together, CIPSCO's nonutility subsidiaries constituted less than 7% of
CIPSCO's assets on a consolidated basis at June 30, 1996 and provided less than
2% of CIPSCO's consolidated operating revenues in each of 1994, 1995 and for the
twelve months ended June 30, 1996. At June 30, 1996, CIPSCO Investment had
assets of $118.3 million out of total consolidated assets of CIPSCO of
approximately $1.8 billion, and operating revenues (excluding intercompany
eliminations) of $12.4 million out of consolidated operating revenues of
approximately $879.5 million.
A corporate chart of CIPSCO and its subsidiaries, showing their nonutility
interests, is filed as Exhibit E-9.
4. Present Electric Coordination
CIPS and UE are currently physically interconnected at nine tie points,
four of which have two-way transfer capability where power and energy can flow
freely in either direction and five of which are operated as radial ties where
the power and energy can be moved in only one direction. The interconnections
are shown on Exhibit E-2. The interconnections with two-way transfer capability
have a maximum total transfer capability of 791 mW. With the transfer of UE's
Illinois service area and its associated electric properties to CIPS, the
companies will have an additional amount of one-way tie capability, in excess of
1,000 mW, which is for power delivery from UE to CIPS.
CIPS is planning to build a new interconnection with Iowa Electric Services
("IES"). CIPS will build a 138,000 volt line from Macomb, Illinois, to Niota,
Illinois. CIPS and IES will jointly install a substation to transform the
voltage from 138,000 volts to 161,000 volts. IES will construct a 161,000 volt
line into Iowa to its Burlington generating station. This project should be
completed in 1998. UE is planning to reconductor the two Cahokia-Central 138,000
volt lines by 1997. Also, UE is planning to build a 345,000 volt line from its
Sioux generating plant to Roxford, Illinois, by 1999. These lines, planned
before CIPSCO and UE agreed to the Transaction, will increase transmission
capacity, eliminate the minimal existing transmission constraints and enhance
electric coordination of the CIPS and UE systems.
CIPS and UE intend to jointly dispatch their generating resources. UE and
CIPS have considered the transfers resulting from joint dispatch, and have
concluded that these changes should not cause constraints on the UE/CIPS
interfaces or materially change the transfer capability that would exist if
there were no joint dispatch.
17
<PAGE>
UE and CIPS are members of the Illinois-Missouri Pool with Illinois Power
Company. In addition, both utilities are members of Mid-America Interconnected
Network, Inc. ("MAIN"), which is one of the nine regional reliability councils
of the North American Electric Reliability Council ("NERC"). Membership in these
groups involves the coordination of long-range system planning and day-to-day
operations. In addition, both companies have a number of interchange agreements
with other utilities.
UE and CIPS are also interconnected with other electric utilities as
outlined below:
DIRECT TRADING PARTNERS
UE/CIPS COMBINATION
Union Electric Company Central Illinois Public Service Company
- ---------------------- ---------------------------------------
. AP&L (Entergy) . Commonwealth Edison
. Associated Electric Cooperative . Public Service of Indiana
. Central Illinois Public Service . Indiana Michigan Power (AEP)
. City of Columbia (MO) . Northern Indiana Public Service
. Interstate Power . Central Illinois Light
. Mid American Energy . Wabash Valley Power Association
. Kansas City Power & Light . City Water Light & Power
. Western Resources (Springfield, IL)
. Missouri Public Service . Illinois Municipal Electric Agency
. Northern States Power . Indiana Municipal Power Agency
. Public Service of Oklahoma . Soyland Electric Cooperative
. St. Joseph Light & Power . Southern Illinois Power Cooperative
. Southwestern Power Administration . Union Electric Company
Common to Both Companies
------------------------
. Electric Energy, Inc.
. IES Utilities
. Illinois Power
. Kentucky Utilities
. Tennessee Valley Authority
5. Present Gas Coordination
Most of CIPS' gas systems are currently integrated by way of physical
interconnects and contractual arrangements. This part of CIPS' overall system
comprises the areas that are served by PEPL, TRKL, TETCO and NGPL, and
represents over 80% of the total peak day demand of CIPS' entire gas system.
UE's Alton System is basically contiguous to the southern end of CIPS' Western
Division gas system. The Alton System is served by two pipelines, MRTC and IP.
CIPS has significant transportation capacity on NGPL, which is the pipeline
through which gas flows into IP. MRTC is also interconnected with TRKL, another
pipeline on which CIPS holds significant capacity, and with NGPL. Thus, the
Alton System can easily be integrated into CIPS' existing gas supply and
operations.
18
<PAGE>
UE's gas system consists of four distribution systems, each of which is
served by a major interstate pipeline. In addition, two of these distribution
systems are served by intrastate pipelines. The largest system is located in
central and eastern Missouri and is connected to the interstate pipeline PEPL
and to the intrastate carrier MPC. Two systems are located in southeast
Missouri and are served by the interstate pipelines TETCO and NGPL. UE's
remaining gas system is located in the Alton, Illinois area and is connected to
the interstate pipeline MRTC and the intrastate pipeline IP.
For further discussion of the gas systems, see Item 3.A.2.b.ii.(B) infra.
C. Description of Transaction and Statement as to Consideration
1. Background
Since the late 1980s, the management of UE has periodically analyzed
various potential strategic options that might be available to UE, including
possible business combinations with other utilities. During this time since the
late 1980s, the management of UE looked at substantially all of the utilities of
significant size and with service areas proximate to the main service areas of
UE, and periodically briefed the UE Board on such matters. None of the other
utilities appeared to offer strategic and operational synergies as attractive as
those that could be realized through a merger with CIPSCO. The physical
proximity of the service areas of CIPS and UE, the compatibility of and
similarity between UE's and CIPSCO's operations, the familiarity with CIPSCO
resulting from various cooperative transactions including power purchases and
sales, the joint ownership of EEI, and the excellent reputation of CIPSCO's
management, made CIPSCO the natural first choice for a combination partner for
UE.
Since the late 1980s, the management of CIPS (and later CIPSCO) has
periodically analyzed various potential strategic options that might be
available, including possible business combinations with other utilities.
CIPSCO management looked at substantially all utilities of significant size and
with service areas proximate to the service area of CIPS, as well as several
other utilities with Midwestern operations, and periodically briefed the Boards
of CIPS and CIPSCO on such matters. During 1994, CIPSCO management and
representatives of the investment banking firm Morgan Stanley & Co. ("Morgan
Stanley") discussed generally the utility merger and acquisition environment
with the CIPSCO Board. The CIPSCO Board was briefed at its December 6, 1994
meeting with respect to the fact that CIPSCO management was reviewing various
strategic alternatives. As a continuation of such reviews, in May 1995, CIPSCO
management concluded that no other potential merger partner provided a better
overall strategic fit than did UE on the basis of factors such as: low cost
structure, competitive energy rates, strong credit ratings, potential merger-
related cost savings, possible economies of scale, marketing potential and
similar common stock trading characteristics. These reasons, combined with the
compatibility of and similarity between CIPS' and UE's operations, CIPS' prior
experience working with UE in the context of power purchases and sales, service
restoration following major storms, joint ownership of EEI and the excellent
reputation of UE's management team made UE the natural combination partner for
CIPSCO.
19
<PAGE>
At its June 6, 1995 Board meeting, CIPSCO management reviewed possible
strategic alternatives for CIPSCO, including a business combination with UE, the
possibility of remaining an independent company and the possibility of a
combination with other Midwestern utilities. There was a review of the
consequences of CIPSCO remaining an independent company. Management reported
that it had sought advice from the investment banking firm of Morgan Stanley and
the law firm of Jones, Day, Reavis & Pogue with respect to strategic
alternatives. At the June 6, 1995 meeting, the CIPSCO Board authorized
management to continue further studies regarding a business combination with UE.
After this meeting, no alternative merger scenarios were seriously considered by
CIPSCO management.
Mr. Charles W. Mueller, President and Chief Executive Officer of UE, and
Mr. Clifford L. Greenwalt, President and Chief Executive Officer of CIPSCO, have
had for many years a business and social relationship, and have spoken
periodically by telephone and in person at business and social occasions.
Messrs. Greenwalt and Mueller have, in the course of their business dealings
over the years, noted the similarities of UE and CIPSCO listed above. In June
of 1995, a series of discussions occurred between Messrs. Mueller and Greenwalt
which ultimately resulted in a meeting on June 19, 1995 between Messrs. Mueller
and Greenwalt, at which the two companies' views of the future of the utility
industry were discussed. The two men discussed in a very preliminary fashion
the concept of a business combination between UE and CIPSCO. At such meeting,
the concept of a holding company structure for a potential business combination
was discussed, and Messrs. Greenwalt and Mueller also identified the issues of
management succession, board composition and the location of the headquarters as
significant points to be agreed upon.
After the June 19, 1995 meeting, CIPSCO informed Morgan Stanley and Jones,
Day, Reavis & Pogue that CIPSCO was contemplating a business combination with
UE. Additionally, during this period, Mr. Mueller orally briefed individual UE
directors on the reviews and discussions which had taken place.
On June 21, 1995, officers of UE and CIPSCO, including Donald E. Brandt,
Senior Vice President, Finance & Corporate Services and William E. Jaudes, Vice
President and General Counsel, of UE, and William A. Koertner, Vice President,
and Craig D. Nelson, Treasurer, of CIPSCO, held discussions with respect to
potential synergies that could result from a potential business combination
transaction. Following such meeting the companies entered into a
confidentiality agreement, pursuant to which the parties agreed to exchange
nonpublic information with a view toward exploring a possible business
combination.
Shortly after the June 21, 1995 meeting, UE engaged the law firm of
Wachtell, Lipton, Rosen & Katz to advise it with respect to the potential
transaction.
The parties agreed that it was desirable to arrange an introductory meeting
of the parties' respective management teams and advisors to discuss, among other
things, the due diligence and negotiation process.
On July 14, 1995, Messrs. Brandt, Jaudes, Koertner and Nelson, together
with other personnel from UE and CIPSCO, as well as their financial and legal
advisors, held an
20
<PAGE>
introductory meeting to discuss, among other things, a timetable for
accomplishing the tasks required to negotiate, prepare and execute a merger
transaction between the two companies. Representatives of the Management
Consulting Division of Deloitte & Touche LLP ("Deloitte & Touche"), which had
been jointly retained by UE and CIPSCO, were also present at such meeting. At
the July 14 meeting, working groups composed of representatives of both
companies were formed to examine various issues, including structure, financial
modeling, regulatory considerations, integration of employee benefit plans,
communications and an analysis of synergies. Deloitte & Touche was engaged to
assist the senior managements of UE and CIPSCO and certain employees designated
by them in identifying and quantifying the potential cost savings from synergies
resulting from the proposed merger.
On July 26, 1995, Messrs. Brandt, Jaudes, Koertner and Nelson, as well as
other personnel from UE and CIPSCO, together with their respective financial
advisors, held a meeting for the purpose of conducting due diligence and
discussing further the potential synergies that could be achieved by a business
combination transaction (such as cost savings from economies of scale and
reduced electric production and gas purchase costs, reduction in operating and
maintenance expenses and elimination of duplicative administrative
expenditures), and the legal and regulatory implications of alternative
combination structures.
On August 1, 1995, CIPSCO management, Morgan Stanley, Deloitte & Touche,
legal counsel and Synergy Consulting Services Corporation ("Synergy
Consulting"), an independent nuclear consultant retained by CIPSCO, briefed the
CIPSCO Board on various matters identified below relating to a business
combination with UE.
At that meeting, management and Deloitte & Touche reported the analyses of
the potential synergies that could be achieved by a combination with UE
presenting assumptions underlying their analyses. This presentation gave an
overview of the types of synergy savings (financial, regulatory and operational)
that could be achieved by a combination and emphasized that the identified
synergies were all directly related to a possible merger and did not include
other types of savings that might be achieved without a merger. An overview of
categories of synergy savings was given which identified the following areas for
potential synergies: personnel reductions, corporate and administrative
programs, electric production and gas supply costs and purchasing economies for
such items as materials, supplies and contract services. The analyses assumed a
period of 1997 to 2006, that the combination would result in a registered public
utility holding company, continuation of current regulation of the utility
industry, that management and operational integration of corporate, distribution
and production support functions would occur without total physical
centralization, that labor savings would be achieved exclusively through
attrition and phased in over time, and that the costs to achieve the savings
would be incurred over the first two years. The synergy analyses were prepared
by management of CIPSCO and UE with the assistance of Deloitte & Touche based on
information provided by each company.
At the August 1, 1995 meeting of the CIPSCO Board, legal counsel presented
information as to the regulatory approvals that would be required for a
combination with UE, the standards of review to be applied by the various
regulatory bodies, implications
21
<PAGE>
under the Act of various structures and other matters. Morgan Stanley presented
an analysis of UE and reported on its due diligence activities. Synergy
Consulting presented a report containing the results of its evaluation of the
Callaway nuclear generating station of UE and identified and characterized for
the CIPSCO Board generic nuclear power plant business risks. Synergy Consulting
concluded that the Callaway Plant ranked at the top of the industry's nuclear
generating plants in all respects, was in good condition and was well managed
and also concluded that the plans for decommissioning the plant at the end of
its useful life were adequate. In the course of its evaluation Synergy
Consulting reviewed documentation containing relevant operating statistics
(capacity factors, production costs and regulatory performance) and reviewed
external performance evaluations of the plant including Institute of Nuclear
Power Operations (INPO) ratings, NRC Systematic Assessment of Licensee
Performance (SALP) ratings and other ratings based on publicly available
industry benchmarking data of nuclear station performance. Each of these
ratings put the Callaway Plant among the highest of the applicable rating
categories for the past five years. The Synergy Consulting evaluation took into
account specific risks associated with the Callaway Plant in the following
categories: production, costs, organization and management and decommissioning
plan. Finally, Synergy Consulting briefed the CIPSCO Board on the generic risks
associated with nuclear generating plants, including premature permanent plant
shutdown, temporary plant shutdown, uneconomic plant operation, inability to
extend plant life, unanticipated costs, consequences of a nuclear accident,
changes in regulations, fuel storage and fuel disposal and decommissioning
costs.
In the ten days following August 1, 1995, the representatives of each party
continued their work with respect to the synergies analyses, business plans,
legal structures, regulatory plans, due diligence and employee benefits. In
addition, discussions commenced between the UE management and UE's investment
banking firm, Goldman, Sachs & Co. ("Goldman Sachs") on the one hand, and CIPSCO
and Morgan Stanley on the other hand, with respect to management negotiation of
the exchange ratios, and between counsel for CIPSCO and counsel for UE, with
respect to the terms of the draft merger agreement and the terms of possible
stock option agreements.
On August 8, 1995, the UE Board met and received detailed information and
advice from Goldman Sachs and legal counsel, as well as a detailed report from
management on the merger negotiations. The UE Board also received a report on
the analysis of potential synergies, including discussions of potential cost
savings from economies of scale and decreased electric production and gas
purchase costs and elimination of duplicative administrative expenses. Goldman
Sachs reviewed financial and other information concerning UE and CIPSCO and the
status of negotiations with respect to an exchange ratio. Counsel outlined in
detail the terms and conditions of the draft merger agreement and proposed stock
option agreements. Counsel also reviewed the handling of various other issues
relating to the Transaction, such as the composition of the Ameren Board and the
location of the corporate headquarters of Ameren. Counsel then reviewed the
implications of adopting a registered holding company structure under the Act,
including the possibility that divestiture of the combined entity's gas and
certain nonutility operations would be required. The UE Board discussed the
significant potential benefits from a combination to shareholders and customers
of CIPSCO and UE.
22
<PAGE>
On August 8, 1995, the CIPSCO Board met and received detailed advice from
Morgan Stanley and legal counsel. The CIPSCO Board also received an updated
briefing from management and Deloitte & Touche on the analysis of potential
synergies, including discussions of potential cost savings from economies of
scale and decreased electric production and gas purchase costs and the
elimination of duplicative administrative expenses. Morgan Stanley reviewed
financial and other information concerning UE and CIPSCO and the status of
negotiations with respect to an exchange ratio. Counsel outlined in detail the
terms and conditions of the draft merger agreement and proposed stock option
agreements. Counsel also reviewed in detail the status of negotiations on the
merger agreement and the due diligence process. Management reported on the
handling of various other issues relating to the Transaction, such as the
composition of the Ameren Board and the location of the corporate headquarters
of Ameren, the transfer of UE's Illinois utility business to CIPS and
communications plans. Legal counsel then reviewed the implications of adopting a
registered holding company structure under the Act, including the possibility
that divestiture of the combined entity's gas and certain nonutility operations
would be required. Legal counsel and management described the covenants which
would govern the operations of UE and CIPSCO prior to the effective time of the
Mergers and issues relating to employee and workforce matters which would govern
the operations of Ameren and its subsidiaries subsequent to the effective time.
The CIPSCO Board discussed the significant potential benefits from a combination
to shareholders and customers of CIPSCO and UE.
The representatives and advisors for both parties met and spoke on numerous
occasions on August 9, 10, and 11, discussing the transaction and the related
documentation, the final terms of the Merger Agreement, including the conditions
to closing, the termination provisions, the breakup fees, the covenants which
would govern the operations of UE and CIPSCO prior to the effective time and
various other matters, such as employee benefits and workforce matters, which
would govern the operations of Ameren after the effective time. These
discussions also addressed issues relating to composition of Ameren's
management, the Ameren Board and committees of the Ameren Board. Goldman Sachs
and Morgan Stanley held further discussions with respect to an exchange ratio
and, on August 11, decided to present for their respective clients'
consideration a ratio which would result in each share of UE Common Stock being
converted into one share of Ameren Common Stock, and a ratio which would result
in each share of CIPSCO Common Stock being converted into 1.03 shares of Ameren
Common Stock.
On August 11, 1995, at a meeting of the UE Board, Goldman Sachs and counsel
to UE described the status of the merger negotiations and the changes in the
proposed merger agreement and stock option agreements which had been made since
the August 8 meeting of the UE Board. Counsel also reviewed the handling of the
various other issues relating to the transaction, such as the composition of the
Ameren Board and the location of the headquarters of the combined entity. At the
August 11 meeting, Goldman Sachs delivered its oral opinion to the UE Board
that, as of such date and based upon the assumptions made, matters considered
and limits of review discussed therein, and in light of the proposed exchange
ratio of 1.03 shares of Ameren Common Stock per share of CIPSCO Common Stock,
the proposed exchange ratio of one share of Ameren Common Stock per share of UE
Common Stock was fair to the holders of UE Common Stock. Following discussion,
the UE Board unanimously approved the Merger Agreement and the Stock Option
Agreements (as
23
<PAGE>
defined in the Merger Agreement) and authorized their execution. (With respect
to the Stock Option Agreements, see Item 1.C.4. below.)
On August 11, 1995, the CIPSCO Board met and received advice from Morgan
Stanley and legal counsel. Morgan Stanley reviewed various financial and other
information and rendered to the CIPSCO Board its oral opinion, confirmed in a
written opinion dated August 11, 1995, to the effect that, as of the date of
said opinion and based upon and subject to the matters stated therein, the
proposed exchange ratio of 1.03 shares of Ameren Common Stock per share of
CIPSCO Common Stock, in light of the exchange ratio of one share of Ameren
Common Stock to be received by shareholders of UE for each share of UE Common
Stock, was fair to the holders of CIPSCO Common Stock from a financial point of
view. Legal counsel reviewed the final forms of Merger Agreement and Stock
Option Agreements and other documents with the CIPSCO Board. The CIPSCO Board
discussed the advice they had received at the various CIPSCO Board meetings and
the significant potential benefits to shareholders and customers of CIPSCO which
would result from a combination of CIPSCO and UE. After such discussions, the
CIPSCO Board approved the Merger Agreement and the Stock Option Agreements and
authorized their execution. One director of CIPSCO, Mr. John L. Heath, voted
against approval of the Merger Agreement noting that in light of CIPSCO's strong
financial position he was not in favor of the merger. He indicated that if at a
later date it became desirable for CIPSCO to become larger, he would prefer that
CIPSCO pursue a merger involving an entity smaller than itself. Following the
meetings of the UE Board and the CIPSCO Board, the Merger Agreement and the
Stock Option Agreements were executed.
2. Benefits of the Transaction
UE and CIPSCO believe that the Transaction offers the following significant
strategic and financial benefits to each company and to their respective
shareholders, as well as to their employees and customers and the communities in
which they do business:
-- Cost Efficiencies to Help Maintain Competitive Rates--Ameren will be
more effective in meeting the challenges of the increasingly
competitive environment in the utility industry than either UE or
CIPSCO standing alone. The Transaction will create the opportunity for
strategic, financial and operational benefits for customers in the
form of lower rates over the long term and for shareholders in the
form of greater financial strength and financial flexibility.
-- Integration of Corporate and Administrative Functions--Ameren will be
able to consolidate certain corporate and administrative functions of
UE and CIPSCO, thereby eliminating duplicative positions, reducing
other non-labor corporate and administrative expenses and limiting or
avoiding expenditures for administrative programs and information
systems. A joint transition task force has examined the manner in
which to best organize and manage the businesses of Ameren and
identify duplicative positions in the corporate and administrative
areas. It is anticipated that, as a result of combining staff and
other functions, Ameren will have somewhat fewer employees within
several
24
<PAGE>
years than UE and CIPSCO currently have in the aggregate. UE and
CIPSCO are committed to achieve cost savings in the area of personnel
reductions through attrition, strictly controlled hiring, and
reassignment and retraining. In addition, some savings in areas such
as insurance and regulatory costs and legal, audit and consulting fees
should be realized.
-- Reduced Operating Costs--The combination should result in decreased
electric production costs through the joint dispatch of the systems.
Natural gas supply savings through combined purchasing are also
anticipated.
-- Purchasing Economies--The combination of the two companies should
result in greater purchasing power for items such as materials,
supplies and contract services.
-- Increased Marketing Opportunities--The combined companies will have
enhanced opportunities for marketing in the wholesale and interchange
markets. The combined companies will have electric interconnections
with 28 other utility systems, enhancing opportunities to make sales
transactions with these systems and others.
-- More Diverse Service Territory--The combined service territories of UE
and CIPS will be larger and more diverse than either of the service
territories of UE or CIPS as independent entities. This increased
geographical diversity will reduce the exposure to changes in economic
or competitive conditions in any given sector of the combined service
territory.
-- Expanded Management Resources--In combination, UE and CIPSCO will be
able to draw on a larger and more diverse mid- and senior-level
management pool to lead Ameren forward in an increasingly competitive
environment for the delivery of energy and should be better able to
attract and retain the most qualified employees. The employees of
Ameren should also benefit from new opportunities in the expanded
organization.
-- Community Involvement--Ameren will continue to play a leadership role
in the economic development efforts of the communities UE and CIPS now
serve. The philanthropic and volunteer programs currently maintained
by the two companies will be continued.
UE and CIPSCO believe that synergies from the Transaction will generate
substantial cost savings to Ameren, which would not be available absent the
Transaction. Estimates by the managements of UE and CIPSCO indicate that the
Transaction could result in net cost savings (that is, after taking into account
the costs incurred to achieve such savings) of approximately $686 million during
the 10-year period following the Transaction./2/
- ----------------
/2/ The savings referred to herein are the most current estimates and reflect
further
(continued...)
25
<PAGE>
Approximately 35% of these savings are expected to be achieved through personnel
reductions involving approximately 320 positions. Other potentially significant
costs savings are reduced corporate and administrative programs (31% of total
potential savings), reduced electric production costs and lower gas supply costs
(18%), and purchasing economies for materials, supplies and contract services
(11%). Achieved savings in costs are expected to inure to the benefit of both
shareholders and customers. The treatment of the benefits and cost savings will
depend on the results of regulatory proceedings in the jurisdictions in which UE
and CIPSCO operate their businesses.
3. Merger Agreement
The Merger Agreement provides for CIPSCO to be merged with and into Ameren
and Arch Merger to be merged with and into UE. The Merger Agreement is
incorporated by reference as Exhibit B-1.
a. Consideration
Under the terms of the Merger Agreement, upon consummation of the
Transaction:
- each issued and outstanding share of UE Common Stock/3/ will be
converted into the right to receive one share of Ameren Common Stock;
- each issued and outstanding share of CIPSCO Common Stock/4/ will be
converted into the right to receive 1.03 shares of Ameren Common
Stock;
- each share of Arch Merger Common Stock issued and outstanding prior to
the Transaction will be converted into one share of UE Common Stock;
and
- all shares of capital stock of Ameren issued and outstanding
immediately prior to the Transaction will be cancelled.
The outstanding shares of preferred stock of UE and CIPS will not be affected.
Based on the capitalization of CIPSCO and UE on June 30, 1996, a UE Ratio of
1.00 and a CIPSCO Ratio of 1.03, the shareholders of CIPSCO and UE would own
securities representing approximately 25.6% and 74.4%, respectively, of the
outstanding voting power of Ameren.
- ----------------
/2/ (...continued)
study and refinement from the estimates made at the time the Mergers were
approved by the UE and CIPSCO Boards of Directors.
/3/ Other than treasury and certain other shares which will be cancelled, and
shares held by holders who dissent in compliance with Missouri law.
/4/ Other than treasury and certain other shares which will be cancelled, but
including shares held by holders who dissent in compliance with
Illinois law.
26
<PAGE>
b. Other Terms
The Transaction is subject to customary closing conditions, including the
receipt of the requisite shareholder approvals of CIPSCO and UE (which have been
obtained) and all necessary governmental approvals (MPSC, ICC, FERC and NRC, in
addition to the approval of the Commission under the Act).
c. Management Following the Mergers
The Merger Agreement contains certain covenants relating to the conduct of
business by the parties pending the consummation of the Transaction. Generally,
the parties must carry on their businesses in the ordinary course consistent
with past practice, may not increase common stock dividends beyond specified
levels, and may not issue capital stock except as specified. The Merger
Agreement also contains restrictions on, among other things, charter and bylaw
amendments, capital expenditures, acquisitions, dispositions, incurrence of
indebtedness, certain increases in employee compensation and benefits, and
affiliate transactions.
The Merger Agreement provides that, after the effectiveness of the
Transaction, Ameren's principal corporate office will remain in St. Louis,
Missouri. Ameren's board of directors will consist of a total of 15 directors,
10 of whom will be designated by UE and five of whom will be designated by
CIPSCO. Charles W. Mueller, the current Chief Executive Officer and President of
UE, will be entitled to serve as Chairman, President and Chief Executive Officer
of Ameren. Clifford L. Greenwalt, the current President and Chief Executive
Officer of CIPSCO and Chief Executive Officer and President of CIPS, will be
entitled to serve as Vice Chairman of the Board of Ameren.
The Transaction is expected to be tax-free to UE and CIPSCO shareholders
(except as to dissenters and fractional shares) under the Internal Revenue Code
of 1986, as amended (the "Code"). CIPSCO and UE believe that the Transaction
will be treated as a "pooling of interests" for accounting purposes.
4. Related Agreements
In connection with the Merger Agreement, CIPSCO and UE also entered into
the reciprocal Stock Option Agreements (the "Stock Option Agreements" which are
incorporated as Exhibits B-2 and B-3 hereto) giving each company the right to
acquire shares of the other's common stock under specified circumstances. The
Stock Option Agreements provide that no option may be exercised until all
necessary regulatory approvals (including any required approval of the
Commission under the Act) have been obtained for the acquisition of shares
pursuant to such option.
D. Dividend Reinvestment Plan and Employee Benefits Plans
Ameren proposes to issue and/or acquire in open market transactions, from
time to time during the first five years after the date of the Order issued by
the Commission herein, up to 19 million shares of Ameren Common Stock under
Ameren's proposed dividend
27
<PAGE>
reinvestment plan and certain employee benefit plans described below that will
use Ameren Common Stock (collectively, the "Ameren Plans").
1. Sources of Common Stock and Use of Proceeds
Any shares of Ameren Common Stock used to fund the Ameren Plans may be, at
the discretion of Ameren, authorized but unissued shares, treasury shares or
shares purchased on the open market by an independent plan administrator or
agent. As of the date of this Application/Declaration, shares are being
purchased in the open market for the existing plans of UE and CIPSCO as
described below. The decision as to whether shares are to be purchased directly
from Ameren, or in the open market or in privately negotiated transactions, will
be based on Ameren's need for common equity and any other factors considered by
Ameren to be relevant. Any determination by Ameren to alter the manner in which
shares will be purchased for the Ameren Plans, and implementation of any such
change, will comply with applicable law and Commission rules, regulations and
interpretations under the Act then in effect.
Net proceeds from new issue or treasury shares of Ameren Common Stock
received by Ameren will be added to Ameren's general funds to be available for
general corporate purposes. Ameren will not receive any proceeds from shares
acquired in the open market or in privately negotiated transactions.
Ameren will not use any proceeds from any new issue or treasury shares to
acquire the securities of or any interest in any exempt wholesale generator
("EWG") or foreign utility companies (as those terms are defined in Sections
32(e) and 33(a) of the Act, as amended by the Energy Policy Act of 1992), until
such time as such use shall be approved by regulation or order of the
Commission, to the extent such approval is required under the Act.
2. Dividend Reinvestment Plan
UE currently has in place the DRPlus, a dividend reinvestment and stock
purchase plan (the "UE Plan") and CIPSCO has in place the CIPSCO Automatic
Dividend Reinvestment and Stock Purchase Plan (the "CIPSCO Plan"). Upon
completion of the Mergers, both the UE Plan and the CIPSCO Plan will cease and
participants therein will become participants in a newly formed Ameren dividend
reinvestment and stock purchase plan, which is referred to below as the "Ameren
DRIP." Set forth below is a description of the principal terms of the Ameren
DRIP.
All holders of record of shares of (i) Ameren Common Stock or (ii) any UE
Preferred Stock or CIPS Preferred Stock (collectively, the "Preferred Stock,"
and together with Ameren Common Stock, the "Eligible Securities") may
participate in the Ameren DRIP. The Ameren DRIP will also permit other investors
who are not shareholders of any of these companies and may permit beneficial
owners of the companies' stock held by brokers and other custodial institutions
of such brokers and other custodial institutions, provided they have established
procedures which permit their customers to participate, to make an original
purchase of Ameren Common Stock, whereupon they will become
28
<PAGE>
shareholders of Ameren and will be entitled to participate in the Ameren DRIP
like other shareholders. The purpose of the Ameren DRIP will be, among other
things, to provide holders of Eligible Securities and other investors with a
simple, convenient and economical method of purchasing shares of Ameren Common
Stock through reinvestment of dividends and cash investments. The Ameren DRIP is
designed to encourage and facilitate broader ownership of Ameren Common Stock.
Full investment of funds will be possible under the Ameren DRIP, subject to any
minimum and maximum purchase limits imposed under the Ameren DRIP, because the
Ameren DRIP will permit fractional as well as whole shares to be credited to a
participant's account. The Ameren DRIP will also provide Ameren with a means to
increase ownership by small, long-term investors and, to the extent original
issue shares are used, to raise equity capital.
A full statement of the provisions of the Ameren DRIP is included in
Ameren's Post-Effective Amendment on Form S-3 to the Form S-4 Registration
Statement (incorporated as Exhibit C-3 hereto).
3. Employee Benefit Plans
a. Long Term Incentive Plan
Pursuant to the Merger Agreement, it was agreed that Ameren would adopt a
stock compensation plan ("Ameren LTIP") to replace the UE Long-Term Incentive
Plan of 1995 (the "LTIP") subject to approval by shareholders.
The purpose of the Ameren LTIP is to enable Ameren and its subsidiaries and
other affiliates (as defined in the Ameren LTIP) to attract, retain and motivate
officers and employees and to provide Ameren and its affiliates with the ability
to provide incentives directly linked to the profitability of Ameren's
businesses, increases in shareholder value and the enhancement of customer
service.
The Ameren LTIP will provide for the grant of stock options, stock
appreciation rights, restricted stock, performance units and such other awards
based upon Ameren Common Stock as Ameren's Board may determine, subject to
shareholder approval. Ameren will reserve four million shares for issuance
pursuant to the Ameren LTIP.
The Ameren LTIP will be designed to comply with Code limits on the ability
of a public company to claim tax deductions for compensation paid to certain
highly compensated executives. Section 162(m) of the Code generally denies a
federal income tax deduction for annual compensation exceeding $1,000,000 paid
to the Chief Executive Officer and the four other most highly compensated
officers of a public company. Certain types of compensation, including some
performance-based compensation, are generally excluded from this deduction
limit. While Ameren believes compensation payable pursuant to the Ameren LTIP
will be deductible for federal income tax purposes under most circumstances,
compensation not qualified under Section 162(m) of the Code may be payable under
certain circumstances such as death, disability and change in control (all as
defined in the Ameren LTIP).
29
<PAGE>
A full statement of the provisions of the Ameren LTIP is included in
Ameren's Form S-8 (incorporated by reference as Exhibit C-4 hereto).
b. Savings Plans
UE and CIPSCO currently have five plans which involve the issuance of the
companies' common stock to participating employees as follows: the UE Savings
Investment Plan, CIPSCO Employee Long-Term Savings Plan, CIPSCO Employee Long-
Term Savings Plan - IUOE No. 148, CIPSCO Employee Long-Term Savings Plan - IBEW
No. 702 and CIPSCO Employee Stock Ownership Plan.
It is anticipated that for an undetermined period of time after the
consummation of the Transaction all such UE and CIPSCO plans will be maintained
on substantially the same terms, except that shares of Ameren common stock will
be used instead of UE and CIPSCO common stock. Ameren will seek authorization
from the Commission as required in connection with Ameren shares to be issued
under the UE and CIPSCO plans.
At some point subsequent to the consummation of the Transaction, it is
intended that certain of the stock-based plans of Ameren (the "Ameren Stock-
Based Benefit Plans") will replace the UE and CIPSCO benefit plans with a
similar name. Again, Ameren will seek authorization from the Commission as
required in connection with Ameren shares to be issued under the Ameren Stock-
Based Benefit Plans.
A description of the existing plans is included in Exhibit C-5 hereto.
4. Solicitation of Proxies
To the extent deemed necessary or desirable in order to comply with Rule
16b-3 under the Securities Exchange Act of 1934, to comply with Section 162(m)
of the Code or for other purposes, Ameren will solicit proxies from the holders
of its Common Stock to approve the adoption or amendment to the Ameren LTIP or
other benefit plans described above. The description of the nature of that
solicitation and the expenses (to the extent in excess of that permitted by Rule
65(b)) to be incurred in connection with any such solicitation will be provided
by amendment hereto.
Item 2. Fees, Commissions and Expenses
The fees, commissions and expenses paid and to be paid or incurred,
directly or indirectly, in connection with the Transaction, including the
solicitation of proxies, registration of securities of Ameren under the
Securities Act of 1933, and other related matters, are estimated as follows:
<TABLE>
<S> <C>
Commission filing fee for the
Registration Statement on Form S-4......... $ 1,842,000
Accountants' fees............................ 170,000
Legal fees and expenses relating to the Act.. 350,000
</TABLE>
30
<PAGE>
<TABLE>
<S> <C>
Other legal fees and expenses................ 3,825,000
Shareholder communication and proxy 1,064,000
solicitation...............................
NYSE listing fee............................. 200,000
Exchanging, printing, and engraving of
stock certificates......................... 750,000
Investment bankers' fees and expenses........ 11,100,000
(Goldman Sachs: $5,700,000)
(Morgan Stanley: $5,400,000)
Consulting fees related to human
resource issues, public relations,
regulatory support, and other
matters relating to the
Transaction................................ 600,000
Other expenses of the transaction
(excluding merger transition costs)
and miscellaneous.......................... 1,933,000
-----------
TOTAL $21,834,000
</TABLE>
Item 3. Applicable Statutory Provisions
The following sections of the Act and the Commission's rules thereunder are
or may be directly or indirectly applicable to the Transaction:
<TABLE>
<CAPTION>
TRANSACTIONS TO WHICH SECTION OR
SECTIONS OF THE ACT RULE IS OR MAY BE APPLICABLE
- ------------------- --------------------------------
<S> <C>
4,5 Registration of Ameren as a holding company following
consummation of the Transaction.
6(a), 7 Issuance of Ameren Common Stock in the Transaction in
exchange for shares of CIPSCO Common Stock and UE
Common Stock; issuance of Ameren Common Stock under
Ameren Plans; issuance of stock of Ameren Services to
Ameren; approval of all outstanding intra-system debt,
including guaranties and support agreements.
</TABLE>
31
<PAGE>
<TABLE>
<CAPTION>
TRANSACTIONS TO WHICH SECTION OR
SECTIONS OF THE ACT RULE IS OR MAY BE APPLICABLE
- ------------------- ---------------------------------
<S> <C>
9(a)(1), 10 Acquisitions of Ameren Common Stock in open-market
transactions under Ameren Plans; acquisition by Ameren
of stock of Ameren Services and indirect acquisition by
Ameren of nonutility subsidiary of UE; acquisition by
Ameren of CIPSCO Investment; indirect acquisition by
Ameren of 60% of the stock of EEI.
9(a)(2), 10(a), Acquisition by Ameren of CIPS Common Stock and UE
(b), (c) and (f) Common Stock and indirect acquisition by Ameren of 60%
of the stock of EEI.
8, 9(c)(3), 11(b), 21 Retention by Ameren of gas operations and retention or
acquisition of nonutility businesses of UE, UEDC, CIPS
and CIPSCO Investment.
12 Transfer of Transferred Utility Facilities from UE to
CIPS; approval of all outstanding intra-system debt,
including guaranties and support agreements; approval
of proxy solicitation for shareholder approval of
Ameren plans.
13 Approval of the General Services Agreement and services
provided to utility and nonutility affiliates
thereunder by Ameren Services; incidental services
between UE and CIPS.
</TABLE>
<TABLE>
<CAPTION>
TRANSACTIONS TO WHICH SECTION OR
RULES RULE IS OR MAY BE APPLICABLE
- ----- --------------------------------
<S> <C>
42 Open-market purchases of Ameren Common Stock pursuant
to Ameren Plans.
43 Transfer of Transferred Utility Facilities from UE to
CIPS.
62 Solicitation of proxies for approval by holders of
Ameren Common Stock for adoption or amendment of Ameren
Plans.
65 Proxy solicitation expenditures.
</TABLE>
32
<PAGE>
TRANSACTIONS TO WHICH SECTION OR
RULES RULE IS OR MAY BE APPLICABLE
- ----- --------------------------------
80-92 Reimbursements between and among Ameren, UE, CIPS and
CIPSCO Investment and other system companies under the
General Services Agreement.
83(a) Exemption from at-cost standards with respect to
certain services.
87(a)(3) Incidental Services between and among UE, CIPS and
among Ameren system companies.
88 Approval of Ameren Services as a subsidiary service
company.
93, 94 Accounts, records and annual reports by Ameren
Services.
To the extent that other sections of the Act or the Commission's rules
thereunder are deemed applicable to the Transaction and the other matters
described herein, such sections and rules should be considered to be set forth
in this Item 3.
A. Analysis of Transaction
Section 9(a)(2) makes it unlawful, without approval of the Commission under
Section 10, "for any person . . . to acquire, directly or indirectly, any
security of any public utility company, if such person is an affiliate . . . of
such company and of any other public utility or holding company, or will by
virtue of such acquisition become such an affiliate." Under the definition set
forth in Section 2(a)(11)(A), an "affiliate" of a specified company means "any
person that directly or indirectly owns, controls, or holds with power to vote,
5 per centum or more of the outstanding voting securities of such specified
company", and "any company 5 per centum or more of whose outstanding voting
securities are owned, controlled, or held with power to vote, directly or
indirectly, by such specified company."
UE, CIPS and EEI are public utility companies as defined in Section 2(a)(5)
of the Act. Because Ameren will acquire, directly or indirectly, more than five
percent of the voting securities of each of CIPS, UE and EEI as a result of the
Transaction, and because UE, CIPS and EEI will become "affiliates" of Ameren as
a result of the Transaction, Ameren must obtain the approval of the Commission
for the Transaction under Sections 9(a)(2) and 10 of the Act. The statutory
standards to be considered by the Commission in evaluating the proposed
Transaction are set forth in Sections 10(b), 10(c) and 10(f) of the Act.
As set forth more fully below, the Transaction complies with all of the
applicable provisions of Section 10 of the Act and should be approved by the
Commission:
33
<PAGE>
- the consideration to be paid in the Transaction is fair and
reasonable;
- the Transaction will not create detrimental interlocking relations or
concentration of control;
- the Transaction will not result in an unduly complicated capital
structure for the Ameren system;
- the Transaction will not be detrimental to the public interest or the
interest of investors or consumers or the proper functioning of the
Ameren system;
- the Transaction is consistent with Sections 8 and 11 of the Act;
- the Transaction tends toward the economical and efficient development
of an integrated public utility system; and
- the Transaction will comply with all applicable state laws.
Furthermore, the Transaction also provides an opportunity for the
Commission to follow certain of the interpretive recommendations made by the
Division of Investment Management (the "Division") in the report approved by the
Commission for issuance by the Division on June 20, 1995 entitled "The
Regulation of Public Utility Holding Companies" (the "1995 Report"). While the
Transaction and the requests contained in this Application/Declaration are well
within the precedent of transactions approved by the Commission as consistent
with the Act prior to the 1995 Report and thus could be approved without any
reference to the 1995 Report, a number of the recommendations contained therein
serve to strengthen the analysis presented herein and would facilitate the
creation of a new holding company better able to compete in the rapidly evolving
utility industry. The Division's overall recommendation that the Commission "act
administratively to modernize and simplify holding company regulation . . . and
minimize regulatory overlap, while protecting the interests of consumers and
investors,"/5/ should be used in reviewing this Application/Declaration since,
as demonstrated herein, the Transaction would benefit both consumers and
shareholders of Ameren and since the other federal and state regulatory
authorities with jurisdiction over this Transaction will have approved it as in
the public interest. In addition, although discussed in more detail in each
applicable item below, the specific recommendations of the Division with regard
to financing transactions,/6/ utility ownership/7/ and diversification/8/ are
applicable to this Transaction.
- ----------------
/5/ Letter of the Division of Investment Management to the Securities and
Exchange Commission, 1995 Report at xii-xiii.
/6/ E.g., the reduced regulatory burdens associated with routine financings.
1995 Report at 50.
/7/ E.g., the Commission should apply a more flexible interpretation of the
integration requirements under the Act; the Commission's analysis should
focus on whether the resulting system will be subject to effective
regulation; the Commission should liberalize its interpretation of the
"A-B-C" clauses and permit combination systems where the affected states
agree, and the Commission should "watchfully defer" to the work of other
regulators. 1995 Report at 71-77.
34
<PAGE>
1. Section 10(b)
Section 10(b) provides that, if the requirements of Section 10(f) are
satisfied, the Commission shall approve an acquisition under Section 9(a)
unless:
(1) such acquisition will tend towards interlocking relations or the
concentration of control of public utility companies, of a kind or to an
extent detrimental to the public interest or the interest of investors or
consumers;
(2) in case of the acquisition of securities or utility assets, the
consideration, including all fees, commissions, and other remuneration, to
whomsoever 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.
a. Section 10(b)(1)
i. Interlocking Relationships
By its nature, any merger results in new links between theretofore
unrelated companies. However, these links are not the types of interlocking
relationships targeted by Section 10(b)(1), which was primarily aimed at
preventing business combinations unrelated to operating synergies. See Section
1(a)(4) and (5) of the Act.
The Merger Agreement provides for the Board of Directors of Ameren to be
composed of members drawn from the Boards of Directors of both UE and CIPSCO.
Ten of the Ameren directors will be designated by UE and five by CIPSCO./9/ Two
representatives each of UE and CIPS will continue to serve as members of the EEI
Board of Directors. In addition, UE, CIPS and CIPSCO Investment will be
parties, along with
- ----------------
/8/(...continued)
/8/ E.g., the Commission should promulgate rules to reduce the regulatory
burdens associated with energy-related diversification, and the Commission
should adopt a more flexible approach in considering all other requests to
enter into diversified activities. 1995 Report at 88-90.
/9/ Ameren acknowledges the requirements of Section 17(c) of the Act and Rule
70 thereunder with respect to limitations upon directors and officers of
registered holding companies and subsidiary companies thereof having
affiliations with commercial banking institutions and investment bankers,
and undertakes that, upon completion of the Mergers, it will be in
compliance with the applicable provisions thereof.
35
<PAGE>
Ameren, to the General Services Agreement with Ameren Services. These actions
are necessary to initially create, and to integrate UE and CIPSCO fully into,
the Ameren system and will therefore be in the public interest and the interest
of investors and consumers. Forging such relations is beneficial to the
protected interests under the Act, and thus is not prohibited by Section
10(b)(1). The benefits of the Transaction described herein that will accrue to
investors, customers and the public make clear that the interlocking
relationships will not be detrimental. In CINergy Corp., 57 SEC Docket 2353
(Oct. 21, 1994), which involved a formation of a new, registered holding company
system in a manner substantially similar to the present Transaction, the
Commission made no findings of adverse interlocking relations or concentration
of control under Section 10(b)(1). Likewise, the facts of this case require no
adverse finding.
ii. Concentration of Control
Section 10(b)(1) is intended to prevent utility acquisitions that would
result in "huge, complex and irrational holding company systems at which the Act
was primarily aimed." AMERICAN ELEC. POWER CO., 46 SEC 1299, 1307 (July 21,
1978). In applying Section 10(b)(1) to utility acquisitions, the Commission
must determine whether the acquisition will create "the type of structures and
combinations at which the Act was specifically directed." VERMONT YANKEE
NUCLEAR CORP., 43 SEC 693, 700 (Feb. 6, 1968).
The integration of UE and CIPS under Ameren will not create a "huge,
complex and irrational system," but rather will afford the opportunity to
achieve economies of scale and efficiencies which are expected to benefit
investors and consumers.
Size: If approved, the Ameren system will serve approximately 1.4 million
electric customers and 285,403 gas customers in portions of Missouri and
Illinois. As of June 30, 1996: (1) the combined assets of UE and CIPSCO
totaled approximately $8.6 billion; (2) 12-month combined operating revenues
totaled approximately $3.0 billion; and (3) combined, owned generating capacity
totaled 10,761 MW.
By comparison, the Commission has approved a number of acquisitions
involving operating utilities with combined assets exceeding or approximating
those of Ameren. SEE, E.G., CINERGY CORP., 57 SEC Docket 2353 (Oct. 21, 1994)
(combination of Cincinnati Gas & Electric and PSI Resources; combined assets at
time of acquisition of approximately $7.9 billion); ENTERGY CORP., 55 SEC Docket
2035 (Dec. 17, 1993) (acquisition of Gulf States Utilities; combined assets at
time of acquisition in excess of $21 billion); NORTHEAST UTILITIES, 47 SEC
Docket 1270 (Dec. 21, 1990) (acquisition of Public Service of New Hampshire;
combined assets at time of acquisition of approximately $9 billion); CENTERIOR
ENERGY CORP., 35 SEC Docket 769 (Apr. 29, 1986) (combination of Cleveland
Electric Illuminating and Toledo Edison; combined assets at time of acquisition
of approximately $9.1 billion); AMERICAN ELEC. POWER CO., 46 SEC 1299 (July 21,
1978) (acquisition of Columbus and Southern Ohio Electric; combined assets at
time of acquisition of close to $9 billion)./10/
- ----------------------
/10/ These numbers are unadjusted for inflation. The AEP-Columbus number in
(continued...)
36
<PAGE>
As the following table demonstrates, six of the current registered electric
utility holding company systems--Southern, Entergy, CSW, Northeast, GPU and
AEP--will be larger than Ameren in terms of assets, operating revenues,
customers and/or sales of electricity:/11/
<TABLE>
<CAPTION>
Total Operating Electric Sales in
System Assets Revenues Customers kWh
Total ($Millions) ($Millions) (Thousands) (Millions)
<S> <C> <C> <C> <C>
Southern 27,042 8,297 3,507 139,991
Entergy 22,613 5,798 2,360 97,452
AEP 15,713 5,505 2,773 114,080
CSW 10,909 3,623 1,661 57,334
Northeast 10,585 3,643 1,680 40,159
GPU 9,870 3,800 1,976 45,753
UE 6,865 2,111 1,132 34,670
CIPSCO 1,832 880 319 13,988
- ---------- ------ ----- ----- ------
Ameren 8,697 2,991 1,451 48,658
</TABLE>
In the region where UE and CIPS are located, other existing or proposed
electric utility holding companies are larger than, or approximately the same
size as, the proposed Ameren system. Unicom Corp., the holding company of
Commonwealth Edison Co. and Unicom Enterprises, Inc., with assets of $23.247
billion, operating revenues of $6.910 billion, 3.4 million customers and 91.353
billion kWh sales, is substantially larger than the proposed Ameren combination.
CINergy, the combination of Cincinnati Gas & Electric and PSI Resources, is
comparable in size to Ameren; CINergy has total assets of $7.808 billion,
operating revenues of $2.84 billion, 1,321,000 customers, and kWh sales of
49.056 billion. Primergy, the proposed combination of Wisconsin Energy Corp. and
Northern States Power Co., will be larger than Ameren, since the proposed
Primergy would have assets of $10.649 billion, operating revenues of $4.339
billion, 2.352 million customers, and 68.284 billion in kWh sales. Ameren will
be somewhat larger than Interstate Energy Corp., the new company proposed to
result from the merger of Wisconsin Power & Light Co., IES Industries Inc. and
Interstate Power Co. The new Interstate is to have assets of $4 billion,
1,224,000 customers and revenues of $1.91 billion. In addition, the proposed
acquisition of Public
- ----------------
/10/(...continued)
particular would be considerably higher in current dollars.
/11/ Amounts for companies other than Ameren, UE and CIPSCO are as of December
31, 1995, or for the year ended December 31, 1995. Amounts for UE and
CIPSCO are at and for the 12 months ended June 30, 1996.
37
<PAGE>
Service Company of Colorado and Southwestern Public Service Company by New
Century Energies, Inc., would result in a system with assets of $6 billion,
operating revenues of about $2.8 billion and 1.5 million electric customers.
Ameren will be a mid-size registered holding company, and its operations
would not exceed the economies of scale of current electric generation and
transmission technology or provide undue power or control to Ameren in the
region in which it will provide service.
Efficiencies and economies: The Commission in recent years has rejected a
mechanical size analysis under Section 10(b)(1) in favor of assessing the
efficiencies and economies that can be achieved through the integration and
coordination of utility operations. As the Commission stated in American
Electric Power Co., although the framers of the Act were concerned about "the
evils of bigness,"
they were also aware that the combination of isolated
local utilities into an integrated system afforded
opportunities for economies of scale, the elimination of
duplicate facilities and activities, the sharing of
production capacity and reserves and generally more
efficient operations . . . [and] [t]hey wished to preserve
these opportunities. . . .
46 SEC at 1309.
More recent pronouncements of the Commission confirm that size is not
determinative. Thus, in CENTERIOR ENERGY CORP., 35 SEC Docket 769, 771 (Apr. 29,
1986), the Commission stated flatly 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 ENTERGY CORP., 55 SEC
Docket 2035 (Dec. 17, 1993). In addition, in the 1995 Report, the Division
recommended that the Commission approach its analysis on merger and acquisition
transactions in a flexible manner with emphasis on whether the transaction
creates an entity subject to effective regulation and is beneficial for
shareholders and customers as opposed to focusing on rigid, mechanical
tests./12/
By virtue of the Transaction, Ameren will be in a position 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 AMERICAN ELECTRIC
POWER CO. Among other things, the Transaction is expected to yield cost
efficiencies to help maintain competitive rates, integrated corporate and
administrative functions, reduced operating costs, purchasing economies,
increased marketing opportunities, and expanded management resources. These
expected economies and efficiencies from the combined utility operations are
described in greater detail below and are projected to result in savings of
approximately $686 million over the first ten years alone.
- ----------------
/12/ 1995 Report at 73-74.
38
<PAGE>
Competitive Effects: Section 10(b)(1) also requires the Commission to
consider possible anticompetitive effects of a proposed combination. See Entergy
Corp., 55 SEC Docket at 2041 (citing MUNICIPAL ELEC. ASS'N OF MASSACHUSETTS V.
SEC, 413 F.2d 1052, 1056-1058 (D.C. Cir. 1969)). As the Commission noted in
Northeast Utilities, 47 SEC Docket at 1282, the "antitrust ramifications of an
acquisition must be considered in light of the fact that the public utilities
are regulated monopolies and that federal and state administrative agencies
regulate the rates charged to customers." Late in 1996 or early in 1997, CIPSCO
and UE will file Notification and Report Forms with the Department of Justice
and the Federal Trade Commission pursuant to the HSR Act describing the effects
of the Transaction on competition in the relevant market.
In addition, the competitive impact of the Transaction is to be fully
considered by the FERC. UE and CIPS filed their joint application for FERC
approval of the Transaction on December 22, 1995. A detailed explanation of the
reasons why the Transaction will not create or increase market power in any
relevant market is set forth in the prepared testimony of Rodney W. Frame (the
"Testimony"), filed with the FERC on behalf of UE and CIPS, a copy of which is
filed as Exhibit D-1.2. The application filed by UE and CIPS with the FERC is
filed at Exhibit D-1.1. The Commission may appropriately rely upon the FERC with
respect to such matters. ENTERGY CORP., 55 SEC Docket at 2042 (citing CITY OF
HOLYOKE GAS & ELEC. DEP'T V. SEC, 972 F.2d 358, 363-64 (D.C. Cir. 1992) (quoting
WISCONSIN'S ENVIRONMENTAL DECADE, INC. V. SEC, 882 F.2d 523, 527 (D.C. Cir.
1989)). This is consistent with the 1995 Report's recommendation that the
Commission "watchfully defer" to the work of other regulators. 1995 Report at
77.
As detailed in the Testimony, the Transaction will not create or increase
market power in any relevant market, nor facilitate its exercise through
collusion. Concurrently with their application before the FERC, UE and CIPS
filed consolidated (one-system) open access transmission tariffs. Because these
tariffs would make available all of the direct interconnections of both UE and
CIPS as receipt and delivery points, they have the potential to expand wholesale
bulk power trading opportunities in the region. While the wholesale bulk power
markets within which UE and CIPS operate already are competitive and this will
not be changed as a result of the Mergers, the filing by the two firms of these
single-system tariffs should eliminate any residual concern that market power
problems might arise as a result of the Mergers. No additional measures are
required to mitigate perceived concerns about market power resulting from the
Mergers or from the combination of the transmission systems owned by UE and
CIPS. In support of this conclusion, the Testimony explains that the Transaction
will not create or increase market power in specific relevant wholesale bulk
power markets, i.e., short term capacity, long term capacity and nonfirm energy.
Both UE and CIPS actively seek to market short term capacity, and so the Mergers
necessarily will reduce by one the number of independent sellers. However, many
other independent participants will remain. Moreover, UE has little or no
uncommitted capacity; thus, its ability to participate as a seller in short term
capacity markets essentially is limited to situations in which it resells the
capacity which it simultaneously buys from others, that is, where it acts as a
marketer. Because entry is relatively easy for those seeking only to remarket
capacity purchased from others, the elimination of one such marketer does not
present competitive concerns. As concerns short term capacity, the merged firm's
share of uncommitted capacity in all first tier markets is less than the 20
percent level, which FERC
39
<PAGE>
in the past has used as a threshold to demarcate situations where market power
problems might be present. As concerns the possible exercise of buyer market
power in short term capacity markets, a stand-alone CIPS contemplates no new
resource additions through at least 2016. This makes it very unlikely that a
stand-alone CIPS would be seeking to purchase capacity during this time period
other than for remarketing purposes. If a stand-alone CIPS is not likely to be a
purchaser of short term capacity, the Mergers cannot reasonably be said to
increase buyer market power in short term capacity markets.
With respect to long term generating capacity, it is unlikely as a general
matter that any one firm will possess market power. This is evidenced by the
amount of nonutility generation that has come on line in recent years. Moreover,
UE and CIPS' filing of consolidated or one-system open access transmission
tariffs should make entry by new nonutility generators easier than it would have
been without the Transaction.
For these reasons, the Transaction will not "tend toward interlocking
relations or the concentration of control" of public utility companies, of a
kind or to the extent detrimental to the public interest or the interest of
investors or customers within the meaning of Section 10(b)(1).
b. Section 10(b)(2)--Fairness of Consideration
Section 10(b)(2) requires the Commission to determine whether the
consideration to be given by Ameren to the holders of UE Common Stock and CIPSCO
Common Stock in connection with the Transaction is reasonable and whether it
bears a fair relation to the sums invested in and the earning capacity of the
utility assets underlying the securities being acquired./13/ For the reasons set
forth below, the requirements of Section 10(b)(2) are satisfied here.
i. Reasonableness of Consideration
Ameren believes the consideration involved in the Transaction is reasonable
for the following reasons:
First, the Transaction is a pure stock-for-stock exchange and qualifies for
treatment as a pooling of interests. As set forth more fully above, each share
of UE Common Stock will be converted into the right to receive one share of
Ameren Common Stock, and each share of CIPSCO Common Stock will be converted
into the right to receive 1.03 shares of Ameren Common Stock (collectively, the
"Exchange Ratios"). As a result of this accounting, the Transaction will not
produce any "fictitious or unsound asset values." See Section 1(a)(1) of the
Act.
- ----------------
/13/ In connection with the Transaction, the holders of UE preferred stock and
CIPS preferred stock will not be affected.
40
<PAGE>
Second, the Transaction has been approved by the affected shareholders of
CIPSCO and UE. Approximately 97 percent of the CIPSCO shares voting on the
question approved the Transaction; this figure represents 76 percent of the
outstanding common shares. UE shareholders approved the Transaction with 96
percent of shares voting on the question in favor, or 71 percent of the
outstanding common and preferred shares.
Third, the Exchange Ratios are the product of extensive and vigorous arm's-
length negotiations between CIPSCO and UE. These negotiations were preceded by
weeks of due diligence, analysis and evaluation of the assets, liabilities and
business prospects of each of the respective companies, and extensive arm's-
length bargaining. See Ameren Registration Statement on Form S-4 (Exhibit C-1
hereto). As recognized by the COMMISSION IN OHIO POWER CO., 44 SEC 340, 346
-------------
(June 8, 1970), prices arrived at through arm's-length negotiations are
particularly persuasive evidence that Section 10(b)(2) is satisfied.
Finally, nationally-recognized investment bankers for each of CIPSCO and UE
have reviewed extensive information concerning the companies and analyzed the
Exchange Ratios employing a variety of valuation methodologies, and have opined
that the Exchange Ratios are fair to the respective holders of CIPSCO Common
Stock and UE Common Stock. The investment bankers' analyses and opinions are
described in detail in Ameren's Registration Statement on Form S-4 (Exhibit C-1
hereto). The assistance of independent consultants in setting consideration has
been recognized as evidence that the requirements of Section 10(b)(2) are met.
THE SOUTHERN CO., 40 SEC Docket 350 (Feb. 12, 1988).
In light of these opinions and an analysis of all relevant factors,
including the benefits that may be realized as a result of the Transaction, the
consideration for the Transaction (that is, the respective Exchange Ratios)
bears a fair relation to the sums invested in, and the earning capacity of the
utility assets of, UE and CIPSCO.
ii. Reasonableness of Fees
Ameren believes that the overall fees, commissions and expenses incurred
and to be incurred in connection with the Transaction are reasonable and fair in
light of the size and complexity of the Transaction relative to other similar
transactions and in light of the anticipated benefits of the Transaction to the
public, investors and consumers; that they are consistent with recent precedent;
and that they meet the standards of Section 10(b)(2).
As set forth in Item 2 of this Application, UE and CIPSCO together expect
to incur a combined total of approximately $22 million in fees, commissions and
expenses in connection with the Transaction. By contrast, the parties to the
CINergy Corp. merger incurred fees and expenses of $47 million, Northeast
Utilities alone incurred $46.5 million in fees and expenses in connection with
its acquisition of Public Service of New Hampshire, and Entergy alone incurred
$38 million in fees in connection with its acquisition of Gulf States
Utilities--each of which amounts were approved as reasonable by the Commission.
SEE CINERGY CORP., 57 SEC Docket 2353 (Oct. 21, 1994); NORTHEAST UTILITIES, 51
SEC Docket 934 (June 3, 1992); ENTERGY CORP., 55 SEC Docket 2035 (Dec. 17,
1993). The parties to the proposed Primergy transaction expect to incur about
$30 million in fees.
41
<PAGE>
With respect to financial advisory fees (which are included in the $22
million total), UE and CIPSCO believe that the fees paid to their investment
bankers are fair and reasonable for similar reasons. As noted above, UE and
CIPSCO engaged separate investment banking firms to provide financial advisory
services and to render fairness opinions regarding the consideration to be
received in the Transaction. Pursuant to an engagement letter dated June 23,
1995, UE agreed to pay Goldman Sachs $5.7 million plus expenses for serving as
financial advisor and agreed to indemnify Goldman Sachs and certain related
persons against certain liabilities in connection with its engagement.
Pursuant to the terms of an engagement letter dated June 30, 1995, CIPSCO
agreed to pay Morgan Stanley $5.4 million for acting as financial advisor in
connection with the Transaction. CIPSCO has also agreed to reimburse Morgan
Stanley for its reasonable out-of-pocket expenses (including, without
limitation, professional fees and disbursements) and to indemnify Morgan Stanley
and certain related persons against certain liabilities arising out of or in
connection with its engagement.
Further information concerning the agreements with investment bankers and
their fees can be found in the Ameren Registration Statement on Form S-4
(Exhibit C-1 hereto).
In the instant case, the aggregate fees to be paid to both companies'
investment bankers in connection with the Transaction--approximately $11.1
million--constitute approximately 0.24% of the companies' combined market
value./14/ These fees are generally in accord with the fees approved by the
Commission in recent cases. In one recent case, the Commission approved
investment banking fees equal to 0.96% of the aggregate value of the
acquisition, THE SOUTHERN CO., 40 SEC Docket 350, 354 (Feb. 12, 1988), or four
times the investment banking fee here on a percentage basis. In CENTERIOR ENERGY
CORP., 35 SEC Docket 769 (Apr. 29, 1986), relating to the affiliation of two
utility companies under a new common holding company, the Commission approved
combined investment banking fees amounting to 0.275% of the combined market
value of the two companies' common stock. In its order approving the acquisition
by Northeast Utilities of Public Service of New Hampshire, the Commission
approved approximately $10.6 million in financial advisory fees for Northeast
alone. NORTHEAST UTILITIES, 51 SEC Docket 934 (June 3, 1992). In CINERGY, the
Commission approved combined investment banking fees of $13.1 million, which
constituted approximately 0.31% of the companies' combined market value. CINergy
Corp., 57 SEC Docket 2353 (Oct. 21, 1994). And in the Entergy-Gulf States
decision, the Commission approved financial advisory fees of $8.3 million by
Entergy to its investment banker. ENTERGY CORP., 55 SEC Docket 2035 (Dec. 17,
1993). The financial advisory fees to be paid by UE and CIPSCO in connection
with the Transaction are significantly smaller on a percentage basis than those
approved in SOUTHERN AND CINERGY, proportionately smaller in dollar amount than
those approved in NORTHEAST UTILITIES, and comparable in dollar amount to those
approved in CINERGY. Moreover, the investment banking fees approved
- -------------
/14/ Based on the number of shares of UE Common Stock and CIPSCO Common Stock
outstanding as of August 11, 1995 and their closing prices on that date of
$35 3/8 and $29 5/8 per share, respectively.
42
<PAGE>
in Northeast Utilities and Entergy represented the fees of only one party to the
transactions in question, whereas the investment banking fees here include those
of both parties.
Finally, the investment banking fees of UE and CIPSCO reflect extensive
arms'-length bargaining between the parties.
c. Section 10(b)(3)--Capital Structure; Not Detrimental to Public
Interest
Section 10(b)(3) requires the Commission to determine whether the
Transaction will unduly complicate Ameren's capital structure or will be
detrimental to the public interest, the interest of investors or consumers or
the proper functioning of Ameren's system. The corporate capital structure of
Ameren after the Transaction will not be unduly complicated and will be
substantially similar to capital structures approved by the Commission in other
orders involving similar transactions. SEE, E.G., CINERGY CORP., 57 SEC Docket
2353 (Oct. 21, 1994); CENTERIOR ENERGY CORP., 35 SEC Docket 769, 771-772 (Apr.
29, 1986); MIDWEST RESOURCES, 47 SEC Docket 252 (Sept. 26, 1990). Ameren's
capital structure will also be similar to the capital structures of existing
registered holding company systems.
In the Transaction, the common shareholders of CIPSCO and UE will receive
Ameren Common Stock. Ameren will own 100% of the common stock of UE and CIPS and
there will be no minority common stock interest remaining in either company.
Each outstanding share of UE and CIPS preferred stock will remain outstanding
without change. The existing debt securities of CIPS and UE will likewise remain
outstanding without change. The only voting securities which will be publicly
held after the transaction will be Ameren Common Stock, CIPS preferred stock and
UE preferred stock.
Each share of UE preferred stock is entitled to one vote per share on all
matters presented to stockholders. Likewise, each share of CIPS preferred stock
is entitled to one vote per share on all matters presented to shareholders. If
the Transaction had been consummated June 30, 1996, the outstanding UE preferred
stock would have represented 3.25% of the total voting power of UE preferred and
common stock, 4.90% of the total capital of UE (including long-term and short-
term debt) and 8.74% of the book equity which comprises common and preferred
stock and retained earnings. At that date, the outstanding CIPS preferred stock
represented 2.29% of the total voting power of CIPS preferred and CIPSCO common
stock, 6.41% of the total capital of CIPSCO (including long-term and short-term
debt) and 10.96% of the book equity comprising CIPSCO common and CIPS preferred
stock and retained earnings. For the twelve months ended June 30, 1996, UE's
combined fixed charges and preferred dividend requirements were covered 4.08
times before provision for taxes and such figure was 4.16 times for CIPSCO. In
addition, due to the obligations imposed by the states in which UE and CIPS
operate and the substantial financial commitment of Ameren in UE and CIPS, there
is virtually no likelihood that either UE's or CIPS' assets or businesses will
be permitted to deteriorate to an extent that would jeopardize the interests of
the preferred stock. The Commission has found previously that the existence of
preferred stock under facts similar to those herein does not violate the
standards of Section 10(b)(3), 10(c)(1) or 11(b)(2) of the Act. ILLINOIS POWER
CO., 44 SEC 140 (Jan. 2, 1970). SEE ALSO CIPSCO INC., 47 SEC Docket 174 (Sept.
18, 1990), NIAGARA
43
<PAGE>
MOHAWK POWER CORP., SEC No-Action Letter (January 24, 1991) and TEXAS UTILITIES
CO., 31 SEC 367 (Apr. 5, 1950).
Ameren will have the ability to issue, subject to the approval of the
Commission, preferred stock, the terms of which, including any voting rights,
may be set by Ameren's Board of Directors as has been authorized by the
Commission with regard to other registered holding companies. SEE, E.G., THE
COLUMBIA GAS SYS., INC., 60 SEC Docket 244 (August 25, 1995) (approving restated
charter, including preferred stock whose terms, including voting rights, can be
established by the board of directors). The only class of voting securities of
Ameren's, CIPSCO Investment's or UE's direct nonutility subsidiaries will be
common stock and, in each case, all issued and outstanding shares of such common
stock will be held by Ameren, CIPSCO Investment or UE, as the case may be.
Set forth below are summaries of the historical capital structures of UE
and CIPSCO as of June 30, 1996 and the pro forma consolidated capital structure
of Ameren (assuming the Transactions had occurred at June 30, 1996):
44
<PAGE>
UE and CIPSCO Historical Capital Structures
(dollars in thousands)
(unaudited)
<TABLE>
<CAPTION>
CIPSCO
(consolidated)
<S> <C> <C>
Common stock equity $ 649,947 52.09%
Preferred stock of subsidiary 80,000 6.42%
Long-term debt of subsidiary 464,077 37.20%
Short-term debt (including current
maturity of long-term debt) of
subsidiary 53,482 4.29%
---------- ------
Total $1,247,506 100.00%
UE
Common Stock Equity $2,289,004 51.09%
Preferred stock 219,121 4.90%
Long-term debt 1,825,208 40.74%
Short-term debt (including current
maturity of long-term debt) 146,599 3.27%
---------- ------
Total $4,479,932 100.00%
Ameren Pro Forma Consolidated Capital Structure
(dollars in thousands)
(unaudited)
Common stock equity $2,938,951 50.17%
Preferred stock of subsidiaries 299,121 5.11%
Long-term debt of subsidiaries 2,419,285 41.30%
Short-term debt (including current
maturity of long term debt) of
subsidiaries 200,081 3.42%
---------- ------
Total $5,857,438 100.00%
</TABLE>
Ameren's pro forma consolidated common equity to total capitalization ratio of
50.17% is significantly higher than Northeast Utilities' approved 27.6% common
equity position and
45
<PAGE>
CINergy's level of 39.9% and comfortably exceeds the "traditionally acceptable
30% level". NORTHEAST UTILITIES, 47 SEC Docket at 1270, 1279, 1284 (Dec. 21,
1990). CINERGY CORP., 57 SEC Docket 2353 (Oct. 21, 1994).
2. Section 10(c)
Section 10(c) of the Act provides that, notwithstanding the provisions of
Section 10(b), the Commission shall not 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 11/15/; 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 the
efficient development of an integrated public utility system . . . .
a. Section 10(c)(1)
Section 10(c)(1) requires that the proposed acquisition be lawful under
Section 8. Section 8 prohibits registered holding companies from acquiring,
owning interests in or operating both a gas and an electric utility serving
substantially the same area if state law prohibits it or requires specific
approval for such combinations. Each of UE and CIPS has provided combination gas
and electric utility services in Missouri and Illinois for many years. Because
Missouri and Illinois law do not in any way prohibit or require special approval
for combination gas and electric utilities serving the same area, the
Transaction does not raise any issue under Section 8 and, accordingly, the first
clause of Section 10(c)(1). As more
- ----------------
/15/ By their terms, Sections 8 and 11 only apply to registered holding
companies and are therefore inapplicable at present to UE, CIPSCO or CIPS,
since none of these companies is now a registered holding company. The
retention by UE of the combination gas and electric business was approved
in IN RE UNION ELEC. CO., 40 SEC 1072 (Apr. 2, 1962). While divestiture had
been ordered in IN RE UNION ELEC. CO., 1972 SEC LEXIS 4264 (Sept. 19,
1972), jurisdiction over such issue was reserved and UE was allowed to
retain its gas properties in IN RE UNION ELEC. CO., 45 SEC 489 (Apr. 10,
1974), the leading case concerning operation of combination utilities by
exempt holding companies. The current view of the Commission as to
retainability of combination utilities for an exempt holding company is
reflected in CIPSCO INC., 47 SEC Docket 174 (Sept. 18, 1990). There the
retention by CIPSCO and CIPS of the combination gas and electric business
was unconditionally approved by the Commission. Id. (citing WISCONSIN
ENERGY CORP., 37 SEC Docket 387 (Dec. 18, 1986); WPL HOLDINGS, INC., 40 SEC
Docket 634 (Feb. 26, 1988)). The following discussion of Sections 8 and 11
is included because, under the present Transaction structure, Ameren will
register as a holding company after consummation of the Transaction.
46
<PAGE>
fully discussed below, Section 8 in fact indicates that a registered holding
company may own both gas and electric utilities where there is no conflicting
state policy.
Section 10(c)(1) also requires that the Transaction not be detrimental to
carrying out the provisions of Section 11. Three provisions of Section 11 are
relevant here.
Section 11(a) of the Act requires the Commission to examine the corporate
structure of registered holding companies to ensure that unnecessary
complexities are eliminated and voting powers are fairly and equitably
distributed. Similarly, 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." As described above, the Transaction will not result in
unnecessary complexities or unfair voting powers. As noted, in this regard
Ameren will be similar to the existing registered holding companies. See Item
3.A.1(a) and (c).
Finally, 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." One or more "additional" integrated public utility systems may be
retained if, as here, the "ABC Clauses" described below are satisfied. The
Transaction raises only two arguably significant issues under Section (10)(c)(1)
and by reference Section 11(b)(1): (i) whether Ameren may retain, through
control of UE and CIPS, control of integrated combination gas and electric
utility companies and (ii) whether Ameren may retain, through control of UEDC
and CIPSCO Investment, their existing nonutility investments. As detailed below,
retention by Ameren of these interests will not be detrimental to the carrying
out of any of the provisions of Section 11.
i. Retention of Gas Operations
Ameren questions whether this Commission should continue to deem a
combination company, such as post-Transaction Ameren, as anything other than a
single integrated public-utility system under Section 11. A combination
integrated gas and electric system is fully contemplated by the Act, and the
risk of the potential abuses that this Commission has historically sought to
combat through its interpretation of Section 11 is no longer significant in
light of the nature and level of competition in the energy market. Restricting
registered utility systems to either gas or electric utility businesses will put
such companies at a severe competitive disadvantage in today's evolving energy
market. Accordingly, the Commission should not require combination gas and
electric systems to satisfy the "ABC" test where, as here, they have not been
prohibited by the relevant state authorities.
This Application/Declaration will first describe how Ameren would clearly
meet the traditional ABC Clauses requirements, but will also demonstrate that
the Commission should approve the Transaction without reference to the Clauses
- -- that is, on the basis that the acquisition by Ameren of combination companies
CIPS and UE is not detrimental to the provisions of Section 11 because they
constitute a "single integrated public utility system."
47
<PAGE>
(A) Ameren Satisfies the Traditional "ABC" Test
Section 11(b)(1) of the Act 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)(1) of the Act expressly permits a registered holding
company to control one or more "additional integrated public utility systems"
if:
A) each of such additional systems cannot be operated as an
independent system without the loss of substantial economies which can be
secured by the retention of control by such holding company of such system;
B) all of such additional systems are located in one state, adjoining
states, or a contiguous foreign country; and
C) the continued combination of such systems under the control of
such holding company is not so large (considering the state of the art and
the area or region affected) as to impair the advantages of localized
management, efficient operation, or the effectiveness of regulation.
(1) Clause (A)
Since 1968, in interpreting clause (A) of Section 11(b)(1), the Commission
has looked to the Supreme Court decisions in SEC V. NEW ENGLAND ELEC. SYS., 384
U.S. 176 (1966) ("NEES I") and SEC V. NEW ENGLAND ELEC. SYS., 390 U.S. 207
(1968) ("NEES II"). In NEES I, the Supreme Court accepted the Commission's
interpretation of the "loss of substantial economies" language of clause (A) to
require an applicant seeking to own an electric and gas utility system to show
that the additional system, if separated from the principal system, would be
incapable of independent economic operation.
Historically, in determining whether lost economies are "substantial" under
Section 11(b)(1)(A), the Commission has given consideration to four ratios,
which measure the projected loss of economies as a percentage of: (1) total gas
operating revenues; (2) total gas expense or "operating revenue deductions"; (3)
gross gas income; and (4) net gas income or net gas utility operating income.
Although the Commission has declined to draw a bright-line numerical test under
Section 11(b)(1)(A), it has indicated that cost increases resulting in a 6.78%
loss of operating revenues, a 9.72% increase in operating revenue deductions, a
25.44% loss of gross income and a 42.46% loss of net income would afford an
"impressive basis for finding a loss of substantial economies." IN RE ENGINEERS
PUBLIC SERVICE CO., 12 SEC 41, 59 (Sept. 16, 1942) ("ENGINEERS").
Here, the lost economies would be far greater than in ENGINEERS if the gas
properties of UE and CIPS were to be operated on a stand-alone basis, with no
offsetting increase in benefits to consumers. These lost economies result from
the need to replicate services, the sacrifice of economies of scale, the costs
of reorganization, and other factors, and are
48
<PAGE>
described more fully in the Analysis of the Economic Impact of a Divestiture of
the Gas Operations of UE and CIPS (the "Gas Study") (Exhibit K-1 hereto).
As set forth in the Gas Study, divestiture of the gas operations of UE and
CIPS into stand-alone companies would result in lost economies of $22.1 million
for UE and $36.3 million for CIPS. These lost economies compare with 1995 gas
operating revenues of $87.8 million for UE and $129.6 million for CIPS; gas
operating revenue deductions of $80.5 million for UE and $117.4 million for
CIPS; gas gross income of $7.3 million for UE and $12.2 million for CIPS; and
gas net income of $5.2 million for UE and $8.6 million for CIPS.
On a percentage basis, the lost economies amount to 425% of 1995 UE gas net
income and 424% of 1995 CIPS gas net income (424% of pro forma combined gas net
income) -- far in excess of the loss of net income in Unitil Corp., 51 SEC
Docket 562 (Apr. 24, 1992) (Unitil), where the Commission allowed the retention
of gas utility operations, and the 30% loss in New England Electric System that
the Commission has described as the highest loss of net income in any past
divestiture order./16/ As a percentage of 1995 gas operating revenues, these
lost economies described in the Gas Study amount to 25% for UE and 28% for CIPS
- -- losses substantially higher than the losses in any past divestiture order.
The projected loss of economies as a percentage of operating revenues is even
higher than the loss in Unitil./17/ As a percentage of 1995 gas expenses or
operating
- ----------------
/16/ See Unitil Corp., 51 SEC Docket 562, 567 & n.42 (Apr. 24, 1992) ("The
Commission has required divestment where the anticipated loss in income of
the stand-alone company was approximately 30%" or "29.9% of net income
before taxes") (citing SEC V. NEW ENGLAND ELEC. SYS., 390 U.S. 207, 214
n.11 (1968)).
/17/ The loss as a percentage of operating revenues in Unitil was 13.94%. The
highest loss of operating revenues in any case ordering divestiture is
commonly said to be 6.58%. SEE, E.G., UNITIL CORP., 51 SEC Docket 562, 567
n.41 (Apr. 24, 1992) ("[o]f cases in which the Commission has required
divestment, the highest estimated loss of operating revenues of a stand-
alone company was 6.58%") (citing In RE ENGINEERS PUBLIC SERVICE CO., 12
SEC 41 (Sept. 16, 1942)). In fact, however, the 6.58% ratio is not cited in
ENGINEERS and is a post hoc calculation derived from claimed cost increases
which the Commission had found were "overstated" and "doubtful" in a number
of respects. ENGINEERS PUBLIC SERVICE CO., 12 SEC at 80-81. SEE ALSO IN RE
PHILADELPHIA CO., 28 SEC 35, 51 n.26 (June 1, 1948) (Engineers' "estimate
. . . of increased expenses . . . was overstated in several respects").
While the SEC made no finding as to actual cost increases or ratios for the
Gulf States gas properties, it found that ENGINEERS' estimate of
divestiture-related cost increases for certain sister gas properties in
Virginia were also overstated and cut them and the resulting ratios in
half. ENGINEERS PUBLIC SERVICE CO., 12 SEC at 60. If the same 50% discount
had been applied to Engineers' Gulf States gas properties, the loss of
operating revenues would have been 3.29%, the increase in expenses would
have been 4.73%, the loss of gross income would have been 10.43%, and the
loss of net income would have been 12.63%.
(continued...)
49
<PAGE>
revenue deductions, the lost economies described in the Gas Study would amount
to 27% for UE and 31% for CIPS -- higher than the losses in any past divestiture
order and higher than the losses in both UNITIL and ENTERGY, another case in
which the Commission authorized the retention of gas operations./18/ As a
percentage of 1995 gas gross income, the lost economies described in the Gas
Study amount to 301% for UE and 297% for CIPS--far in excess of the highest loss
of gross income in any divestiture order. The applicable percentages here and
in past cases are summarized in Exhibit K-2 hereto (Table of Estimated Losses of
Economies in Prior Decisions on Divestiture and Retention of Gas Operations).
In order to recover these lost economies, the stand-alone company divested
from UE would need to increase customer rates by about 38% ($33.7 million) in
order to provide an 11.15% rate of return on rate base. Similarly, the stand-
alone company divested from CIPS would need to increase customer rates by about
31% ($40.7 million) in order to provide a 10.98% rate of return on rate base.
These rates of return were conservatively estimated using UE's and CIPS's
approximate costs for capital rather than the higher returns that would likely
be required by the financial community for separate companies.
Finally, it should be noted that the lost economies would, in the absence
of rate relief, result in a negative rate of return on rate base for the gas
operations (-8.73% and -15.93% for UE and CIPS respectively)--significantly more
detrimental than the 2.01% projected stand-alone rate of return in UNITIL, where
retention was authorized. These returns are significantly lower than the
returns of other utilities in the region and represent a decline from UE's and
CIPS' indicated rates of return for 1995.
- ----------------
/17/ (...continued)
Disregarding the 6.58% ratio incorrectly attributed to the Engineers/Gulf
States case, the highest loss of operating revenues in any past divestiture
order was 5.85%. SEE table of ratios in IN RE NEW ENGLAND ELEC. SYS., 41
SEC 888, 905 App. (Mar. 19, 1964). This figure would be even lower if
adjusted for the increase in purchased gas costs since the 1940s.
/18/ The highest percentage of loss related to operating revenue deduction is
sometimes attributed to the Gulf States gas properties of Engineers Public
Service Co. SEE, E.G., IN RE NEW ENGLAND ELEC. SYS., 41 SEC 888, 905 App.
(March 19, 1964) (attributing 9.46% to the Engineers/Gulf States case).
This percentage, however, is based on claimed losses expressly rejected by
the Commission in the ENGINEERS decision. IN RE ENGINEERS PUBLIC SERVICE
CO., 12 SEC 41, 80-81 (Sept. 16, 1942). Disregarding the 9.46% figure
erroneously attributed to the ENGINEERS case, the highest expense
percentage in the cases ordering divestiture appears to have been either
8.01% or 7.42%, depending on how the ratio is calculated. SEE IN RE NORTH
AMERICAN CO., 18 SEC 611 (Apr. 7, 1945); IN RE PHILADELPHIA CO., 28 SEC 35,
51 Table VI (June 1, 1948) (attributing expense ratio of 7.42% to North
American) with IN RE NEW ENGLAND ELECTRIC SYSTEM, 41 SEC 888, 905 App.
(1964) (attributing expense ratio of 8.01% to North American).
50
<PAGE>
(2) Clauses (B) and (C) of Section 11(b)(1) are
Satisfied.
The remaining requirements of Section 11(b)(1) are met because the gas
operations of UE and CIPS are located in the adjoining states of Missouri and
Illinois and because the continued combination of the gas operations under
Ameren is not so large, considering the state of the art and the area or region
affected, as to impair the advantages of localized management, efficient
operation or the effectiveness of regulation. The gas systems are confined to a
relatively small area and are not as large as other gas systems in the same area
and will preserve the advantages of localized management, efficient operation
and effectiveness of regulation. Moreover, as the Commission has recognized
elsewhere, the determinative consideration is not size alone or size in an
absolute sense, either big or small, but size in relation to its effect, if any,
on localized management, efficient operation and effective regulation. From
these perspectives, it is clear that the continued combination of the gas
operations under Ameren is not too large.
Even after the combination, the gas operations of UE and CIPS, with some
285,403 customers combined in only two states, will be significantly smaller
than neighboring Northern Illinois Gas Company (1,769,800 customers), People's
Gas Light and Coke Company (842,510 customers), Laclede Gas Co. (553,000
customers), Missouri Gas Energy (450,000 customers) and Illinois Power Co.
(388,170 customers).
Localized management is discussed for the Transaction as a whole under Item
3.A.2.b.(ii)(A) and (B) below. Applied solely to the gas operations, the
current UE and CIPS gas systems enhance localized management within the larger
corporate structure and will continue to do so after the Transaction is
completed.
As a result of the Transaction, the centralized functions of Ameren will
continue to be handled from St. Louis, Missouri and Springfield, Illinois and
from regional offices. No reduction in customer service or support crews is
expected. Management will therefore remain geographically close to the gas
operations, thereby preserving the advantages of a localized management. From
the standpoint of regulatory effectiveness, the Transaction will eliminate the
dual jurisdictional regulation of the UE system. Upon receipt of state
commission approvals, each utility, UE and CIPS, will operate only in one state,
thus making regulation more streamlined and mitigating allocation issues
regarding purchased gas costs.
With respect to efficient operation, as described below, as part of the
Ameren system, the gas operations of UE and CIPS are expected to reduce
delivered gas costs by $37 million in the first 10 years after the Mergers.
Substantially all of these reductions will be passed on directly to customers
under the purchased gas adjustment ("PGA") clauses in UE's and CIPS' tariffs, if
all of the system's purchased gas costs continue to receive PGA treatment as at
present. See Item 3.A.2.b.ii.(B). Far from impairing the advantages of
efficient operation, the combination of the gas operations under Ameren will
facilitate and enhance the efficiency of gas operations. As discussed in Item
3.A.2.a.i.(B), the "state of the art" with respect to gas operations has changed
significantly in recent years. In the light of current communications
technology and the nature of today's gas business, the combination
51
<PAGE>
of the UE and CIPS gas businesses, under the control of Ameren, will not
jeopardize local control and will significantly improve operating efficiency.
Based on its traditional application of the ABC Clauses, the Commission
should find that UE and CIPS may retain the combined gas businesses as an
"additional" integrated system.
(B) The Commission Should Not Require Ameren to Satisfy the
Traditional "ABC" Test.
Although for many years the Commission has interpreted the Act as not
permitting a registered holding company to control subsidiaries that were
combination gas and electric utilities, except where the "ABC" test is met,
Ameren believes that the Commission should revise its interpretation of the Act,
in light of recent changes both in national energy policy and in the energy
markets./19/
(1) The Act Does Not Prohibit Combination Companies.
Nothing in the Act directly prohibits a registered holding company from
owning an integrated gas and electric system if such a structure does not
violate the laws of the state(s) having jurisdiction over such a system.
Section 8 of the Act provides that:
[w]henever a State law prohibits, or requires approval or
authorization of, the ownership or operation by a single company of
the utility assets of an electric utility company and a gas utility
company serving substantially the same territory, it shall be unlawful
for a registered holding company, or any subsidiary company thereof
. . . (1) to take any step, without the express approval of the state
commission of such State, which results in its having a direct or
indirect interest in an electric utility company and a gas company
serving substantially the same territory; or (2) if it already has any
such interest, to acquire, without the express approval of the state
commission, any direct or indirect interest in an electric utility
company or gas utility company serving substantially the same
territory as that served by such companies in which it already has an
interest.
Thus, on its face, the Act only precludes the use of the registered holding
company form to circumvent any state law restrictions on the ownership of gas
and electric assets by the same company.
Further, the legislative history of the Act indicates that Congress saw the
question of whether combination companies are desirable as one that should be
left to the states.
- ----------------
/19/ These changes are described below and have been recognized by the
Commission. SEE CONSOLIDATED NATURAL GAS, Release No. 35-26512 (Apr. 30,
1996); NORTHEAST UTILITIES, Release No. 35-26554 (August 13, 1996).
52
<PAGE>
The Senate Committee on Interstate Commerce in its report on the Act noted that
the provision in Section 8 concerning combination companies "is concerned with
competition in the field of distribution of gas and electric energy -- a field
which is essentially a question of State policy, but which becomes a proper
subject of Federal action where the extra-State device of a holding company is
used to circumvent State policy." The Report of the Committee on Interstate
Commerce, S. Rep. No. 621 74th Cong., 1st Sess. 31 (1935). In addition,
attached to the committee report is the Report of the National Power Policy
Committee on Public-Utility Holding Companies, which sets forth a recommended
policy that: "Unless approval of a State commission can be obtained the
commission would not permit the use of the holding-company form to combine a gas
and electric utility serving the same territory where local law prohibits their
combination in a single entity."
Congress clearly recognized that local regulators are in the best position
to assess the needs of their communities. The Act was never intended to
supplant local regulation but, rather, was intended to create conditions under
which local regulation was possible. Section 21 of the Act states:
Nothing in [the Act] shall affect . . . the jurisdiction of any other
commission, board, agency or officer of . . . any State, or political
subdivision of any State, over any person, security, or contract,
insofar as such jurisdiction does not conflict with any provision of
[the Act]. . . .
The legislative history reveals that Section 21 of the Act was further intended
"to ensure the autonomy of State commissions [and] nothing in the [Act] shall
exempt any public utility company from obedience to the requirements of State
regulatory law." S. Rep. No. 621, 74th Cong., 1st Sess. 10 (1935).
The Act should not be used as a tool to override state policy, particularly
where the holding company involved is subject to both state and federal
regulation and where the affected state regulatory commissions have supported
the combined electric and gas operations in one holding company system. To do
otherwise would be to act contrary to Congress' intent.
(2) The Commission's Interpretation of the Act.
In its early decisions under the Act, the Commission adhered to the concept
that Section 8 of the Act evidenced the policy of Congress that the decision of
whether to allow combination companies was one that states should make (although
the Commission might have to implement it in certain cases) and, where such
systems were permissible, the role of the Commission was to ensure that both
such systems were integrated as defined in the Act. If the electric systems
were integrated and the electric and gas properties were in close geographic
proximity and were related so that substantial economies were obtained by their
coordination under common control, then combined ownership by the registered
holding company would be permitted. SEE AMERICAN WATER WORKS & ELEC. CO., 2 SEC
972
53
<PAGE>
(Dec. 30, 1937); 1995 Report at 62. If a combination company did not violate
state policy, there was no need for the Commission to exercise jurisdiction to
implement state policy.
By the early 1940s, however, the Commission, faced with further perceived
abuses and based on THEN EXISTING COMPETITIVE CONDITIONS, switched its focus to
Section 11 and adopted a narrow interpretation of the standards contained
therein as the controlling factor with regard to combination registered holding
companies./20/ In this period of the administration of the Act, facing vigorous
constitutional challenges to the Act's validity as well as concerted resistance
in many proceedings to the specific attempts to order divestiture by holding
companies of utility subsidiaries, the Commission pursued a policy of strict
interpretation of the Act to best effectuate the directive from Congress that
the monolithic holding companies be broken up./21/ Furthermore, in connection
with its analysis of combination companies under Section 11, the Commission
frequently noted a policy concern existing at that time which advocated
separating the management of gas and electric utilities based on the belief that
the gas utility business tended to be overlooked by combination company
management who focused on the electric business. Therefore, it was believed that
gas utilities would benefit from having separate management focused entirely on
the gas utility business./22/
(3) The Commission Should Revise Its Interpretation of
The Act.
The Commission is not bound by its historical emphasis on Section 11 of the
Act when assessing combination companies. An agency may revise its
interpretation of its governing statute where its revised interpretation is
reasonable and where it provides a
- ----------------
/20/ SEE, E.G., IN RE COLUMBIA GAS & ELEC. CORP., 8 SEC 443, 463 (Jan. 10,
1941); IN RE UNITED GAS IMPROVEMENT CO., 9 SEC 52 (1941); SEC V. NEW
ENGLAND ELEC. SYS., 384 U.S. 175 (1966). It should be noted that the
Commission continued to give primacy to state utility commission
determinations in making decisions regarding combination exempt holding
companies. SEE, E.G., IN RE NORTHERN STATES POWER CO., 36 SEC 1 (Sept. 16,
1954); DELMARVA POWER & LIGHT CO., 46 SEC 710 (Oct. 19, 1976); WPL
HOLDINGS, Release No. 35-24590 (Feb. 26, 1988); CIPSCO INC., 47 SEC Docket
174 (Sept. 18, 1990).
/21/ That goal has been long accomplished. 1995 Report at ix.
/22/ SEE, E.G., IN RE PHILADELPHIA CO., 28 SEC 35, 48 (June 1, 1948); IN RE
NORTH AMERICAN CO., 11 SEC 194, 216-17 (Apr. 14, 1942); In re Illinois
Power Co., 44 SEC 140 (Jan. 2, 1970). The principal reasons for this change
in policy was to better administer the Act in light of perceived abuses and
conditions in the industry at the time. As noted, industry conditions are
significantly different now than in the 1940s. Also, the actual STATUTORY
basis for this changed policy rested on a very technical INTERPRETATION OF
THE DEFINITION of "integrated public utility system." As will be shown,
this strained interpretation ignores the clear language of Section 8. SEE
1995 Report at 63, 65. As noted below, the Commission has the authority to
reinterpret the meaning of the Act in light of changed conditions.
54
<PAGE>
reasoned basis for its change. CHEVRON USA, INC. V. NAT'L RESOURCES DEFENSE
COUNCIL, INC., 467 U.S. 837 (1984); RUST V. SULLIVAN, 500 U.S. 173, 186-87
(1991) (agency's reversal of policy in effect for 18 years was consistent with
intent of statute and was supported by reasoned analysis, and thus permissible).
The Supreme Court has indicated that the governing principle is the intent
of Congress, not an agency's long-standing practice. In CHEVRON, the Court
stated:
When a court reviews an agency's construction of the statute
which it administers, it is confronted with two questions. First,
always, is the question whether Congress has directly spoken to the
precise question at issue. If the intent of Congress is clear, that is
the end of the matter; for the court, as well as the agency, must give
effect to the unambiguously expressed intent of Congress. If, however,
the court determines Congress has not directly addressed the precise
question at issue, the court does not simply impose its own
construction on the statute, as would be necessary in the absence of
an administrative interpretation. RATHER, IF THE STATUTE IS SILENT OR
AMBIGUOUS WITH RESPECT TO THE SPECIFIC ISSUE, THE QUESTION FOR THE
COURT IS WHETHER THE AGENCY'S ANSWER IS BASED ON A PERMISSIBLE
CONSTRUCTION OF THE STATUTE.
CHEVRON, 467 U.S. at 842-43 (citations omitted; emphasis added).
Moreover, the Court has stated:
[An agency's] revised interpretation [of a statute] deserves deference
because an initial agency interpretation is not instantly carved in stone
and the agency, to engage in informed rulemaking, must consider varying
interpretations and the wisdom of its policy on a continuing basis. An
agency is not required to establish rules of conduct to last forever, but
rather must be given ample latitude to adapt its rules and policies to the
demands of changing circumstances.
RUST, 500 U.S. at 186-87 (citations and internal quotation marks omitted).
The Commission has begun a re-evaluation of the requirements of Section 11
in light of contemporary conditions. To date, that review has principally
focused on the meaning of the ABC Clauses and whether it is necessary to
continue a narrow, restrictive interpretation of those provisions.
In NEES I, the Supreme Court specifically recognized that the language of
clause (A) of Section 11(b)(1) was "not crystal clear" and deferred to the
Commission's "expertise on the total competitive situation." 384 U.S. at 185
(emphasis in original); SEE ALSO NEES II, 390 U.S. at 219. In NEES I and NEES
II, the Court accepted the Commission's interpretation of Clause A as a
"construction well within the permissible range given to those who are charged
with the task of giving an intricate statutory scheme practical sense and
application." 384 U.S. at 185.
55
<PAGE>
The NEES interpretation however, is, not the only permissible
interpretation. There is strong support for the Commission's application of a
different interpretation of Clause A, and the Commission may use its expertise
to develop a different interpretation which is both consistent with Congress'
intent and which properly addresses the "demands of changing circumstances."
RUST, 500 U.S. at 186-87. This Commission is free to apply its expertise to
administer the Act in light of changes in legal, regulatory and economic
circumstances which were not foreseen at the time of the NEES decisions,
including federal legislation (described below) which has "substantially
changed" the Act. SEE CHEVRON, 476 U.S. at 842.
The Division recognized in the 1995 Report that the Commission should no
longer be bound by the narrow interpretation of Clause (A) under the NEES
decisions. In so doing, the Division stated:
[T]he SEC has generally required electric registered holding companies
that seek to own gas utility properties to satisfy the requirements of
the A-B-C clauses concerning additional integrated systems. In
contrast, exempt holding companies have generally been permitted to
retain or acquire combination systems so long as combined ownership of
gas and electric operations is permitted by state law and is supported
by the interested regulatory authorities.
In the past, the SEC has construed the A-B-C clauses narrowly to
permit retention only where the additional system, if separated from
the principal system, would be incapable of independent economic
operations. Although the Supreme Court upheld the SEC's reading, two
justices dissented, contending that the "serious impairment" standard
was at odds with the wording of the Act, had little basis in the
statutory history or aims of the Act, and could not be sustained by
agency or judicial precedent. The dissenting justices believed that
the statutory language "called for a business judgment of what would
be a significant loss."
Applicants in recent matters have argued that, in a competitive
utility environment, any loss of economies threatens a utility's
competitive position, and even a "small" loss of economies may render
a utility vulnerable to significant erosion of its competitive
position. There is general support for a more relaxed standard. A
number of commenters emphasize that these are essentially state
issues. It does not appear that the SEC's precedent concerning
additional systems precludes the SEC from relaxing its interpretation
of section 11(b)(1)(A). Indeed, the SEC has recognized that section 11
does not impose "rigid concepts" but rather creates a "flexible"
standard designed "to accommodate changes in the electric utility
industry."
Congress, in 1935, recognized that competition in the field of
distribution of gas and electric energy is essentially a question of
state policy. The Act was intended to ensure compliance with state law
in
56
<PAGE>
this regard. Moreover, it appears that the utility industry is
evolving toward the creation of one-source energy companies that will
provide their customers with whatever type of energy supply they want,
whether electricity or gas. Accordingly, the Division believes it is
appropriate to reconcile the treatment of registered and exempt
companies in this regard, and so recommends that the SEC permit
registered holding companies to own gas and electric utility systems
pursuant to the A-B-C clauses of section 11(b)(1), where the affected
states agree./23/
The Commission approved the Report on June 20, 1995.
Ameren believes that the Division's recommendation regarding Clause A would
represent sound policy by the Commission. Indeed, the policy so expressed would
equally support a finding that a combination company, if it meets the
requirements of the AMERICAN WATER WORKS decision, constitutes a single
integrated public utility system. From a policy perspective, the Commission's
historic concern underpinning its 1964 NEES decision and a host of earlier
decisions where the retainability of gas properties by registered electric
systems was at issue -- namely, of fostering competition between electric and
gas -- is simply no longer valid given the current "state of the art" in the
electric and gas utility industries. In the three decades since the Commission
decided the NEES cases, profound economic and regulatory factors have wrought a
fundamental transformation in the gas supply and electric generation industry,
rendering obsolete the Commission's earlier premises regarding the primacy of
competition between gas and electric service and the lack of competition within
electric and gas service.
The Commission itself has noted that the 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." UNION ELECTRIC CO., 45 S.E.C. 489, 503 n.52 (1974), AFF'D SUB NOM.
CITY OF CAPE GIRARDEAU V. SEC, 521 F.2d 324 (D.C. Cir. 1974). SEE ALSO EASTERN
UTILITIES ASSOC., Holding Co. Act Release No. 26232 (Feb. 15, 1995). The
Commission has specifically recognized that the "changing realities of the
utility industry" include "the increasing integration of energy markets, as
deregulation and competition increase." CONSOLIDATED NATURAL GAS CO., Release
No. 35-26512 (Apr. 30, 1996) ("CONSOLIDATED").
The Commission took further steps toward the conclusion urged here in
CONSOLIDATED. In that case, Consolidated, a registered gas utility company,
received approval to enter into the wholesale electric marketing business. The
Commission indicated it would approve retail marketing of electricity when state
laws had developed to allow such activity. Quoting an earlier release, the
Commission noted that "the utility industry is evolving toward a broadly based
energy-related business that is no longer focused solely on the traditional,
regulated, production and distribution functions of a utility." Under the
CONSOLIDATED decision, Consolidated (a gas utility) may own electric generating
facilities (e.g., through an EWG) and may sell electricity through the approved
marketing subsidiary. Several months
- ----------------
/23/ 1995 Report at 74, 75, 76. Footnotes omitted.
57
<PAGE>
after CONSOLIDATED, the Commission took a further step. Recognizing that "the
electric and gas industries are no longer separate, but are instead increasingly
integrated," the Commission approved the application of an electric registered
holding company system to engage in RETAIL marketing of energy commodities
(including electricity and gas). SEI HOLDINGS, Release No. 35-26581 (Sept. 26,
1996) ("SEI HOLDINGS"). Thus, registered holding companies are now able to offer
their wholesale and retail customers integrated gas and electric energy services
- -- exactly what Ameren wishes to offer its customers. CONSOLIDATED, SEI HOLDINGS
and the cases following them strongly suggest that the Commission is changing
its interpretation of the Act including those activities deemed "detrimental to
carrying out the provisions of Section 11."/24/
UE and CIPS have conducted combined electric and gas operations for many
years. As the energy markets have developed, especially in recent years, CIPS
and UE have developed, and are further developing, as "energy service"
companies. The provision of gas and electric products is only the start of a
utility's job. In addition, the utility must provide an entire package of both
energy products and services. In this area, CIPS' and UE's efforts are part of a
trend by utilities to organize themselves as "energy service companies," that
is, as providers of a total package of energy services rather than merely
suppliers of gas and electric products. The goal of an energy service company is
to retain its current customers and obtain new customers in an increasingly
competitive environment by meeting customers' needs better than the competition.
An energy service company can provide the customer with a low cost energy option
(i.e., gas, electricity or conservation) without inefficient subsidies.
As energy services companies, UE and CIPS are not solely electric or gas
utilities and do not operate in a manner which could lead to the abuses which,
under competitive conditions previously prevailing in the industry, were
perceived as likely to arise from the combination of gas and electric utilities
under common ownership in a single holding company system -- i.e., the "favoring
of one of these competing forms of energy over the other." NEES I at 183.
Rather, UE and CIPS offer (and the Ameren system will offer) diverse forms of
energy to their consumers, thereby allowing customers to choose among different
forms of energy and fostering efficiency and conservation. This increasing
competition to supply all forms of energy will prevent a holding company from
"favoring"
- ----------------
/24/ SEE NORTHEAST UTILITIES, Release No. 35-26554 (Aug. 13, 1996) and cases
cited in note 14 thereof. See also American Electric Power Co., Release No.
35-26572 (Sept. 13, 1996). While CONSOLIDATED, and SEI HOLDINGS do not
directly interpret the meaning of "single integrated public utility
company," but rather find that the approved marketing activities constitute
a permissible other business under Section 11(b)(1), the finding by the
Commission that marketing of electricity by a gas registered holding
company system is not "detrimental to the carrying out of the provisions of
Section 11" constitutes substantial support for the proposition urged here:
that combination companies are likewise not detrimental to the purposes of
Section 11. The Commission has extended CONSOLIDATED to also allow electric
registered holding company systems to engage in electric and gas brokering
and marketing activities.
58
<PAGE>
one form over the other. Furthermore, consumers and regulators today must be --
and are -- more careful with limited energy resources than was required in 1935.
SEE EASTERN UTILITIES ASSOCIATES, Release No. 35-26232 (Feb. 15, 1995) and the
1995 Report at 22-23 and 30-31. One energy company which allows its customers
to select among different forms of energy based on environmental and economic
factors is a sensible means of allocating scarce national resources under the
purview of local regulators who are most familiar with the needs of local
constituencies.
This trend is exemplified by several recently announced transactions
including the proposed merger of Texas Utilities, an electric utility, with
Enserch Corp., which is a natural gas concern, and the acquisition by Enron
Corp., a major integrated gas company with electric power marketing business, of
the electric utility Portland General Corp. Referring to such cross industry
transactions, Elizabeth A. Moler, Chairwoman of the FERC said: "They have the
potential to increase competition and make more options available to consumers."
Allen R. Myerson, Enron Will Buy Oregon Utility In Deal Valued at $2.1 Billion,
New York Times, July 23, 1996 at D1. Since these transactions were announced,
Houston Industries, an exempt electric utility holding company, announced a
merger with NorAm Energy Corp., a natural gas pipeline and local gas
distribution company. The most recent announcement is the merger of Enova Corp.,
the holding company for San Diego Gas & Electric, an electric company and
Pacific Enterprises, a natural gas distribution utility. This merger will
produce the largest customer base of any investor owned utility. Benjamin A.
Holden, Deal Valued at $2.8 Billion Would Establish Giant for California Energy,
Wall Street Journal, Oct. 15, 1996 at A3. Each of these companies is responding
to industry realities and customer demands that utilities be capable of
supplying TOTAL energy services, not merely one energy commodity. As the
Commission noted in SEI HOLDINGS, "Industry trends and competitive pressures
make it important for registered system companies to be poised to compete in new
markets as they are created." SEE ALSO CONSOLIDATED NATURAL GAS, Release No. 35-
26512 (Apr. 30, 1996).
These proposed cross industry transactions clearly demonstrate that market
forces are demanding the unified delivery of energy services and that such
combinations will be BENEFICIAL to the interests of investors and consumers and
accordingly the public interest. None of the announced mergers is anticipated to
be restrained by the Act./25/ Continued reliance on outdated premises which
prevent registered combination companies and do not reflect current competitive
conditions will put registered holding companies at a severe competitive
disadvantage.
There are many benefits of such combined electric and gas energy services
providers. For customers, the energy service utility provides the convenience
and efficiency of service by a single energy provider and reduces transaction
costs incurred in gathering and analyzing
- ----------------
/25/ It appears that each of the four proposed mergers of predominantly gas
businesses with predominantly electric businesses can be structured to meet
the intrastate exemption of Section 3(a)(1). The benefits to investors and
consumers that will flow from such combinations should not be limited to
only those enterprises operating within one state, but should be available
to all investors and consumers.
59
<PAGE>
information, contacting energy suppliers and negotiating terms of service. For
the communities in which the energy service company operates, the combining of
gas and electric operations simplifies community planning on energy-related
matters through coordination with a single energy provider. For society, the
combination energy services company will allow customers to efficiently choose
energy sources thus ensuring an environmentally efficient allocation of energy.
For utility shareholders and employees, the energy services company is better
able to respond to a competitive environment and to remain an attractive
investment opportunity for shareholders and an appealing employer for utility
employees. Thus, combination utilities benefit all utility stakeholders.
The development of energy services companies stems from dramatic changes in
the regulatory framework of the industry. In the gas area, regulatory changes
have introduced competition into what was formerly a monopoly and have expanded
the availability of "transportation-only service" as an alternative to sales
services from the local gas utility company. CIPS and UE have "open access"
transportation-only service tariffs on file with their respective state
commissions, and approximately 39% and 14% of the gas delivered by CIPS and UE,
respectively, in 1995 was directly purchased by customers. FERC Order 636 is
resulting in the separation of the commodity function from the transportation
function at both wholesale and retail levels.
As a result, combination utilities such as UE and CIPS have less ability
than they did in 1935 to "favor" electric -- the principal policy concern in
decisions ordering the separation of gas and electric systems -- by curtailing
the availability or increasing the price of gas./26/ Combination utilities also
have less incentive to favor electric over gas in light of the increasing
importance of demand-side management, the costs and risks involved in the
construction of new generating capacity and the incentives to avoid such
construction, and, as noted in the June 1994 issue of The Electricity Journal,
the emergence of integrated resource planning involving both gas and electric
service.
In the electric area, the Energy Policy Act of 1992 and the Public Utility
Regulatory Policies Act of 1978 have introduced competition into the electric
utility business. As the chairman of the Senate Banking Committee stated
recently:
"[The Act] was substantially changed by the Energy Policy Act of 1992.
That law restructured the utility industry to promote greater
competition for the benefit of energy customers. The Energy Policy
Act of 1992 was the product of a cooperative effort on the part of the
Banking Committee and the Energy Committee to create a more market-
oriented regulatory framework for the energy industry." Hearing on
S.182, The Communications Act of 1994, before the Comm. on Commerce,
Science and Transportation, 103rd Cong. 2nd
- ----------------
/26/ SEE, E.G., NEES I at 183-184. It is important to note that this issue --
basically an antitrust issue -- was the principal concern in previous
decisions ordering the separation of gas and electric systems and clearly
is no longer applicable to the changed utility competitive environment.
60
<PAGE>
Sess. 344-345 (1994) (prepared Statement of Senator Riegle) (emphasis
added).
As a continuation of the trend towards more competition, on April 24, 1996,
the FERC entered Orders 888 and 889. These orders, entered after more than a
year of debate and public comment, open up wholesale power sales to competition.
All utilities subject to Order 888 must provide transmission service to
qualified wholesale buyers and sellers on terms set by universally applicable
tariffs. This mandatory "wholesale wheeling" will bring competition to the
market for electricity provided to customers for resale./27/
Finally, many states have "retail wheeling" measures under discussion which
are likely to have the effect of extending electric supply competition to the
retail level. Illinois and Missouri are each in the process of evaluating
various options that could increase electric supply competition at the retail
level./28/ Federal legislation is being proposed which would require all states
to adopt a retail wheeling scheme by the year 2000./29/ These initiatives could
soon bring direct commodity competition to retail electric customers much as
such competition already exists for natural gas. Many of these recent changes
to the energy industry are noted in SEI HOLDINGS, Release No. 35-26581 (Sept.
26, 1996).
Accordingly, instead of relying on the blunt instrument of competition
BETWEEN gas and electric energy sources (the driving force behind the
Commission's historic interpretation of the Act), national policy has now
created direct competition WITHIN the gas and electric utility industries.
Thus, combination ownership does not eliminate competition, since a combination
utility now has competitors for both gas and electric service. Moreover,
competition is not an end in itself, but is merely a means to the end of
efficient, cost-effective service. Since combination ownership creates
efficiencies and no longer has the effect of eliminating competition, there is
no reason for the Commission to prohibit combination ownership, at least under
the circumstances presented here.
- ----------------
/27/ As noted above, UE and CIPS filed their electric open-access transmission
tariffs in compliance with Order 888 on July 9, 1996.
/28/ The Illinois General Assembly has appointed a special legislative committee
to develop a policy to introduce retail electric competition. A report will
be filed, and legislative action is expected in 1996 or 1997. Two Illinois
utilities have initiated pilot programs which give retail customers a
choice in electricity providers. CIPS has received approval to participate
as a supplier in those programs. Further information concerning Illinois
initiatives is included in CIPSCO's 1995 Form 10-K and its 1996 Form 10-Q's
filed as exhibits hereto. In Missouri, a joint agreement among the parties
in the MPSC proceeding to approve the Transaction calls for UE to propose
by March 1, 1997 an experimental retail wheeling pilot program in Missouri
for 100 mW of electric power. This agreement, which is pending before the
MPSC, is filed as Exhibit D-2.3 hereto.
/29/ SEE, E.G., HR 3790 (104th Cong.; 2d Session).
61
<PAGE>
Further, there is nothing in national energy policy that would override the
deference Congress intended should be given to the states on this question.
Indeed, as discussed above, in the 1995 Report the Division recommended that the
Commission interpret Section 11(b)(1) of the Act to allow registered holding
companies to hold both gas AND electric operations as long as each affected
state utility regulatory commission approves of the existence of such a
company./30/
As noted, the Commission has begun to reevaluate Section 11, to place more
meaning on Section 8 in its review of the ABC Clauses and to accommodate
electric and gas marketing by a single registered holding company in its
decisions in CONSOLIDATED, SEI HOLDINGS and the cases following them. The
Commission should take the further step, justified by all the same facts,
circumstances and policies, and permitted under CHEVRON and RUST, to determine
that a registered holding company MAY control combination gas and electric
utility companies.
Such a reemphasis on Section 8 fits within the overall regulatory scheme of
the Act. Section 11 of the Act is flexible and was designed to change as the
policy concerns over the regulation of utility holding companies changed./31/
Moreover, a registered holding company would still be required to demonstrate
that any acquisition or transaction by which it would become a combination
company would not be detrimental to carrying out the provisions of Section 11 of
the Act. In other words, its electric system would have to constitute an
integrated electric system and its gas system would have to constitute an
integrated gas system and both systems would have to be capable of being
operated efficiently together (all facts which are clearly present in the
instant case). See AMERICAN WATER WORKS & ELEC. CO., 2 SEC 972 (Dec. 30, 1937).
Thus, the standards of Section 11 would still have to be met, but the
application of those standards should take into account the fundamental policy
of the Act and allow local regulators to make the threshold determination with
regard to combination companies.
As shown under Item 3.A.b.ii., the electric systems of UE and CIPS
constitute an "integrated" electric system and the gas systems constitute an
"integrated" gas system. Moreover, as the Gas Study clearly shows, the electric
system and the gas system TOGETHER are operated as a single integrated energy
company. The integration standard of the Act is designed to require efficient
operations. The Gas Study shows that separating the existing gas systems from
the existing fully integrated companies would result in a loss of significant
economies. These economies relate to more than just corporate operations but
also include substantial savings resulting from such operational matters as
joint gas and electric meter
- ----------------
/30/ The 1995 Report urges flexible interpretation of the ABC Clauses. However,
as demonstrated herein, there is ample reason, in light of changed national
energy policy for the Commission to go further and return to its pre-1940s
reliance on Section 8's clear language to permit State-sanctioned
combination companies.
/31/ IN RE MISSISSIPPI VALLEY GENERATING CO., 36 SEC 159 (Feb. 9, 1955) (noting
that Congress intended the concept of integration to be flexible); UNITIL
CORP., 51 SEC Docket 562 (Apr. 24, 1992) (noting that Section 11 contains a
flexible standard designed to accommodate changes in the industry).
62
<PAGE>
reading, combined field service facilities, combined engineering services,
combined customer service facilities and combined transportation services.
Section 11 was intended to require the separation and independent operation of
utilities that were commonly controlled through the holding company but had no
operational connection. That situation is NOT presented in any way by the
Transaction, thus the purposes of the Act would not be compromised in any way by
approval of retention of the combination gas and electric businesses.
Furthermore, the Commission has had the opportunity to review the gas
utility operations of UE and CIPS in prior orders and found that continued
combination activity would not be "detrimental to the public interest or the
interest of investors or consumers" and would not be "detrimental to the
carrying out of the provision of Section 11." See the CIPSCO and UNION ELECTRIC
cases cited in note 15 above.
(4) UE's and CIPS' Combination Systems Are Not
Prohibited by State Law
Each of UE and CIPS as a combination company is permissible pursuant to the
terms of Section 8 of the Act because the continued combined activities in no
way violate state policy. Moreover, continuation of each as a combination
company is in the public interest. The ICC and MPSC have on numerous occasions
over the years had opportunity to review the combined operations in light of
public interest standards in rate cases and other proceedings. These cases have
approved cost allocation methods, accounting procedures and other factors which
insure that combination activities are not harmful to customers. Furthermore,
as part of state merger approvals, approval of the ICC will be sought for the
acquisition by CIPS of the UE Illinois gas properties. Finally, as required by
Section 11, in addition to the fact that the electric systems of CIPS and UE
constitute an integrated electric system, the gas systems will together
constitute an integrated gas system as explained in detail below under Item
3.A.2.B.(ii).
With respect to Section 8, the combination of electric and gas operations
is lawful under all applicable state laws for each of UE and CIPS and has been
considered and approved indirectly on numerous occasions by Missouri and
Illinois regulators who have, and will continue to have, direct jurisdiction
over the Ameren gas operations. The use of Ameren as a holding company for two
combination companies will not circumvent any state regulations, since the gas
utility operations of each of UE and CIPS individually will continue to be
regulated by the relevant jurisdictions. As noted under Item 1.B.2.c. above, UE
and CIPSCO have requested authority for UE to transfer its Illinois gas
facilities to CIPS. Such a transfer would result in each gas system being under
the regulatory supervision of a single state, thereby enhancing the
effectiveness of local regulation. Both the ICC and the MPSC will have the
opportunity to review the continued operation of combination companies as part
of their approval of the Transaction and would have the ability to impose
conditions on their approval if they felt it necessary to protect the public
interest. SEE, E.G., 220 ILCS 5/7-204. Given the long-standing operation of
combined electric and gas businesses in both Missouri and Illinois, the
statutory authority of the MPSC and ICC and the many opportunities for review of
such combined operations, including the review of the Transaction, Ameren
believes it is clear that state regulators do not believe
63
<PAGE>
combination operations lead to harm to utility customers. UE and CIPSCO will
notify the Commission when the required approvals are received.
Such state commission actions manifest the recognition by those commissions
that the existence of both gas and electric systems in the Ameren holding
company system will allow Ameren's customers greater choice to meet their energy
needs, especially given the fact that the electric and gas systems operate in
substantially the same territory, while sharing in the synergies that result
from the Transaction. Moreover, the prior fear that a holding company such as
Ameren would be able to greatly emphasize one form of energy over the other
based on its own agenda has dissipated both because of the competitive nature of
the energy market, which requires utilities to meet customer energy supply
requirements or risk losing the customer to a competing supplier, and because
state regulators will have sufficient control over, and would be unlikely to
approve, a combination company that attempts to undertake such practices.
For all these reasons, the Commission should change its policy and approve
the retention by UE and CIPS of their respective gas properties as contemplated
by the Transaction. No policy would be furthered by requiring divestiture, and,
indeed, state AND national policy would be thwarted by such a requirement.
ii. Other Businesses
As a result of the Transaction, the nonutility businesses and interests of
UE and CIPSCO described in Item l.B.3 above will become businesses and interests
of Ameren. The total assets of all nonutility investments of UE and CIPSCO at
June 30, 1996 ($140.7 million) constituted less than 1.6% of pro forma
consolidated assets of Ameren or about 2% of pro forma consolidated
capitalization.
From UE, Ameren will hold the following nonutility subsidiaries,
investments or businesses:
- - Steam heating operations of UE.
- - Union Electric Development Corporation ("UEDC") - Ownership of energy
related or civic and community development related investments in the UE
service area. All of UE's nonutility investments are made through UEDC
(with one exception noted below). At June 30, 1996, the total amount
invested in such nonutility investments was $22.4 million. Except as noted
below, all of these investments are passive investments in entities in
which neither UE nor any of its affiliates participates in management or
exercises control. These investments are categorized as follows:
Energy/Utility Related
Gateway Energy Alliance -- At June 30, 1996, $368,000 was invested in
a 50% interest in this limited liability corporation, which is
proposing to develop a chilled water/steam project in the St. Louis,
Missouri area. In addition, this
64
<PAGE>
corporation is exploring other non-electric or gas utility related
activities in St. Louis.
CellNet, Inc. -- Subsequent to June 30, 1996, $10 million was invested
(representing 1.3% of the equity) in this corporation, which is
developing an automated meter reading system for UE as well as other
utility companies. The amount so invested is included in the aggregate
amounts of UEDC and CIPSCO Investment nonutility investments referred
to above.
EnviroTech Investment Fund LLC -- At June 30, 1996, $2 million was
invested in or committed directly by UE (not UEDC) to a 6% interest in
this limited liability corporation, which will make investments in
various companies developing alternative and renewable energy
technologies, environmental and waste treatment technologies and
services, energy efficiency technologies, and other technologies
related to improving the generation, transmission and delivery of
electricity. In addition, a UE pension fund over which UE exercises
investment discretion holds a 9% interest in Envirotech, with $3
million invested or committed. One UE officer is one of a 10-member
advisory board of EnviroTech, which is empowered to approve
investments that fall outside of the types specifically approved by
EnviroTech's charter documents.
On-Call Appliance Plan -- UEDC operates an appliance warranty program
where, for a fee, it provides warranty coverage for certain appliances
including heating and cooling equipment and water heaters. UEDC has
invested less than $500,000 in this business.
Demand Side Management -- UEDC has engaged in providing energy audit
and energy management services to enable a client to modify its
facilities and energy usage to reduce energy consumption.
Community and Civic Development/Venture Capital
Civic Ventures LLC -- At June 30, 1996, $200,000 was committed, of
which $20,000 was invested, in a 4.67% interest in this limited
liability corporation, which is a venture capital fund for minority
business development. It is expected that such venture capital
investments will primarily be made in enterprises in Missouri and
Illinois.
Gateway National Bank -- At June 30, 1996, $60,000 was invested in
preferred stock of this corporation, which specializes in minority
business development lending activities and residential mortgages in
minority areas. It is expected that such business development loan
activities will be made primarily in enterprises in Missouri or
Illinois.
Laclede's Landing Redevelopment -- At June 30, 1996, $10,000 was
invested in a less than 5% limited partnership interest in this
limited partnership,
65
<PAGE>
which is engaged in neighborhood commercial redevelopment projects in
St. Louis, Missouri.
Kiel Investments -- At June 30, 1996, $1.8 million was invested in a
7% limited partnership interest in limited partnerships that own and
operate the Kiel Center, a 20,000-seat multipurpose arena in St.
Louis, Missouri and that own the St. Louis Blues Hockey Club. In
addition, a charitable trust over which UE exercises investment
discretion holds a 1.37% limited partnership interest with a $650,000
investment. These investments were made to further economic
development of downtown St. Louis.
St. Louis Equity Fund -- At June 30, 1996, $4.2 million was invested
in or committed to be invested in varying percentages (not greater
than 23%) of limited partnership interests or limited liability
interests in eight limited partnerships or limited liability
corporations that own low-income housing in the St. Louis, Missouri
area. Such investments produce low-income housing federal and state
income tax credits for UE. Such investments have been made or
committed each year since 1989 in an amount not in excess of $600,000
in any year. An officer of UE and Ameren acts as chairman of the board
of the Fund and an officer of UE is on the investment policy committee
of the Fund. Other major St. Louis corporations are investors and also
participate in various committees./32/
Housing Missouri -- At June 30, 1996, $300,000 was invested in or
committed to a 14% interest in this limited liability corporation,
which owns low income housing in Missouri exclusive of the St. Louis
area. Such investments produce low income housing federal income tax
credits for UE./33/ One officer of UE
- ----------------
/32/ UEDC's investments in limited partnerships which are engaged in providing
low income housing are distinguishable from the situation in MICHIGAN
CONSOLIDATED GAS CO., 44 SEC 361, AFF'D, 444 F.2d 913 (D.D.C. 1971)
("MICHIGAN CONSOLIDATED"). In that case, the registered holding company,
through wholly owned subsidiaries, was actively engaged in the development,
financing, construction and other aspects of the business of providing low
income housing. The Commission found that this business was not
functionally related to the utility business and could not be retained.
Here, UEDC is a passive, limited partner investor in a number of low income
housing projects developed and managed by non-affiliated entities. UEDC's
investments in these limited partnerships are for the purposes of obtaining
federal and state income tax credits (see note 37 below) and fulfilling
UE's civic responsibilities in the communities it serves. Notwithstanding
MICHIGAN CONSOLIDATED, the Commission has the authority under Section
9(c)(3) of the Act to permit Ameren to continue to hold these investments
as being in the ordinary course of business and not detrimental to the
public interest or the interest of investors or consumers.
/33/ See note 32 above.
66
<PAGE>
is on the board of directors and investment policy committee of
Housing Missouri.
From CIPSCO, Ameren will hold the following nonutility subsidiaries and
investments:
- - CIPSCO Investment--organized to manage CIPSCO's nonutility investments. Has
four first-tier subsidiaries: CIPSCO Securities Company, CIPSCO Leasing
Company, CIPSCO Energy Company, and CIPSCO Venture Company. CIPSCO
Investment has no other direct investments or business./34/ At June 30,
1996, the total amount invested through CIPSCO Investment and its
subsidiaries was $118.3 million. These investments are categorized as
follows:
- - CIPSCO Securities Company--invests in marketable securities. At June 30,
1996 $48.9 million was invested in hedged portfolios of preferred and
common stocks and other marketable securities. Of this amount,
approximately $455,000 relates to common and preferred stock of utility
companies. All of these investments are made through mutual funds or
investment managers. In no case does CIPSCO Securities (together with any
of its affiliates) own more than 5% of any class of securities of any
issuer thereof.
- - CIPSCO Leasing Company--invests in long-term leveraged lease transactions.
At June 30, 1996, $34.1 million was invested pursuant to four holdings in
leased assets consisting of a commercial jet aircraft, an interest in a
natural gas liquids plant, natural gas processing equipment and retail
department store properties.
- - CIPSCO Energy Company--seeks energy-related investment opportunities. At
June 30, 1996, $26.1 million was invested in leases, or interests in such
leases, for nine combustion turbine generating units leased to five
investor-owned utilities in the United States; and a 24.75 percent interest
in Appomattox Cogeneration Limited Partnership, which owns a power sales
agreement for electricity produced at a 40-mW cogeneration facility at
Hopewell, Virginia.
- - CIPSCO Venture Company--invests within the CIPS service territory. At June
30, 1996, $700,000 was invested in a limited partnership for the
construction of a building which is leased to a manufacturing firm and
unimproved land to be developed for industrial sites in Illinois.
At June 30, 1996, CIPSCO Investment also had $6.1 million of temporary
marketable investments and no short-term borrowings and had $2,359,400 committed
to investments in Illinois affordable housing programs.
The nonutility interests held by UE and CIPSCO are shown on Exhibits E-8
and E-9.
- ----------------
/34/ Certain of the marketable securities described below as being held by
CIPSCO Securities are held directly by CIPSCO Investment.
67
<PAGE>
Standard for retention: Section 11(b)(1) permits a registered holding
company to retain "such other businesses as are reasonably incidental, or
economically necessary or appropriate, to the operations of [an] integrated
public utility system." Under the traditional cases interpreting Section 11, an
interest is retainable if (1) there is an operating or functional relationship
between the operations of the utility system and the nonutility business sought
to be retained, and (2) retention is in the public interest./35/ In addition,
the Commission has stated that "retainable nonutility interests should occupy a
clearly subordinate position to the integrated system constituting the primary
business of the registered holding company."/36/ As set forth more fully below,
the nonutility business interests that Ameren will hold through UE and CIPSCO
all meet this standard.
In particular, it is important to note that the businesses in question
provide benefits to customers, investors and the public. Businesses such as
CIPSCO Venture Company and the community and civic development investments of
UEDC provide a positive benefit to customers and the public and thereby promote
the company's goodwill, to the benefit of investors. All the other investments
of CIPSCO Investment and UEDC are either marketable securities or longer-term
energy-related, tax advantaged or passive investments. None of the investments
of CIPSCO Investment or UEDC involves the active management of any business.
These investments are financial only and are clearly incidental and DE MINIMIS
in relation to the utility businesses. CIPSCO Investment's business goals are to
produce a return higher than possible for the regulated utility while insulating
the utility from the risks of such investment. UEDC has been used primarily to
enable UE to meet its civic responsibilities to the community and to hold
certain energy related investments. Further, the Transaction is, at heart, a
utility combination, in which the nonutility businesses are small and only
incidentally involved, amounting, in the aggregate, to less than 1.6% of the
consolidated assets and less than 0.5% of consolidated revenues of the Ameren
system. Finally, this is not a case in which an existing registered holding
company system is acquiring new nonutility interests; rather, Ameren is only
seeking authorization to retain the nonutility interests held by UE and CIPSCO
before the Transaction./37/
- ----------------
/35/ SEE, E.G., GENERAL PUBLIC UTILITIES CORP., 32 SEC 807, 839 (Dec. 28, 1951).
SEE ALSO MICHIGAN CONSOLIDATED GAS CO., 44 SEC 361, 365 (June 22, 1970),
AFF'D, 444 F.2d 913 (D.C. Cir. 1971); UNITED LIGHT AND RAILWAYS CO., 35 SEC
516, 519 (Jan. 22, 1954).
/36/ UNITED LIGHT AND RAILWAYS CO., 35 SEC at 519.
/37/ As noted below, Ameren is seeking to make certain additional investments in
the future. Also, it is important to note that approximately $60 million of
CIPSCO Investment's $118.3 million total investments are in the form of
leveraged leases. The investment return on the leveraged lease investments
is significantly impacted by the favorable tax consequences of such
investments. Similarly, approximately $4.5 million of UEDC's investments
produce low-income housing federal income tax credits. Early disposition of
these investments would generally have serious adverse tax consequences,
thus negatively impacting expected returns.
68
<PAGE>
The investment programs of UEDC and CIPSCO Investment have been found to be
in the public interest by the ICC. UNION ELECTRIC CO., Docket 94-0237 (Sept. 21,
1994) (approving investments in UEDC) (the "UEDC Order"); CENTRAL ILLINOIS
PUBLIC SERVICE CO., Docket 86-0256 (Oct. 7, 1987, order on reopening Apr. 5,
1989) (approving formation of CIPSCO as holding company for CIPS) (the "CIPSCO
Order")./38/
The UEDC Order notes that UE's investments in UEDC would be for the purpose
of benefiting and improving UE's business and/or service area and to make
charitable contributions. The ICC found that investments in UEDC for such
purposes "are in the public interest and should be approved." Under the UEDC
Order, UE is limited to investing in UEDC not more than $80 million as of
December 31, 1997, not more than $90 million as of December 31, 1998 and not
more than $100 million at any time thereafter. All investments made through UEDC
and described herein were in compliance with the requirements of the UEDC Order.
In connection with the formation of CIPSCO as a holding company for CIPS,
the ICC extensively reviewed CIPSCO's proposal to create CIPSCO Investment as a
vehicle for making nonutility investments. CIPS represented that one of the
principal purposes for the holding company reorganization was to permit the
diversification into other business opportunities. The CIPSCO Order notes that
such diversification would be for (1) service area development, (2) greater
utilization of utility resources and (3) direct acquisition of existing business
or other properties. The ICC imposed conditions designed to prevent cross
subsidization and other potential harms to ratepayers in addition to the
protections afforded by Illinois statutes. The ICC found that the CIPSCO
reorganization, including the anticipated nonutility diversification, was in the
public interest by making the findings required by the Illinois Public Utilities
Act./39/
As described below, Ameren's nonutility businesses should be retainable
under Commission precedent. Further, certain of these investments would be
energy-related companies under the Commission's proposed Rule 58. Under proposed
Rule 58, an energy-related company is a company that derives or will derive
substantially all of its revenues (exclusive of revenues from temporary
investments) from one of the twelve businesses described in the Rule and from
such other activities and investments as the Commission may approve under
Section 10. Proposed Rule 58 would require that the aggregate investment in
"energy related" companies not exceed 15% of the consolidated capitalization of
a registered holding company. As of June 30, 1996, the aggregate investment in
"energy
- ----------------
/38/ The ICC has extensive jurisdiction over the formation of holding companies
and transactions between regulated utilities and their "affiliated
interests" and certain other entities. The order approving investments in
UEDC was entered under the affiliated interest provisions of 220 ILCS 5/7-
101 and the provisions of 220 ILCS 5/7-102 regulating certain
intercorporate relationships including diversion of utility assets. The
order approving the formation of CIPSCO as a holding company for CIPS was
entered under 220 ILCS 5/7-204. These provisions of Illinois law are
described in more detail under Item 4.C. below at notes 50 to 56.
/39/ The required public interest findings are set out in note 51 below.
69
<PAGE>
related" companies of CIPSCO Investment and UEDC would come within that
limitation and would constitute about 2% of Ameren's consolidated
capitalization.
In the 1995 Report, in addition to the proposed Rule 58 safe harbor for
energy-related diversification, the Division suggested the adoption of a DE
MINIMIS "budget approach" for limited investments in activities which do not fit
within previous orders of the Commission, yet appear to be within the meaning of
the "other business" clauses of Section 11. The Division suggested that this
approach would allow registered holding companies to make minimal investments
without regard to the identity of each investment up to a certain authorized
amount, provided certain structural considerations were observed which limited
the potential losses to the amount of the investment and insulated the other
system assets by isolating the activity in a separate subsidiary./40/
Furthermore, under the provisions of Section 9(c)(3), the Commission may
permit investments which it determines are "appropriate in the ordinary course
of business" and "not detrimental to the public interest or the interest of
investors or consumers."
The following is a description of the specific bases under which the
nonutility investments may be retained:
- - Community Development (UEDC's Community and Civic Development/Venture
Capital investments, CIPSCO Venture Company and certain CIPSCO Investment
commitments): Under Rule 40(a)(5), registered holding company systems are
permitted to invest in community development projects similar to those in
which UEDC and CIPSCO Venture Company invest. Under that Rule, investments
may be made up to $5 million annually in qualified state sponsored
industrial development companies and up to $1 million annually in other
local industrial or non-utility enterprises. The Commission has in specific
cases authorized investments in excess of the dollar limitations of Rule
40(a)(5). SEE, E.G., EAST OHIO GAS CO., 45 SEC Docket 766 (Feb. 27, 1990)
(authorizing $500,000 investment in limited partnerships engaged in
financing development of urban real estate projects aimed at "impact[ing]
favorably upon urban blight"); OHIO POWER CO., 52 SEC Docket 919 (Aug. 11,
1992) (authorizing loan to non-profit corporation for construction of
building in service territory). SEE ALSO NORTHEAST UTILITIES, 40 SEC Docket
412 (Feb. 24, 1988) ($250,000 investment in locally focused venture capital
fund); CONSOLIDATED NATURAL GAS CO., 33 SEC Docket 1192 (Aug. 20, 1985)
($100,000 investment in fund formed to encourage and finance local
entrepreneurial ventures). Further, the Commission has approved investments
in limited partnerships formed to make venture capital investments within
the affiliated utility's service area. SEE, E.G., GEORGIA POWER CO., 55 SEC
Docket 1860 (Dec. 15, 1993) (limited partnership formed to provide venture
capital to high-technology companies within utility's service territory);
HOPE GAS, INC., 53 SEC Docket 633 (Jan. 26, 1993) (venture capital
- ----------------
/40/ 1995 Report at 89-90. The Division also recommended a flexible approach
with respect to investments which did not meet the energy-related test of
proposed Rule 58 and exceeded the DE MINIMIS amount.
70
<PAGE>
partnership designed to provide venture capital to local business); THE
POTOMAC EDISON CO., 48 SEC Docket 1409 (May 14, 1991) (risky, for-profit,
economic development corporation created to stimulate and promote growth
and retain jobs). SEE ALSO MIDDLE SOUTH UTILITIES, INC., 26 SEC Docket 1693
(Jan. 11, 1983) (authorizing the creation of a nonutility subsidiary to
investigate new business opportunities). Ameren's total investments in this
area (made over several years) would amount to $7,656,316.
- - Temporary Investments/Marketable Securities (CIPSCO Investment and CIPSCO
Securities Company): Under Section 9(c)(2) and Rule 40(a)(1), registered
holding company systems are permitted to acquire marketable securities.
Substantially all the investments of CIPSCO Securities qualify for this
exception (except to the extent non-debt securities do not fall under such
Rule). To the extent any holdings are not marketable, the Commission will
view the "functional relationship" requirement of Section 9(c)(3) less
strictly when the investment at issue--as here--evolved in connection with
the system's utility business, is not significant in relation to the
utility system's total financial resources, and has potential to benefit
investors and/or consumers. SEE JERSEY CENTRAL POWER & LIGHT CO., 37 SEC
Docket 1243 (Mar. 18, 1987). CIPSCO Securities Company's investments
(including the common and preferred stocks) are all highly liquid temporary
investments or readily marketable securities that are held pending
application to long-term investment opportunities. Such opportunities could
include investments in UE or CIPS to the extent necessary and appropriate
and as approved, to the extent required, by regulators.
- - Leveraged Leases (CIPSCO Leasing Company): The Commission has approved
investment in leveraged leases under Section 9(c)(3), which exempts from
Section 9(a) and Section 10, "such commercial paper and other securities,
within such limitations, as the Commission may by rules and regulations or
order prescribe as appropriate in the ordinary course of business of a
registered holding company or subsidiary company thereof and as not
detrimental to the public interest or the interest of investors or
consumers." CENTRAL AND SOUTH WEST CORP., 32 SEC Docket 412 (Jan. 22,
1985). As the Commission noted in CENTRAL AND SOUTH WEST, title held by the
lessor in such circumstances is insufficient to make lessor an "owner"
under Section 2(a)(3) or (4) of the Act. Moreover, attempting to reduce
one's tax liability via the leveraged lease structure is within the
ordinary course of business. CIPSCO Leasing Company, like the leasing
concern in CENTRAL AND SOUTH WEST, makes the type of passive investment
contemplated by Section 9(c)3). St. Louis Equity Fund and Housing Missouri
are also tax advantaged investments.
- - Energy-Related Investments (UEDC's Energy/Utility Related investments;
CIPSCO Energy Company): The Commission has approved investments similar to
those made by UEDC described under "Energy/Utility Related" above. In
CINERGY CORP., 61 SEC Docket 823 (Feb. 20, 1996), the Commission approved
investments in two subsidiaries that would conduct chilled water
operations. In CENTRAL AND SOUTH WEST CORP., Release No. 35-26250 (Mar. 14,
1995), approval was granted to develop and provide meter reading services
to non-affiliated utility companies. Several other registered holding
companies have received approval to invest in EnviroTech
71
<PAGE>
partnerships. SEE, E.G., SOUTHERN CO., Release No. 35-26240 (Feb. 28,
1995). Appliance sales, installation and servicing businesses have been
approved and are included as energy related businesses in Proposed Rule 58.
SEE, E.G., CONSOLIDATED NATURAL GAS, Release No. 35-26234 (Feb. 23, 1995).
Finally, the Commission has approved various demand side management or
energy conservation services, and such activities are included as energy
related business in Proposed Rule 58. SEE, E.G., EASTERN UTILITIES
ASSOCIATES, Release No. 35-26232 (Feb. 15, 1995). Under legislation enacted
in 1985, 1986 and 1992, registered holding companies and their subsidiaries
may own qualifying cogeneration facilities and qualifying small power
production facilities (collectively, "QFs"), as defined under the Public
Utility Regulatory Policies Act of 1978, as amended ("PURPA"), in light of
the requirements of section 11(b)(1) of the Act./41/ For purposes of the
Act, a QF constitutes a nonutility investment if made by a registered
holding company./42/ The 1985 amendment permitted registered gas holding
companies to acquire cogeneration QFs without regard to the requirement of
a functional relationship between the QF and the utility business of the
registered system./43/ The 1986 legislation provided similar relief to
registered electric holding companies./44/ The two amendments thus
permitted registered holding companies and their subsidiaries to own
cogeneration QFs without regard to location. The 1992 amendment eliminated
the distinction made in the earlier amendments between cogeneration QFs and
small power production QFs. Sections 32 and 33 of the Act permit registered
holding companies to invest in EWG's and foreign utility companies subject
to the requirements of those sections and the commission's rules
thereunder. CIPSCO Energy Company's investments, like CIPSCO Leasing
Company, are in the form of leveraged leases of electric generating
- ----------------
/41/ PURPA appears generally in 16 U.S.C. (S) 2601 et seq. Section 3(18) of the
Federal Power Act ("FPA"), as amended by PURPA, defines a cogeneration
facility as a facility which produces - (i) electric energy, and (ii) steam
or forms of useful energy (such as heat) which are used for industrial,
commercial, heating, or cooling purposes. 16 U.S.C. (S) 796(18)(A). Section
210 of PURPA encourages energy conservation by directing the FERC to define
and to prescribe rules that would exempt so-called "qualifying"
cogeneration facilities and "qualifying" small power production facilities
from the FPA, the Act, and certain state laws "if the [FERC] determines
such exemption is necessary to encourage cogeneration and small power
production." 16 U.S.C. (S) 824a-3(e)(1). The rules adopted by the FERC
concerning qualifying facilities require electric utilities to interconnect
with QFs and to offer to purchase power from, and sell power to, QFs, and
set the general standard for determining the rates for power sales
transactions with QFs. 18 CFR 292.301-308.
/42/ Under section 210 of PURPA, a QF is exempt under the Act from the
definition of an "electric utility company" and is entitled to other
benefits under state and federal law.
/43/ Pub. L. No. 99-186, 99 Stat. 1180 (codified at 15 U.S.C. (S) 79k note
(1988)).
/44/ Pub. L. No. 99-553, 100 Stat. 3087 (codified at 15 U.S.C. (S) 79k note
(1988)).
72
<PAGE>
equipment or interests. Proposed Rule 58 would require that the aggregate
investment in "energy related" companies not exceed 15% of the consolidated
capitalization of a registered holding company. As of June 30, 1996, the
aggregate investment in "energy related" companies of UEDC and CIPSCO
Investment would come within that limitation and would constitute about 2%
of Ameren's consolidated capitalization.
- - Steam Heating (UE): The steam heating business of UE, which is located
exclusively in its service territory and limited to Jefferson City,
Missouri, serves the needs of the Missouri State Capitol complex and had
annual revenues, under rates approved by the MPSC, of approximately
$452,000 for the 12 months ended June 30, 1996 (0.02% of UE's total
revenues) and net assets of $400,000 (0.005% of UE's total net assets). The
steam is supplied by a plant formerly used by UE to generate electricity
for its system. The retention of this business will further Ameren's
ability to be an energy service company providing consumers with additional
options to meet their energy needs, thereby allowing Ameren to compete more
effectively in the energy-service business. The Commission has previously
approved the retention of such businesses. SEE, E.G., IN RE GENERAL PUBLIC
UTILITY CORP., 32 SEC 807, 840-841 (Dec. 28, 1951) (Commission authorized
retention of steam heating systems. Steam from such systems was used to
generate electricity and sold to customers for heating purposes.) SEE ALSO
IN RE THE NORTH AMERICAN CO., 11 SEC 194 (Apr. 14, 1942) (Commission
authorized retention of steam heating operations which provided steam heat
to customers and was used in the generation of electricity.) In CINERGY
CORP., 61 SEC Docket 823 (Feb. 20, 1996) (Release No. 35-26474), the
Commission found a district heating and cooling business which also
provided steam to be functionally related to the utility business. Since
the Commission has determined that steam heating operations, whether used
for internal generation purposes or for direct sale to customers, are
reasonably incidental to the operation of an electric utility system, this
business may be retained. The production, conversion and distribution of
thermal energy products, including process steam and chilled water, is also
permitted by proposed Rule 58. Thus, the production and distribution of
thermal energy is reasonably incidental to Ameren's utility operations and
may be retained.
In addition to approval to retain investments as described above made
through the date of this Application/Declaration, Ameren hereby seeks approval
to make through UEDC or CIPSCO Investment (or other appropriate subsidiary),
through a date not later than five years from the date of the Commission's
approving order in this docket, the following additional investments:
1. the consummation of investments for which commitments have been made
and are outstanding on or prior to the date of such order in the
entities described above (such commitments made to date are identified
above);
2. additional investments in the entities described above and investments
in entities which are substantially similar to the investments
described above but which fall outside those permitted by Commission
rule to be made without specific approval;
73
<PAGE>
3. investments in "energy related" companies within the meaning and to
the extent permitted by Rule 58, if adopted; and
4. investments in other businesses which are appropriate and in the
ordinary course of business and not detrimental to the public interest
and which are specifically described in an amendment hereto filed
prior to the entry of such order;
provided that all such investments, when aggregated with the investments
specifically described above (exclusive of any investment which would be
permitted pursuant to any rule not imposing any aggregate limitation), will not
exceed 15% of Ameren's consolidated capitalization. This aggregate limitation is
consistent with proposed Rule 58 and is consistent with the budget approach
recommended by the Division. SEE 1995 Report at 89-90. All of the investments
outlined above would be made through UEDC, CIPSCO Investment or subsidiaries
thereof and thus be separated from the utility business and, without further
approval of the Commission, will be nonrecourse to Ameren and any of its utility
subsidiaries. Ameren would make such quarterly or other reports to the
Commission describing such investments as are required by the order in this
docket.
b. Section 10(c)(2)
Because the Transaction is expected to result in substantial cost savings
and synergies, it will tend toward the economical and efficient development of
an integrated public utility system, thereby serving the public interest, as
required by Section 10(c)(2) of the Act.
i. Efficiencies and Economies
The Transaction will produce economies and efficiencies more than
sufficient to satisfy the standards of Section 10(c)(2) of the Act. Although
some of the anticipated economies and efficiencies will be fully realizable only
in the longer term, they are properly considered in determining whether the
standards of Section 10(c)(2) have been met. SEE AMERICAN ELEC. POWER CO., 46
SEC 1299, 1320-1321 (July 21, 1978). Some potential benefits cannot be precisely
estimated; nevertheless they too are entitled to be considered: "[S]pecific
dollar forecasts of future savings are not necessarily required; a demonstrated
potential for economies will suffice even when these are not precisely
quantifiable." CENTERIOR ENERGY CORP., 35 SEC Docket 769, 775 (Apr. 29, 1986).
UE and CIPSCO have estimated the nominal dollar value of synergies from the
Transaction to be approximately $686 million over the 10-year period from 1997
to 2006./45/ The Transaction is expected to yield several types of: (1)
purchasing economies; (2) electric production cost savings; (3) labor cost
savings; (4) administrative and general savings; (5) natural gas economies; and
(6) other operations savings. The amount of savings currently estimated in each
of these categories, on a nominal dollar basis, is summarized in the table
below:
- ----------------
/45/ See Note 2 herein.
74
<PAGE>
<TABLE>
<CAPTION>
Category Amount
-------- (in millions)
-------------
<S> <C>
Purchasing Economies $ 84
Electric Production Cost Savings $101
Labor Cost Savings $267
Administrative and General Savings $235
Natural Gas Economies $ 37
Other Operations Savings $ 35
----
Total Gross Savings $759
Transaction Costs (22)
Transition Costs (51)
----
Net Merger Savings $686
</TABLE>
UE and CIPSCO have estimated that, overall, on a nominal dollar basis, merger
savings will flow to UE and CIPS in proportion to the size of the electric and
natural gas businesses in each company. About 70 percent of electric savings
will flow to UE and 30 percent will flow to CIPS. In natural gas, the split is
expected to be about 30 percent to UE and 70 percent to CIPS.
These expected savings exceed the anticipated savings in a number of recent
acquisitions approved by the Commission. SEE, E.G., KANSAS POWER & LIGHT CO., 50
SEC Docket 1224 (Feb. 5, 1992) (expected savings of $140 million over five
years); IE INDUSTRIES, 48 SEC Docket 1735 (June 3, 1991) (expected savings of
$91 million over ten years); MIDWEST RESOURCES, 47 SEC Docket 252 (Sept. 26,
1990) (estimated savings of $25 million over five years). The savings are
comparable to other recently completed or proposed transactions that are similar
in scope to the Ameren Transaction. CINERGY CORP. 57 SEC Docket 2353 (Oct. 21,
1994) ($895 million over 10 years); NEW CENTURIES ENERGIES, Inc. (File No. 70-
08787) ($770 million over 10 years); INTERSTATE ENERGY CORP. ($700 million over
10 years). The Ameren savings categories are described in greater detail below.
Purchasing Economies: CIPSCO and UE estimate that approximately $84
million in savings on a nominal dollar basis can be achieved. Combining
companies can achieve savings through the centralization of purchasing and
inventory functions related to the construction, operation and maintenance
of generating plants, service centers, warehouses and headquarters. In
addition, combining the purchases of the two companies results in greater
purchasing power, which provides additional cost savings through lower unit
prices.
With respect to the purchase of goods, i.e, materials and supplies,
savings can be realized in the procurement of commodity items, consumables
and equipment, e.g., pipe, connectors and fittings and tools for gas
utilities and conductors, wire, cable and other equipment for electric
utilities. Savings also may be realized in the cost associated with
maintaining appropriate stock levels of inventory. In addition,
standardization of system components such as gas mains and pipe for gas
utilities or copper wire, transformers and conductors for electric
utilities, can be achieved through a common design process, providing
additional savings opportunities.
75
<PAGE>
With respect to the procurement of services, particularly contract
services such as pipe inspection, trenching and construction, line and pole
inspection, landscaping and tree trimming and outage assistance, a
combination will result in a consolidation of expenditures and, typically,
in contracting for such services from fewer sources. Cost savings are
created by achieving a lower per unit cost for the service provided due to
a broader contract or the repackaging of work into more attractive options
to the contractor. This volume purchasing of services is the primary method
through which service procurement savings are realized.
Electric Production Cost Savings: CIPSCO and UE estimate that
production cost savings (including fuel savings) of approximately $101
million on a nominal dollar basis will result. Of this total, $74 million
relates to energy production savings based on joint dispatch and $9 million
of savings is due to sharing of non-spinning reserves, coordinated
maintenance scheduling and improved heat rates. Another $18 million in
savings relates to coal purchases and sulfur dioxide emission allowances
made possible by joint purchases and operation. The EPRI MIDAS production
costing computer model was used to estimate the savings possible from joint
dispatch. The model is commonly used in the analysis of different
production costing scenarios in long range planning such as for least cost
planning. In simple terms, three computer simulations were performed. The
first two simulations assumed that UE's and CIPS' generation systems would
be operated as stand-alone systems. The third simulation assumed that the
combined generation resources of the two systems would be operated as one
system. Annual energy costs for the three simulations were collected. The
two stand-alone system simulation results were added together and compared
to the results for the combined system operation simulation. The difference
in the two results was identified as the potential savings from joint
dispatch.
Labor Cost Savings: CIPSCO and UE estimate that a net reduction in
labor costs of approximately $267 million on a nominal dollar basis can be
achieved as a result of the Transaction through elimination of
approximately 320 equivalent duplicative positions in certain corporate,
administrative and technical-support functions. The labor reductions are
estimated to be achieved essentially through attrition.
Administrative and General Savings: CIPSCO and UE estimate that a
reduction in non-labor administrative and general expenses totaling
approximately $235 million on a nominal dollar basis would be possible
through reductions in certain non-labor costs, primarily through the
consolidation of overlapping or duplicative programs and expenses. The
duplicative programs include information services, professional services,
vehicles, miscellaneous overhead, benefits administration, insurance,
advertising, shareholder services, and facilities.
Natural Gas Economies: The companies estimate that, in the first 10
years after the Transaction, $37 million of savings can be realized by
combining the gas supply functions of the companies. The savings are
expected to come from: reducing the amount of peak day capacity needed,
reducing the amount of balancing services
76
<PAGE>
that are needed, using the increased competitive leverage of the combined
companies to get better rates on the capacity they reserve, and integrating
the purchases of gas for the two gas systems on common pipelines. Of
course, some of the savings in corporate programs and personnel costs will
also reduce costs allocable to the gas service function.
Other Operations Savings: CIPSCO and UE estimate that other operations
savings of approximately $35 million on a nominal dollar basis will be
achieved as a result of the Transaction. These savings are made possible by
consolidating power plant services, extending the time period between
routine power plant maintenance outages and by sharing work and load
management technology in region operations.
Additional Expected Benefits: In addition to the benefits described above,
there are other benefits which, while presently difficult to quantify, are
nonetheless substantial. These other benefits include reduced future rate
increases, increased marketing opportunities, expanded management resources,
more diverse service territory and increased community involvement.
Reduced Future Rate Increases: The operating cost savings resulting
from the Transaction will allow both UE and CIPS to hold future rate
increases below what would otherwise be necessary for the individual
utilities, thus maintaining the low-cost advantage currently enjoyed by
customers of CIPS and UE.
Increased Marketing Opportunities: The combined companies will have
enhanced opportunities for marketing in the wholesale and interchange
markets. The combined companies will have electric interconnections with 28
other utility systems, enhancing opportunities to make sales transactions
with these systems and others.
Expanded Management Resources: In combination, UE and CIPSCO will be
able to draw on a larger and more diverse mid- and senior-level management
pool to lead the combined company forward in an increasingly competitive
environment for the delivery of energy.
More Diverse Service Territory: The combined service territories of UE
and CIPS will be larger and more diverse than either of the service
territories of UE or CIPS as independent entities. This increased
geographical diversity will reduce the exposure to changes in economic or
competitive conditions in any given sector of the combined service
territory.
Community Involvement: Ameren will be a stronger partner in the
economic development efforts of the communities UE and CIPS now serve. The
philanthropic and volunteer programs currently maintained by the two
companies will be continued with the enhanced resources of the combined
entity. Moreover, Ameren's substantial customer base will give it a
stronger voice in national policy debates on issues affecting the region.
77
<PAGE>
ii. Integrated Public Utility System
(A) Electric Utility System
As applied to electric utility companies, the term "integrated public
utility system" is defined in Section 2(a)(29)(A) of the Act as:
a system consisting of one or more units of generating plants and/or
transmission lines and/or distributing 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 operation 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.
On the basis of this statutory 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 acquisition of securities:
(1) the utility assets of the system are physically interconnected or
capable of physical interconnection;
(2) the utility assets, under normal conditions, may be economically
operated as a single interconnected and coordinated system;
(3) the system must be confined in its operations to a single area or
region; and
(4) 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.
ENVIRONMENTAL ACTION, INC. V. SEC, 895 F.2d 1255, 1263 (9th Cir. 1990) (citing
IN RE ELECTRIC ENERGY, INC., 38 SEC 658, 668 (1958)). The Transaction satisfies
all four of these requirements.
First, UE and CIPS are already physically interconnected, as further
described herein. See Item 1.B.4. Both UE and CIPS are physically
interconnected with EEI.
Second, UE and CIPS will be economically operated as a single
interconnected and coordinated system. CIPS and UE are currently interconnected
at nine tie points, four of which have two-way transfer capability where power
and energy can flow freely in either direction and five of which are operated as
radial ties where the power and energy can be moved in only one direction. The
interconnections with two-way transfer capacity have a maximum total transfer
capability of 791 mW. With the transfer of UE's Illinois service area and its
associated electric properties to CIPS, the companies will have an additional
78
<PAGE>
amount of tie capability, in excess of 1,000 mW, which is for power delivery
from UE to CIPS. CIPS and UE intend to jointly dispatch their generating
resources. UE and CIPS have considered the transfers resulting from joint
dispatch, and have concluded that these changes should not cause constraints on
the UE/CIPS interfaces or materially change the transfer capability that would
exist if there were no joint dispatch.
UE and CIPS are members of the Illinois-Missouri Pool with Illinois Power
Company. In addition, both utilities are members of MAIN, which is one of the
nine regional reliability councils of NERC. Membership in these groups involves
the coordination of long-range system planning and day-to-day operations. In
addition, both companies have a number of interchange agreements with other
utilities. Joint dispatch should not affect the reliability of the region, since
both companies have been complying with the same planning and operating
guidelines established in MAIN and NERC, and both companies will continue to
comply with such guidelines, individually or through their single control area,
as appropriate.
UE and CIPS will operate their combined generation and transmission
facilities as a single control area. A control area is defined by NERC as an
electric system that conforms to consistently applied regional and national
reliability standards, guidelines or criteria, and is capable of adjusting its
generation to meet its constantly changing demand, meet its interchange schedule
with other systems and contribute to the frequency control of the bulk electric
network of which it is a part. Presently, UE and CIPS operate as separate
control areas. Every control area operator is responsible for having, on an
hourly basis, sufficient generation or purchases to supply all of the expected
load of its customers, plus enough operating reserve to provide for loss of
generation or unexpected load increases. Presently, UE and CIPS perform the
activities described above for their individual control areas. After the
Mergers, these activities will be accomplished by a single control area. The
control area will interface directly with 28 other utilities to economically buy
and sell capacity and energy, using the generation and transmission resources of
the combined system. For dispatch purposes, all load requirements will be
combined and all resources will be controlled by a single automatic generation
control located in St. Louis at Ameren Services.
By dispatching on a single-system basis, the total production costs will be
lower than if the two companies were dispatched separately. As load on system
increases, it will be served instantaneously by the next available, lowest cost
source of generation, regardless of whether that generation is owned by UE or
CIPS, or, in the case of a purchase, regardless of whether the source is
connected to UE or CIPS. This change in operation should enhance interchange
purchase and sales activities. The system operators of both companies now
communicate with each other several times each day, as they do with other
interconnected companies. Subsequent to the Mergers, one group of system
operators will have all the resources and information that the two separate
groups previously had to communicate to each other. Both UE and CIPS as a single
control area will be able to interface directly with 28 interconnected
utilities, optimizing the sale and purchase opportunities. The result should be
reduced costs for UE and CIPS, because each company will have improved access to
a greater number of competitive sources of supply, thus increasing the potential
for purchases and sales. In particular, a combined operation will
79
<PAGE>
eliminate the need for a transmission charge or adder that UE or CIPS would
otherwise have had to pay to effect a purchase or sale across the other's
system. Today, the existence of such charges may preclude consummation of
certain transactions. For example, assume CIPS has two available sources of
energy, one connected with it ("Utility A"), and one connected with UE ("Utility
B"). Assume further that the price of Utility A's energy is higher than that of
Utility B's energy. However, the cost of moving Utility B's energy across UE's
system to CIPS' system exceeds the difference between Utility A's and Utility
B's prices. In such circumstances, CIPS will purchase from Utility A, because
the total cost is lower. Post-Merger, CIPS would purchase from Utility B,
because there would be no additional transmission charge, and Utility B would be
the least-cost option.
For integration purposes under the Act, what is relevant is that: (i)
Ameren will have sufficient internal transmission capacity to fully accommodate
the anticipated transfers between CIPS and UE under central economic dispatch;
and (ii) Ameren's estimated generation capacity and production cost savings can
be fully achieved without the need for contracting for transmission service with
others. The scheduled transfers to achieve the $101 million in electric
production cost savings can be achieved without exceeding the capability of the
transmission facility owned by the Ameren system.
Third, this single integrated system will be confined to the area
delineated on Exhibit E-1, covering portions of Missouri and Illinois.
Fourth, the system is not so large as to impair the advantages of localized
management, efficient operations, and the effectiveness of regulation. After the
Transaction, CIPS and UE will maintain their current headquarters as subsidiary
headquarters and as local operating headquarters for the areas they presently
serve, while Ameren maintains the system headquarters. This structure will
preserve all the benefits of localized management CIPS and UE presently enjoy
while simultaneously allowing for the efficiencies and economies that will
derive from their strategic alliance. Furthermore, as described earlier, the
system will facilitate efficient operation.
Finally, the Ameren system will not impair the effectiveness of state
regulation. UE and CIPS will continue their separate existence as before and
their utility operations will remain subject to the same regulatory authorities
by which they are presently regulated, namely the ICC, the MPSC, the FERC and
the NRC. Orders approving the Transaction by each of these agencies will be
filed herein.
In Missouri, UE has entered into a Stipulation and Agreement which, among
other matters, addresses the MPSC's jurisdiction following the Merger. UE has
agreed that the MPSC will retain retail rate authority over costs charged under
agreements with affiliates. In addition, UE has agreed to provide the MPSC
appropriate access to books, records, officers and employees of all Ameren
affiliates to permit exercise of this regulatory authority. A copy of the
Stipulation and Agreement is filed as Exhibit D-2.3. A similar jurisdictional
offer has been made to the ICC.
80
<PAGE>
(B) Gas Utility System
Section 2(a)(29)(B) defines an "integrated public utility system" as
applied to gas utility companies as:
a system consisting of one or more gas utility companies which are so
located and related that substantial economies may be effectuated by
being operated as a single coordinated system confined in its
operation 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: provided, that gas
utility companies deriving natural gas from a common source of supply
may be deemed to be included in a single area or region.
The Ameren gas utility system will meet the standard set forth in Section
2(a)(29)(B) and, therefore, will satisfy the requirements of Sections 10(c)(1)
and (2) and should be approved by the Commission.
First, both the Commission's limited precedent and current technological
realities indicate that the Ameren gas utility system will operate as a
coordinated system confined in its operation to a single area or region because
it will derive natural gas from common sources of supply, transportation and
storage. The gas utility operations of UE and CIPS will operate in a single area
or region covering portions of Missouri and Illinois. See Exhibits E-5 and E-7
hereto. The Commission has not traditionally required that the pipeline
facilities of an integrated system be physically interconnected,/46/ and instead
has looked to such issues as from whom the distribution companies within the
system receive much, although not all, of their gas supply./47/ The Commission
also has considered obtaining gas from a common pipeline/48/ as well as from
different pipelines when the gas
- ----------------
/46/ SEE IN RE PENNZOIL CO., 43 SEC 709 (Feb. 7, 1968) (finding an integrated
system where facilities both connected with an unaffiliated transmission
company but not each other). SEE ALSO, IN RE AMERICAN NATURAL GAS CO., 43
SEC 203 (Dec. 12, 1966) ("It is clear the integrated or coordinated
operations of a gas system under the Act may exist in the absence of such
interconnection").
/47/ SEE, E.G., IN RE PHILADELPHIA CO. AND STANDARD POWER AND LIGHT CO., 28 SEC
35 (June 1, 1948) ("most of the gas used by these companies in their
operations is obtained from common sources of supply"); CONSOLIDATED
NATURAL GAS CO., 45 SEC Docket 672 (Feb. 14, 1990) (finding integrated
system where each company derived natural gas from two transmission
companies, although one such company also received gas from other sources).
/48/ IN RE NORTH AMERICAN CO., 31 SEC 463 (May 19, 1950) (finding Panhandle
Eastern pipeline to be a common source of supply).
81
<PAGE>
originates from the same gas field in determining a common source of supply./49/
Since the time of most of these decisions, the state of the art in the industry
has developed to allow efficient operation of systems whose gas supplies derive
from many sources.
Because natural gas is made up of naturally occurring elements found in
geologic formations and is not a refined energy product produced from other
fuels, the natural gas and electricity industries developed in different
structures. The gas industry developed in three separate segments:
Function Ownership
-------- ---------
Production Independent Producers
Transmission/Storage Interstate Pipelines/Storage Companies
Distribution/Retail Sales Local Distribution Companies (LDCs)
While the UE and CIPS gas systems are not completely physically interconnected,
they will functionally perform as a coordinated system through the centrally
coordinated purchase of natural gas from common sources of supply, delivery
through common interstate pipelines (all of which are open access transportation
only pipelines under FERC Order 636) and storage of gas in common underground
storage facilities. This coordination will also result in greater, not lesser,
efficiency.
Most of CIPS' gas systems are currently integrated by way of physical
interconnects and contractual arrangements. This part of CIPS' overall system
comprises the areas that are served by PEPL, TRKL, TETCO and NGPL, and
represents over 80% of the total peak day demand of CIPS' entire gas system.
UE's gas systems, which are served from the same pipelines that serve the
combined part of CIPS' system, can be integrated with CIPS' integrated systems,
at least to a degree, for joint dispatch. In addition, the companies are
considering acquisition of capacity contracts on the pipelines that serve the
integrated systems. This would allow deliveries to any point on the combined gas
systems. Further, the companies may seek to have all the delivery points to the
combined systems under these contracts treated as a central delivery point. This
would increase flexibility to use the contracts with the lowest cost first
regardless of where on the combined systems the gas is needed.
As explained previously under Items 1.B.2.a.v.; 1.B.2.b.v. and 1.B.5., UE
and CIPS: (i) each contract for interstate pipeline transportation services from
PEPL, TETCO and NGPL; (ii) each contract for underground storage services from
PEPL, TETCO and NGPL; (iii) each procure transportation services from certain
non-common pipelines (MRTC, TRKL, TXG, MW, MPC and IP, and one local gas
distribution company, NIGAS) and non-
- ----------------
/49/ SEE IN RE CENTRAL POWER CO. AND NORTHWESTERN PUBLIC SERVICE CO., 8 SEC 425
(Jan. 6, 1941) (declaring an integrated system to exist where two entities
purchase from different pipeline companies since "both pipelines run out of
the Otis field, side by side, and are interconnected at various points in
their transmission system; and that they are within two miles of each other
at Kearney").
82
<PAGE>
common storage providers (Eastex, Western Gas Resources Storage Inc., MRTC and
TRKL) and (iv) each procure natural gas supplies from producers in common supply
areas: the Mid-Continent and Gulf Coast regions.
Integrated UE and CIPS gas operations would present opportunities to use
more consolidated gas supply procurement to increase competition among
suppliers, transporters and storage providers to capture approximately $37
million in delivered gas cost reductions. One hundred percent of these
reductions will flow directly through to customers under the purchased gas
adjustment (PGA) clauses in UE's and CIPS' tariffs if all of the system
purchased gas costs continue to receive PGA treatment as at present. Integrated
gas operations could also offer opportunities for more efficient utilization of
UE and CIPS peak shaving operations and more efficient reserve margins. With the
cooperation of the common pipeline interconnections, the ability to engage in
swap transactions will also exist.
Finally, the system will not be so large as to impair the advantages of
localized management or the effectiveness of regulation. As set forth in Item
3.A.2.a.i.(A)(2), the combined gas system will be smaller than many regional
competitors. Further, as noted in Item 3.A.2.b.(ii)., localized management will
be preserved. The centralized gas supply functions of Ameren will be located in
Springfield and the local functions will continue to be handled from St. Louis
and Springfield. Management will, accordingly, remain close to the gas
operations, thereby preserving the advantages of local management.
As also set forth in Item 3.A.2.(b)(ii)(A), from a regulatory standpoint,
there will be no impairment of regulatory effectiveness. The same regulators
currently overseeing these gas operations will continue to have jurisdiction
after the Transaction except that regulation will be simplified and enhanced by
transferring the UE Illinois properties to CIPS.
For all of these reasons, the post-Transaction gas operations satisfy the
integration requirements of Section 2(A)(29)(B).
3. Section 10(f)--Compliance with State Law
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 to 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.
As described in Item 4 of this Application, and as evidenced by the MPSC and ICC
applications seeking authorization of the Transaction, Ameren intends to comply
with all applicable state laws related to the Transaction.
83
<PAGE>
4. Section 9(a)(1)
Ameren is also requesting authorization from the Commission under Section
9(a)(1) of the Act for the acquisition by it of the voting securities of Ameren
Services, as part of the Transaction. Section 9(a)(1) of the Act requires a
holding company or any subsidiary thereof to obtain authorization from the
Commission before acquiring "any securities or utility assets or any other
interest in any business." In order to approve an acquisition under Section
9(a)(1), the Commission must find that such acquisition meets the standards of
Section 10 of the Act, which in turn requires compliance with Sections 8 and 11
of the Act. Ameren is requesting the Commission's authorization for these
transactions at this time to enhance administrative efficiency even though it
will not be subject to Section 9(a)(1) until consummation of the Transaction.
The acquisition by Ameren of the common stock of Ameren Services, making it
a wholly-owned subsidiary of Ameren, will allow Ameren to create a subsidiary
service company and capture economies of scale from the centralization of
administrative and general services to be provided to system companies. Since
the cost of such services is considered in rate cases, the benefits realized as
a result of Ameren Services will accrue to utility ratepayers. Virtually every
registered holding company has one or more subsidiary service companies
performing many of the same functions as Ameren Services will perform. The
acquisition of Ameren Services is in the public interest, will not unduly
complicate the capital structure of Ameren and will not cause the Ameren system
to violate any other provision of the Act. Ameren Services will have only one
class of authorized stock, which will be its common stock, all of which will be
owned by Ameren. The operation of Ameren Services and the allocation of cost for
its respective operations, are discussed in detail in Item 3.C. below.
Ameren is also requesting authorization to acquire all of the issued and
outstanding common stock of CIPSCO Investment, which serves as an intermediate
holding company for certain of the system's nonutility subsidiaries, and also to
acquire indirectly the stock of UEDC. CIPSCO Investment and UEDC provide a clear
separation between the system's utility and nonutility operations and allow for
centralization of the nonutility operations. CIPSCO Investment and UEDC will
receive services from Ameren Services. Costs for any work performed for CIPSCO
Investment or UEDC by Ameren Services will be charged to CIPSCO Investment or
UEDC in accordance with the appropriate allocation method set forth in the
General Services Agreement.
Ameren's acquisition of its own stock to satisfy the requirements of the
Ameren Plans is discussed in Item 3.A.5. Finally, Ameren is requesting approval
of the indirect acquisition of 60% of the common stock of EEI. As noted above,
the acquisition of EEI, as an incidental part of the acquisition by Ameren of
CIPS and UE, satisfies the requirements of Section 10 and 11 of the Act.
5. Other Applicable Provisions--Sections 6, 7, 12 and 13
UE and CIPSCO each have dividend reinvestment plans and, along with CIPS,
employee benefit plans which may require the issuance of common stock, described
above
84
<PAGE>
as the Ameren Plans. The Merger Agreement provides for Ameren to adopt benefit
plans with substantially the same provisions as certain of the existing benefit
plans. Ameren hereby requests authority for a period of five years following
entry by the Commission of an order in this docket, to issue or acquire or cause
to be acquired on the open market or otherwise up to 19 million shares of Ameren
Common Stock pursuant to such existing and amended or replacement Ameren Plans.
(Copies or summaries of such plans will be filed by amendment.)
The issuance by Ameren of shares of Ameren Common Stock pursuant to the
Ameren Plans and to effect the Transaction will comply with the standards of
Section 7 of the Act. With reference to Sections 7(c) and 7(d) of the Act,
Ameren Common Stock has a par value of $0.01 per share, will be Ameren's only
outstanding voting security and will not be preferred as to dividends or
distributions over any other security of Ameren. Ameren Common Stock is
reasonably adapted to Ameren's security structure (common stock being the
cornerstone of a registered holding company's capital structure).
As noted in Item 1.B.2.c. above, UE proposes to transfer the Transferred
Utility Facilities to CIPS subject to approval of the MPSC and ICC. It is
contemplated that after consummation of the Transaction, UE will declare an in-
kind dividend of the Transferred Utility Facilities to Ameren and Ameren in turn
will make an in-kind capital contribution of the Transferred Utility Facilities
to CIPS. The transfer will be made free of the lien of the UE mortgage
indentures. This transfer is to enhance the effectiveness of state regulation
and increase the efficient operations of the Ameren system by concentrating all
utility facilities in Illinois in one company. This transfer will be consistent
with the requirements of Sections 9(a)(1), 10, 11 and 12 of the Act. SEE IN RE
MANUFACTURERS LIGHT AND HEAT CO., Release No. 35-13862 (Nov. 7, 1958).
The requirements of Section 13 are discussed under Item 3.C. below.
Solicitation of proxies in connection with the benefit plans is discussed in
Item 1.D.4. above.
B. Intra-system Financing
UE has obtained ICC approval to make advances to or investments in UEDC as
permitted by the UEDC Order. See Item 3.A.2.a.ii. above. UE funds UEDC's
investments through such intercompany loans or advances or investments from time
to time. These intercompany loans bear interest at a market rate and are short-
term in nature or due on demand.
In the ordinary course of business, there have been and will continue to be
intercompany loans and advances among CIPSCO and its direct and indirect
nonutility subsidiaries including CIPSCO Investment. Generally, if at any time
during the year any of the subsidiaries of CIPSCO Investment has excess cash,
such excess is loaned to CIPSCO Investment or CIPSCO Securities. These borrowed
funds, as well as any funds borrowed under a $30 million line of credit
available to CIPSCO Investment or other bank lines, are used by CIPSCO
Investment to finance its own activities or are loaned to its subsidiaries. Such
subsidiaries will borrow funds from CIPSCO Investment, to the extent available,
to finance their own activities or to finance the activities of entities in
which they have an
85
<PAGE>
equity investment. These intercompany loans bear interest at a market rate. The
loans are generally short-term in nature or due on demand.
CIPSCO has entered into a Support Agreement dated May 21, 1992 pursuant to
which it has agreed to maintain the financial condition of CIPSCO Investment.
Beneficiaries of the Support Agreement include the lenders under the credit
agreement referred to above. In addition, CIPSCO has entered into certain
support letters and CIPSCO Investment has entered into certain guaranties in
connection with leveraged lease investments. A listing of these support
agreements and guaranties is set forth on Exhibit B-6.
UE and CIPS hereby request that the Commission approve the continuance of
all outstanding and committed intercompany loans and advances, support
arrangements and guarantees.
Ameren expects to establish a "money pool" similar to those maintained by
other registered systems whereby system companies may invest amounts temporarily
not required for their business and also borrow funds when needed. Ameren will
file for necessary approvals of the money pool to be effective after
consummation of the Transaction.
C. Ameren Services
In order to realize economies, certain administrative and service functions
will be consolidated. Ameren Services will provide UE, CIPS, UEDC and CIPSCO
Investment, pursuant to the General Services Agreement, with one or more of the
following: building services, accounting, corporate communications, corporate
planning, customer services and division support, economic development, energy
supply, engineering and construction, environmental services and safety, fossil
fuel procurement, gas supply, general counsel, human resources, industrial
relations, information services, internal audit, marketing, merger coordination,
motor transportation, purchasing, real estate, stores, tax, treasury operations,
investor services and other services. In accordance with the General Services
Agreement, services provided by Ameren Services will be directly assigned,
distributed or allocated by activity, project, program, work order or other
appropriate basis. To accomplish this, employees of Ameren Services will record
transactions utilizing existing data capture and accounting systems. Costs of
Ameren Services will be accumulated in accounts and directly assigned,
distributed and allocated to the appropriate company in accordance with the
guidelines set forth in the General Services Agreement. (See Exhibit B-4.) UE
and CIPS are currently developing the system and procedures necessary to
implement the General Services Agreement. It is anticipated that Ameren Services
will be staffed primarily by transferring personnel from the current employee
rosters of UE and CIPS. Ameren Services' accounting and cost allocation methods
and procedures will be structured so as to comply with the Commission's
standards for service companies in registered holding company systems and are
described in Exhibit B-5 hereto. Ameren Services will maintain its books and
records in accordance with the FERC Uniform System of Accounts. In determining
how to charge and allocate various costs, Ameren Services will rely on the
"Uniform System of Accounts for Mutual Service Companies and Subsidiary Service
86
<PAGE>
Companies" established by the Commission for service companies of registered
holding company systems.
As compensation for services, the General Services Agreement will provide
for the client companies to "pay to Service Company the cost of such services,
computed in accordance with applicable rules and regulations (including, but not
limited to Rules 90 and 91) under the Act and appropriate accounting standards."
Where more than one company is involved in or has received benefits from a
service performed, the General Services Agreement will provide that client
companies will pay their fairly allocated pro rata share in accordance with the
methods set out in a schedule to the General Services Agreement. Thus, charges
for all services provided by Ameren Services to affiliated utility companies and
nonutility companies will be on an "at cost" basis as determined under Rules 90
and 91 of the Act.
No change in the organization of Ameren Services, the type and character of
the companies to be serviced, the methods of allocating costs to associate
companies, or in the scope or character of the services to be rendered subject
to Section 13 of the Act, or any rule, regulation or order thereunder, shall be
made unless and until Ameren Services shall first have given the Commission
written notice of the proposed change not less than 60 days prior to the
proposed effectiveness of any such change. If, upon the receipt of any such
notice, the Commission shall notify Ameren Services within the 60-day period
that a question exists as to whether the proposed change is consistent with the
provisions of Section 13 of the Act, or of any rule, regulation or order
thereunder, then the proposed change shall not become effective unless and until
Ameren Services shall have filed with the Commission an appropriate declaration
regarding such proposed change and the Commission shall have permitted such
declaration to become effective.
Ameren will structure the General Services Agreement so as to comply with
Section 13 of the Act and the Commission's rules and regulations thereunder.
Rule 88(b) provides that "[a] finding by the Commission that a subsidiary
company of a registered holding company . . . is so organized and conducted, or
to be so conducted, as to meet the requirements of Section 13(b) of the Act with
respect to reasonable assurance of efficient and economical performance of
services or construction or sale of goods for the benefit of associate
companies, at cost fairly and equitably allocated among them (or as permitted by
[Rule] 90), will be made only pursuant to a declaration filed with the
Commission on Form U-13-1, as specified in the instructions for that form, by
such company or the persons proposing to organize it." Notwithstanding the
foregoing language, the Commission has on at least two recent occasions made
findings under Section 13(b) based on information set forth in an application on
Form U-1, without requiring the formal filing of a Form U-13-1. SEE UNITIL
CORP., 51 SEC Docket 562 (Apr. 24, 1992); CINERGY CORP., 57 SEC Docket 2353
(Oct. 21, 1994). In this Application, Ameren has submitted substantially the
same application information as would have been submitted in a Form U-13-1.
Accordingly, it is submitted that it is appropriate to find that Ameren
Services will be so organized and shall be so conducted as to meet the
requirements of Section 13(b), and
87
<PAGE>
that the filing of a Form U-13-1 is unnecessary, or, alternatively, that this
Application should be deemed to constitute a filing on Form U-13-1 for purposes
of Rule 88.
D. Other Services
In addition to the services to be provided by Ameren Services, UE and CIPS
may from time to time or in emergency situations provide one another with
certain services incidental to their utility businesses, such as meter reading,
materials management, transportation, and services of linemen and gas trouble
crews. These services will be provided at cost in accordance with the standards
of the Act and the Commission's rules and regulations thereunder.
Item 4. Regulatory Approvals
Set forth below is a summary of the regulatory approvals that Ameren has
obtained or expects to obtain in connection with the Transaction.
A. Antitrust
The HSR Act and the rules and regulations thereunder provide that certain
transactions (including the Transaction) may not be consummated until certain
information has been submitted to the DOJ and FTC and specified HSR Act waiting
period requirements have been satisfied. CIPSCO and UE will submit Notification
and Report Forms and all required information to the DOJ and FTC late in 1996 or
early in 1997. For the Transaction to be consummated, the 30-day waiting period
under the HSR Act must expire without adverse action, or any request for
additional information or documentary material, by the FTC or the DOJ.
The expiration of the HSR Act waiting period does not preclude the
Antitrust Division or the FTC from challenging the Transaction on antitrust
grounds; however, Ameren believes that the Transaction will not violate Federal
antitrust laws. If the Transaction is not consummated within twelve months after
the expiration, or earlier termination of the initial HSR Act waiting period,
CIPSCO and UE would be required to submit new information to the Antitrust
Division and the FTC, and a new HSR Act waiting period would have to expire or
be earlier terminated before the Transaction could be consummated.
B. Federal Power Act
Section 203 of the Federal Power Act of 1935, as amended (the "Federal
Power Act"), provides that no public utility shall sell or otherwise dispose of
its jurisdictional facilities or directly or indirectly merge or consolidate
such facilities with those of any other person or acquire any security of any
other public utility, without first having obtained authorization from the FERC.
UE and CIPS filed their joint application for FERC approval of the Transaction
on December 22, 1995. A copy of the petition portion of the application is
submitted with this Application/Declaration as Exhibit D-1.1. If the Commission
determines that it needs to review the exhibits and testimony filed with the
88
<PAGE>
FERC petition, the Applicants will promptly provide copies of those materials to
the Commission.
In conjunction with the application at the FERC regarding the Transaction,
CIPS and UE jointly filed single-system open access tariffs in December 1995 in
compliance with FERC policy. On April 24, 1996, FERC issued orders 888 and 889
related to its "mega-NOPR" rulemaking designed to eliminate market power held by
public utilities through the ownership of transmission systems. Citing a goal of
enhancing competition in the wholesale market for generation sales, FERC has
issued a policy which requires transmission owning public utilities to provide
transmission access and service to others in a manner similar and comparable to
that which the utility has by virtue of transmission ownership. In its Order
888, the FERC adopted pro forma tariffs for use by a utility and its
transmission customers in obtaining transmission service. Order 888 also
provides for the recovery of stranded costs at the wholesale level, based on a
revenues lost calculation, which result from the transition to an open access
business environment.
Also issued April 24, 1996, Order 889 sets forth the standards of conduct
and information requirements that must be put in place and observed by
transmission owners doing business under the open access rule. These include the
establishment by each utility of an "open access same-time information system",
or OASIS. This system will provide all information, on a real time basis, for
the utility and its customers to apply for and obtain transmission service.
Using the OASIS, the utility must obtain transmission service for its own use in
the same manner its customer will obtain service, thus assuring mitigation of
market power through control of transmission facilities. UE is preparing to
implement the requirements of Order 889. CIPS has applied for a waiver from the
requirements of Order 889 pending consummation of the Transaction.
On October 16, 1996, the FERC set the Transaction for hearing to determine
the effect of the Transaction on (1) UE's and CIPS' wholesale rates, (2) the
effectiveness of FERC regulation and (3) competition. The exact date of the
hearing has not yet been determined. FERC ordered the presiding administrative
law judge to issue an initial decision no later than April 30, 1997. FERC also
ordered UE and CIPS to submit revised non-price terms and conditions for their
tariffs which conform to the terms of the pro forma tariffs adopted in Order
888. The FERC also set for hearing the rates contained in the UE and CIPS
single-system open access transmission tariffs. These hearings were consolidated
with the hearings on non-tariff issues.
C. State Public Utility Regulation
UE has filed an Application for approval of the Transaction pursuant to
Missouri law requesting the MPSC to grant approval, INTER ALIA, of the merger of
UE into Arch Merger and to grant approval for the transfer of the Transferred
Utility Facilities to CIPS and for other related transactions necessary to
effect the merger and reorganization. UE, the MPSC staff, and other parties in
the Missouri proceeding have entered into a joint Stipulation and Agreement (the
"Stipulation") that recommends approval of the Transaction. A copy of the
Stipulation is filed as Exhibit D-2.3. A copy of the petition portion of the
Missouri filing is submitted with this Application/Declaration as Exhibit D-2.1.
The exhibits and testimony
89
<PAGE>
supporting the Missouri petition are largely duplicative of the exhibits and
testimony submitted to the FERC with Exhibit D-1.1 hereto. If the Commission
determines that it needs to review the exhibits and testimony filed with the
Missouri petition, the Applicants will promptly provide copies of those
materials to the Commission.
In Missouri, UE has entered into a Stipulation and Agreement which, among
other matters, addresses the MPSC's jurisdiction following the Mergers. UE has
agreed that the MPSC will retain retail rate authority over costs charged under
agreements with affiliates. In addition, UE has agreed to provide the MPSC
appropriate access to books, records, officers and employees of all Ameren
affiliates to permit exercise of this regulatory authority. A copy of the
Stipulation and Agreement is filed as Exhibit D-2.3. A similar jurisdictional
offer has been made to the ICC.
On September 25, 1996, the MPSC entered an Order Requesting Additional
Information directing all parties to the Missouri proceeding to submit
additional testimony prior to November 1, 1996 addressing certain issues of
"market power" raised by the MPSC. UE will submit testimony demonstrating, as it
has at FERC, that the Transaction does not raise market power concerns.
UE, CIPSCO and CIPS have filed a Joint Application for Approval of Merger
and Reorganization pursuant to the Illinois Public Utilities Act ("Illinois
PUA") requesting the ICC to grant approval, INTER ALIA, of their mergers and
reorganization, including the merger of CIPSCO into Ameren, the merger of UE
into Arch Merger and the transfer of the Transferred Utility Facilities to CIPS.
Applicants also are seeking approval of various transactions among affiliated
interests necessary to effect the Mergers and reorganization, the capital
structure of CIPS, discontinuance of service by UE and transfer to CIPS of
various Illinois certificates of convenience and necessity of UE. A copy of the
petition portion of such filing is submitted with this Application/Declaration
as Exhibit D-3.1. The exhibits and testimony supporting the Illinois petition
are largely duplicative of the exhibits and testimony submitted to the FERC with
Exhibit D-1.1 hereto. If the Commission determines that it needs to review the
exhibits and testimony filed with the Illinois petition, the Applicants will
promptly provide copies of these materials to the Commission.
Section 7-204 of the Illinois PUA requires state approval of a
"reorganization," defined as a change in the ownership of a majority of the
voting stock of a public utility./50/ Under that section, the ICC may not
approve a reorganization that "will adversely affect the utility's ability to
perform its duties under [the Illinois PUA]." The ICC is required to make five
specific findings in this regard./51/ Section 7-204 of the Illinois PUA also
provides that
- ----------------
/50/ 220 ILCS 5/7-204 and 7-204A.
/51/ The ICC must find that:
(a) the proposed reorganization will not diminish the utility's
ability to provide adequate, reliable, efficient, safe and least-cost
public-utility service;
(continued...)
90
<PAGE>
the ICC, in approving a reorganization, "may impose such terms, conditions or
requirements as, in its judgment, are necessary to protect the interests of the
public utility and its customers."
The Illinois PUA further empowers the ICC to take certain remedial measures
with regard to the operations of the utility subsidiaries of a public-utility
holding company. Among other things, the ICC may: (1) order a utility subsidiary
to cease the payment of dividends to the holding company whenever the ICC finds
that the capital of the utility would be impaired by the payment of a
dividend;/52/ (2) prohibit a utility from lending money to, and guaranteeing the
obligations of, the holding company or its nonutility subsidiaries;/53/ (3)
exercise controls against the cross-subsidization of nonutility businesses by
utility subsidiaries;/54/ and (4) regulate and prohibit certain transactions
between utility and nonutility subsidiaries./55/ The ICC is also empowered to
maintain continuing oversight over the operations of the holding company system.
The ICC has full access to the books and records of all companies in the holding
company system. Lastly, the PUA requires "stand-alone" treatment of the utility
in rate proceedings./56/
- ----------------
/51/ (...continued)
(b) the proposed reorganization will not result in the unjustified
subsidization of nonutility activities by the utility or its customers;
(c) costs and facilities are fairly and reasonably allocated between
utility and nonutility activities in such a manner that the [ICC] may
identify those costs and facilities which are properly included by the
utility for ratemaking purposes;
(d) the proposed reorganization will not significantly impair the
utility's ability to raise necessary capital on reasonable terms or to
maintain a reasonable capital structure;
(e) the utility will remain subject to all applicable laws,
regulations, rules, decisions and policies governing the regulation of
Illinois public utilities.
220 ILCS 5/7-204.
/52/ 220 ILCS 5/7-103.
/53/ 220 ILCS 5/7-102(f) and (h).
/54/ 220 ILCS 5/7-204(b).
/55/ 220 ILCS 5/7-101, 7-102, 7-204 and 7-204A(b).
/56/ 220 ILCS 5/9-230.
91
<PAGE>
The Commission has reviewed the powers of the ICC relating to holding
companies in CIPSCO INC., 47 SEC Docket 174 (Sept. 18, 1990).
D. Nuclear Regulatory Commission
UE has filed an application with the NRC requesting approval of an
amendment to the operating license for the Callaway Nuclear Power Plant to
reflect UE's future status as an operating company subsidiary of Ameren. The NRC
docketed the application on March 4, 1996. A copy of the application to the NRC
is submitted with this application as Exhibit D-4.1.
Item 5. Procedure
The Commission is respectfully requested to issue and publish not later
than November 15, 1996, 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 6, 1996, by which comments may be entered and a date not later
than December 6, 1996, 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 proposed
Transaction. 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
A. Exhibits
A-1 Restated Articles of Incorporation of Ameren
A-2 Restated Articles of Incorporation of UE
A-3 Amended and Restated Articles of Incorporation of CIPSCO
A-4 Restated Articles of Incorporation of CIPS
B-1 Merger Agreement
B-2 CIPSCO Stock Option Agreement
B-3 UE Stock Option Agreement
B-4 Form of General Services Agreement among Ameren Services, Ameren,
UE, CIPS and CIPSCO Investment
B-5 Description of Ameren Services' accounting and cost allocation
methods and procedures (To be filed by Amendment)
B-6 Description of support agreements and guarantees of CIPSCO and
CIPSCO Investment
C-1 Registration Statement of Ameren on Form S-4
C-2 Joint Proxy Statement and Prospectus (included in Exhibit C-1)
C-3 Ameren's Post-Effective Amendment to Form S-4 Registration
Statement on Form S-3 (DRIP) (To be filed by Amendment)
92
<PAGE>
C-4 Ameren LTIP Form S-8 (To be filed by Amendment)
C-5 Description of existing savings plans (To be filed by Amendment)
D-1.1 Joint Application of UE and CIPS before the FERC
D-1.2 Testimony of Rodney W. Frame before the FERC
D-1.3 Order of the FERC dated __________, 19__ (To be filed by Amendment)
D-2.1 Application of UE and Ameren before the MPSC
D-2.2 MPSC Order dated __________, 19__ (To be filed by Amendment)
D-2.3 Stipulation and Agreement filed with MPSC dated July 12, 1996
D-3.1 Joint Application of CIPS, CIPSCO and UE before the ICC
D-3.2 ICC Order dated __________, 19__ (To be filed by Amendment)
D-4.1 Application of UE before the NRC
D-4.2 Order of the NRC dated _______, 19__ (To be filed by Amendment)
E-1 Map of service areas of CIPS and UE
E-2 Map showing interconnections of UE and CIPS
E-3 Map of CIPS service area
E-4 Map of UE electrical system
E-5 Map of UE gas system
E-6 Map of CIPS electric system
E-7 Map of CIPS gas system
E-8 UE corporate chart
E-9 CIPSCO corporate chart
F-1.1 Preliminary Opinion of Counsel (To be filed by Amendment)
F-1.2 Final "Past Tense" Opinion of Counsel (To be filed by Amendment)
F-2.1 Preliminary Opinion of Counsel (Jones, Day, Reavis & Pogue) (To be
filed by Amendment)
F-2.2 Final "Past Tense" Opinion of Counsel (Jones, Day, Reavis & Pogue)
(To be filed by Amendment)
G-1 Financial Data Schedule
H-1 Opinion of Goldman Sachs
H-2 Opinion of Morgan Stanley
I-1 Annual Report of UE on Form 10-K for the year ended December 31,
1995
I-2 Annual Report of CIPSCO and CIPS on Form 10-K for the year ended
December 31, 1995
I-3 UE 1995 Annual Report to Shareholders
I-4 Statement of CIPS on Form U-3A-2 dated February 28, 1996
I-5 UE Quarterly Reports on Form 10-Q for the quarters ended March 31,
1996 and June 30, 1996
I-6 CIPSCO and CIPS Quarterly Reports on Form 10-Q for the quarters
ended March 31, 1996 and June 30, 1996
J-1 Proposed Form of Notice
K-1 Gas Study
K-2 Table of Estimated Losses of Economies in Prior Decisions on
Divestiture and Retention of Gas Operations
K-3 Legal Memorandum Regarding Standards for Retention of Gas
Properties (To be filed by Amendment)
93
<PAGE>
B. Financial Statements
FS-1 Ameren Unaudited Pro Forma Combined Condensed Consolidated Balance
Sheets as of June 30, 1996 (see Quarterly Report of UE on Form 10-Q
for the quarter ended June 30, 1996 (Exhibit I-5 hereto), at p. 12)
FS-2 Ameren Unaudited Pro Forma Combined Condensed Consolidated
Statements of Income for the years ended December 31, 1995, 1994
and 1993 (see Annual Report of UE on Form 10-K for the year ended
December 31, 1995 (Exhibit I-1 hereto), at pp. 16-18)
FS-3 CIPSCO Consolidated Balance Sheets as of June 30, 1996 (see
Quarterly Report of CIPSCO on Form 10-Q for the quarter ended June
30, 1996 (Exhibit I-6 hereto), at p. 5)
FS-4 CIPSCO Consolidated Statements of Income for its last three fiscal
years (see Annual Report of CIPSCO on Form 10-K for the year ended
December 31, 1995 (Exhibit I-2 hereto), at p. 41)
FS-5 CIPS Balance Sheets as of June 30, 1996 (see Quarterly Report of
CIPS on Form 10-Q for the quarter ended June 30, 1996 (Exhibit I-6
hereto), at p. 8)
FS-6 CIPS Statements of Income for its last three fiscal years (see
Annual Report of CIPS on Form 10-K for the year ended December 31,
1995 (Exhibit I-2 hereto), at p. 69)
FS-7 UE Consolidated Balance Sheet as of June 30, 1996 (see Quarterly
Report of UE on Form 10-Q for the quarter ended June 30, 1996
(Exhibit I-5 hereto), at p. 2)
FS-8 UE Consolidated Statement of Income for its last three fiscal years
(see UE Annual Report to Shareholders for the year ended December
31, 1995 (Exhibit I-3 hereto), at p. 22)
Item 7. Information as to Environmental Effects
The Transaction neither involves a "major federal action" nor
"significantly affects the quality of the human environment" as those terms are
used in Section 102(2)(C) of the National Environmental Policy Act, 42 U.S.C.
Sec. 4321 et seq. The only federal actions related to the Transaction pertain to
the Commission's declaration of the effectiveness of Ameren's Registration
Statement on Form S-4, the expiration of the applicable waiting period under the
HSR Act, FERC approval of the application filed by UE and CIPS with the FERC
under the Federal Power Act, and Commission approval of this Application/
Declaration. Consummation of the Transaction will not result in changes in the
operations of UE or CIPS that would have any impact on the environment. No
federal agency is preparing an environmental impact statement with respect to
this matter.
94
<PAGE>
SIGNATURE
Pursuant to the requirements of the Public Utility Holding Company Act of
1935, the undersigned company has duly caused this Application/Declaration to be
signed on its behalf by the undersigned thereunto duly authorized.
Date: October 31, 1996
Ameren Corporation
/s/ William E. Jaudes
-------------------------------------------------
By: William E. Jaudes
Secretary
95
<PAGE>
INDEX OF EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT TRANSMISSION
NUMBER EXHIBIT METHOD
<C> <S> <C>
A-1 Restated Articles of Incorporation of Ameren By Reference
(previously filed as Annex F to the Registration
Statement of Ameren on Form S-4, Registration
No. 33-64165 (Exhibit C-1 hereto), filed by Ameren
on November 13, 1995 and incorporated herein by
reference)
A-2 Restated Articles of Incorporation of UE By Reference
(previously filed as Exhibit 3(i) to UE's Annual
Report on Form 10-K for the year ended
December 31, 1993 and incorporated herein by
reference)
A-3 Amended and Restated Articles of Incorporation of By Reference
CIPSCO (previously filed as Exhibit 3.01 to
CIPSCO's Annual Report on Form 10-K for the
year ended December 31, 1990 and incorporated
herein by reference)
A-4 Restated Articles of Incorporation of CIPS By Reference
(previously filed as Exhibit 3(b) to CIPS's Quarterly
Report on Form 10-Q for the quarter ended
March 31, 1994 and incorporated herein by
reference)
B-1 Merger Agreement by and among UE, CIPSCO, By Reference
CIPS, Ameren and Arch Merger (previously filed
with the Commission as Annex A to the
Registration Statement of Ameren on Form S-4,
Registration No. 33-64165 (Exhibit C-1 hereto),
filed by Ameren on November 13, 1995, and
incorporated herein by reference)
B-2 CIPSCO Stock Option Agreement (previously filed By Reference
with the Commission as Annex B to the
Registration Statement of Ameren on Form S-4,
Registration No. 33-64165 (Exhibit C-1 hereto),
filed by Ameren on November 13, 1995, and
incorporated herein by reference)
</TABLE>
96
<PAGE>
INDEX OF EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT TRANSMISSION
NUMBER EXHIBIT METHOD
<C> <S> <C>
B-3 UE Stock Option Agreement (previously filed with By Reference
the Commission as Annex C to the Registration
Statement of Ameren on Form S-4, Registration
No. 33-64165 (Exhibit C-1 hereto), filed by Ameren
on November 13, 1995, and incorporated herein by
reference)
B-4 Form of General Services Agreement among Electronic
Ameren Services, Ameren, UE, CIPS and CIPSCO
Investment
B-5 Description of Ameren Services' accounting and By Amendment
cost allocation methods and procedures
B-6 Description of support agreements and guarantees Electronic
of CIPSCO and CIPSCO Investment
C-1 Registration Statement of Ameren on Form S-4 By Reference
(Registration No. 33-64165 (filed with the
Commission by Ameren on November 13, 1995,
and incorporated herein by reference)
C-2 Joint Proxy Statement and Prospectus (previously By Reference
filed with the Commission as part of Ameren's
Registration Statement on Form S-4, Registration
No. 33-64165 (Exhibit C-1 hereto), filed by Ameren
on November 13, 1995, and incorporated herein by
reference)
C-3 Ameren's Post-Effective Amendment to Form S-4 By Amendment
Registration Statement on Form S-3 (DRIP)
C-4 Ameren LTIP Form S-8 By Amendment
C-5 Description of existing savings plans By Amendment
D-1.1 Joint Application of UE and CIPS before the Electronic
FERC
D-1.2 Testimony of Rodney W. Frame before the FERC Electronic
</TABLE>
97
<PAGE>
INDEX OF EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT TRANSMISSION
NUMBER EXHIBIT METHOD
<C> <S> <C>
D-1.3 Order of the FERC dated ___________, 19__ By Amendment
D-2.1 Application of UE before the MPSC Electronic
D-2.2 MPSC Order dated ___________, 19__ By Amendment
D-2.3 Stipulation and Agreement filed with the MPSC Electronic
dated July 12, 1996
D-3.1 Joint Application of CIPS, CIPSCO and UE before Electronic
the ICC
D-3.2 ICC Order dated ___________, 19__ By Amendment
D-4.1 Application of UE before the NRC Electronic
D-4.2 Order of the NRC dated ___________, 19__ By Amendment
E-1 Map of service areas of CIPS and UE Form SE
E-2 Map showing interconnections of UE and CIPS Form SE
E-3 Map of CIPS service area Form SE
E-4 Map of UE electrical system Form SE
E-5 Map of UE gas system Form SE
E-6 Map of CIPS electric system Form SE
E-7 Map of CIPS gas system Form SE
E-8 UE corporate chart Electronic
E-9 CIPSCO corporate chart Electronic
F-1.1 Preliminary Opinion of Counsel By Amendment
F-1.2 Final "Past Tense" Opinion of Counsel By Amendment
</TABLE>
98
<PAGE>
INDEX OF EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT TRANSMISSION
NUMBER EXHIBIT METHOD
<C> <S> <C>
F-2.1 Preliminary Opinion of Counsel (Jones, Day, By Amendment
Reavis & Pogue
F-2.2 Final "Past Tense" Opinion of Counsel (Jones, Day, By Amendment
Reavis & Pogue)
G-1 Financial Data Schedule Electronic
H-1 Opinion of Goldman Sachs dated November 13, By Reference
1995 (previously filed with the Commission as
Annex D to the Registration Statement of Ameren
on Form S-4, Registration No. 33-64165 (Exhibit
C-1 hereto), filed by Ameren on November 13, 1995,
and incorporated herein by reference)
H-2 Opinion of Morgan Stanley dated November 13, By Reference
1995 (previously filed with the Commission as
Annex E to the Registration Statement of Ameren
on Form S-4, Registration No. 33-64165 (Exhibit
C-1 hereto), filed by Ameren on November 13, 1995,
and incorporated herein by reference)
I-1 Annual Report of UE on Form 10-K for the year By Reference
ended December 31, 1995 (filed by UE on
March 28, 1996, File No. 1-2967, and incorporated
herein by reference)
I-2 Annual Report of CIPSCO and CIPS on Form By Reference
10-K for the year ended December 31, 1995 (filed by
CIPSCO and CIPS on March 12, 1996, File
Nos. 1-10628 and 1-3672, and incorporated herein
by reference)
I-3 UE 1995 Annual Report to Shareholders By Reference
(previously furnished to the Commission and
incorporated herein by reference)
</TABLE>
99
<PAGE>
INDEX OF EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT TRANSMISSION
NUMBER EXHIBIT METHOD
<C> <S> <C>
I-4 Statement of CIPS on Form U-3A-2 dated By Reference
February 28, 1996 (filed with the Commission by
CIPS on February 29, 1996, File No. 69-140, and
incorporated herein by reference)
I-5 UE Quarterly Reports on Form 10-Q for the By Reference
quarters ended March 31, 1996 and June 30, 1996
(filed with the Commission by UE on May 13, 1996
and August 13, 1996, respectively, File No. 1-2967,
and incorporated herein by reference)
I-6 CIPSCO and CIPS Quarterly Reports on Form By Reference
10-Q for the quarters ended March 31, 1996 and
June 30, 1996 (filed with the Commission by
CIPSCO on May 14, 1996 and August 14, 1996,
respectively, File Nos. 1-10628 (CIPSCO) and
1-3672 (CIPS), and incorporated herein by
reference)
J-1 Proposed Form of Notice Electronic
K-1 Gas Study Electronic
K-2 Table of Estimated Losses of Economies in Prior Electronic
Decisions on Divestiture and Retention of Gas
Operations
K-3 Legal Memorandum Regarding Standards for By Amendment
Retention of Gas Properties
FS-1 Ameren Unaudited Pro Forma Combined By Reference
Condensed Consolidated Balance Sheets as of
June 30, 1996 (previously filed with the
Commission at page 12 of UE's Quarterly Report
on Form 10-Q for the quarter ended June 30, 1996
(Exhibit I-5 hereto), filed by UE on August 13,
1996, File No. 1-2967, and incorporated herein by
reference)
</TABLE>
100
<PAGE>
INDEX OF EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT TRANSMISSION
NUMBER EXHIBIT METHOD
<C> <S> <C>
FS-2 Ameren Unaudited Pro Forma Combined By Reference
Condensed Consolidated Statements of Income for
the years ended December 31, 1995, 1994 and 1993
(previously filed with the Commission at pages
16-18 of UE's Annual Report on Form 10-K for the
year ended December 31, 1995 (Exhibit I-1 hereto),
filed by UE on March 28, 1996, File No. 1-2967,
and incorporated herein by reference)
FS-3 CIPSCO Consolidated Balance Sheets as of By Reference
June 30, 1996 (previously filed with the
Commission at page 5 of CIPSCO's Quarterly
Report on Form 10-Q for the quarter ended
June 30, 1996 (Exhibit I-6 hereto), filed by CIPSCO
on August 13, 1996, File No. 1-10628, and
incorporated herein by reference)
FS-4 CIPSCO Consolidated Statements of Income for its By Reference
last three fiscal years (previously filed with the
Commission at page 41 of CIPSCO's Annual
Report on Form 10-K for the year ended
December 31, 1995 (Exhibit I-2 hereto), filed by
CIPSCO on March 4, 1996, File No. 1-10628, and
incorporated herein by reference)
FS-5 CIPS Balance Sheets as of June 30, 1996 By Reference
(previously filed with the Commission at page 8 of
CIPS's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1996 (Exhibit I-6 hereto),
filed by CIPS on August 13, 1996, File No. 1-3672,
and incorporated herein by reference)
FS-6 CIPS Statements of Income for its last three fiscal By Reference
years (previously filed with the Commission at
page 69 of CIPS's Annual Report on Form 10-K for
the year ended December 31, 1995 (Exhibit I-2
hereto), filed by CIPS on March 4, 1996, File No.
1-3672, and incorporated herein by reference)
</TABLE>
101
<PAGE>
INDEX OF EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT TRANSMISSION
NUMBER EXHIBIT METHOD
<C> <S> <C>
FS-7 UE Balance Sheet as of June 30, 1996 (previously By Reference
filed with the Commission at page 2 of UE's
Quarterly Report on Form 10-Q for the quarter
ended June 30, 1996 (Exhibit I-5 hereto), filed by
UE on August 13, 1996, File No. 1-2967, and
incorporated herein by reference)
FS-8 UE Consolidated Statement of Income for its last By Reference
three fiscal years (previously filed with the
Commission at page 22 of UE's Annual Report to
Shareholders for the year ended December 31,
1995 (Exhibit I-3 hereto), previously provided to
the Commission by UE on March 7, 1996, File
No. 1-2967, and incorporated herein by reference).
</TABLE>
102
<PAGE>
Exhibit B-4
GENERAL SERVICES AGREEMENT
BETWEEN
AMEREN SERVICES COMPANY
AND
AMEREN CORPORATION, UNION ELECTRIC COMPANY,
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY, AND
CIPSCO INVESTMENT COMPANY
THIS AGREEMENT, made and entered into this __ day of _________, 1996, by
and between the following Parties: AMEREN SERVICES COMPANY (hereinafter
sometimes referred to as "Service Company"), a Missouri corporation; and AMEREN
CORPORATION ("Ameren Corporation"), a Missouri Corporation; UNION ELECTRIC
COMPANY ("UE"), a Missouri corporation; CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
("CIPS"), an Illinois corporation, and CIPSCO INVESTMENT COMPANY, ("CIC"), an
Illinois corporation, (hereinafter sometimes referred to collectively as "Client
Companies");
WITNESSETH:
WHEREAS, Client Companies, including Ameren Corporation, which has filed
for registration under the terms of the Public Utility Holding Company Act of
1935 (the "Act") and its other subsidiaries, desire to enter into this agreement
providing for the performance by Service Company for the Client Companies of
certain services more particularly set forth herein; and
WHEREAS, Service Company is organized, staffed and equipped and has filed
with the Securities and Exchange Commission ("the SEC") to be a subsidiary
service company under Section 13 of the Public Utilities Holding Company Act of
1935 (the "Act") to render
<PAGE>
to Ameren Corporation, and other subsidiaries of Ameren Corporation, certain
services as herein provided; and
WHEREAS, to maximize efficiency, and to achieve merger related savings, the
Client Companies desire to avail themselves of the advisory, professional,
technical and other services of persons employed or to be retained by Service
Company, and to compensate Service Company appropriately for such services,
NOW, THEREFORE, in consideration of the premises and of the mutual
agreements herein, the parties hereto agree as follows:
Section 1. Agreement to Furnish Services
- ----------------------------------------
Service Company agrees to furnish to Client Companies and their
subsidiaries, if any, upon the terms and conditions herein provided, the
services hereinafter referred to and described in Section 2, at such times, for
such period and in such manner as Client Companies may from time to time
request. Service Company will keep itself and its personnel available and
competent to render to Client Companies such services so long as it is
authorized so to do by the appropriate federal and state regulatory agencies.
Section 2. Services to be Performed
- ------------------------------------
The services to be provided by Service Company hereunder may, upon request,
include the services as set out in Schedule 1, attached hereto and made a part
hereof.
-2-
<PAGE>
In addition to the Services set out in Schedule 1, Service Company shall
render advice and assistance in connection with such other matters as Client
Companies may request and Service Company determines it is able to perform with
respect to Client Companies' business and operations.
Section 3. Compensation of Service Company
-------------------------------
As compensation for such services rendered to it by Service Company, Client
Companies hereby agree to pay to Service Company the cost of such services,
computed in accordance with applicable rules and regulations (including, but not
limited to, Rules 90 and 91) under the Act and appropriate accounting standards.
Compensation to be paid by Client Companies shall include direct charges
and Client Companies' fairly allocated pro rata share of certain of Service
Company's costs, determined as set out on Schedule 2, attached hereto and made a
part hereof.
Section 4. Securities and Exchange Commission Rules
----------------------------------------
It is the intent of the Parties that the determination of the costs as used
in this Agreement shall be consistent with, and in compliance with the rules and
regulations of the SEC, as they now read or hereafter may be modified by the
Commission.
Section 5. Service Requests
----------------
Services will be performed in accordance with a Service Request system,
consisting of work orders established to capture
-3-
<PAGE>
the various types of costs incurred by Service Company. Costs will be charged to
the appropriate service requests, which will then be the basis for the billing
of costs to Client Companies.
Section 6. Payment
-------
Payment shall be by making remittance of the amount billed or by making
appropriate accounting entries on the books of the companies.
Payment shall be accomplished on a monthly basis, and remittance or
accounting entries shall be completed within 30 days of billing.
Section 7. Ameren Corporation
------------------
Except as authorized by rule, regulation, or order of the Securities and
Exchange Commission, nothing in this Agreement shall be read to permit Ameren
Corporation, or any person employed by or acting for Ameren Corporation, to
provide services for other Parties, or any companies associated with said
Parties.
Section 8. Client Companies
----------------
Except as limited by Section 7, nothing in this Agreement shall be read to
prohibit Client Companies or their subsidiaries from furnishing to other Client
Companies or their subsidiaries services herein referred to, under the same
conditions and terms as set out for Service Company.
-4-
<PAGE>
Section 9. Effective Date and Termination
------------------------------
This Agreement is executed subject to the consent and approval of all
applicable regulatory agencies, and if so approved in its entirety, shall become
effective as of the date the merger between Union Electric and CIPSCO is
consummated, and shall remain in effect from said date unless terminated by
mutual agreement or by any Party giving at least sixty days' written notice to
the other Parties prior to the beginning of any calendar year, each Party fully
reserving the right to so terminate the Agreement.
This Agreement may also be terminated to the extent that performance may
conflict with any rule, regulation or order of the Securities and Exchange
Commission adopted before or after the making of this Agreement.
Section 10. Assignment
----------
This Agreement and the rights hereunder may not be assigned without the
mutual written consent of all Parties hereto.
-5-
<PAGE>
IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be
executed and attested by their authorized officers as of the day and year first
above written.
AMEREN SERVICES COMPANY
By ______________________________
Title ___________________________
ATTEST:
By ______________________
Title ___________________
AMEREN CORPORATION
By ______________________________
Title ___________________________
ATTEST:
By ______________________
Title ___________________
UNION ELECTRIC COMPANY
By ______________________________
Title ___________________________
ATTEST:
By ______________________
Title ___________________
-6-
<PAGE>
CENTRAL ILLINOIS PUBLIC SERVICE CO.
By _______________________________
Title ____________________________
ATTEST:
By ______________________
Title ___________________
CIPSCO INVESTMENT COMPANY
By ____________________________
Title _________________________
ATTEST:
By ______________________
Title ___________________
-7-
<PAGE>
AMEREN SERVICES
DESCRIPTION OF EXPECTED SERVICES BY FUNCTION/DEPARTMENT
FUNCTION/DEPARTMENT DESCRIPTION
- --------------------------------------------------------------------------------
Building Service Provide facility management services for owned
and leased facilities, excluding power plants.
Services include operation and maintenance of
structures, capital improvements, interior
space planning, security and janitorial.
Controller's Perform all accounting services necessary to
properly maintain and report on the books and
records of Ameren and its subsidiaries.
Provide investor relations services.
Corporate Develop strategies for advertising and
Communications marketing efforts, develop employee
communication programs, coordinate community
relations efforts and develop policies and
procedures for media relations.
Corporate Planning Provide rate engineering, interchange
marketing, resource planning and business
analysis services.
Customer Services/ Answer customer inquiries pertaining to
Division Support electric/gas service usage and perform credit
activities. Provide technical support relating
to planning, engineering, constructing and
operating the distribution and transmission
systems. Provide technical support and
maintenance of protective relay schemes,
station meter work, system testing and data
acquisition systems.
Economic Development Provide community and business development
services, as well as natural gas development
services. Analyze community and business
development opportunities.
Energy Supply Coordinate the use of the generating,
transmission and interconnection facilities to
provide economical and reliable energy.
Engineering and Provide professional services related to
Construction engineering studies, design, procurement,
planning, building and management of projects.
Study technology that may reduce costs of
producing, delivering and using electricity.
Schedule 1
Page 1 of 3
<PAGE>
FUNCTION/DEPARTMENT DESCRIPTION
- --------------------------------------------------------------------------------
Environmental Services Perform analysis and advocacy of regulatory
& Safety and legislative issues in the areas of
environment, health and safety. Communicate
final regulatory requirements to operating
groups. Provide assistance and support and
compliance review in meeting those
requirements. Oversee hazardous substance site
investigation and remediation activities.
Fossil Fuel Procurement Provide resources necessary to procure fuel
for the fossil power plants and minimize
production costs.
Gas Supply Provide gas supply and pipeline capacity
procurement and management services. Develop
policies, procedures and standards which
govern the design, construction and operation
of the gas systems.
General Counsel Provide legal advice and services in regards
to legislative activities, regulatory agencies
and security matters. Make regulatory filings,
maintain minutes of the boards of directors,
conduct stockholder meetings and procure
property and casualty insurance bonds.
Human Resources Administer and negotiate employee benefits
including pensions, major medical, long-term
disability, life insurance, defined
contribution plans, executive benefit and
flexible spending plans. Provide employment
services, including required regulatory
reporting and maintenance of personnel
records. Provide employee training and
communications services.
Industrial Relations Negotiate, represent and administer provisions
of labor agreements applicable to unions
representing union employees.
Information Services Provide for the development and operation of
computer software, telecommunications and
other equipment used to conduct business and
engineering activities. Maintain all billing
records and process customer meter readings.
Internal Audit Audit company operations, perform operational
and productivity reviews, review
justifications for capital projects and
perform quality assurance reviews.
Marketing Provide marketing services including account
management, program development, market
research and customer energy services.
Schedule 1
Page 2 of 3
<PAGE>
FUNCTION/DEPARTMENT DESCRIPTION
- --------------------------------------------------------------------------------
Merger Coordination Monitor programs to achieve savings, merger
costs and position reductions as they relate
to the implementation plans.
Motor Transportation Provide engineering, support, and mechanical
servicing of vehicles, procurement of vehicles
and safety and training programs.
Purchasing Provide procurement of goods and services
other than fuel. Provide materials inventory
management services.
Real Estate Acquire necessary land rights and permits
including coordination of site selection.
Maintain existing land rights while permitting
licenses and leases to minimize investment or
costs of holding property.
Stores Receive, inspect, store, issue and deliver
materials and supplies throughout all service
areas. Process transformers, tools, scrap
material and hazardous waste.
Tax Research and consult on tax issues in
connection with federal, state and local tax
compliance and planning matters, including the
preparation and filing of returns.
Treasurer's Provide treasury operation, mailing, financial
planning, investments, and executive payroll
and pension disbursement services.
Schedule 1
Page 3 of 3
<PAGE>
AMEREN SERVICES
EXPECTED ALLOCATED DIRECT COST FACTORS
ALLOCATION NUMBER DESCRIPTION
----------------- -----------
1 Composite*
2 Number of customers
3 Sales (kwh and dekatherm)
4 Kwh sales
5 Number of employees
6 Current tax expense
7 Peak load (electric)
8 Total revenues
9 CPU cycles
10 Total capitalization
11 Dekatherm sales
12 Total assets
13 Number of vehicles
14 Generating capacity
15 Gas throughput (includes
transportation)
16 Peak load (gas)
17 O&M labor
18 Construction expenditures
19 Electric revenue
20 Gas revenue
*Composite consists of the following three factors (equal weight to each
factor):
Sales (kwh and dekatherm)
Number of customers
Number of employees
Schedule 2
<PAGE>
EXHIBIT B-6
SUPPORT AGREEMENTS AND GUARANTIES
OF CIPSCO AND CIPSCO INVESTMENT
<TABLE>
<CAPTION>
================================================================================
CIPSCO SUPPORT AGREEMENTS
- --------------------------------------------------------------------------------
Date On Behalf Of Transaction Pertaining To
- --------------------------------------------------------------------------------
<S> <C> <C>
Sept. 24, 1991 CLC Aircraft Leasing Co. Lease of one MD-88 aircraft to
Delta Air Lines, Inc.
- --------------------------------------------------------------------------------
Nov. 26, 1991 CIPSCO Leasing Co. Lease regarding Enron Gas
Processing Co., Bushton, Kansas
processing plant
- --------------------------------------------------------------------------------
Dec. 15, 1991 CLC Leasing Co. A Lease of certain natural gas
production, treating and
processing equipment to Amoco
Equipment Leasing Co.
- --------------------------------------------------------------------------------
Dec. 1, 1992 CLC Leasing Co. B Certain sale-leaseback transactions
with Wal-Mart Stores, Inc.
===============================================================================
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT B-6
=========================================================================================
CIPSCO INVESTMENT GUARANTIES
- -----------------------------------------------------------------------------------------
<S> <C> <C> <C>
Date On Behalf Of For The Benefit Of Transaction Pertaining To
- -----------------------------------------------------------------------------------------
Aug. 26, 1993 CEC-PGE, L.P. Trustee and Term Sale of the beneficial interest
Lenders in a trust which holds title to
certain combustion turbine units
- -----------------------------------------------------------------------------------------
Aug. 26, 1993 CEC-APL, L.P. Trustee and Term Sale of the beneficial interest
Lenders in a trust which holds title to
certain simple cycle gas turbine
units
- -----------------------------------------------------------------------------------------
Aug. 26, 1993 CEC-PSPL, L.P. Trustee and Term Sale of the beneficial interest
Lenders in a trust which holds title to
certain combustion turbine units
- -----------------------------------------------------------------------------------------
June 10, 1994 CEC-MPS, L.P. Trustee, Trustor and Sale of the beneficial interest
Term Lenders in a trust which holds title to
certain combustion turbine units
- -----------------------------------------------------------------------------------------
June 10, 1994 CEC-MPS, L.P. Boatmen's First Sale of the beneficial interest
National Bank of in a trust which holds title to
Kansas City certain combustion turbine units
- -----------------------------------------------------------------------------------------
June 10, 1994 CEC-MPS, L.P. Trustee, Trustor and Sale of the beneficial interest
Term Lenders in a trust which holds title to
certain combustion turbine units
- -----------------------------------------------------------------------------------------
June 10, 1994 CEC-MPS, L.P. Boatmen's First Sale of the beneficial interest
National Bank of St. in a trust which holds title to
Louis certain combustion turbine units
- -----------------------------------------------------------------------------------------
July 11, 1994 CEC-ACE, L.P. Access Leasing Corp. Sale of the beneficial interest
in a trust which holds title to
certain combustion turbine units
- -----------------------------------------------------------------------------------------
July 11, 1994 CEC-ACE, L.P. Shawmut Bank Sale of the beneficial interest
Connecticut, N.A. in a trust which holds title to
certain combustion turbine units
- -----------------------------------------------------------------------------------------
Sept. 19, 1994 CIPSCO Term Lenders Effingham Development
Venture Building II, L.L.C.
Co.
=========================================================================================
</TABLE>
2
<PAGE>
Exhibit D-1.1
JONES, DAY, REAVIS & POGUE
METROPOLITAN SQUARE
1450 G STREET, N.W.
WASHINGTON, D.C. 20005-2088
ATLANTA IRVINE TELEPHONE 202-879-3939
BRUSSELS LONDON TELEX DOMESTIC 892410
CHICAGO LOS ANGELES TELEX INTERNATIONAL 64363
CLEVELAND NEW YORK CABLE ATTORNEY'S WASHINGTON
COLUMBUS PARIS FACSIMILE 202-737-2832
DALLAS PITTSBURGH WRITER'S DIRECT NUMBER
FRANKFURT RIYADH (202) 879-3687
GENEVA TAIPEI
HONG KONG TOKYO
December 22, 1995
DELIVER BY HAND
- ---------------
Ms. Lois D. Cashell
Secretary
Federal Energy Regulatory Commission
888 First Street, N.E.
Washington, D.C. 20426
Re: Union Electric Company and
Central Illinois Public Service Company
Docket Nos. EC96- and ER96-
---------------------------------------
Dear Ms. Cashell:
Pursuant to Sections 203 and 205 of the Federal Power Act, 16 U.S.C. (S)(S)
824b and 824b (1994), and the Commission's applicable regulations thereunder,
there is submitted herewith for filing an original and five copies of the Joint
Application of Merger of Union Electric Company and Central Illinois Public
Service Company for Approval of: Merger and Disposition of Facilities, Joint
Dispatch Agreement, System Support Agreement, Recovery of Nuclear
Decommissioning Costs, Transfer of SubAccount of Nuclear Decommissioning Trust
and Prospective Regulatory Accounting Treatment. This filing consists of the
following:
. Volume I: Transmittal and Application
. Volume II: Section 205 Application Agreements
. Volume III and IV: Testimony and Exhibits
. Volume V: Workpapers
The Applicants are separately serving copies of this application on each of
the state commissions affected, and therefore request a waiver of that part of
(S) 33.6 that requires that a copy of the application be filed for each state
affected. Also enclosed herewith are six copies of a form of notice suitable for
publication.
Applicants have made filings with the Illinois Commerce Commission and the
Missouri Public Service Commission seeking approval of the merger. Copies of
such filings are included as part of Exhibit G. A Form S-4 Registration
Statement relating to the transaction has been filed with the Securities and
Exchange Commission ("SEC") and was declared effective. A copy of the
Registration Statement is submitted as part of Exhibit G.
<PAGE>
JONES, DAY, REAVIS & POGUE
Ms. Lois D. Cashell
December 22, 1995
Page 2
Applicants anticipate that other federal regulatory filings will be made in
connection with the proposed transaction. Promptly after each such filing is
made, Applicants will supplement this filing with the requisite number of copies
of each such filing. The pending filing include:
. with the SEC, approval of acquisition of securities and utility assets
and other assets, and registration of the new holding company under
the Public Utility Holding Companies Act;
. with the Nuclear Regulatory Commission, authorization to transfer
license for Callaway Nuclear Power Plant;
. with the Federal Trade Commission and Department of Justice, a
notification and report under the Hart-Scott-Rodino Antitrust Act.
A separate copy of this transmittal letter and the Joint Application
(without accompanying exhibits and testimony) is enclosed. Applicants request
that the Commission file-stamp these documents to signify receipt of this
filing.
Applicants respectfully request that the Commission treat the matters
raised in the Joint Application on a consolidated basis and that the Commission
reach its determination on authorization of the merger pursuant to Section 203
as expeditiously as possible. Applicants believe at this time that the
Commission should be able to complete its consideration of the Joint Application
without convening an evidentiary hearing. However, should any issue arise with
regard to (1) the Section 205 matters, (2) the proposed regulatory accounting
treatment, or (3) the relief requested as to the disposition and funding of
Union Electric Company's decommissioning fund, all of which are included in the
Joint Application, and should the Commission deem that hearings are necessary
with regard to such issue, Applicants request that the Commission approve the
merger and separately set such issue for hearing at a later date.
Very truly yours,
/s/ Robert S. Waters
-----------------------------------------
Robert S. Waters
Martin V. Kirkwood
Jones, Day, Reavis & Pogue
1450 G Street, N.W.
Washington, D.C. 20005
Enclosures
<PAGE>
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Union Electric Company and )
Central Illinois Public ) Docket Nos. EC96-7-000
Service Company ) and ER96-679-000
NOTICE OF FILING
(December __, 1995)
Take notice that on December 22, 1995, Union Electric Company ("UE") and
Central Illinois Public Service Company ("CIPS") (collectively, the
"Applicants") filed a joint application pursuant to Sections 203 and 205 of the
Federal Power Act and the Federal Energy Regulatory Commission's applicable
regulations seeking authorization and approval of a strategic alliance between
the Applicants under a common holding company, Ameren Corporation ("Ameren"), a
corporation newly incorporated in the State of Missouri.
Applicants further request findings that the System Support Agreement and
Joint Dispatch Agreement are just and reasonable and an order allowing them to
become effective as of completion of the transaction resulting in the holding
company structure. Additionally, Applicants seek approval of the proposed
regulatory accounting treatment of a shared savings plan and cost recovery
mechanism, and certain approvals as to UE's decommissioning fund.
UE is a combination electric and gas utility operating in Missouri and west
central Illinois. CIPS is a combination electric and gas utility operating in
Illinois and is a wholly owned subsidiary of CIPSCO, Inc. ("CIPSCO"). Pursuant
to the Merger Agreement, CIPSCO will be merged into Ameren, with Ameren as the
surviving entity. CIPS and other non-utility subsidiaries of CIPSCO will, thus,
become wholly owned subsidiaries of Ameren. UE will be merged with and into Arch
Merger, Inc., a corporation newly incorporated in the State of Missouri as a
wholly-owned subsidiary of Ameren, with UE as the surviving corporation. UE will
thus become a wholly-owned subsidiary of Ameren. In addition, UE will transfer
to CIPS certain of its Illinois electric and gas public utility facilities.
<PAGE>
Any person desiring to be heard or to protest said application should file
a motion to intervene or protest with the Federal Energy Regulatory Commission,
888 First Street, N.E., Washington, D.C. 20426, in accordance with Rules 211 and
214 of the Commission's Rules of Practice and Procedure (18 CFR Sections 385.211
and 385.214). All such motions or protests should be filed on or before
__________________, 1996. Protests will be considered by the Commission in
determining the appropriate action to be taken but will not serve to make
protestants parties to the proceedings. Any person wishing to become a party
must file a motion to intervene. Copies of this application are on file with the
Commission and are available for public inspection.
Lois D. Cashnell, Secretary
<PAGE>
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Union Electric Company and ) Docket Nos. EC96- -000
Central Illinois Public ) and ER96- -000
Service Company )
JOINT APPLICATION OF UNION ELECTRIC COMPANY AND
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY FOR
APPROVAL OF: MERGER AND DISPOSITION OF FACILITIES,
JOINT DISPATCH AGREEMENT, SYSTEM SUPPORT AGREEMENT,
RECOVERY OF NUCLEAR DECOMMISSIONING COSTS, TRANSFER OF
SUBACCOUNT OF NUCLEAR DECOMMISSIONING TRUST AND
PROSPECTIVE ACCOUNTING TREATMENT
William E. Jaudes David J. Rosso
Vice President and General Christopher W. Flynn
Counsel Thomas D. Brooks
James J. Cook Jones, Day, Reavis & Pogue
Associate General Counsel 77 West Wacker Drive
Joseph H. Raybuck, Attorney Chicago, Illinois 60601
Union Electric Company
1901 Chouteau Avenue Robert S. Waters
St. Louis, Missouri 63166 Martin V. Kirkwood
Jones, Day, Reavis & Pogue
1450 G Street, N.W.
Washington, D.C. 20005
Attorneys for Union Electric Attorneys for Central Illinois
Company Public Service Company
December 22, 1995
<PAGE>
TABLE OF CONTENTS
-----------------
Page
----
I. INTRODUCTION....................................................... 1
II. DESCRIPTION OF THE PROPOSED TRANSACTION............................ 3
III. THE PROPOSED TRANSACTION IS IN THE PUBLIC INTEREST................. 11
A. Overview of the regulatory standards.......................... 11
B. The proposed Transaction satifies the
Commonwealth Edison standards................................. 21
1. The Transaction will reduce operating costs
and keep rates lower than they otherwise
would be................................................. 21
2. Applicants will use the "pooling" method of
accounting............................................... 23
3. The exchange ratio was negotiated at arm's
length and is reasonable................................. 25
4. There is no issue of coercion............................ 26
5. The Transaction will promote competition................. 26
6. Both wholesale and retail regulation will
remain effective......................................... 29
C. The El Paso standard: UE and CIPS will provide
comparable transmission service upon consummation
of the merger................................................. 30
IV. THE COMMISSION SHOULD APPROVE THE TRANSACTION
EXPEDITIOUSLY WITHOUT HEARING...................................... 31
V. SYSTEM SUPPORT AGREEMENT........................................... 33
VI. JOINT DISPATCH AGREEMENT........................................... 36
VII. PROPOSED REGULATORY ACCOUNTING TREATMENT OF
SHARED SAVINGS PLAN................................................ 40
VIII. NUCLEAR DECOMMISSIONING TRUST...................................... 42
IX. AUTHORIZATIONS REQUESTED........................................... 44
-i-
<PAGE>
X. INFORMATION REQUIRED BY 18 C.F.R. (S) 33.2......................... 46
A. (S) 33.2(a) - Names and addresses of principal
business offices.............................................. 46
1. UE....................................................... 47
2. CIPS..................................................... 47
B. (S) 33.2(b) - Names and addresses of the persons
authorized to receive notices and communications
with respect to this Application.............................. 47
1. UE....................................................... 47
2. CIPS..................................................... 47
C. (S) 33.2(c) - Designation of the territories
served, by counties and states................................ 48
1. UE....................................................... 48
2. CIPS..................................................... 48
3. Maps..................................................... 48
D. (S) 33.2(d) - Description of jurisdictional
transmission facilities....................................... 49
1. UE....................................................... 49
2. CIPS..................................................... 49
3. Maps..................................................... 50
E. (S) 33.2(e) - Description of Transaction and
statement as to consideration................................. 50
F. (S) 33.2(f) - Description of facilities involved
in the Transaction and of their Current and
Proposed Uses................................................. 51
1. UE....................................................... 51
2. CIPS..................................................... 51
G. (S) 33.2(g) - Statement of the cost of the
jurisdictional facilities involved in the
Transaction................................................... 52
-ii-
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C>
H. (S) 33.2(h) - Statement as to the effect of the
Transaction upon any contract for the purchase,
sale or interchange of electric energy........................ 52
I. (S) 33.2(i) - Statement as to other required
regulatory approvals.......................................... 53
1. Federal Energy Regulatory Commission..................... 53
2. Securities and Exchange Commission....................... 53
3. Missouri Public Service Commission....................... 54
4. Illinois Commerce Commission............................. 55
5. Nuclear Regulatory Commission............................ 55
6. Hart-Scott-Rodino........................................ 56
7. Other.................................................... 56
J. (S) 33.2(j) - Facts relied upon by the Applicants
to show that the Transaction will be consistent
with the public interest...................................... 56
K. (S) 33.2(k) - Description of franchises....................... 57
L. (S) 33.2(l) - Form of notice.................................. 57
XI. EXHIBITS REQUIRED BY 18 C.F.R. (S) 33.3............................ 57
XII. CONCLUSION......................................................... 57
</TABLE>
APPENDICES
----------
APPENDIX 1
APPENDIX 2
APPENDIX 3
APPENDIX 4
APPENDIX 5
-iii-
<PAGE>
REQUIRED EXHIBITS
-----------------
EXHIBIT A
EXHIBIT B
EXHIBIT C
EXHIBIT D
EXHIBIT E
EXHIBIT F
EXHIBIT G
EXHIBIT H
EXHIBIT I
PREPARED DIRECT TESTIMONY AND EXHIBITS
--------------------------------------
Gary L. Rainwater
Donald E. Brandt
William A. Koertner
Warner L. Baxter
Maureen A. Borkowski
Gilbert W. Moorman
Rodney Frame
Steven D. Pettit
Thomas J. Flaherty
Douglas W. Kimmelman
Jerre E. Birdsong
Michael C. Williams
-iv-
<PAGE>
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Union Electric Company and )
Central Illinois Public ) Docket No. EC96-________
Service Company ) ER96-________
JOINT APPLICATION OF UNION ELECTRIC COMPANY AND
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY FOR
APPROVAL OF: MERGER AND DISPOSITION OF FACILITIES,
JOINT DISPATCH AGREEMENT, SYSTEM SUPPORT AGREEMENT,
RECOVERY OF NUCLEAR DECOMMISSIONING COSTS, TRANSFER OF
SUBACCOUNT OF NUCLEAR DECOMMISSIONING TRUST AND
PROSPECTIVE ACCOUNTING TREATMENT
------------------------------------------------------
I. INTRODUCTION
Pursuant to Sections 203 and 205 of the Federal Power Act ("FPA"), 16
U.S.C. (S)(S) 824b and 824d (1994), and the Federal Energy Regulatory
Commission's ("FERC" or "Commission") applicable regulations, Union Electric
Company ("UE") and Central Illinois Public Service Company ("CIPS")
(collectively, the Applicants)/1/ submit this Joint Application ("Application")
respectfully requesting the Commission to authorize and approve, to the extent
they are jurisdictional, the mergers and corporate transactions described below
(referred to, in the aggregate, as the "Transaction") and the other agreements
entered into and actions to be taken in connection with the Transaction, which
are also described below. Evidence supporting a finding that the Transaction is
consistent with the public interest is submitted
- ---------------
/1/ Both UE and CIPS have electric and gas operations. All references in this
Joint Application to UE and to CIPS are intended to refer to the respective
corporate entities, including both the electric and gas operations.
<PAGE>
with this Application. The Applicants request that the Commission issue its
approval of the Transaction expeditiously without conducting an evidentiary
hearing.
Applicants further request findings that the System Support Agreement
and Joint Dispatch Agreement filed herewith are just and reasonable pursuant to
Section 205 of the FPA and an order allowing them to become effective as of
completion of the Transaction.
Additionally, pursuant to Section 205 of the FPA, Applicants request
certain approvals with regard to the disposition and funding of the current
Illinois subaccount of UE's decommissioning trust fund for its Callaway nuclear
plant. In summary, the Applicants request that the Commission approve the
transfer of the current balance in the Illinois subaccount of UE's tax-qualified
decommissioning trust to a FERC subaccount, to the extent such approval is
required by the FPA. Additionally, the Applicants request that the FERC approve
the amount for decommissioning expenses in the System Support Agreement as being
included in UE's cost-of-service. Such approval is required to comply with
requirements of the Internal Revenue Service ("IRS") in order to contribute this
amount to a tax-qualified decommissioning trust fund.
-2-
<PAGE>
Finally, Applicants seek approval of the accounting treatment for
regulatory purposes of the shared savings plan and cost recovery mechanism
proposed in this proceeding.
II. DESCRIPTION OF THE PROPOSED TRANSACTION
On August 11, 1995, UE and CIPSCO Incorporated, ("CIPSCO"), an
Illinois corporation which owns all of the common stock of CIPS, entered into an
Agreement and Plan of Merger (the "Merger Agreement"). (A copy of the Merger
Agreement is attached to the testimony of Mr. Gary L. Rainwater, UE's Vice
President of Corporate Planning, filed with this Application as Exhibit No. ___
(GLR-2).)
The Transaction provided for in the Merger Agreement is a strategic
alliance between the Applicants, under a holding company, Ameren Corporation
("Ameren"), pursuant to which:
(1) the Illinois operations and facilities (excluding UE's electric
generating and transmission facilities located in Illinois (the "UE
Retained Illinois Facilities")) of both UE and CIPS will be owned and
operated by CIPS; and
(2) the Missouri operations and facilities of UE (as well as the UE
Retained Illinois Facilities) will be owned and operated by UE.
Significant cost savings and efficiencies will be realized as a result of the
Transaction, resulting in further decreases to the Applicants' costs of
rendering utility services, thus providing a
-3-
<PAGE>
benefit to customers, shareholders and the local economies which Applicants
serve.
CIPS is a combination electric and gas utility, operating in a 20,000
square mile region in central and southern Illinois, which serves 317,000 retail
electric customers in 557 communities and 166,000 retail natural gas customers
in 267 communities. CIPS also provides wholesale electric capacity and energy
to various rural electric cooperative, municipal and investor-owned electric
systems located in Illinois and surrounding states pursuant to a variety of
service agreements. It is wholly-owned by CIPSCO, which is a holding company
exempt from registration under the Public Utility Holding Company Act ("PUHCA").
By virtue of its ownership of twenty percent (20%) of the voting common stock of
Electric Energy, Inc. ("EEInc."), an Illinois corporation which owns a 1015 MW
generating station at Joppa, Illinois, CIPS is also a holding company, and it
too is exempt from registration under PUHCA. EEInc. sells substantially all of
its generation to a uranium enrichment plant located near Paducah, Kentucky
(originally operated by the Atomic Energy Commission and operated today by the
United States Enrichment Corporation) and to EEInc.'s utility shareholders.
UE is a combination electric and gas utility, operating in a 24,000
square mile area in Missouri and west central Illinois, which serves 1,060,000
retail electric customers and 100,000 natural gas customers in Missouri and
64,000 retail
-4-
<PAGE>
electric customers and 18,000 natural gas customers in Illinois. Its Missouri
retail electric service area includes the City of St. Louis and St. Louis
County, as well as all or portions of 65 other counties. Its Illinois retail
electric service area includes the cities of East St. Louis and Alton. UE also
serves 16 wholesale electric customers, all of which are located in Missouri.
UE provides gas service to customers in 22 Missouri and 2 Illinois counties. UE
is also a holding company by virtue of its ownership of forty percent (40%) of
the voting common stock of EEInc. and is exempt from registration under PUHCA.
The forty percent (40%) of EEInc.'s voting common stock not owned by CIPS and UE
is owned by two other non-affiliated utilities.
Under the proposed Transaction:
1. CIPSCO will be merged into Ameren Corporation ("Ameren"), a
corporation newly incorporated in Missouri, with Ameren as the
surviving entity. CIPS and other non-utility subsidiaries of
CIPSCO will, thus, become wholly-owned subsidiaries of Ameren.
CIPS will retain ownership of 20 percent of the common stock of
EEInc.
2. UE will be merged into Arch Merger, Inc. ("Arch"), a corporation
newly incorporated in Missouri as a wholly-owned subsidiary of
Ameren, with UE as the surviving corporation, thus becoming a
wholly-owned subsidiary of Ameren. UE will retain
-5-
<PAGE>
ownership of 40 percent of the common stock of EEInc., together
with the common stock of its wholly-owned non-utility subsidiary.
3. UE will transfer to CIPS all of its electric and gas public
utility facilities located in Illinois which are necessary or
useful in the provision of retail electric and gas service to the
public within UE's Illinois service territory (the "Transferred
Assets"), except the UE Retained Illinois Facilities. A list of
the Transferred Assets is attached as Exhibit No. ___ (GLR-7) to
Mr. Rainwater's testimony.
4. Common stockholders of CIPSCO and UE will receive common stock in
Ameren in exchange for their existing shares in accordance with
the exchange ratios set forth in the Merger Agreement. Debt and
Preferred shares of CIPS and UE will remain outstanding.
As a result, Ameren will become a registered utility holding company under
PUHCA, owning two operating utility subsidiaries, UE and CIPS. UE will continue
to operate the same electric and gas facilities in Missouri plus the UE Retained
Illinois Facilities, all of which UE operated before the Transaction. CIPS,
except as noted above, will conduct all of the combined electric and gas
operations of the Applicants in Illinois.
-6-
<PAGE>
Ameren also will directly own CIPSCO Investment Company which manages CIPSCO's
non-utility investments.
After the merger, UE and CIPS will jointly operate and dispatch their
electric generation and transmission facilities pursuant to a Joint Dispatch
Agreement between the two utilities, a copy of which is attached to the
testimony of Ms. Maureen A. Borkowski, UE's Manager of Energy Services, as
Exhibit No. ___ (MAB-6). In addition, CIPS will enter into a System Support
Agreement to purchase capacity and energy from UE in order to provide service to
the Illinois customers formerly served by UE which are being transferred to
CIPS. A copy of the System Support Agreement is attached to Ms. Borkowski's
testimony as Exhibit No. ___ (MAB-8). Certain administrative functions of both
UE and CIPS will be consolidated and performed either within UE, within CIPS or
within an affiliated service company. The Applicants have, therefore, developed
a General Services Agreement which is flexible enough to allow for any ultimate
organizational structure. This General Services Agreement will be filed at the
Securities and Exchange Commission ("SEC"). A copy of the General Services
Agreement is attached, for the Commission's information, to Mr. Rainwater's
testimony as Exhibit No. ___ (GLR-9).
The Applicants specifically seek an order of the Commission under
Section 203 of the FPA (i) granting authorization and approval of the
Transaction and for the
-7-
<PAGE>
carrying out of the Merger Agreement and (ii) finding that the transaction and
the following elements of the Transaction are in the public interest:
(1) the disposition to Ameren, by virtue of the merger, of indirect
control over the facilities of both UE and CIPS, which the Commission
may deem to be jurisdictional;
(2) the disposition to Ameren, by virtue of the merger, of indirect
control over a sixty percent (60%) ownership interest in the
facilities of EEInc., which the Commission may deem to be
jurisdictional;
(3) the disposition to CIPS of direct control over the Transferred Assets,
to the extent that the Commission may deem any of them to be
jurisdictional; and
(4) the carrying out of the Merger Agreement.
In addition, Applicants are also filing under Section 205 of the FPA
the Joint Dispatch Agreement and the System Support Agreement, to become
effective upon completion of the Transaction, and seek an order of the
Commission finding that the rates, charges, terms and conditions embodied in the
Joint Dispatch Agreement and the System Support Agreement are just and
reasonable.
Further, the Applicants seek approval of the proposed accounting
treatment for regulatory purposes of the shared
-8-
<PAGE>
savings plan and cost recovery mechanism which they propose in this proceeding.
Finally, the Applicants request certain approvals with regard to the
disposition and funding of the portion of UE's nuclear decommissioning trust
fund established for its Illinois retail jurisdiction as a result of the
transfer of the retail customers in that jurisdiction to CIPS.
The Transaction will more than satisfy the requirements of Section 203
because it not only is consistent with, but also will affirmatively benefit, the
public interest by offering opportunities for significant net cost savings which
could not be realized without the synergies provided by the Transaction.
Additionally, the Transaction will extend the Commission's pro-competitive
policies because in connection with this Application for authorization of the
Transaction, Applicants propose that the Commission place into effect, subject
to refund and modification in accordance with the outcome of the Open Access
NOPR, FERC Statutes and Regulations, (P) 32,514 ("Open Access NOPR"), open-
access transmission tariffs which are designed fully to satisfy comparability of
service principles. UE and CIPS have filed these tariffs concurrently with this
Application in a separate Section 205 proceeding.
The Applicants request the Commission to issue an order granting
authorization and approval of the Transaction and
-9-
<PAGE>
finding that the Transaction and carrying out of the Merger Agreement are
consistent with the public interest. Further, Applicants request that such
order be issued on an expedited basis, without hearing and without awaiting
resolution of transmission-related issues in the Section 205 proceeding, of any
issues of cost allocation which may arise with regard to the Joint Dispatch
Agreement, the System Support Agreement and the General Services Agreement, or
of any issues in connection with the proposed accounting treatment for
regulatory purposes of the shared savings plan and cost recovery mechanism.
Should any issue arise with regard to the Joint Dispatch Agreement, the System
Support Agreement, or the proposed accounting treatment for regulatory purposes,
and should the Commission deem that hearings are necessary with regard to such
issue, Applicants request that the Commission approve the merger and separately
set such issue for hearing at a later date. Applicants respectfully submit that
consideration of cost allocation issues with respect to the General Services
Agreement is premature in this docket. Kansas Power and Light Co. and Kansas
Gas and Electric Co., 54 FERC (P) 61,077 at 61,255. (1991) Such issues should
be left to future wholesale rate increase requests, after the mechanism for
consolidation of administrative functions has been determined.
If this procedural approach is adopted, the Applicants will commit, as
a condition of the Transaction, (1) to proceed with the transmission tariff
Section 205 filing docket after
-10-
<PAGE>
approval of the Transaction, and (2) to accept any tariff provisions ordered by
the Commission in a final, non-appealable order in the Section 205 case and
ultimately to conform their transmission tariff provisions to the requirements
set forth in any final, non-appealable order resulting from the Commission's
Open Access NOPR. The Commission's recent decisions in Cincinnati Gas &
Electric Company and PSI Energy, Inc., 69 FERC (P) 61,005 (1994) and in Midwest
Power Systems, Inc. and Iowa-Illinois Gas and Electric Company, 71 FERC (P)
61,386 (1995) adopted this approach.
III. THE PROPOSED TRANSACTION IS IN THE PUBLIC INTEREST.
A. OVERVIEW OF THE REGULATORY STANDARDS
Merging entities need only show that "the proposed merger is
compatible with the public interest." Pacific Power & Light Co. v. FPC, 111
F.2d 1014, 1016 (9th Cir. 1940); Northeast Utilities Service Co. v. FERC, 993
F.2d 937, 951 (1st Cir. 1993), quoted in Entergy Services, Inc. and Gulf States
Utilities Co., 65 FERC (P) 61,332, 62,471 (1993). There is no requirement that
applicants make a showing of "a positive benefit of the merger". Utah Power &
Light Co., 47 FERC (P) 61,209, at 61,750 (1989), remanded on other grounds,
Environmental Action v. FERC, 939 F.2d 1057 (D.C. Cir. 1991); Entergy Services,
Inc., 62 FERC (P) 61,073, at 61,370 (1993) (footnotes and citations omitted).
The proposed merger will provide the following benefits: (1) it will
result in synergies that will permit cost
-11-
<PAGE>
savings of approximately $590 million during the first 10 years of the merger,
thus enhancing the Applicants' ability to continue to provide reliable service
at reasonable, competitive rates; and (2) transmission customers will be
provided with access to the combined transmission facilities of the Applicants
at a single system rate, resulting in enhanced access among suppliers and
purchasers in wholesale bulk power markets encompassing a substantial geographic
area. As a result, the Transaction more than satisfies the "consistent with the
public interest" standard of Section 203.
In general, only two issues have given rise to material factual
disputes requiring evidentiary hearings in Commission merger cases: the impact
of the merger on (1) costs and rates and (2) competition. The Applicants have
identified approximately $590 million in potential cost savings resulting from
the merger. Even if certain items in these savings estimates are disputed, it
is indisputable that significant savings will result from the merger, even after
allowing for recovery of all merger related costs.
The wholesale requirements customers of both UE and CIPS are currently
served pursuant to negotiated contracts. Neither of the Applicants proposes to
amend those contracts as a result of the Transaction. Furthermore, since these
contracts were negotiated and agreed to before the Transaction was contemplated,
the Applicants (with the exception noted below)
-12-
<PAGE>
will not include any portion of Ameren's merger investment in the calculation of
rates pursuant to those contracts through the remaining term of those contracts.
Any inclusion of merger investment costs in rates during periods after the
expiration of the current terms of these contracts would be negotiated with
those customers, which will be guaranteed the availability of competitive supply
options by the provision of open access transmission tariffs by the Applicants.
The exception noted above relates to three of CIPS' customers served under
formula-based contracts. The formulas used to determine charges for those
customers would reflect a small portion of the $19 million post-merger costs to
achieve savings, to the extent that those costs are reflected in CIPS'
administrative and general expense or production or transmission O&M expenses.
However, any such post-merger expenses included in those formula rates would be
more than offset by cost reductions due to the merger, which would also flow
through the formula rates. Since merger savings will exceed merger costs in
every year, any customer which, in the future, may choose to be served under
Applicants' filed wholesale tariffs, rather than under negotiated contracts,
would not be detrimentally impacted by the Transaction.
Moreover, Applicants are committing to an "open season" for their
wholesale requirements customers, under which any UE or CIPS wholesale
requirements customer identified in Exhibit No. ___ (GLR-8) or Exhibit No. ___
(GWM-11) could terminate its contract
-13-
<PAGE>
by giving a 90-day notice commencing on the day UE or CIPS files for a rate
increase which would impact that customer. Since UE's wholesale contract rates
are tied to UE's Missouri retail electric rates, this option would be activated
for UE customers when UE files for an electric rate increase with either the
Missouri Public Service Commission or the FERC. For CIPS customers, the open
season would be activated with a filing by CIPS for an increase in base rates
with the FERC. The filing Applicant would notify its customers at least 30 days
in advance of any such rate filing and would include in that notice an estimate
of the proposed increase. Neither UE nor CIPS would make any increase in its
base wholesale rates effective until at least 90 days after any such filing.
This open season guarantee would be effective for the first five years following
consummation of the merger.
The open season commitment would have to be administered somewhat
differently for the three CIPS formula-based customers, since their rates could
theoretically increase through the formula without CIPS filing for a rate
increase. Consequently, Applicants would provide those customers with an
additional guarantee. For those customers, the open season would be activated
not only by the filing at FERC of a base rate increase impacting them, but also
at any time at which the level of administrative and general expense reflected
in their formula rates during the immediately preceding twelve-month period is
-14-
<PAGE>
higher than the level of administrative and general expense reflected in those
rates during the twelve-month period immediately preceding the Transaction.
Administrative and general expense has been chosen as the base-line for this
additional safeguard because it would include most of the merger savings and
most of that portion of the post-merger costs to achieve savings which will flow
through the formula.
In addition, Applicants are willing to extend, under currently
applicable terms and conditions, the contract of any wholesale customer which
expires prior to the fifth anniversary of the effective date of the Transaction
for a period ending on the fifth anniversary date. This contract extension
offer will be held open until the effective date of the Transaction. As a
result of the foregoing commitments, the Transaction cannot have an adverse
impact on rates to wholesale requirements customers, regardless of the level of
savings actually achieved.
The attached testimony of Mr. Rodney Frame, Vice President of National
Economic Research Associates, Inc., demonstrates that the merger will not have
any adverse impact on competition in relevant wholesale bulk power markets. To
the contrary, bulk power market participants actually will benefit from single
system rates over the combined transmission systems of the Applicants.
-15-
<PAGE>
It is clear, therefore, that neither the issue of impact on costs and
rates, nor that of the impact on competition, requires an evidentiary hearing
with regard to approval of this Transaction.
In Commonwealth Edison Co., 36 FPC 927 (1966), aff'd sub nom. Utility
Users League v. FPC, 394 F.2d 16 (7th Cir. 1968), cert. denied, 393 U.S. 953
(1968), the Commission set forth six factors that it normally will consider in a
Section 203 proceeding: (1) the effect of the merger on operating costs and rate
levels; (2) the accounting treatment for the transaction; (3) the reasonableness
of the purchase price; (4) whether the merger was the result of coercion; (5)
the impact of the merger on competition; and (6) whether the merger impairs
effective state or federal regulation.
In El Paso Electric Co. and Central and South West Services, 68 FERC
(P) 61,181 (1994), the Commission established an additional standard for its
analysis of whether a merger is in the public interest. Under El Paso Electric,
an application to merge transmission facilities will not be deemed to be in the
public interest unless the merging companies commit to provide comparable
transmission services, whether or not the merger results in an increase in
market power.
In the recent order in Midwest Power Systems, Inc. and Iowa-Illinois
Gas and Electric Co., ("Midwest"), Commissioners
-16-
<PAGE>
Massey and Hoecker in their concurring opinion stated "[t]he time has come for
the Commission to reexamine its merger policy" in view of recent dramatic
changes in the industry and in regulatory policy. Concurring Opinion of
Commissioners Massey and Hoecker, 71 FERC (P) 61,386 at 62,512 (June 22, 1995).
The concurring Commissioners went on to state:
As we argue above, a merger's effect on competition is likely to
dominate Commission merger analysis in the future. In addition to
requiring open access as a condition of mergers, the Commission will
have other competition issues to address, including the importance of
the concentration of discrete transmission and generation assets, the
size and market power of the merged company, the extent of horizontal
or vertical integration, the treatment of claimed benefits achievable
outside the merger, and any decline in the number of generation or
transmission alternatives that remain in the wake of the merger.
Id. at 62,513. The concurring Commissioners elaborated further on their view of
competitive effects in the context of generation and transmission assets:
The sole competitive effect of mergers may be to increase the
concentration of generation assets. In some instances, this increased
concentration may be significant, but not important from a competitive
perspective. In other cases, however, the increase in concentration
might seriously hinder competition.
Id. at 62,512.
[W]e suspect a strong case could be made that, insofar as the
horizontal merger and integration across a region of discrete and open
transmission facilities is concerned, bigger may be better.
-17-
<PAGE>
Id. at 62,513.
Applicants view the concurring opinion in Midwest as an attempt to
initiate a policy discussion by listing certain categories of issues of
potential future concern, while leaving the elaboration and exposition of
specific additional criteria for evaluation of proposed mergers, if any are
indeed ultimately adopted, to the future. While the concurring opinion in
Midwest did not effect a change in the criteria applied by the Commission in
evaluating whether a proposed merger is consistent with the public interest, it
does indicate issues of potential concern to at least two Commissioners.
Consequently, to the extent that Applicants have correctly understood those
concerns, in light of the early level of discussion, they have been addressed in
the evidence provided herewith.
First, as to the concentration of generation, Mr. Frame testifies that
the merger will expand, not diminish, the bulk power supply options of the vast
majority of the utilities that are interconnected with the Applicants. The
merger will provide customers with open access to the transmission facilities of
UE and CIPS at a single system postage stamp rate pursuant to the terms and
conditions that the Commission has found are necessary to meet its comparability
requirements. This expanded access to bulk power markets results from "the
horizontal merger and integration across a region of discrete and open
transmission" systems referred to by the concurring Commissioners. The benefit
-18-
<PAGE>
conferred upon other utility systems by granting access to the combined
transmission system under a single postage stamp rate pursuant to the
combination of UE and CIPS goes beyond the benefit these other systems would
realize by virtue of separate compliance with the Open Access NOPR by UE and
CIPS. This results from the fact that, due to the combination, these other
systems will have to pay only one transmission rate in order to utilize both
systems. In addition, evidence is provided indicating that, using traditional
measures of concentration, the combination of CIPS and UE does not present
concerns about market power.
Proper antitrust analysis requires an evaluation of whether a proposed
merger will substantially harm competition by creating or increasing market
power, or facilitating its exercise through collusion, in areas of actual and
potential competitive overlaps between the business activities of the proposed
merger partners. This requires the proper definition of "relevant markets" in
both their product and geographic dimensions. Merger analysis should be
concerned only with the likelihood that the specific proposed merger will lessen
competition, and should not attempt to anticipate or shape the future structure
of the market or engage in industrial planning. It is possible, for example,
that firms A and B should be permitted to merge because they can do so without a
likely adverse effect on competition; but that, at a later point in time,
otherwise identical firms C and D will
-19-
<PAGE>
not be permitted to merge, because changes in the market (perhaps the merger of
A and B) will cause the merger of C and D to result in adverse effects on
competition. This is no reason to bar the merger of A and B. Regulation should
allow the future structure of the market to be determined by the competitive
facts of life. Intervention is appropriate only with regard to those proposed
mergers which are shown to have a likely adverse effect on competition in a
relevant market.
Mr. Frame has thoroughly analyzed the Transaction in accordance with
these basic antitrust precepts. He has defined the relevant markets to be
examined and analyzed the impact of the proposed Transaction on these relevant
markets under a framework which is substantially the same as that contained in
the Department of Justice and Federal Trade Commission Horizontal Merger
Guidelines, dated April 2, 1992. He has found that there is no likelihood of an
adverse effect on competition in any of the relevant markets. That is the
appropriate scope of an antitrust inquiry and, in this case, that inquiry
establishes that there is no reason to bar this merger.
Finally, the evidence establishes that both UE and CIPS have been
engaged in cost savings and reengineering programs to reduce costs and increase
efficiencies on their own and that none of those savings and efficiencies have
been claimed as merger-related benefits and used to justify the merger. Only
cost
-20-
<PAGE>
savings and efficiencies realizable solely as a result of the merger are
included in the $590 million of merger savings.
The issues delineated in the Commonwealth Edison and El Paso Electric
cases, which continue to be applicable to the Commission's review of electric
utility mergers, are discussed more fully below.
B. THE PROPOSED TRANSACTION SATISFIES THE COMMONWEALTH EDISON STANDARDS.
1. THE TRANSACTION WILL REDUCE OPERATING COSTS AND KEEP RATES LOWER
THAN THEY OTHERWISE WOULD BE.
The Applicants are submitting the testimony of Mr. Thomas J. Flaherty,
National Partner for Utilities Consulting in the Deloitte & Touche Consulting
Group, a division of Deloitte & Touche LLP, and Mr. Rainwater, which shows that
the Applicants can achieve approximately $590 million in cost savings during the
first 10 years of the merger as a result of consolidating their systems after
accounting for cost reduction measures previously initiated by the Applicants.
After netting out the costs (including transaction costs and merger premium)
that will be incurred to achieve these savings, the total projected net savings
during the first 10 years of the merger are approximately $317 million.
The projected savings and costs to achieve are summarized as follows:
-21-
<PAGE>
<TABLE>
<CAPTION>
TOTAL SAVINGS
1997 - 2006
SAVINGS CATEGORY ($ MILLIONS)
---------------- -------------
<S> <C>
Corporate and Operations Labor $ 195.8
Corporate and Administrative Programs 204.1
Purchasing Economies (Non-fuel) 68.8
Electric Production 84.1
Gas Supply 37.1
-------
Total Savings 589.9
Less: Costs to Achieve (19.1)
Transaction Costs (22.0)
Merger Premium (232.0)
-------
Net Savings $ 316.8
=======
</TABLE>
As Mr. Flaherty testifies, these projected savings were developed at
the request of the Applicants during the initial phases of their merger
negotiations in order for the Applicants to determine whether the Transaction
made economic sense. The same savings projections now are being used, reviewed
and refined by the Applicants as part of their internal transition planning for
post-merger operations. The cost savings projections presented herein thus are
not an ex post facto attempt to justify a decision to merge, but instead have
constituted and continue to constitute an important element of the Applicants'
internal merger planning completely apart from this or any other regulatory
proceeding.
-22-
<PAGE>
Although the exact level of merger savings that will be achieved
cannot be predicted with precision, there can be no question but that
substantial savings will result from the proposed Transaction. For purposes of
a Section 203 proceeding, no further showing is required, and an evidentiary
hearing on this issue is not necessary. See Midwest Power, 71 FERC at 62,506-
08; Cincinnati Gas & Electric, 64 FERC at 62, 713-14.
In addition, the Applicants are committing to provide the previously
described open season to protect their wholesale requirements customers from any
rate increases that occur as a result of the Transaction. In the Midwest Power
proceeding, the Commission accepted such an open season commitment as an
appropriate safeguard, 71 FERC at 62,508. The Applicants' commitment thus
provides further support for a decision by the Commission that an evidentiary
hearing on the rate effects of the merger is not necessary.
2. APPLICANTS WILL USE THE "POOLING" METHOD OF ACCOUNTING.
As described more fully in the testimony of Mr. Warner L. Baxter, UE's
Assistant Controller, Ameren will account for the merger by using the pooling of
interests method, as provided for in Accounting Principles Board Opinion No. 16
(APB No. 16). The pooling of interests method accounts for the merger as a
uniting, or "pooling", of ownership interests accomplished by the exchange of
voting securities. This method is used where the merger
-23-
<PAGE>
satisfies the criteria set forth in APB No. 16. As discussed in the testimony of
Mr. Baxter, the proposed merger meets those criteria. This is a reasonable
accounting treatment to use for a merger and does not require any consideration
at hearing./2/
Additionally, the Applicants request the Commission to find that the
shared savings plan described in the testimony of Mr. Rainwater is consistent
with appropriate regulatory accounting treatment./3/ The Applicants do not
propose any wholesale rate increases with this Application and do not anticipate
the need for any rate increases attributable to the merger. The shared savings
plan merely establishes a regulatory accounting treatment that will enable
shareholders and customers equitably to share merger savings, net of the merger
premium and other transaction related costs, described in the testimony of
Messrs. Rainwater and Kimmelman. The Applicants recognize that approval of the
shared savings plan as an acceptable regulatory accounting approach will not
constitute a ratemaking order issued under FPA sections 205 and 206.
- ---------------------
/2/ See Utah Power & Light Company, Pacific Corp., and PC/UP&L Merging
Corporation, 41 FERC (P) 61,283 at 61,755; Southern California Edison Company
and San Diego Gas and Electric Company, 47 FERC (P) 61,196 at 61,675; Midwest
Power, 71 FERC at 62,509.
/3/ To the extent necessary, this request is made pursuant to FPA Section 301,
as well as FPA Section 203.
-24-
<PAGE>
3. THE EXCHANGE RATIO WAS NEGOTIATED AT ARM'S LENGTH AND IS
REASONABLE.
The Merger Agreement (attached to Mr. Rainwater's testimony as Exhibit
No. __ (GLR-2)) was negotiated at arm's length between UE and CIPSCO and was
approved by the respective Boards of Directors of each company. On December 20,
1995, the shareholders of each of the companies also approved the Merger
Agreement. Under that agreement, neither company can be said to be "purchasing"
the other for an established price. Instead, there will be a strategic alliance
whereby the holders of common stock in UE and CIPSCO will each exchange their
shares of stock for shares in Ameren. The rate of exchange for common stock --
1.00 share of UE stock and 1.03 shares of CIPSCO stock for each share of Ameren
stock -- was negotiated at arm's length by the merging companies and approved by
their respective Boards of Directors.
The Commission has held that the arm's length nature of negotiations
leading to a merger obviates the need for a hearing on the reasonableness of the
purchase price. Midwest Power, 71 FERC at 62,510. Further, the proposed merger,
including the proposed rate of exchange for common stock, must be approved by a
vote of UE's and CIPSCO's shareholders. As a consequence, the Commission need
not "consider the effect of the purchase price on shareholders. The federal and
state securities laws provide a mechanism to address these concerns." Southern
Cal. Edison Co.,
-25-
<PAGE>
47 FERC (P) 61,196, at 61,673 n.20 (1989). See also Midwest Power, 71 FERC at
62,510.
4. THERE IS NO ISSUE OF COERCION.
As established in the testimony of Mr. Donald E. Brandt, UE's Senior
Vice President-Finance and Corporate Services, neither company coerced the other
into the Transaction. Each company has low production costs and entered into the
Transaction for long term strategic reasons. The Transaction was entered into
freely by, and in the interest of, each company. The fact that the Transaction
must be approved by the shareholders of each company further ensures that the
Transaction is at arm's length, free of undue influence by either side.
5. THE TRANSACTION WILL PROMOTE COMPETITION.
Included with this Application is the testimony of Mr. Rodney Frame,
an independent economist, which provides an evaluation of the impact of the
proposed merger on competition. Mr. Frame's testimony follows the analytic
framework established by the Commission in prior merger cases for the
consideration of market power issues.
Mr. Frame's analysis identifies the relevant product and geographic
markets and considers the impact of the merger on competition in these markets.
Among other things, he concludes that the comparable service transmission
tariffs filed by the Applicants and the availability of service over the
combined
-26-
<PAGE>
facilities of both systems at a single system rate expands the supply
alternatives in affected wholesale markets.
In analyzing short term capacity markets, Mr. Frame analyzed the
uncommitted capacity of UE, CIPS, UE and CIPS combined, and all other electric
systems directly interconnected with UE and/or CIPS for the years 1995 and 1998.
His analysis showed that UE and CIPS control only relatively small shares (far
less than the 20% threshold which the FERC has utilized in the past to denote
situations that obviously present no concern as to market power) of the
uncommitted generating capacity held by all directly interconnected utilities.
Thus, he concludes that the combination of UE and CIPS will not create an
opportunity to exercise seller market power in short term capacity markets. He
then examined how the merger affects concentration of uncommitted capacity in
first tier markets (defined as markets centered on each utility directly
interconnected with CIPS or UE and including each utility which is either
directly connected to, or "one wheel" away from that utility). Once again, he
finds that the combination of UE and CIPS produces shares of uncommitted
capacity that are below threshold levels which might indicate concern about the
possible exercise of market power in short term capacity markets.
With respect to long term capacity markets, Mr. Frame concludes that
the Transaction will not create or enhance control over sites for new generating
facilities or other key factor
-27-
<PAGE>
inputs to new resource additions, such as fuel supply or fuel transportation.
Consequently, Mr. Frame concludes that Ameren will have no market power in long
term capacity markets.
Mr. Frame also concludes that the combination of UE and CIPS does not
create or enhance market power in non-firm energy markets. This is based in part
upon the market expanding effects associated with Applicants' combined (single
system) transmission tariff. It is also based upon specific analyses which Mr.
Frame has performed. Mr. Frame examined the combined firms' share of generating
capacity in the first tier markets discussed above and analyzed actual data on
non-firm and substitutable energy or capacity and energy sales. His analyses
indicate that the combined UE and CIPS share of total generating capability in
first tier markets is below threshold levels which could suggest possible
concerns about market power. The analyses also indicate that the combined UE and
CIPS non-firm energy transactions do not result in market shares and increases
in the Herfindahl-Hirschmann Index (HHI) which indicate that the combination of
UE and CIPS is likely to have any substantially adverse impact on competition in
the non-firm energy market.
Mr. Frame also concludes that the Transaction will not adversely
affect retail competition. His testimony addresses franchise, yardstick,
locational (or customer) and fringe area competition, as well as interfuel
competition between gas and electricity at the retail level.
-28-
<PAGE>
6. BOTH WHOLESALE AND RETAIL REGULATION WILL REMAIN EFFECTIVE.
Upon completion of the proposed Transaction, the Missouri Public
Service Commission will continue to have jurisdiction over the retail electric
and gas rates of UE, which will operate substantially the same facilities as it
previously operated in Missouri. Similarly, the Illinois Commerce Commission
will continue to have jurisdiction over CIPS' electric and gas rates. CIPS will
operate substantially the same facilities as were previously operated in
Illinois by CIPS and UE, with the exception of the UE Retained Illinois
Facilities.
Ameren will be regulated as a registered holding company under PUHCA
and thus many of the transactions of Ameren and its subsidiaries, other than
electric and gas sales, will require prior approval of the SEC.
Finally, both state utility commissions will have the authority to
review various aspects of the proposed Transaction. See Section X(I)(3) and (4).
As the Commission stated in Entergy, "the interests of [the] states vis-a-vis
state regulation can be protected by those state commissions" in the context of
their review of the proposed merger. 62 FERC at p. 61,374; See also Kansas Power
& Light Co., 54 FERC (P) 61,077 at p. 61,255 (1991).
-29-
<PAGE>
C. THE EL PASO STANDARD: UE AND CIPS WILL PROVIDE COMPARABLE TRANSMISSION
SERVICE UPON CONSUMMATION OF THE MERGER.
Transmission access has been viewed as a critical issue in merger
cases by the Commission since the PacifiCorp/UP&L merger. More recently, the
Commission has clarified the terms and conditions of transmission access which
are required for a merger to meet the "consistent with the public interest"
test. In 1994, the Commission announced in the El Paso Electric case that all
merging utilities would have to provide "comparable service" after the merger.
The Commission did not specify in El Paso Electric what it considered to be
"comparable service". However, the recently issued Open Access Notice of
Proposed Rulemaking ("Open Access NOPR") in Docket No. RM95-8-000 goes into
great detail on this subject and even provides model pro forma tariffs that the
Commission has stated contain the terms and conditions necessary to provide
comparable service. FERC Statutes and Regulations (P) 32,514.
Furthermore, in its Order on Rehearing and Clarification and Providing
Further Guidance on Processing Open Access Filings, Docket No. ER93-540-003
(June 28, 1995) ("Further Guidance Order"), the Commission stated that unless
merger applicants file tariffs consistent in all material respects with the pro
forma tariffs, they may have to wait until the conclusion of any hearing
regarding their tariffs before the merger is approved. 71 FERC (P) 61,393 at
62,541.
-30-
<PAGE>
As discussed above, the Applicants simultaneously have filed under
Section 205 of the FPA Open Access NOPR pro forma tariffs, to become effective
when the proposed merger is consummated. These tariffs are discussed in more
detail in the testimony of Ms. Borkowski and copies of the tariffs, with any
changes from the Commission's pro forma tariffs indicated, are attached as
Exhibits Nos. ____ and ____ (MAB-10 and 11) to her testimony. As Ms. Borkowski
explains in her testimony, the filing by Applicants is consistent in all
material respects with the pro forma tariffs, with only minor changes having
been made.
Ms. Borkowski also explains that the Applicants commit to revise their
tariff filing to reflect any changes imposed by the Commission in its final rule
in Docket No. RM95-8-000.
As a consequence, there is no material transmission access issue
involved with the Transaction. The Applicants have followed the Commission's
guidelines in the Open Access NOPR and the Further Guidance Order, and they are
in full compliance with El Paso Electric.
IV. THE COMMISSION SHOULD APPROVE THE TRANSACTION EXPEDITIOUSLY WITHOUT HEARING
The Commission has held repeatedly that Section 203 does not require
the holding of an evidentiary hearing. Instead, an evidentiary hearing is
necessary only when there are material issues of disputed fact that must be
resolved to determine whether the proposed merger is consistent with the public
-31-
<PAGE>
interest. As a consequence, in the recent Delmarva and Midwest Power cases, the
Commission approved the proposed mergers without conducting any evidentiary
hearing. Furthermore, as the Commission has recognized in previous merger cases,
expediting the approval of a proposed merger is appropriate to permit the prompt
realization of merger-related synergies and benefits and to address the
commercial realities and time pressures presented by a proposed merger. See
Kansas Power and Light, 54 FERC at p. 61,252; Northeast Utilities Service
Company, 58 FERC (P) 61,070, at 61,202 (1992); Entergy, 62 FERC at p. 61,368.
As demonstrated above and in the attached testimony, there can be no
dispute that the Transaction will produce substantial cost savings, will expand
wholesale market opportunities for the majority of regional market participants
and, therefore, will be consistent with the public interest. Consequently, it is
appropriate for the Commission to expedite its review of Applicants' proposed
merger and approve the merger without an evidentiary hearing so that UE's and
CIPS' retail and wholesale customers and prospective users of their transmission
systems may begin to enjoy the economic and competitive benefits of the merger
as soon as possible. As indicated above, issues which may arise with regard to
the matters discussed in Sections V through VIII below are separable and, should
hearings on such issues be required, may be scheduled for hearing subsequent to
the granting of the Section 203 authorization.
-32-
<PAGE>
V. SYSTEM SUPPORT AGREEMENT
The Illinois territory currently served by UE is generally known as
the St. Louis Metro-East area. The UE Illinois electric service territory
comprises a geographic area of about 330 square miles, with about 64,000
customers in 22 communities. As discussed in the testimony of Mr. Rainwater,
CIPS is acquiring UE's electric and gas distribution systems, including electric
lines and substations, as well as all associated general plant-in-service in
Illinois. CIPS is not taking ownership of any UE electric generating or
transmission facilities operating in Illinois.
In order to provide service to the transferred area, UE and CIPS have
agreed to enter into a System Support Agreement for the provision of power and
energy to CIPS. That agreement is premised on certain principles which are
intended to maintain the low cost structure now in place for the customers in
UE's Illinois service area, avoid the reallocation of UE's costs from Illinois
to Missouri, and minimize the need to advance the plans for adding supply-side
resources by CIPS. CIPS will be responsible for meeting power requirements in
excess of those provided by the System Support Agreement for all future load
growth in the transferred area.
The Applicants are asking the Commission to recognize the System
Support Agreement as a just and reasonable rate providing an appropriate cost
allocation mechanism for the
-33-
<PAGE>
continued recovery of UE generation and transmission costs from the transferred
Illinois electric customers. Applicants seek to avoid cost shifting between
state jurisdictions with consequent rate impacts caused by the merger structure
and not by changes in underlying costs. CIPS and UE are attempting to maintain
the status quo, with the generation and transmission system planned and
installed to serve these customers continuing to serve them, and the cost of
rendering that service continuing to be recovered from them. The transfer of the
customers is designed to promote administrative convenience, resulting in
economies for the companies and the Illinois Commerce Commission. Without the
System Support Agreement, the transfer of the Illinois customers would not be
possible, and the resulting economies would be lost.
UE's generation and transmission system was planned and constructed as
an integrated system designed to serve all of UE's customers, including those
customers being transferred to CIPS. Consequently, cost allocations have
historically been made between jurisdictions to reflect UE's generation and
transmission costs in serving each jurisdiction, resulting in revenue levels
that provide for cost recovery. The agreement preserves the recovery of costs
for UE's generation and transmission systems that will continue to serve
Illinois customers after the merger is effective.
In the System Support Agreement, CIPS agrees to a long-term assignment
of capacity and energy from UE's generation,
-34-
<PAGE>
which is equivalent to the generation currently committed to serving UE's
Illinois customers. CIPS will be responsible for providing capacity and energy
in excess of the contract amounts specified in the support agreement. As UE's
existing generation is retired, the contracted level of capacity and energy
support to CIPS from the UE generation will proportionately decrease. The
contract capacity and energy also may be adjusted downward if CIPS experiences
the loss of a significant customer load in the transferred area. This aspect of
the agreement will help balance the system support capacity provided by UE with
customer load.
The System Support Agreement has a fixed cost component as well as a
variable cost, or energy, component. The formula will reflect actual costs as
they change from time to time. The energy cost component of the System Support
Agreement provides for the assignment of average variable costs from UE to CIPS.
CIPS' remaining customers will be isolated from the impact of the costs
allocated under the System Support Agreement, since that agreement is designed
to allocate UE generation and transmission costs solely to the former UE
Illinois service area customers.
In short, the System Support Agreement is central to the Transaction
because it is necessary in order to effect the transfer of UE's Illinois
properties to CIPS, and is designed to ensure that the transfer will not impact
the rates of either UE's existing Missouri or Illinois customers.
-35-
<PAGE>
VI. JOINT DISPATCH AGREEMENT
UE and CIPS will operate their combined generation and transmission
facilities as a single control area. The control area will interface directly
with 28 other utilities to buy and sell capacity and energy economically, using
the generation and transmission resources of the combined system. All load
requirements will be combined and all resources will be controlled by a single
Automatic Generation Control. By committing and dispatching resources on a
single system basis, the total production costs will be lower than if the two
companies' resources were committed and dispatched separately. As load on the
system increases, it will be served instantaneously by the next available,
lowest cost source of generation, regardless of whether that generation is owned
by UE or CIPS, or, in the case of a purchase, regardless of whether the source
is connected to UE or CIPS. This change in operation should enhance interchange
purchase and sales activities. The fact that the single control area will be
able to interface directly with 28 interconnected utilities will allow UE and
CIPS to optimize sale and purchase opportunities. The result should be reduced
costs for UE and CIPS, because each company will have improved access to a
greater number of competitive sources of supply, thus increasing the potential
for cost-reducing purchases and sales. In particular, a combined operation will
eliminate the need for a transmission charge or adder that UE or CIPS would
otherwise have had to pay to effect a purchase or sale across the
-36-
<PAGE>
other's system. Today, the existence of such charges may preclude consummation
of certain transactions, because the incremental cost of a lower cost generating
unit plus the transmission adder may be higher than the incremental cost of a
somewhat higher cost generating unit which does not require the transmission
adder.
There are four categories of costs that can be affected by coordinated
operation. These are: (1) fixed costs associated with generation; (2) variable
production costs; (3) interchange power costs; and (4) transmission costs.
Each company will continue to own and operate the generating units
that it presently owns. Each company will be responsible for the fixed costs
associated with the generation it owns, except as otherwise provided in the
System Support Agreement discussed above.
The variable production cost category includes fuel costs, variable
operating and maintenance costs and emission allowances costs. Interchange power
costs include the costs for any purchased capacity or energy required in the
operation of the control area whether it be for emergency, capacity or economy
purposes. They include both demand charges and energy charges incurred under
FERC approved wholesale contracts. Variable production costs and interchange
power costs will be allocated pursuant to the Joint Dispatch Agreement. The
basic principles
-37-
<PAGE>
reflected in the agreement with respect to allocation of interchange power costs
and variable production costs are as follows:
1. Each company will be allocated its own lowest-cost generation to
serve its own load requirements.
2. Variable production costs associated with generating units that
are designated to run out of order due to operating constraints
will be assigned to the owning company, unless the load or
operating requirement of the other company is specifically
identified as causing the constraints.
3. An after-the-fact analysis will be performed to assign the
generating and purchase power resources to each company's load
requirements and to the combined systems' off-system sales.
4. The after-the-fact analysis will determine what generation was
required from one company to serve the other's native load. The
incremental production costs associated with this generation will
be assigned to the receiving party.
5. The after-the-fact analysis will also show which company's load
was served by a purchase. Energy costs associated with that
purchase will be assigned to that company. Energy purchases that
-38-
<PAGE>
are economic for both companies will be shared on a load ratio
basis, except that energy from purchases agreed to before the
merger will be made available first to the contracting company.
Demand charges for purchases agreed to before the merger will be
borne solely by the contracting company. Demand charges for
purchases agreed to after the merger will be assigned on a load
ratio basis.
6. Revenue in the amount of the incremental costs of generating
energy to provide sales will be credited to the company that
supplied the energy. Net energy revenues from sales will be
allocated based upon a monthly ratio of net outputs.
7. Demand charges for sales that were agreed to before the merger
will be allocated to the contracting company. Demand charges for
sales that are agreed to after the merger will be allocated on
the basis of a ratio of surplus reserves.
8. The parties contemplate that the costs associated with
transmission facilities will be borne by the company owning such
facilities. To the extent that the companies construct jointly-
owned facilities in the future, it is expected that costs will be
borne in proportion to the agreed
-39-
<PAGE>
upon respective ownership interests. The revenues from the open
access transmission tariff for the combined system will be shared
between UE and CIPS by initially compensating each company for
any costs of direct assignment or distribution facilities
included in the transmission service revenues. Each company will
then be reimbursed for any incremental expenses incurred to
provide the transmission service. Any remaining revenue will be
shared in proportion to each company's transmission plant
investment included in the tariff rates.
VII. PROPOSED REGULATORY ACCOUNTING TREATMENT OF SHARED SAVINGS
PLAN
Applicants propose that their stockholders be allowed an opportunity
to recover the investment which was required to achieve the merger savings, as
well as being allowed to share in net merger savings. Ameren Corporation's
shareholders will incur a merger premium of $232 million, based on the effective
cost above market that Ameren will pay to acquire the stock of CIPSCO, and will
incur other transaction costs of $41 million in order to complete the merger.
That represents a $273 million investment which will return $590 million in
savings over a 10-year period, an additional $970 million in the second 10-year
period, and almost $1.4 billion in the third 10-year period. Unless this
investment is recognized as a cost in any plan for the sharing of
-40-
<PAGE>
savings, shareholders will have little chance to be made whole from the savings
generated by this investment. Applicants propose to recover Ameren's investment
in all jurisdictions which they serve through a shared savings plan, which will
allow Ameren's stockholders and customers to share equally in the net merger
savings. The shared savings plan will allow stockholders to recover their direct
merger investment, the $273 million referred to above, over a 10-year period.
The plan will amortize that investment in proportion to expected savings in each
of the 10 years to ensure there are net savings in each year. It will then split
the net savings equally between shareholders and customers. The plan is fully
described in the testimony of Mr. Rainwater. Mr. Rainwater indicates how
Ameren's merger investment will be amortized, how a portion of projected net
savings will be allocated to cost of service, and how an equal portion of net
savings will be made available to reduce customers' cost of service.
Applicants request the Commission to find that the shared savings plan
and cost recovery mechanism is consistent with appropriate regulatory accounting
treatment, permitting recovery of Ameren's investment based on the proposed
shared savings plan. The plan provides shareholders the opportunity to recover
the amortized merger costs over the next 10 years. The cost reductions created
by the merger should make achievement of that objective possible without the
need for a rate increase.
-41-
<PAGE>
VIII. NUCLEAR DECOMMISSIONING TRUST
As previously indicated, the Applicants are requesting certain
approvals with regard to the disposition and funding of that portion of UE's
nuclear decommissioning trust fund established for its Illinois jurisdiction as
a result of the transfer of the retail customers in that jurisdiction to CIPS.
UE's rates in Illinois, as well as its wholesale rates and its rates in
Missouri, recognize nuclear decommissioning expenses. The amounts reflected in
cost-of-service are deposited quarterly in an external tax-qualified trust. The
amount collected by UE annually from Illinois ratepayers is $355,000, and, as of
June 30, 1995, a total of $5.7 million is held in the Illinois subaccount of the
external tax-qualified trust. This annual funding level for Illinois has not
changed since 1985 when set in UE's last Illinois rate case.
As discussed above, once the Merger is consummated, UE will no longer
have an Illinois retail electric jurisdiction. Since the IRS requires that
contributions into a tax-qualified trust be included in the contributing
jurisdiction's cost-of-service, UE will no longer be able to place the annual
contribution from Illinois customers into the tax-qualified trust.
As also discussed above, UE and CIPS propose to enter into a System
Support Agreement. That agreement provides for the payment by CIPS to UE of
nuclear decommissioning expenses which
-42-
<PAGE>
would be contributed to the tax-qualified trust quarterly in a FERC subaccount,
because the System Support Agreement is FERC jurisdictional.
As addressed in the testimony of Mr. Michael C. Williams, UE's Manager
of Nuclear Services, Exhibit No. ___ (MCW-1), the current (1995) estimate for
the costs to decommission Callaway is $433 million. UE's Treasurer, Mr. Jerre E.
Birdsong, explains that the System Support Agreement sets forth a rate which
includes a component of $425,000 annually for nuclear decommissioning costs.
(Exhibit No. ___ (JEB-1)) As Mr. Birdsong indicates in his testimony, $425,000
is a reasonable component for such costs based on UE's estimate for the costs to
decommission Callaway. Applicants request that the Commission authorize this
amount as being included in UE's cost-of-service. Such authorization is required
by the IRS in order for UE to place contributions into the tax-qualified trust.
Applicants request that, if required by the Federal Power Act, the
Commission authorize transfer of the balance of funds in the Illinois
subaccount, as of the date of the Merger, to a FERC subaccount. With this
change, the oversight of the obligation to fund nuclear decommissioning as to
UE's current Illinois electric jurisdiction will be transferred from the
Illinois Commerce Commission to the FERC. As discussed in the testimony of Mr.
Williams and Mr. Birdsong, such a transfer of funds, and such authorization that
the decommissioning expenses
-43-
<PAGE>
are included in UE's cost-of-service, are reasonable and in the public interest.
IX. AUTHORIZATIONS REQUESTED
The Applicants are requesting this Commission's approval for several
aspects of the proposed Transaction. The Applicants request that these filings
be considered on a timely basis so that the Transaction can be consummated as
soon as possible during 1996.
First, the Applicants are requesting in this Application that the
Commission approve that part of the Transaction involving the merger of CIPSCO
into Ameren, with Ameren as the surviving corporation, which will result in CIPS
and other non-utility subsidiaries of CIPSCO becoming wholly-owned subsidiaries
of Ameren.
Second, the Applicants are requesting approval in this Application of
the merger of Arch into UE, with UE as the surviving corporation, which will
result in UE becoming a wholly-owned subsidiary of Ameren.
Third, the Applicants are requesting approval in this Application, to
the extent necessary, of the transactions by which UE will transfer title to the
Transferred Assets to Ameren, which will in turn transfer title to the
Transferred Assets to CIPS.
-44-
<PAGE>
Fourth, the Applicants recognize that the Commission must approve,
under Section 205 of the FPA, the System Support Agreement pursuant to which UE
will sell capacity and energy to CIPS. Consequently, the Applicants are filing
that agreement for the Commission's approval under Section 205 of the FPA with
this Application and request that the Commission issue an order finding the
System Support Agreement to be just and reasonable and permitting it to become
effective upon completion of the Transaction.
Fifth, the Applicants recognize that the Commission must approve,
under Section 205 of the FPA, the Joint Dispatch Agreement pursuant to which UE
and CIPS will dispatch their generating resources on an integrated basis.
Consequently, the Applicants are filing that agreement for the Commission's
approval under Section 205 of the FPA with this Application and request that the
Commission issue an order finding the Joint Dispatch Agreement to be just and
reasonable and permitting it to become effective upon completion of the
Transaction.
Sixth, the Applicants request that the Commission find that the shared
savings plan and cost recovery mechanism, fully described in Mr. Rainwater's
testimony, is consistent with appropriate regulatory accounting treatment.
Seventh, concurrently with this Application, the Applicants also are
filing open-access comparable service
-45-
<PAGE>
transmission tariffs under Section 205 of the FPA. These consist of a Network
Integration Service Tariff and a Point-to-Point Transmission Tariff. These
tariffs, which will become effective upon the consummation of the Transaction,
essentially duplicate the pro forma tariffs that were included by the Commission
in the Open Access NOPR.
Eighth, with regard to decommissioning, the Applicants are requesting
the following: (1) that the Commission authorize the transfer of the current
balance in the Illinois subaccount of UE's decommissioning trust fund to a FERC
subaccount, if such approval is required by the Federal Power Act; and (2) that
the Commission approve the amount of $425,000 in the System Support Agreement as
being included in UE's cost-of-service to comply with IRS requirements regarding
tax-qualified decommissioning funds.
X. INFORMATION REQUIRED BY 18 C.F.R. (S) 33.2
In support of this Application, the Applicants submit the following
information required by Section 33.2 of the Commission's regulations, 18 C.F.R.
(S) 33.2.
A. (S) 33.2(A) - NAMES AND ADDRESSES OF PRINCIPAL BUSINESS OFFICES
The following are the names and principal business offices of the
Applicants:
-46-
<PAGE>
1. UE
--
Union Electric Company
1901 Chouteau Avenue
P.O. Box 149
St. Louis, MO 63166
2. CIPS
----
Central Illinois Public Service Company
607 East Adams Street
Springfield, IL 62739
B. (S) 33.2(B) - NAMES AND ADDRESSES OF THE PERSONS AUTHORIZED TO RECEIVE
NOTICES AND COMMUNICATIONS WITH RESPECT TO THIS APPLICATION
The following persons are authorized to receive notices and
communications with respect to this Application:
1. UE
--
Mr. Joseph H. Raybuck
Attorney
Union Electric Company
P.O. Box 149 (MC 1310)
St. Louis, MO 63166
Mr. James J. Cook
Assoc. General Counsel
Union Electric Company
P.O. Box 149 (MC 1310)
St. Louis, MO 63166
2. CIPS
----
Mr. William A. Koertner
Vice President, Finance
Central Illinois Public Service Company
607 East Adams Street
Springfield, IL 62739
-47-
<PAGE>
Mr. Robert J. Mill
Manager, Rate Department
Central Illinois Public Service Company
607 East Adams Street
Springfield, IL 62739
Mr. David J. Rosso
Mr. Christopher W. Flynn
Jones, Day, Reavis & Pogue
77 West Wacker Drive
Chicago, IL 60601
Mr. Robert Waters
Jones, Day, Reavis & Pogue
Metropolitan Square
1450 G Street, N.W.
Washington, D.C. 20005
The Applicants also request that the foregoing persons be placed on
the official service list for this proceeding.
C. (S) 33.2(C) - DESIGNATION OF THE TERRITORIES SERVED, BY COUNTIES AND
STATES
1. UE
--
The counties and states, or portions thereof, which are served by UE
are listed in Appendix 2.
2. CIPS
----
The counties and states, or portions thereof, which are served by CIPS
are listed in Appendix 3.
3. MAPS
----
The retail electric service territories of the Applicants are shown on
the maps contained in Exhibit I.
-48-
<PAGE>
D. (S) 33.2(D) - DESCRIPTION OF JURISDICTIONAL TRANSMISSION FACILITIES
1. UE
--
As of December 31, 1994, UE owned and operated, or partially owned,
approximately 3,300 miles of transmission lines/4/ and has interconnection
arrangements with 15 investor-owned utilities and with Associated Electric
Cooperative, Inc., the City of Columbia, the Southwestern Power Administration
and the Tennessee Valley Authority. It is a member of the Mid-America
Interconnected Network ("MAIN"). UE has the following Missouri wholesale
utility customers: California, Centralia, Citizens Electric, Farmington,
Fredericktown, Hannibal, Jackson, Kahoka, Kirkwood, Linneus, Marceline,
Owensville, Perry, Rolla, St. James and Sho-Me Power Corporation. A further
description of the facilities owned or operated by UE for transmission of
electric energy in interstate commerce or the sale of electric energy at
wholesale in interstate commerce is found in the testimony of Ms. Borkowski.
2. CIPS
----
On December 31, 1994, CIPS owned and operated, or partially owned,
approximately 4787 miles of 34.5 kV or above (4028 miles of 69 kV and above)
transmission lines. It has interconnection arrangements with 10 investor-owned
utilities and with the Tennessee Valley Authority, Wabash Valley Power
_____________________
/4/ 69 kV and above.
-49-
<PAGE>
Association, City Water, Light & Power of Springfield, Illinois, Illinois
Municipal Electric Agency, Indiana Municipal Power Agency, Soyland Electric
Cooperative and Southern Illinois Power Cooperative. It is a member of MAIN.
CIPS provides full requirements service in Illinois to Norris Electric
Cooperative, City of Newton, Village of Greenup and Mt. Carmel Public Utility
Company. It also sells system participation power to Soyland Power Cooperative
and the Illinois Municipal Electric Agency in Illinois, as well as to Wabash
Valley Power Association in Indiana. A further description of the facilities
owned or operated by CIPS for transmission of electric energy in interstate
commerce or the sale of electric energy at wholesale in interstate commerce is
found in the testimony of Mr. Gilbert W. Moorman, Vice President, Power Supply
for CIPS.
3. MAPS
----
The location of the transmission systems, interconnections and
generating plants of the Applicants are shown on maps contained in Exhibit I.
E. (S) 33.2(E) - DESCRIPTION OF TRANSACTION AND STATEMENT AS TO
CONSIDERATION
A copy of the Merger Agreement is included with this Application as
Exhibit No. ___ (GLR-2) to Mr. Rainwater's testimony and the Transaction and the
consideration for the merger are described in Section II of this Application, in
the Merger Agreement and in the testimony of Mr. Rainwater.
-50-
<PAGE>
F. (S) 33.2(F) - DESCRIPTION OF FACILITIES INVOLVED IN THE TRANSACTION AND OF
THEIR CURRENT AND PROPOSED USES
A description of each Applicant's utility property involved in this
combination is provided below in summary form. The proposed Transaction
includes all of the operating property of the Applicants, including all
franchises, permits and rights owned by the Applicants. UE and CIPS will use
such property in the same general manner as it was used immediately prior to the
merger.
1. UE
--
UE owns six steam electric plants (one nuclear plant and five fossil
fuel plants), two hydroelectric generating plants, one pumped-storage hydro
plant, nine combustion turbines, and six diesel generators, which have an
estimated total net generating capacity of 7,825 megawatts. As of December 31,
1994, UE owned approximately 3,300 circuit miles of electric transmission lines.
UE's extensive transmission system allows UE to transact directly with 18 other
utilities.
UE, through its gas division, owns gas distribution and peak shaving
facilities to serve approximately 118,200 customers in 77 Missouri and 4
Illinois communities.
2. CIPS
----
CIPS' generating capacity is approximately 2,834 MW. The source of
this capacity is the ownership of 11 coal-fired units (2,663 MW), and 1 oil-
fired steam unit and 1 oil-fired
-51-
<PAGE>
diesel generator (171 MW). As of December 31, 1994, CIPS owned approximately
4787 circuit miles of electric transmission lines. CIPS' extensive transmission
system allows CIPS to transact directly with 18 other utilities. A further
description of the generation, transmission and distribution facilities of CIPS
is found in the testimony of Mr. Moorman.
CIPS owns gas distribution and storage facilities and a propane-air
peak shaving facility to serve approximately 166,000 customers in 267 Illinois
communities.
G. (S) 33.2(G) - STATEMENT OF THE COST OF THE JURISDICTIONAL FACILITIES
INVOLVED IN THE TRANSACTION
As described above, the Transaction will involve all of the
jurisdictional facilities of UE and CIPS. The jurisdictional facilities of the
Applicants are, and after the merger will continue to be, accounted for pursuant
to the Commission's Uniform System of Accounts. Original cost is the basis for
the valuation of UE's and CIPS' utility plant in service. Statements of the
jurisdictional transmission plant in service and the cost thereof are included
as Exhibit No. ___ (MAB-4) to Ms. Borkowski's testimony, and Exhibit No. ___
(GWM-6) to Mr. Moorman's testimony.
H. (S) 33.2(H) - STATEMENT AS TO THE EFFECT OF THE TRANSACTION UPON ANY
CONTRACT FOR THE PURCHASE, SALE OR INTERCHANGE OF ELECTRIC ENERGY
As discussed in Sections II and III(c), UE and CIPS are submitting
open-access transmission tariffs which will expand the
-52-
<PAGE>
rights of third parties to transmission access on their combined transmission
systems. UE and CIPS will continue to be bound by their respective contractual
commitments and the Transaction, therefore, with one exception, will have no
effect on the Applicants' existing contracts. The exception relates to the Ill-
Mo Pool Agreement among UE, CIPS and Illinois Power Company, which will have to
be amended to reflect changes in delivery points resulting from the transfer of
the Transferred Assets. For those existing agreements with wholesale
requirements customers that permit UE or CIPS to file for a rate increase under
Section 205 of the FPA, UE and CIPS, respectively, will provide the open season
opportunities as explained in the testimony of Mr. Rainwater if a rate increase
is sought.
I. (S) 33.2(I) - STATEMENT AS TO OTHER REQUIRED REGULATORY APPROVALS
The following are the regulatory approvals that may or will be
necessary.
1. FEDERAL ENERGY REGULATORY COMMISSION
------------------------------------
Applicants are seeking the approvals which are the subject of this
proceeding, as well as approval of the Section 205 transmission rate filing.
2. SECURITIES AND EXCHANGE COMMISSION
----------------------------------
The Applicants are required to make filings with the SEC for (a)
registration of the exchange of Ameren common stock for the common stock of
CIPSCO and Union Electric pursuant to an
-53-
<PAGE>
S-4 Registration Statement, under the Securities Act of 1933, and (b) approval
of acquisition of securities and utility assets and other interests and other
matters under Sections 6, 7, 9, 10, and 11 of PUHCA, approval of arrangements
for provision of services among affiliates, and registration of Ameren as a
holding company under Section 5 of PUHCA.
The S-4 Registration Statement has been declared effective by the SEC
and a copy thereof is submitted with this Application as a part of Exhibit G.
The filing under PUHCA will be made after shareholder approval is obtained.
Shareholder meetings for both UE and CIPSCO are scheduled for December 20, 1995.
3. MISSOURI PUBLIC SERVICE COMMISSION
UE has filed an Application for Approval of the Merger pursuant to
Missouri law requesting the Missouri Public Service Commission to grant
approval, inter alia, of the merger of UE into Arch and to grant approval for
the transfer of the Transferred Assets to CIPS and for other related
transactions necessary to effect the merger and reorganization. A copy of the
Petition portion of such filing is submitted with this Application as part of
Exhibit G. Applicants have not included the exhibits and testimony supporting
the Missouri Petition as they are largely duplicative of the exhibits and
testimony submitted herewith. If the Commission determines that it needs to
review the exhibits and testimony filed with the Missouri
-54-
<PAGE>
Petition, the Applicants will promptly provide copies of those materials to the
Commission.
4. ILLINOIS COMMERCE COMMISSION
UE and CIPS have filed a Joint Application for Approval of Merger and
Reorganization pursuant to the Public Utilities Act of Illinois requesting the
ICC to grant approval, inter alia, of their merger and reorganization, including
the merger of CIPSCO into Ameren, the merger of UE into Arch and the transfer of
the Transferred Assets to CIPS. Applicants also are seeking approval of various
transactions among affiliated interests necessary to effect the merger and
reorganization, the capital structure of CIPS, discontinuance of service by UE
and transfer to CIPS of various Illinois certificates of convenience and
necessity of UE. A copy of the Petition portion of such filing is submitted
with this Application as part of Exhibit G. Applicants have not included the
exhibits and testimony supporting the Illinois Petition as they are largely
duplicative of the exhibits and testimony submitted herewith. If the Commission
determines that it needs to review the exhibits and testimony filed with the
Illinois Petition, the Applicants will promptly provide copies of those
materials to the Commission.
5. NUCLEAR REGULATORY COMMISSION
UE will file an application with the Nuclear Regulatory Commission
(NRC) requesting authorization for transfer, directly or indirectly, through
transfer of control, of the operating
-55-
<PAGE>
license, and all rights thereunder, for the Callaway Nuclear Power Plant. A
copy of this filing with the NRC will be submitted to the Commission immediately
after such filing is made.
6. HART-SCOTT-RODINO
The Applicants will file a Notification and Report Form for Certain
Mergers and Acquisitions with the Federal Trade Commission and the Antitrust
Division of the United States Department of Justice under the Hart-Scott-Rodino
Antitrust Improvements Act of 1976, as amended. A copy of such filing will be
submitted to the Commission immediately after such filing is made.
7. OTHER
Applicants may file other applications for, or request, certain other
consents or authorizations by federal, state or municipal agencies in connection
with the issuance of securities, system operations and franchises.
J. (S) 33.2(J) - FACTS RELIED UPON BY THE APPLICANTS TO SHOW THAT THE
TRANSACTION WILL BE CONSISTENT WITH THE PUBLIC INTEREST
See Section III of this Application, the required exhibits and the
evidence in support filed herewith, which Applicants submit contain information
sufficient for the Commission to approve the proposed merger as being consistent
with the public interest.
-56-
<PAGE>
K. (S) 33.2(K) - DESCRIPTION OF FRANCHISES
A list of the municipal franchises of UE is set forth in Appendix 4.
The municipal franchises of CIPS are listed in Appendix 5.
L. (S) 33.2(L) - FORM OF NOTICE
A form of notice suitable for publication in the Federal Register is
attached hereto as Appendix 6.
XI. EXHIBITS REQUIRED BY 18 C.F.R. (S) 33.3
Exhibits A through I which are required to be filed with this Joint
Application pursuant to 18 C.F.R. (S) 33.3 are included herewith.
XII. CONCLUSION
For the above-stated reasons, the Applicants respectfully request
approval of the Transaction and specifically request that the Commission, on an
expedited basis and without hearing, (1) find that the Transaction is consistent
with the public interest pursuant to Section 203 of the FPA; and (2) grant the
Applicants authorization to do all things necessary and proper within the
Commission's jurisdiction to effectuate the Transaction and dispose of the
jurisdictional facilities as requested in this Joint Application.
In addition, the Applicants respectfully request that the System
Support Agreement and Joint Dispatch Agreement be found just and reasonable
pursuant to Section 205 and be
-57-
<PAGE>
permitted to become effective upon consummation of the Transaction, and,
further, that the proposed regulatory accounting treatment for regulatory
purposes of the shared savings plan and cost recovery mechanism also be
approved. Finally, Applicants request that the Commission grant the relief
requested as to the disposition and funding of UE's nuclear decommissioning
fund.
Respectfully submitted,
/s/ R.S. Waters for William E. Jaudes /s/ R.S. Waters for David J. Rosso
- ------------------------------------- ----------------------------------
William E. Jaudes David J. Rosso
Vice President and General Christopher W. Flynn
Counsel Thomas D. Brooks
James J. Cook Jones, Day, Reavis & Pogue
Associate General Counsel 77 West Wacker Drive
Joseph H. Raybuck, Attorney Chicago, Illinois 60601
Union Electric Company
1901 Chouteau Avenue Robert Waters
St. Louis, Missouri 63166 Martin V. Kirkwood
Jones, Day, Reavis & Pogue
1450 G Street, N.W.
Washington, D.C. 20005
Attorneys for Union Electric Attorneys for Central Illinois Public
Service Company
December 22, 1995
-58-
<PAGE>
Exhibit D-1.2
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Union Electric Company and )
Central Illinois Public ) Docket Nos. EC96-7-000
Service Company )
PREPARED DIRECT TESTIMONY
OF
RODNEY FRAME
Washington, DC
December 22, 1995
<PAGE>
TABLE OF CONTENTS
I. INTRODUCTION.............................................................1
II. PURPOSE OF TESTIMONY AND SUMMARY OF CONCLUSIONS..........................5
III. APPROACH TO ANALYZING COMPETITIVE EFFECTS ASSOCIATED WITH
ELECTRIC UTILITY MERGERS................................................11
IV. TRANSMISSION............................................................19
A. OPEN ACCESS TRANSMISSION TARIFFS..................................19
B. INTERCONNECTIONS..................................................24
C. TRANSMISSION OVERLAPS.............................................41
V. BULK POWER..............................................................45
A. SHORT TERM CAPACITY...............................................49
B. LONG TERM CAPACITY................................................70
C. NONFIRM ENERGY....................................................76
D. OTHER CONSIDERATIONS..............................................90
VI. RETAIL COMPETITION ISSUES...............................................92
VII. VERTICAL ISSUES.........................................................97
<PAGE>
Exhibit No. ____(RWF-1)
Page 1 of 100
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Union Electric Company )
Docket No. EC96-___-000
Central Illinois Public Service Company )
Prepared Direct Testimony
of
RODNEY FRAME
I. INTRODUCTION
Q. PLEASE STATE YOUR NAME AND POSITION.
A. My name is Rodney Frame. I am a Vice President of National Economic
Research Associates, Inc. (NERA).
Q. WHAT IS YOUR BUSINESS ADDRESS?
A. My business address is 1800 M Street, N.W., Washington, D.C. 20036.
Q. WHAT IS NERA?
<PAGE>
Exhibit No. ___(RWF-1)
Page 2 of 100
A. NERA is a consulting firm founded in 1961 to provide business, government
and the legal profession with research and analysis in microeconomics--a
field that encompasses price and cost determination, the behavior of firms
and consumers, and the impact of competition and regulation upon the
efficiency of firms, markets and the economy as a whole. We have nine
offices in the U.S. and a staff of approximately 230. We have offices
overseas in London and Madrid.
Q. WHAT IS YOUR FORMAL EDUCATIONAL BACKGROUND?
A. I received a Bachelors degree in Business Administration from George
Washington University in 1970. Also at George Washington I completed all
requirements for my Ph.D. in Economics with the exception of my thesis. My
graduate studies at George Washington were funded under the National
Science Foundation Graduate Traineeship program.
Q. PLEASE DESCRIBE YOUR PROFESSIONAL EXPERIENCE.
A. I have been employed at NERA since 1984, originally as a Senior Consultant
and since 1990 as a Vice President. Most of my work has involved
consulting with electric utility clients on various competition related
matters, including retail competition, bulk power markets and competition,
transmission access and pricing, partial requirements ratemaking,
contractual terms for wholesale service, mergers and contracting for
generation supplies from nonutility generators.
<PAGE>
Exhibit No.___(RWF-1)
Page 3 of 100
From 1976 to 1984 I was a Senior Economist at Transcomm, Inc. (Transcomm),
in Falls Church, Virginia. There I directed a number of projects
concerning market structure and ratemaking in the telecommunications
industry, competition among electric utilities and postal ratemaking.
Prior to my affiliation with Transcomm, I worked as an independent economic
consultant advising clients mostly on telecommunications issues.
I have testified in federal and local courts and before state and federal
regulatory commissions. I submitted testimony to the Commerce Commission
of New Zealand on the competitive implications of alternative transmission
pricing proposals. I provided an affidavit and supporting competitive
analyses in Federal Energy Regulatory Commission (FERC or Commission)
Docket No. EC92-5-000 concerning the merger of Iowa Power, Inc. and Iowa
Public Service Company. I submitted prepared direct and rebuttal testimony
in FERC Docket Nos. ER93-465-000 and ER93-922-000 concerning competitive
issues raised by Florida Power & Light Company's (FP&L) proposed
interchange contract modifications, wholesale electric service tariff
revisions and "open access" transmission tariffs. In the same proceeding I
also submitted separate pieces of testimony relating to "comparability" of
transmission services, the appropriateness of crediting transmission rates
to account for customer-owned transmission facilities, and the implications
of FERC's Notice of Proposed Rulemaking (NOPR) on FP&L's proposed
transmission tariffs. In FERC Docket No. ER93-498-000, I submitted
prepared answering and prepared rebuttal testimony concerning allegations
that a contractual agreement entered into by Central Louisiana Electric
Company constituted predatory pricing. In FERC Docket No. EC95-4-
<PAGE>
Exhibit No.___(RWF-1)
Page 4 of 100
000, I submitted prepared direct testimony concerning competitive issues
raised by the proposed merger of Midwest Power Systems, Inc. (MPSI) and
Iowa-Illinois Gas and Electric Company (IIGE). In Docket Nos. EC94-7-000
and ER94-898-000, I submitted prepared rebuttal testimony concerning issues
of comparability associated with open access transmission tariffs submitted
by El Paso Electric Company and Central and South West Services, Inc. In
Docket No. ER93-540-000, I submitted prepared rebuttal testimony concerning
pricing and comparability issues associated with American Electric Power
Company's (AEP) proposed open access transmission tariff. In Docket No.
ER95-1686-000, I submitted prepared direct testimony addressing market
power issues associated with an application by Northeast Utilities Service
Company for market-based pricing authority. On numerous occasions I have
spoken before electric industry groups on transmission access and pricing
and other competition related matters.
A copy of my resume is attached as Exhibit ___(RWF-2).
Q. BY WHOM HAVE YOU BEEN RETAINED IN THIS PROCEEDING?
A. I have been retained by Union Electric Company (UE) and Central Illinois
Public Service Company (CIPS)/1/, collectively "Applicants."
- ---------------------------------
/1/ Abbreviations are used throughout this testimony and accompanying exhibits
and workpapers to identify utilities, regional reliability councils and
other entities. A list of all such abbreviations is contained in
Exhibit___(RWF-3).
<PAGE>
Exhibit No.___(RWF-1)
Page 5 of 100
II. PURPOSE OF TESTIMONY AND SUMMARY OF CONCLUSIONS
Q. WHAT IS THE PURPOSE OF YOUR PREPARED DIRECT TESTIMONY?
A. UE and CIPSCO, Incorporated (CIPSCO), the holding company for CIPS, have
proposed to merge. After the merger UE and CIPS each will be a wholly
owned subsidiary of Ameren Corporation (Ameren), a new, registered public
utility holding company. Details concerning this transaction are provided
in the testimony of Mr. Gary L. Rainwater. For convenience, throughout my
testimony I will refer to this transaction as the merger of UE and CIPS,
even though I recognize that UE and CIPS will continue to operate as
separate, albeit commonly controlled corporate entities after the
combination takes place. My testimony considers whether the merger of UE
and CIPS is likely to create or increase market power and significantly
affect competition. I separately address the effects of the proposed
merger on the supply of transmission services, various wholesale or bulk
power markets and various retail markets. I also consider whether there
are important vertical concerns raised by the merger.
Q. PLEASE SUMMARIZE YOUR CONCLUSIONS.
A. I conclude that the merger of UE and CIPS will not create or increase
market power in any relevant market, nor facilitate its exercise through
collusion. Concurrently with their merger application, Applicants are
filing consolidated (one-system) open access transmission tariffs which
conform with FERC's requirements as tentatively set forth in its
transmission NOPR. Because these tariffs make available all of the direct
interconnections
<PAGE>
Exhibit No.___(RWF-1)
Page 6 of 100
of both UE and CIPS as receipt and delivery points, they have the potential
to expand wholesale bulk power trading opportunities in the region. While I
believe that the wholesale bulk power markets within which UE and CIPS
operate already are competitive and that this will not be changed as a
result of the merger, the filing by the two firms of these single-system
tariffs should eliminate any residual concern that market power problems
might arise as a result of the merger. The evidence which I have reviewed
does not suggest that any additional measures are required to mitigate
perceived concerns about market power resulting from the merger or from the
combination of the transmission systems owned by Applicants.
In addition to the competition-enhancing inference logically associated
with Applicants' filing of their open access tariffs, existing structural
conditions in and around areas served by Applicants also mitigate concern
that the merger will create or enhance market power. There are several
utilities that are interconnected with UE or CIPS that already have filed
open access transmission tariffs. Some of these also are the result of
mergers and therefore allow transport across what formerly were two
independent systems without the pancaking of transmission charges. For the
most part the transmission systems of UE and CIPS do not overlap, and so
the merger does not eliminate one independent and potentially competing
transmission alternative. Where there are entities that are interconnected
with both UE and CIPS, the merger-induced reduction of one directly
connected trading partner does not present competitive concerns because
several other directly connected trading partners remain in each case.
<PAGE>
Exhibit No.___(RWF-1)
Page 7 of 100
I also conclude that the merger will not create or increase market power in
specific relevant wholesale bulk power markets that I examine, i.e., short
term capacity, long term capacity and nonfirm energy. Both UE and CIPS
actively seek to market short term capacity, and so the merger necessarily
will reduce by one the number of independent sellers. However, many other
independent participants still will remain. Moreover, UE has little or no
uncommitted capacity, and so its ability to participate as a seller in
short term capacity markets essentially is limited to situations where it
resells the capacity which it simultaneously buys from others, that is,
where it acts as a marketer. Because entry is relatively easy for those
seeking only to remarket capacity purchased from others, the elimination of
one such marketer does not present competitive concerns. As concerns short
term capacity, I also examine the concentration of uncommitted capacity in
various first tier markets and find that the merged firm's share of
uncommitted capacity in all first tier markets is less than the 20 percent
level which FERC in the past has used as a threshold to demarcate
situations where market power problems potentially might be present. As
concerns the possible exercise of buyer market power in short term capacity
markets, a stand-alone CIPS contemplates no new resource additions through
at least 2016. This makes it very unlikely that a stand-alone CIPS would
be seeking to purchase capacity during this time period other than for
remarketing purposes. If a stand-alone CIPS is not likely to be a
purchaser of short term capacity, the merger cannot reasonably be said to
increase buyer market power in short term capacity markets.
<PAGE>
Exhibit No.___(RWF-1)
Page 8 of 100
With respect to long term generating capacity, I believe that it is
unlikely as a general matter that any one firm will possess market power.
This is evidenced by the plethora of nonutility generation that has come on
line in recent years. Moreover, Applicants' filing of consolidated or one-
system open access transmission tariffs should make entry by new nonutility
generators easier than it would have been without the merger. The evidence
in this case also indicates that Applicants do not possess the ability to
deny to their would-be competitors access to other key inputs (i.e., fuel
supplies, fuel transport facilities, generating sites) needed for such
competition. The possibility that Applicants might exercise buyer or
monopsony power in long term capacity markets is undercut by their
relatively small share of total demand in the region where they operate,
the ability of those who would construct new generation to move their
projects elsewhere if Applicants refuse to offer acceptable purchase terms,
and the ability of those who would construct new generation to use
Applicants' open access transmission tariffs to market that new generation
capacity to others.
My conclusions concerning nonfirm energy markets are similar. Nonfirm
energy markets encompass a variety of closely substitutable interchange
transactions that generating utilities engage in principally to improve the
economics of dispatch. A buyer whose own capacity resources are sufficient
to accommodate its needs nevertheless may choose to purchase nonfirm energy
from another supplier if doing so allows it to lower its total generation
cost. But its desire to do so will be limited by the prices which
interchange suppliers seek and so, in that sense, the buyer's own
generation is a substitute product.
<PAGE>
Exhibit No.___(RWF-1)
Page 9 of 100
Typically, vertically integrated suppliers in this country participate in
nonfirm energy markets as both suppliers and purchasers, depending upon
their demands and resources and market conditions at a point in time. Both
UE and CIPS engage in nonfirm energy transactions with their neighbors,
frequently using energy which they purchase from one party to support
simultaneous sales to other parties. I perform two types of analyses
concerning the possibility that the merger might create or enhance seller
market power in nonfirm energy markets. First, as FERC has done on other
occasions, I compute the merged firm's share of total generating capacity
in first tier markets. I find that when the data are properly interpreted,
the merged firm's share of total generating capacity in each first tier
market falls below FERC's 20 percent threshold. I also examine historical
data on actual nonfirm energy sales within a relatively narrow region
encompassing just UE and CIPS and their direct interconnections. There are
several reasons that such an analysis will tend to overstate concentration,
and therefore possible inferences about market power, but I still find that
the data do not suggest concerns about seller market power under Department
of Justice guidelines. Moreover, the facts (i) that UE and CIPS when
combined comprise a relatively small percentage of total demand in the
region in which they operate, and (ii) that so many interconnected
utilities already have filed open access transmission tariffs, both suggest
that any concerns relating to merger-induced buyer market power in regional
nonfirm energy markets are unfounded.
I also conclude that the merger will not significantly affect electric
versus electric retail competition. This conclusion holds for each of the
types of retail electric competition that
<PAGE>
Exhibit No.___(RWF-1)
Page 10 of 100
sometimes are discussed--franchise competition, yardstick competition,
locational or customer competition, and fringe area competition.
I also conclude that the merger will not significantly affect gas versus
electric competition at the retail level. Both UE and CIPS sell gas and
electricity to retail customers, but there are only about 900 customers
that today can purchase electricity from CIPS and gas from UE and no
customers that can purchase gas from CIPS and electricity from UE. Thus,
there is little potential for direct gas versus electric competition
between the two firms premerger, and therefore little such competition
which the merger could reduce. Of course, traditional regulatory
protections remain for the few situations where gas versus electric
competition might be reduced.
Finally, I conclude that a merger of UE and CIPS does not present important
concerns about vertical issues. The principal vertical issue that exists
in this industry today is whether, when generation and transmission are
commonly owned, the integrated firm is able to use its transmission
ownership in a fashion such that sales of its own generation are favored
over those of its competitors. The functional unbundling requirement that
is contained in FERC's transmission NOPR addresses this topic, but some
would argue that it does not address perceived vertical concerns
sufficiently. However, whether or not that is true is more of a generic
issue and not one which presents itself in the context of assessing the
effects of a merger between UE and CIPS. The evidence which I have
reviewed does not suggest that a merger between UE and CIPS will create or
exacerbate market power
<PAGE>
Exhibit No.___(RWF-1)
Page 11 of 100
such that additional remedies beyond those contained in the transmission
NOPR can be justified in the context of this merger.
Q. HOW IS YOUR TESTIMONY ORGANIZED?
A. My testimony is organized as follows: Section III describes the general
approach which is appropriate for analyzing the competitive effects of
mergers; Section IV discusses transmission issues, including the
Applicants' proposed open access transmission tariffs and the effects of
the merger on transmission availability; Section V discusses the effects of
the merger on individual wholesale bulk power markets (short term capacity,
long term capacity, and nonfirm energy); Section VI addresses retail
electric and gas versus electric competition issues; and Section VII
addresses potential vertical concerns.
III. APPROACH TO ANALYZING COMPETITIVE EFFECTS ASSOCIATED WITH ELECTRIC UTILITY
MERGERS
Q. WHAT IS THE PURPOSE OF A COMPETITIVE ANALYSIS OF A MERGER BETWEEN UE AND
CIPS?
A. As would be true for a competitive analysis of any other proposed merger,
the purpose is to determine whether a merger of UE and CIPS will create or
increase market power in any relevant market, or facilitate its exercise.
The usual focus in such a competitive investigation is on possible merger-
induced increases in seller market power, but in some cases there may also
be concern about possible increases in buyer market power.
Q. HOW COULD A MERGER ALLOW THE EXERCISE OF SELLER OR BUYER MARKET POWER?
<PAGE>
Exhibit No.___(RWF-1)
Page 12 of 100
A. Seller market power exists when sellers can raise prices above competitive
levels and increase profits by doing so. If buyers have relatively few
good supply alternatives, the sellers may be able to maintain prices above
competitive levels in the marketplace. If the buyers do have good supply
alternatives, they would simply switch, and the price increases would not
hold. At least as concerns its potential effects on wholesale bulk power
markets, the combination of UE and CIPS can be viewed principally as a
horizontal merger, which is one where, premerger, the parties compete or
potentially could compete in the same market. In theory, a horizontal
merger could create or increase market power because it would reduce by one
the number of alternative suppliers to whom customers could turn if the
merged firm sought to increase price. A horizontal merger also could
facilitate the exercise of seller market power if the number of surviving
firms was small enough that it would facilitate collusion on pricing and
output decisions.
Buyer market power exists when those who purchase inputs are able to
restrict the amount of such purchases and therefore depress the price paid
below competitive levels. If sellers have relatively few good alternatives
for marketing their output, the buyers can hold prices below competitive
levels in the marketplace. If the sellers do have good alternatives, they
would simply sell to them instead, and the price decrease would not hold.
A horizontal merger in theory could create or increase buyer market power
because it would reduce by one the number of alternative buyers to whom
sellers could turn. Likewise, a horizontal merger could facilitate the
exercise of buyer market power if the number of surviving firms was small
enough such that it would facilitate collusion on purchasing policies.
<PAGE>
Exhibit No.___(RWF-1)
Page 13 of 100
Q. WHAT ARE RELEVANT MARKETS?
A. A relevant market is a market which bears directly upon activities
considered in an antitrust analysis. In this case, the areas of interest
which are affected by the merger are the areas of actual and potential
competitive overlap between the business activities of UE and the business
activities of CIPS. This overlap should be defined with both product and
geographic dimensions.
Q. HOW ARE RELEVANT MARKETS DEFINED FOR A MERGER ANALYSIS?
A. The analysis begins with a definition of the actual or potential overlap
between the business activities of the merging parties. By way of example,
both UE and CIPS make nonfirm energy sales (or sales of closely
substitutable products) to other utilities in the regions surrounding the
areas where they serve. Therefore, nonfirm energy sales represent one area
of overlap to consider in a competitive analysis of the merger's effects.
By contrast, UE sells electricity to individual retail customers located in
its service territory (e.g., metropolitan St. Louis), whereas CIPS sells
electricity to individual retail customers located in its service territory
(e.g., Carbondale and Quincy, Illinois). Because these two service
territories are mutually exclusive, the sales of electricity to individual
retail customers located in these areas do not represent an area of overlap
to consider in a merger analysis because there is no existing competition
between the two firms for making sales to these individual customers. This
situation will not change unless existing institutional arrangements in the
industry are dramatically altered.
<PAGE>
Exhibit No.___(RWF-1)
Page 14 of 100
Once the realistic overlap areas between the business activities of the
merging firms are determined, each is expanded, as appropriate, to reflect
both demand and supply-side substitutability. Demand-side substitutability
means that the analysis must encompass not only products and services sold
by the merging parties but also products or services that are reasonably
interchangeable. Competition from these substitute products or services
places constraints on the prices which can be charged for products in the
overlap area. Supply-side substitutability refers to the ability of firms
not currently in the market to alter their productive processes to produce
the product or service in question. Firms that can alter their productive
processes easily ought to be considered as participants in the relevant
market because the potential for competition from them acts as a constraint
on price. The goal is to define the relevant market to include
sufficiently close substitutes to the products or services in the overlap
area but to exclude those that are remote. Moreover, just as the overlap
area needs to be expanded to incorporate products and services that are
reasonably interchangeable with those sold by the merging firms, it also
must be expanded geographically to incorporate supplies that might be made
available from beyond the areas where the merging parties sell their
products and services. Supplies from outside the area where the merging
parties historically have sold their products and services, if they can be
transported into that area at reasonable cost, also will act as a
constraint on the prices that the merging firms can charge and,
accordingly, ought to be considered as part of the relevant market.
<PAGE>
Exhibit No.___(RWF-1)
Page 15 of 100
Q. IS DEFINING RELEVANT MARKETS A TASK WHICH CAN BE PERFORMED WITH PRECISION?
A. Generally not. Decisions about where boundaries ought to be drawn, and
which suppliers and products ought to be included and which ought to be
excluded, frequently must be based upon imperfect or less than complete
information. Because there generally are not clear breaks in the "chain of
substitution," the exercise of judgment by the analyst is important.
Q. HOW DOES THE APPROACH WHICH YOU HAVE OUTLINED FOR DEFINING RELEVANT MARKETS
CORRESPOND TO THAT CONTAINED IN THE DEPARTMENT OF JUSTICE AND FEDERAL TRADE
COMMISSION HORIZONTAL MERGER GUIDELINES DATED APRIL 2, 1992 (MERGER
GUIDELINES)?
A. The framework outlined above is substantially the same as that contained in
the Merger Guidelines. The Merger Guidelines defines a relevant market as
the smallest grouping of substitute products and geographic areas for which
a hypothetical profit maximizing firm "that was the only present and future
producer or seller of those products in that area" could impose a "small
but significant and nontransitory" price increase. The analysis begins by
using individual products sold by the merging firms as preliminary relevant
market definitions. Then, if in response to a small but significant and
nontransitory price increase for such product by the hypothetical
monopolist, reductions in sales reduce profitability, additional products
must be added to this preliminary version of the market until a small but
significant and nontransitory price increase does not reduce profitability.
Once defined, according to the Merger Guidelines, participants in the
relevant market will include "firms currently providing or selling the
market's products in the market's geographic area" and
<PAGE>
Exhibit No.___(RWF-1)
Page 16 of 100
"may include other firms depending on their likely supply responses to a
'small but significant and nontransitory price increase.'" These
adjustments essentially are the same as described above, i.e., expanding
the boundaries of the overlap area, as appropriate, to reflect both demand
and supply-side substitutability.
The Merger Guidelines, however, also provides precise criteria to determine
breaks in the chain of substitutability. Thus, the Merger Guidelines
specifies a "price increase of five percent lasting for the foreseeable
future" for "the small but significant and nontransitory increase in price"
(although suggesting that different figures might be appropriate for
different industries) and indicates that firms not currently producing the
relevant product in the relevant market will be considered as participants
if probable supply responses by them could occur within one year.
Q. HOW ARE RELEVANT MARKETS USED TO DETERMINE WHETHER A PROPOSED MERGER IS
LIKELY TO CREATE OR INCREASE MARKET POWER, OR FACILITATE ITS EXERCISE
THROUGH COLLUSION?
A. Relevant markets provide a useful analytical construct to focus the
required competitive investigation on areas that potentially may present
problems as opposed to those which obviously will not. Once relevant
markets are defined, the usual approach, if data are available, is to use
market share and other concentration measures for those markets to
distinguish between mergers which require further investigation and those
which do not. Relatively high values for these indicators signal that
market power concerns may be present and therefore represent a call for
more detailed analyses. Conversely, relatively
<PAGE>
Exhibit No.___(RWF-1)
Page 17 of 100
low values for these measures suggest that market power concerns almost
certainly are absent, even though one competitor will have been removed
from the market, and therefore that no further and more detailed analyses
need be undertaken. Thus, these summary statistical indicators are a
screening device.
However, there is no single measure of concentration, nor level of any such
measure, that unambiguously differentiates between situations where market
power is and is not likely to be of concern. The Merger Guidelines
principally uses the Herfindahl-Hirschmann Index (HHI) as a screening
device. An HHI is calculated by summing the squared market shares of all
firms in the market. The maximum possible HHI (i.e., 100/2/ x 1 = 10,000)
is present in a market that has only a single supplier. A market with ten
equally sized firms has an HHI of 1,000 (i.e., 10/2/ x 10 = 1,000). The
Merger Guidelines considers markets with postmerger HHIs below 1,000 to be
"unconcentrated." Under the Merger Guidelines, mergers in unconcentrated
markets "ordinarily require no further analyses." The Merger Guidelines
considers markets with postmerger HHIs between 1,000 and 1,800 to be
"moderately concentrated." If a merger in such a market causes the HHI to
increase by more than 100, the merger, again according to the Merger
Guidelines, "potentially raise[s] significant competitive concerns"
depending on other factors such as ability to collude and barriers to
entry. The Merger Guidelines considers markets with postmerger HHIs
greater than 1,800 to be "highly concentrated." If a merger in such a
market causes the HHI to increase by more than 50, the merger "potentially
raise[s] significant competitive
<PAGE>
Exhibit No.___(RWF-1)
Page 18 of 100
concerns," according to the Merger Guidelines, depending again on other
factors. I develop HHI data below for my analysis of nonfirm energy
markets.
Q. ARE THERE OTHER SUMMARY SCREENING MEASURES USED FOR MERGER ANALYSES?
A. Yes. The Merger Guidelines also includes market share as a screening
device in merger analyses. Under some circumstances a postmerger market
share of 35 percent for the merging parties "may be relied upon to
demonstrate that there is a significant share of sales in the market
accounted for by customers who would be adversely affected by the merger."
Also, on other occasions (e.g., Public Service Company of Indiana, 51 FERC
(P) 61,367; Entergy Services, Inc., 58 FERC (P) 61,234, hereafter Entergy;
and Louisville Gas and Electric, 62 FERC (P) 61,016), FERC has used a 20
percent market share figure to distinguish between firms which may or may
not have market power in energy and capacity markets. My discussion below
develops market shares for energy and short term capacity markets.
Again, however, market share and other concentration data are useful as
screening devices to distinguish between mergers which may present
competitive concerns and those which do not. As the Merger Guidelines
states, these measures "provide only the starting point for analyzing the
competitive impact of a merger." Other factors, including ease of entry,
also must be considered. Indeed, where entry is easy, i.e., "timely,
likely and sufficient in its magnitude, character and scope to deter or
counteract the competitive effects of concern
<PAGE>
Exhibit No.___(RWF-1)
Page 19 of 100
. . . [a] . . .merger raises no antitrust concern and ordinarily requires
no further analysis" (Merger Guidelines at page 47).
Q. WHAT RELEVANT BULK POWER MARKETS HAVE YOU EXAMINED IN THIS CASE?
A. As indicated earlier, I have examined the same wholesale bulk power markets
that have been examined in other merger or market power investigations at
FERC: short term capacity, long term capacity and nonfirm energy. I also
have considered whether the merger will affect electric versus electric and
gas versus electric competition at the retail level.
IV. TRANSMISSION
Q. WHAT SET OF TOPICS ARE ADDRESSED IN THIS SECTION OF YOUR TESTIMONY?
A. I discuss three topics in this subsection of my testimony. First, I
briefly describe the open access tariffs that UE and CIPS are filing in
conjunction with their merger application. Second, I identify the
interconnections of UE and CIPS and consider whether the merger-induced
reduction in the number of directly interconnected trading partners that
some utilities will see presents significant competitive concerns. Third,
I consider whether a merger of UE and CIPS presents market power concerns
as a result of a reduction in competing transmission paths.
A. OPEN ACCESS TRANSMISSION TARIFFS
--------------------------------
<PAGE>
Exhibit No.___(RWF-1)
Page 20 of 100
Q. PLEASE BRIEFLY DESCRIBE THE OPEN ACCESS TRANSMISSION TARIFFS WHICH UE AND
CIPS ARE FILING.
A. Concurrently with their merger application, UE and CIPS are filing open
access transmission tariffs designed to comply with FERC's requirements as
tentatively set forth in its transmission NOPR issued in Docket No. RM95-8-
000. These tariffs--the "Ameren Tariffs"--are described more fully in the
testimony of Ms. Maureen A. Borkowski but, in essence, largely replicate
the pro forma tariffs attached to the NOPR.
Q. WILL THE FILING OF THE AMEREN TARIFFS EXPAND THE OPPORTUNITIES OF OTHERS
FOR PARTICIPATING IN REGIONAL BULK POWER MARKETS BEYOND WHAT WOULD COME
ABOUT JUST FROM THE IMPLEMENTATION OF FERC'S TRANSMISSION NOPR?
A. Yes. A significant consideration is that a one-system tariff has been
filed which combines the transmission assets of both CIPS and UE. Thus,
while FERC's NOPR, unless it is changed significantly, ultimately will
require that all jurisdictional transmission owners (including UE and CIPS
were they not to merge) file open access transmission tariffs along the
lines set forth in the NOPR, the filing by UE and CIPS still expands bulk
power trading opportunities for other, interconnected utilities by
combining under a single tariff the transmission systems of both UE and
CIPS. This will allow most of those interconnected utilities to transact
with more trading partners by paying only a single wheeling fee whereas,
without a merger, arranging two transmission transactions and paying two
wheeling charges would have been required. Because of the manner in which
transmission prices are determined under FERC's traditional pricing
procedures, the ceiling price under
<PAGE>
Exhibit No.___(RWF-1)
Page 21 of 100
the Ameren Tariffs necessarily always will be less than the sum of the two
stand-alone ceiling prices. As a result, transactions may go forward in the
future that, without the merger, would have been deterred by the
"pancaking" of transmission charges.
Q. CAN YOU PROVIDE SOME EXAMPLES?
A. There are several possible examples. Under the proposed tariff, AEP and
Northern Indiana Public Service Company (NIPSCO) in Indiana and Central
Illinois Light Company (CILCO) in Illinois will be able to transact with
Associated Electric Cooperative, Inc. (AEC) and Kansas City Power & Light
(KCPL) in Missouri by paying only a single wheeling fee, whereas without
the merger two separate wheeling transactions would be required. Likewise,
CINergy, Inc. (CINergy) now will be able to transact with AEC, KCPL and
MidAmerican Energy Company (MEC) by paying only a single wheeling fee,
whereas without the merger two wheeling fees would be required.
Springfield, Illinois (Springfield, IL), a generating municipal system now
interconnected with only Illinois Power Company (IP), CILCO and CIPS, will
have all of UE's direct interconnections opened to it for a single wheeling
fee. Columbia, Missouri (Columbia), a generating municipal system now
interconnected with only UE and AEC, will have all of CIPS's
interconnections opened to it for a single wheeling fee.
Q. IS THIS CONSIDERATION IMPORTANT FOR WHAT SOMETIMES ARE CHARACTERIZED AS
TRANSMISSION DEPENDENT UTILITIES OR TDUS?
<PAGE>
Exhibit No.___(RWF-1)
Page 22 of 100
A. Yes. As I discuss below, there are several full and partial requirements
customers that have connections with only UE or CIPS, but with no other
utility. Consistent with their purchase obligations under these existing
contracts, postmerger these smaller systems will be able to have power
wheeled to them from all of the other utilities directly interconnected
with either UE or CIPS, whereas without the merger their "one wheel"
options would be confined to just the direct interconnections of UE or
CIPS, whichever they are connected with, but not both.
Q. WILL THE CONSOLIDATED (ONE-SYSTEM) TRANSMISSION CHARGE BE BENEFICIAL TO ALL
PARTIES?
A. Having a consolidated transmission charge obviously is beneficial to
parties that, in the absence of the merger, would be forced to pay pancaked
wheeling charges to get across the systems of both UE and CIPS or, because
such pancaked charges would be too high, would pursue alternative purchase
or sales opportunities. However, because of the manner in which
transmission prices are developed under existing FERC procedures, it is
possible that some customers will be disadvantaged. The ceiling price
under the Ameren Tariffs necessarily will fall somewhere between the single
system ceiling price for wheeling across UE's system and the single system
ceiling price for wheeling across CIPS's system. The former is lower and
the latter is higher. Accordingly, customers that in the absence of the
merger would have desired to wheel across just the UE system may face price
increases. Without the merger, their payments would be capped at the lower
ceiling price for wheeling across UE's system, but postmerger their
payments will be capped by the higher ceiling price associated with the
consolidated system. Assessing the significance of this
<PAGE>
Exhibit No.___(RWF-1)
Page 23 of 100
effect requires that several factors be considered. One is that, as
suggested, prices in the Ameren Tariffs represent only limits on the
maximum prices which can be charged and that prices will fall below these
price caps when market conditions dictate. A second consideration is that
the ceiling price increases which will be faced by any customers who want
to wheel across just the UE system--i.e., stand-alone UE charge versus
consolidated Ameren charge--necessarily are counterbalanced by ceiling
price decreases for those customers that wish to wheel across just the CIPS
system. A third consideration is that even those customers who wish to
enter into transactions that involve wheeling across just the UE system
presumably at times will benefit from the ability to wheel across both
systems also. Finally, these increased transmission charges will not have
adverse competitive consequences to the extent that UE must charge itself
the same price for transmission service for bulk power sales it makes.
Consider, for example, one of the municipal systems that currently
purchases its full requirements supply from UE. At the expiration of its
current contract with UE, it will be eligible to use the Ameren Tariffs to
purchase its power supply requirements from other vendors. The price which
it pays under those tariffs will be the same whether it continues with UE
as its supplier or selects another.
Q. WILL THE OPEN ACCESS TARIFFS MITIGATE CONCERN THAT THE MERGED FIRM WILL BE
ABLE TO EXERCISE "TRANSMISSION MARKET POWER," OR MIGHT ADDITIONAL REMEDIES
BE REQUIRED TO DO SO?
A. I understand the expression "transmission market power" to refer to a
vertically integrated utility's use of its transmission assets to exercise
market power in generation or bulk power
<PAGE>
Exhibit No.___(RWF-1)
Page 24 of 100
markets. FERC previously has indicated that it could not "find any merger
consistent with the public interest if the merging public utilities do not
offer comparable transmission services. . ." and "that, as a general
matter, comparable transmission access should adequately mitigate any
utility's increased transmission market power. . ." (El Paso Electric
Company and Central and South West Services, Inc., 68 FERC (P)61,181)
resulting from a merger. The evidence which I have reviewed, and which is
discussed below, indicates that the merged firm will not be able to
exercise market power in wholesale bulk power markets anyway. The filing of
the Ameren Tariffs should address any residual concern in this area. Based
upon my review of the evidence, I see no reason to go beyond the comparable
open access requirement in this case to mitigate concerns about the
exercise of perceived transmission market power.
B. INTERCONNECTIONS
----------------
Q. WITH WHAT OTHER UTILITIES DOES UE HAVE INTERCONNECTIONS?
A. These interconnections are identified in the testimony of Ms. Borkowski in
this proceeding and in Exhibit ___(RWF-4). Essentially these
interconnections fall into the following two categories: (i) direct
interconnections via facilities owned solely by UE, and (ii) contractual
interconnections through facilities owned at least in part by others. The
distinction between these two categories is important because the types of
use that UE can make of its contractual interconnections is limited to
those permitted by the underlying contract vehicles. In particular, as
discussed below, certain of UE's interconnections are through "common bus"
agreements which do not contemplate wheeling for third parties.
<PAGE>
Exhibit No.___(RWF-1)
Page 25 of 100
Thus, while these interconnections may allow UE to buy electricity from its
contractual trading partners, or sell electricity to them, they do not
permit UE or the merged entity to provide transmission service which allows
third parties to conduct similar transactions.
Q. IS THIS A CONSIDERATION THAT IS RELATED TO THE MERGER?
A. No. UE cannot wheel power for others to or from these interconnections
whether or not it merges with CIPS.
Q. DOES IT PRESENT COMPETITIVE CONCERNS AS A RESULT OF THE MERGER?
A. No. As I discuss below, each potentially affected trading partner still
has numerous other entities with which it can deal, postmerger, and so the
fact that it may not be able to transact directly with UE's contractual
interconnections does not present merger-related competitive concerns.
Moreover, summary share and concentration data for short term capacity and
nonfirm energy markets, discussed below, fall below threshold levels for
concern about the potential exercise of market power
Q. PLEASE CONTINUE WITH YOUR DISCUSSION OF UE'S INTERCONNECTIONS.
A. UE has direct interconnections with six investor-owned utilities (IOUs),
one municipal utility system, one generation and transmission (G&T)
cooperative, two federal government agencies, and one other entity jointly
owned by it, CIPS and two other IOUs. The six IOUs are CIPS, IES
Utilities, Inc. (IES), IP, KCPL, MEC, and Missouri Public Service Company
(MoPub). The interconnected municipal system is Columbia, while the
<PAGE>
Exhibit No.___(RWF-1)
Page 26 of 100
interconnected G&T cooperative is AEC which, with total capacity of more
than 3,500 megawatts (including firm purchases), is one of the largest G&T
cooperatives in the country. The two interconnected federal governmental
agencies are the Tennessee Valley Authority (TVA) and the Southwestern
Power Administration (SPA). The interconnection with TVA is via a joint
agreement with CIPS and IP, the other two members of the Ill-Mo Pool in
which UE participates. The interconnected joint venture entity is Electric
Energy, Inc. (EEI). EEI, which is jointly owned by UE (40 percent), CIPS
(20 percent), IP (20 percent), and Kentucky Utilities or KU (20 percent),
owns 1,015 megawatts of coal-fired electric generation capacity in southern
Illinois (the "Joppa Plant") and a substation which connects the Joppa
Plant to EEI's owners (collectively "Sponsors") as well as transmission
lines which connect EEI to a uranium processing plant (the "Paducah
Project") in western Kentucky that today is operated by the United States
Enrichment Corporation (USEC).
UE's direct interconnection with MEC is via facilities covered by the Twin
Cities-Iowa-St. Louis 345 Kilovolt Interconnection Coordination Agreement
(East Line Agreement). Each of the participants in this agreement owns
individual segments of the entire line, referred to as the East Line, which
extends from the Twin Cities area in the north to UE's Montgomery
substation west of St. Louis. UE's participation in this line provides it
with contractual interconnections with the other owners, including IES,
with which it also has a direct interconnection, and Interstate Power
Company (IPW) and Northern States Power Company (NSP), with which it does
not have direct interconnections. Through its participation in the
Missouri-Arkansas EHV Interconnection, UE has contractual
<PAGE>
Exhibit No.___(RWF-1)
Page 27 of 100
interconnections with AEC and Arkansas Power & Light Company (APL), an
Entergy Corporation (Entergy) subsidiary. The line covered by this
agreement extends from southeast Missouri into northeast Arkansas. Through
its participation in the Mo-Kan-Ok 345 Line, UE has contractual
interconnections with AEC, Kansas Gas & Electric Company (KGE) and Public
Service Company of Oklahoma (PSO). This line extends from UE's Labadie
substation at its Labadie plant near St. Louis across Missouri to KGE's
Neosho substation in southeast Kansas and then south to PSO's Oneta
substation in northeast Oklahoma. KGE is a subsidiary of Western Resources,
Inc. (WR), and PSO is a subsidiary of Central and South West Corporation
(CSW). Also, through the agreements governing ownership of EEI, UE and the
other "northern owners" (CIPS and IP) have constructed transmission lines
to the Joppa Plant. KU, the other owner, has constructed transmission
facilities which connect directly with the Paducah Project and has
contractual rights to conduct interchange transactions from that point with
EEI and the northern owners. Accordingly, all of EEI's owners are
contractually connected with each other through facilities at the Joppa
Plant and the Paducah Project and can exchange power with each other
pursuant to the service schedules attached to the underlying Sponsors-EEI
Agreement. It is my understanding that in each of the above cases--i.e.,
the East Line Agreement, the Missouri-Arkansas EHV Interconnection, the Mo-
Kan-Ok 345 Line, and the Sponsors-EEI Agreement--the underlying contractual
agreements have not been interpreted historically to accommodate third
party wheeling. Accordingly, where these agreements provide the only
interconnection between UE and another system (i.e., IPW, NSP, APL/Entergy,
KGE/WR, PSO/CSW, and KU), that other system is not included as a
<PAGE>
Exhibit No.___(RWF-1)
Page 28 of 100
potential receipt and delivery point under the open access tariffs now
being filed. An exception concerns MEC, with which UE has no
interconnections other than through the East Line. However, UE has a
separate contractual arrangement with IES which allows UE to wheel power to
and from MEC, even though the direct interconnection between UE and MEC is
governed by the East Line Agreement which does not contemplate wheeling.
Accordingly, MEC is included as a receipt and delivery point under the
proposed open access tariff. Also, systems with which UE has both direct
and contractual interconnections (i.e., AEC, EEI, IES, IP and TVA) are
included as potential receipt and delivery points un der the tariff.
Finally, UE's interconnection agreement with AEC, which incorporates a
variety of rights and obligations which the parties have, includes a
provision giving UE a contractual interconnection with St. Joseph Light &
Power Company (SJLP), with which it otherwise has no direct trading rights.
UE believes that via this provision it can provide wheeling service to or
from SJLP and, accordingly, SJLP is included as a potential receipt and/or
delivery point under the Ameren Tariffs.
Q. IN WHAT RELIABILITY COUNCIL REGIONS ARE THE UTILITIES THAT ARE
INTERCONNECTED WITH UE LOCATED?
A. They are located in the Mid-Continent Area Power Pool (MAPP) to the north
of UE, the Southwest Power Pool (SPP) to the west and south of UE, the
Southeastern Electric Reliability Council (SERC) region to the south and
east of UE, the East Central Area
<PAGE>
Exhibit No.___(RWF-1)
Page 29 of 100
Reliability Coordination Agreement (ECAR) region to the east of UE, and the
Mid-America Interconnected Network (MAIN), which is the reliability council
region within which UE operates. IES, IPW, MEC and NSP are located in MAPP;
AEC, CSW, Entergy, KCPL, MoPub, SJPL and SPA are located in SPP; TVA is
located in SERC; KU is located in ECAR; and CIPS, Columbia, EEI and IP all
are located in MAIN.
Q. ARE THERE OTHER UTILITY SYSTEMS CONNECTED TO UE'S TRANSMISSION LINES?
A. Yes. In addition to the interconnected utilities discussed above, there
are 14 municipal utility systems and two distribution cooperative systems
connected to UE's transmission lines. These systems are all either full or
partial requirements customers of UE and operate within UE's control area.
The municipal systems serve in California, Centralia, Farmington,
Fredericktown, Hannibal, Jackson, Kahoka, Kirkwood, Linneus, Marceline,
Owensville, Perry, Rolla and St. James, Missouri. One of the distribution
cooperatives, Citizens Electric Corporation, is a full requirements
customer of UE and serves in mostly rural areas of Missouri to the south of
St. Louis. The other distribution cooperative customer, Sho-Me Power
Corporation (Sho-Me), receives only a very small portion of its
requirements from UE--less than 0.3 percent--with most of its capacity and
energy being supplied by AEC. (UE provides full requirements service at
only one of Sho-Me's delivery points, under an agreement which will
terminate at the end of 1995). Other distribution cooperatives in Missouri
also are served by AEC. With the exception of Sho-Me, none of these 16
systems is connected with any utility other than UE (and even for Sho-Me
the distribution point served by UE is not integrated with those served by
AEC). Only five of
<PAGE>
Exhibit No.___(RWF-1)
Page 30 of 100
these systems (Jackson, Kahoka, Marceline, Owensville and Sho-Me) any
generation (a total of approximately 36 megawatts) of their own. The sum of
the individual peak demands on UE's system for these 6 utilities was 335
megawatts in 994.
Q. WILL THESE OTHER SYSTEMS BE ELIGIBLE CUSTOMERS UNDER THE OPEN ACCESS
TRANSMISSION TARIFFS NOW BEING FILED BY UE AND CIPS?
A. These systems are served under contracts which expire on December 3, 998
(eight systems), December 3, 2000 (six systems), May 3, 2003 (one system)
and, as mentioned, in one case under an agreement which expires December 3,
995. So long as they meet their purchase obligations under their existing
contracts, these systems will be eligible customers under the Amere n
Tariffs when the merger is consummated. As a result, the merger
significantly expands the bulk power supply alternatives available to them
from those which would exist without the merger. Whereas premerger these
munic ipal and cooperative suppliers could access only the utilities now
directly interconnected with UE through payment of a single wheeling
charge, that single wheeling charge postmerger will allow them to access
all of CIPS's direct interconnections as well, including Commonwealth
Edison Company (CE), AEP, NIPSCO and PSI Energy, Inc. (PSI)/CINergy.
Q. WITH WHAT OTHER UTILITIES IS CIPS INTERCONNECTED?
A. These interconnections are identified in the testimony of Mr. Gilbert W.
Moorman and in Exhibit ___(RWF-4). CIPS has direct interconnections with
EEI, TVA, seven IOUs, one
<PAGE>
Exhibit No.___(RWF-1)
Page 31 of 100
municipal system, three G&T cooperatives, and two municipal joint action
agencies. The interconnections with EEI and TVA are via the same agreements
which interconnect UE (and IP as well) with these entities. The seven IOUs
are CE, CILCO, IP, Indiana Michigan Power Company (IM), NIPSCO, PSI and UE.
IM is a subsidiary of AEP, while PSI is a subsidiary of CINergy. The
municipal system is Springfield, IL, while the three G&T cooperatives are
Southern Illinois Power Cooperative (SIPCO), Soyland Power Cooperative,
Inc. (Soyland), and Wabash Valley Power Association (WVPA). The municipal
joint action agencies are the Illinois Municipal Electric Agency (IMEA) and
the Indiana Municipal Power Agency (IMPA).
In addition to these direct interconnections, CIPS has a contractual
interconnection with KU, just as does UE, by virtue of its role as one of
EEI's Sponsors. However, this represents CIPS's only interconnection with
KU and, accordingly, as stated above, KU does not represent a potential
receipt and/or delivery point under the Ameren Tariffs.
Finally, CIPS now has a limited purpose interconnection with IES, which
does not allow scheduling of interchange transactions. CIPS, however, is
constructing new facilities which will give it a full purpose
interconnection beginning in 1998.
Q. IN WHAT RELIABILITY COUNCIL REGIONS ARE THE UTILITIES THAT ARE
INTERCONNECTED WITH CIPS LOCATED?
<PAGE>
Exhibit No.___(RWF-1)
Page 32 of 100
A. They are located in MAPP to the west and north of CIPS, in ECAR to the east
of CIPS, in SERC to the south and east, and in MAIN where both CIPS and UE
operate. IES is located in MAPP; AEP, CINergy, KU, IMPA, NIPSCO and WVPA
are located in ECAR; TVA is located in SERC; and all of the others (CE,
CILCO, IMEA, SIPCO, Soyland, Springfield, IL and UE) are located in MAIN.
Q. ARE THERE OTHER UTILITIES CONNECTED TO CIPS'S TRANSMISSION SYSTEM?
A. Yes. Within its control area CIPS has connections with the municipal
systems serving in Greenup (3.3 megawatts peak) and Newton, Illinois (8.0
megawatts peak), the Norris Electric Cooperative (61.2 megawatts peak) and
Mt. Carmel Public Utility Company (Mt. Carmel), a small (40 megawatts peak)
IOU. Each of these systems purchases its full requirements from CIPS and
operates as part of CIPS's control area. None operates any of its own
generation. A portion of the load of both IMEA and Soyland also is
included in CIPS's control area.
Q. WILL THE MUNICIPAL AND COOPERATIVE SYSTEMS, AND MT. CARMEL, BE ELIGIBLE
CUSTOMERS UNDER THE AMEREN TARIFFS?
A. Yes. The existing full requirements contracts under which Newton and
Greenup are served extend until the later of July 1, 1996, and July 1,
1999, respectively, or 18 months after notice to terminate is given. The
existing contract to serve the Norris Electric Cooperative extends until
the later of July 1, 2007, or 36 months after notice to terminate is given.
The existing contract to serve Mt. Carmel extends until the later of June
30, 2001, or 12 months
<PAGE>
Exhibit No.___(RWF-1)
Page 33 of 100
after notice to terminate is given. Soyland, IMEA and WVPA all purchase
system participation power from CIPS, at formula rates, under long term
power supply agreements. These give them the right to a contractually
specified proportion of the output of each of CIPS's generating stations,
which amount is different for each of the three agreements. The agreement
with WVPA also provides for transmission service, but separate transmission
service agreements are used to provide for delivery of the system
participation power from CIPS to IMEA and Soyland. The existing power
supply agreements under which Soyland and IMEA are served expire December
31, 1999, and December 31, 2014, respectively. The existing transmission
service agreements under which each of these two entities is served expire
December 31, 2014. The existing agreement to supply bulk power and
transmission service to WVPA terminates at the end of 2011. So long as they
meet their obligations under their existing contracts, each of the above
seven entities--Newton, Greenup, Mt. Carmel, the Norris Electric
Cooperative, IMEA, Soyland and WVPA--will be an eligible customer under the
Ameren Tariffs.
Q. WHAT OTHER ENTITIES HAVE INTERCONNECTIONS WITH BOTH UE AND CIPS?
A. Including the interconnection with IES which will be completed in 1998,
there are five such entities (EEI, IES, IP, KU and TVA) as indicated by the
bold type in Exhibit No.____(RWF-4).
Q. WILL THE MERGER OF UE AND CIPS HAVE A SIGNIFICANT EFFECT UPON THESE FIVE
ENTITIES' PARTICIPATION IN REGIONAL BULK POWER MARKETS?
<PAGE>
Exhibit No.___(RWF-1)
Page 34 of 100
A. No. Although it is true that each of the utilities interconnected with
both UE and CIPS will see a reduction in their number of directly
interconnected trading partners postmerger, a circumstance which will occur
to some extent with most any electric utility merger, each of the five
still will have several other systems with which it can engage in purchase
and sale transactions directly without wheeling over an intervening system.
With the exception of EEI, Exhibit No. ___(RWF-5) identifies these
postmerger interconnections for each of the utilities now interconnected
with both merging partners. For example, premerger TVA has 12
interconnected trading partners, whereas postmerger it still will have 11.
For IES, IP and KU, the postmerger numbers of interconnections are 8, 9 and
10, respectively. Figures this large should help mitigate concern about
the merged entity's ability to exercise market power in generation markets.
I am excluding EEI from this discussion because of my view, developed
below, that it is not appropriate to view EEI as an independent participant
in regional bulk power markets.
Moreover, with the advent of open access transmission tariffs, the trading
options for these utilities obviously need not be confined to directly
interconnected utilities alone. Both IES and IP will be able to use the
Ameren Tariffs that are being filed simultaneously with this merger
application to access any other utility directly interconnected with UE
and/or CIPS to engage in wholesale bulk power transactions. Both IES and
IP also are directly interconnected with MEC, which has its own open access
transmission tariffs. Accordingly, they can access all entities
interconnected with MEC just as easily as they can reach entities
interconnected with UE or CIPS. In some cases transmission under MEC's
<PAGE>
Exhibit No.___(RWF-1)
Page 35 of 100
open access tariffs would represent only an alternative transmission path
to reach utilities also accessible under the Ameren Tariff, while in other
cases it adds utilities not otherwise included in a "one wheel" market.
IES also is a member of MAPP and, through the MAPP Agreement and
accompanying service schedules, has the ability to exchange a variety of
energy and capacity services with each of the other 27 MAPP members, even
if not directly interconnected with them. As discussed above, KU cannot be
accessed under the merged entity's open access transmission tariffs, but
both it and IP are directly interconnected with AEP and can use AEP's open
access transmission tariff to access all entities interconnected with AEP.
This is a very large list including, among others, Allegheny Power System,
Carolina Power & Light Company, Centerior Energy Corporation, CE, Consumers
Power Company, Duke Power Company, Ohio Edison Company, and Virginia
Electric & Power Company (VEPCO). KU also is interconnected with PSI and
therefore can use CINergy's open access tariff to trade with entities
accessible via that tariff. Other utilities, of course, also will file
open access transmission tariffs in the future if FERC's NOPR is
implemented in anything close to its current format, and maybe even if it
is not.
TVA will be able to use the merged firm's open access tariffs to engage in
purchase, but presumably not sales, transactions. It also can use the
existing open access tariffs of other utilities with which it is directly
interconnected, e.g., AEP, Entergy, KU and IP, for a similar purpose.
<PAGE>
Exhibit No.___(RWF-1)
Page 36 of 100
Q. WHY DO YOU PRESUME THAT TVA WILL BE UNABLE TO USE THE MERGED FIRM'S OPEN
ACCESS TARIFFS TO ENGAGE IN SALES TRANSACTIONS?
A. It is my understanding that legislation passed by Congress in 1959--the
1959 Self-Financing Amendment to The TVA Act of 1933--created a "fence"
around TVA which restricted its power marketing activities. Among other
things, the fence prevents TVA from making power sales to any entity other
than those with which it had interchange arrangements as of July 1, 1957.
These entities include both CIPS and UE as well as EEI and the other EEI
Sponsors (IP and KU). Accordingly, I presume that, unless this legislation
is changed, TVA would be unable to use the open access tariff of the merged
firm, or of anyone else, to sell electricity directly to any entity that is
not among those with which it had interchange arrangements as of July 1,
1957.
Q. DO YOU HAVE ANY SPECIFIC EVIDENCE INDICATING THAT ELECTRICITY TRANSMITTED
OVER THE MERGED FIRM'S TRANSMISSION SYSTEM WILL BE ECONOMICALLY ATTRACTIVE
TO WOULD-BE BUYERS IN COMPARISON TO DIRECT PURCHASES FROM AN UNMERGED UE OR
CIPS DIRECTLY?
A. Yes. Most of the interchange sales made by both UE and CIPS in recent
years--e.g., excluding sales to requirements customers and CIPS's system
participation sales--have been supported by simultaneous interchange
purchases. For UE, for the time period January 1, 1993, to May 31, 1995,
66.5 percent of its interchange sales have fallen into this category. For
CIPS, for the time period from January 1, 1993, to August 31, 1995, 60.4
percent of its interchange sales have fallen into this category. For these
simultaneous buy-and-sell transactions, which in some respects are
analogous to wheeling, buyers apparently
<PAGE>
Exhibit No.___(RWF-1)
Page 37 of 100
have found it economic to procure power remotely and pay for losses and
implicit wheeling fees across the intervening (UE or CIPS) system.
Postmerger, many buyers' (and sellers') options ought to be improved
because, rather than relying on either CIPS or UE to arrange such
transactions, they--or marketers seeking to sell to (or buy from) them--
will be able to use the merged firm's (single system) open access
transmission to ferret out their own deals.
Q. YOU INDICATED ABOVE THAT EACH OF THE ENTITIES INTERCONNECTED WITH BOTH UE
AND CIPS STILL WILL HAVE SEVERAL OTHER DIRECT INTERCONNECTIONS POSTMERGER.
HAVE YOU CONSIDERED THE RELATIVE IMPORTANCE OF THE INTERCONNECTIONS WITH
ENTITIES OTHER THAN THE MERGING PARTIES?
A. Yes. I considered the possibility that these other interconnections might
exist but not actually be used as extensively as the interconnections with
UE and CIPS. This could be the case if significant transmission
constraints existed which prevented such use, if entities on the other side
of the interconnections did not have economic supplies available for sale,
or if entities on the other side of the interconnections did not represent
good markets. If these conditions existed, the affected firms might be
forced to deal only with UE and CIPS in bulk power markets, and so a merger
of the two potentially could have more severe consequences. However, this
does not appear to be the case.
Q. PLEASE EXPLAIN.
<PAGE>
Exhibit No.___(RWF-1)
Page 38 of 100
A. Exhibit ___ (RWF-6) shows, for each of the four entities other than EEI
which are interconnected with both UE and CIPS, their total interchange
sales and purchases for the time period 1991-1994--except for TVA where the
time period covered is 1992-1994--as well as the percentage of each
accounted for by transactions with UE and CIPS. Sales to these entities by
UE and CIPS accounted for at most 16.3 percent of all sales made to these
entities by all parties. UE and CIPS accounted for at most 31.5 percent of
total purchases from any of these entities. In short, it is apparent that
each of these four systems has not been restricted to dealing with just UE
and/or CIPS for their wholesale bulk power transactions. Their other
interconnections have been used for wholesale bulk power transactions far
more extensively than the interconnections with UE and CIPS.
Q. DO YOU HAVE ANY ADDITIONAL INFORMATION ON THIS TOPIC?
A. Yes. In her testimony, Ms. Borkowski reports on her examination of
publicly available data concerning transfer capabilities between these
systems and their neighbors and concludes that significant quantities of
unused transfer capability are projected to exist. Thus, both the
historical data on actual transactions contained in Exhibit ___ (RWF-6) and
Ms. Borkowski's review of projected transmission availability indicate that
directly interconnected entities have practical bulk power trading
alternatives available to them other than dealing with the merged entity.
Q. YOU INDICATED ABOVE THAT IT IS NOT APPROPRIATE TO VIEW EEI AS AN
INDEPENDENT PARTICIPANT IN REGIONAL BULK POWER MARKETS. WHY IS THAT?
<PAGE>
Exhibit No.___(RWF-1)
Page 39 of 100
A. EEI acts as both a generator and a reseller. In its role as a generator,
energy and capacity from the Joppa Plant are sold under contract to USEC
and Sponsors. EEI can make sales to entities other than USEC or Sponsors
only to the extent that USEC and Sponsors decline to take their full
entitlements. In recent years, because the energy has been priced very
favorably for sales to USEC and Sponsors, there has been very little
available for sales to others. TVA is the only other entity now with
contractual arrangements in place to make such purchases but during the
last two years has purchased less than two gigawatt-hours from EEI. This
constitutes less than one-hundredth of one percent of EEI's total sales of
approximately 29,000 gigawatt-hours during these two years. The remainder
has been sold to USEC and Sponsors. Thus, from a practical standpoint, EEI
does not generate energy that is sold to others in competitive bulk power
markets.
In its role as a reseller, EEI supplies nonfirm energy only to USEC,
usually for weekly, monthly or longer term blocks. This nonfirm energy is
bid to it by Sponsors who in turn may be reselling energy purchased from
others and, at least in the case of UE and CIPS, are likely to be reselling
energy purchased from others. EEI combines the bids of Sponsors, adds a
markup of up to one mill per kilowatt hour, and then offers what is in
effect a supply curve to USEC in 50 megawatt increments. That supply curve
may compete with another supply curve offered by TVA. However, while there
is competition with TVA to meet USEC's nonfirm energy requirements, the
real competition is between TVA and those who directly and indirectly
supply EEI, and not between TVA and EEI. Moreover, it is my understanding
that USEC has the ability to, and does, vary its production schedules by
time
<PAGE>
Exhibit No.___(RWF-1)
Page 40 of 100
period according to the energy prices which are offered to it. So at any
point in time individual suppliers are competing not only with the prices
which other suppliers offer them, but also with the prices that USEC
believes will be forthcoming in the future.
Q. HOW WILL THIS COMPETITION CHANGE IN THE FUTURE?
A. There will be two principal changes. First, as a result of the merger, UE
and CIPS presumably no longer will bid separately to supply components of
the package which EEI offers to USEC, but will bid as one. Standing alone,
this could be viewed as a lessening of competition, although it must be
remembered that IP and KU still can bid in competition with the merged firm
to fill EEI's package and that TVA can bid in competition with EEI to meet
USEC's nonfirm energy needs. TVA has been the largest supplier of USEC's
nonfirm energy needs recently, supplying 55 percent of the total since the
beginning of 1995. The energy supplied by TVA, of course, may have been
purchased from others (as is true for most of UE's and CIPS's sales), but I
am not aware of any publicly available data source that could document the
extent of this. Second, the merged firm will have filed an open access
tariff which will allow any eligible customer to package together nonfirm
energy supplies to sell to EEI. This suggests an expansion of the number
of entities that can compete to supply the ultimate needs of USEC.
Q. HAVE YOU CONSIDERED WHETHER, POSTMERGER, EEI WILL TEND TO FAVOR PURCHASES
FROM THE MERGED FIRM INSTEAD OF PURCHASES FROM OTHER SUPPLIERS?
<PAGE>
Exhibit No.___(RWF-1)
Page 41 of 100
A. This does not seem like a significant concern. My presumption is that EEI
will seek to procure the lowest priced energy which it can without regard
to source. The availability of the Ameren Tariffs, as well as the open
access tariffs of IP and KU, will enable other utilities and marketers to
reach EEI by those tariffs. Moreover, both Mr. Rainwater for UE and Mr.
William A. Koertner for CIPS testify that their firms will not interfere
with the discretion of EEI to procure power competitively from other
sources and will encourage the other EEI owners to allow this.
C. TRANSMISSION OVERLAPS
---------------------
Q. ARE UE AND CIPS ACTUAL OR POTENTIAL COMPETITORS FOR THE SUPPLY OF
TRANSMISSION SERVICES BETWEEN UTILITIES THAT ARE DIRECTLY INTERCONNECTED
WITH BOTH?
A. For the most part, no. UE is located to the west of CIPS, and the two
transmission systems do not overlap in the sense that they represent
alternative paths between specified points of receipt and specified points
of delivery. However, I have already indicated that, excluding EEI (for the
reasons discussed above), there are four utilities that today are or by
1998 will be interconnected with both merging parties. These four are
IES, IP, KU, and TVA. In principle the merger could combine into a single
entity transmission paths for transactions between particular pairs of
these four entities.
Q. DOES THE MERGER THEREFORE PRESENT COMPETITIVE CONCERNS BECAUSE IT WILL
COMBINE UNDER COMMON OWNERSHIP POTENTIALLY COMPETING TRANSMISSION PATHS?
<PAGE>
Exhibit No.___(RWF-1)
Page 42 of 100
A. No. The principal reason is that a more complete analysis of the effects
of the proposed merger on bulk power markets will focus upon all options
available to sellers and buyers and how those options might be affected by
a merger, rather than focusing upon only the subset of options represented
by individual transmission paths between two or just a few utilities. When
the market is defined correctly to incorporate all of these options,
concerns about a potential lessening of competition vanish. In the case of
IES, additional options include, at a minimum, transacting with any of the
eight parties with which it is interconnected or transacting with any of
the additional parties that it can reach under Ameren's proposed open
access tariff. IES's options also include transacting with parties
accessible under MEC's existing open access transmission tariff, and
transactions which it can arrange through its MAPP participation. In the
cases of IP, KU and TVA, those additional options include transacting with
any of the 9, 10 and 11 parties, respectively, with which they are
interconnected. Additional options available to IP and KU include using the
merged firm's transmission tariffs to facilitate transactions with
additional entities or using existing open access tariffs of other entities
with which they are directly interconnected (e.g., MEC's or AEP's tariff
for IP and the PSI/CINergy, AEP and Louisville Gas and Electric Company
tariffs for KU). TVA also can use the merged firm's open access tariff and
those of other entities directly interconnected with it (e.g., AEP and
Entergy) to make bulk power purchases but, presumably, because of the
"fence," not to make bulk power sales. I have already discussed Exhibit
__(RWF-6), which indicates that the other interconnections of IES, IP, KU
and TVA do provide them with significant trading opportunities other than
dealing with just UE and CIPS. Another way of stating
<PAGE>
Exhibit No.___(RWF-1)
Page 43 of 100
this general point is that transmission service between various
combinations of IES, IP, KU and TVA does not, by itself, represent a
distinct relevant market for purposes of assessing the competitive effects
of this merger. Such a market definition is too narrow, because origin area
sellers and destination area buyers both have numerous alternatives
available to them besides transmission over the merged entity's system. A
proper relevant market definition will incorporate these alternatives.
I note also that each of IP, KU and TVA is interconnected with each of the
other two. IP and KU are interconnected with each other (and with EEI, UE
and CIPS) via the Sponsors-EEI agreement described earlier. IP is
interconnected with TVA (and with UE and CIPS) via the Interconnection
Agreement between TVA and the Ill-Mo Pool members which I referred to
earlier. KU has its own direct interconnection with TVA. Accordingly, if
any of these three entities wish to transact with any of the others, almost
certainly they will do so via their own contractual paths rather than
paying extra to wheel over a third party system, whether that third party
is UE or CIPS on a stand-alone, premerger basis or Ameren on a postmerger
basis. The merger of UE and CIPS therefore takes away an independent
transmission alternative from these entities only to the extent that their
own direct interconnections are not sufficient to accommodate the bulk
power transactions they desire to undertake.
Q. DO YOU HAVE ANY ADDITIONAL COMMENTS ON THIS TOPIC?
<PAGE>
Exhibit No.___(RWF-1)
Page 44 of 100
A. Yes. The prices at which transmission service is provided are regulated
precisely because it is believed that transmission is a natural monopoly.
The concern is that, without regulation, prices would be "too high."
Parallel path competition among alternative transmission suppliers can
cause prices to fall below just and reasonable prices and, in effect, shift
the fixed cost burdens of supporting the transmission system to customers
that are not able to benefit from such competition. Because electrons flow
according to laws of physics and not according to contractual
relationships, the costs that any one transmission owner will incur when a
wheeling transaction takes place are independent of whether or not it
receives revenues as part of the contractual path supporting the wheeling
transaction. Accordingly, where parallel path competition is possible, the
individual transmission owner will be motivated to bid far below its just
and reasonable price in order to receive at least some revenue from the
wheeling transaction if the facilities which it owns could comprise a
contractual path. If it fails to do so it will receive no revenues but
incur the same costs that it will incur if some other transmission owner
underbids it and becomes part of the contract path. When the price for
transmission service drops as a result of this phenomenon, other users,
through the ratemaking process, will be forced to bear a higher proportion
of the fixed cost burdens of transmission assets. There are no obvious
economic efficiency benefits associated with this type of competition and,
accordingly, I do not believe that its preservation, where it exists,
should form a significant consideration for assessing the proposed merger
of UE and CIPS.
Q. WHAT DO YOU CONCLUDE ABOUT THE EFFECT OF THE MERGER ON CONTROL OF
TRANSMISSION?
<PAGE>
Exhibit No.___(RWF-1)
Page 45 of 100
A. As is true with any merger, it is axiomatic that a merger of UE and CIPS
will reduce by one the number of independent participants at least
potentially capable of providing service. However, this reduction does not
create competitive concerns relating to the merged entity's control of
transmission. One reason is that the transmission systems of UE and CIPS
do not overlap and therefore for the most part do not represent potentially
competing transmission paths. A second reason is that each potentially
affected party postmerger still will have numerous other independent
trading alternatives available, including use of its own direct
interconnections. Data on past transactions indicate that these
interconnections with other parties are used for interchange transactions
much more extensively than are these utilities' interconnections with UE
and CIPS. Finally, regional utilities (and marketers) will have the
opportunity to engage in bulk power transactions using the merged firm's
open access transmission tariff (and the open access tariffs of several
other utilities which already have been filed at FERC) at rates, terms and
conditions determined by FERC to be appropriate. In actuality, the merger,
as a result of the open access transmission tariff which the Applicants are
filing, will expand the bulk power alternatives available to all but a few
regional utilities because it will increase the number of trading partners
that they can reach via payment of a single wheeling fee.
V. BULK POWER
Q. PLEASE DESCRIBE YOUR APPROACH TO DEFINING BULK POWER MARKETS.
<PAGE>
Exhibit No.___(RWF-1)
Page 46 of 100
A. Ultimately electric utilities are seeking to assemble a low cost firm power
supply for resale to their customers. There are a variety of components
that can be packaged together to achieve this goal. These components
include generating resources which utilities construct and operate
themselves as well as very long term (perhaps life-of-unit) purchases such
as many utilities have made from nonutility generators (NUGs)/2/ in recent
years. Owned or purchased resources can take many forms, differing by fuel
type, size, technology and mode of operation (peaking versus baseload),
among other things. The components used to assemble a low cost firm power
supply also include a variety of shorter term bulk power purchases that
generating utilities engage in to improve the economics of dispatch,
enhance reliability and/or correct short term capacity imbalances. Examples
include economy energy, term energy, emergency and scheduled outage energy,
seasonal participation power, short term capacity and energy of various
durations, peaking power and others. In recent years demand-side management
(DSM) measures also have become increasingly important components available
to utilities.
These various components can be substituted for one another to varying
degrees. For example, a utility with an approaching capacity deficiency may
elect to buy under a long term contract from a NUG (or other utility) in
the marketplace instead of building its own new generation capacity. It
also may seek to purchase capacity from others on a short term
- --------------------
/2/ I use the NUG term to refer to all such nontraditional suppliers including
Qualifying Facilities, Exempt Wholesale Generators, and others. I recognize
that in some cases NUGs defined in this fashion actually may be owned by
affiliates of traditional utility suppliers.
<PAGE>
Exhibit No.___(RWF-1)
Page 47 of 100
basis to delay the point in time at which new capacity must be constructed
or purchased on a longer term basis. The substitution is also very direct
when a utility elects to purchase economy energy from another supplier
rather than generating additional output from its own units.
Thus, alone or in combination, these various components are substitutable
with one another in the development of the firm bulk power package which
utilities require for sale to their customers. Because of this
substitutability, one approach for defining relevant markets would be to
include all of these separate components (including DSM and self-
generation) in the same relevant market within which the competitive
effects of the proposed merger would be examined. Such an approach would
include relatively disparate components (e.g., economy energy and
construction of a new baseload generating station) that obviously are not
directly substitutable. Another approach would be to examine multiple
groupings of products where each such grouping is more compact and
homogeneous. This is the approach utilized below.
Q. WHAT RELEVANT BULK POWER MARKETS HAVE YOU EXAMINED?
A. Consistent with previous merger and market power investigations before
FERC, I have examined whether the proposed merger would create or increase
market power in the following three bulk power markets: (i) short term
capacity; (ii) long term capacity; and (iii) nonfirm energy. The usual
distinction between short and long term capacity is that the former
generally excludes sales from capacity not yet in commercial operation
(unless the
<PAGE>
Exhibit No.___(RWF-1)
Page 48 of 100
date for commercial operation is very near), whereas the time period for
the latter extends far enough into the future that new capacity can be
constructed to compete for the sale. Long term capacity also can include
purchases made out of existing surpluses where those surpluses are expected
to extend well into the future. Options for obtaining long term capacity
generally include the construction of new generating units, life extension
of existing units, the purchase of long term (perhaps life-of-unit)
interests in units to be constructed by others and purchases from existing
surpluses that are expected to be long-lived. Options for short term
capacity consist predominantly of purchases from the surpluses that other
in-region or nearby utilities hold.
Nonfirm energy and other closely substitutable interchange transactions are
transactions that generating utilities engage in principally to improve the
economics of dispatch. Although I use the expression nonfirm energy to
describe this market, many of the types of transactions which are included
actually are styled as relatively short term capacity and energy
transactions. An example would be daily or weekly capacity that one utility
might sell to another, not because the buyer was short of capacity, but
rather because it wished to receive (and was willing to pay for) the low
cost energy associated with the purchased capacity. Paying the demand
charge for the capacity and receiving the low cost energy associated with
it may be more economical for the buyer than operating its own higher fuel
cost units. This is the same reason that a party would purchase economy (or
another form of nonfirm) energy, i.e., to reduce the need to generate from
its own higher cost units.
<PAGE>
Exhibit No.___(RWF-1)
Page 49 of 100
Q. ARE THERE DISTINCT BOUNDARIES FOR EACH OF THESE THREE RELEVANT BULK POWER
MARKETS?
A. No. Because of substitutability among components, the boundaries between
these three separate relevant markets can blur. Moreover, as defined above,
some potentially close substitutes (e.g., DSM measures or self-generation
as an alternative to purchased economy energy) are excluded when, if they
are price competitive, they ought to be included.
Q. ARE THERE GENERAL CONSIDERATIONS WHICH FIGURE INTO YOUR ANALYSES OF BULK
POWER MARKETS IN THIS CASE?
A. Yes. There are several considerations which suggest on an a priori basis
that a merger between UE and CIPS is not a merger likely to create or
enhance market power in bulk power markets. The merging partners comprise
only a small portion of aggregate generating capability in the region (6.5
percent), where "region" in this sense is defined to include all utilities
interconnected with at least one of them. Utilities interconnected with
both merging parties have numerous alternative trading partners. Bulk power
markets in this area historically have been competitive. Several utilities
interconnected with either UE or CIPS (e.g., CE, CILCO, KCPL, KU, IP, MEC,
WR, Entergy, CSW, AEP and CINergy) already have filed open access tariffs
and presumably more will in the future, either voluntarily or as a result
of FERC's NOPR. Finally, as discussed, Applicants are filing a consolidated
(single system) open access transmission tariff which can allay residual
concerns about the creation of market power in wholesale bulk power
markets.
A. SHORT TERM CAPACITY
-------------------
<PAGE>
Exhibit No.___(RWF-1)
Page 50 of 100
Q. I WOULD LIKE TO BEGIN WITH THE EFFECTS OF THE MERGER ON THE SHORT TERM
CAPACITY MARKET. PLEASE REPEAT YOUR DESCRIPTION OF THE PRODUCT WHICH IS
TRADED IN THIS MARKET.
A. Short term capacity refers to purchases and sales of firm power over time
periods too short to allow new construction to compete for those
transactions. Utilities can supply short term capacity to others when their
own generating resources exceed those required to serve their native load
customers reliably and fulfill existing contractual commitments. They can
also act as marketers and resell short term capacity that they have
purchased from others. There is no precise number of years that demarcates
short term from long term, although, except for peakers, it seems unlikely
that significant quantities of new capacity could be brought on line in
less than four years.
Q. HOW WILL THE MERGER AFFECT THE NUMBER OF COMPETITORS SELLING SHORT TERM
CAPACITY?
A. Both UE and CIPS actively seek to market capacity to other nearby utilities
and therefore are direct competitors. In addition to UE and CIPS, there are
also many other in-region utilities that can market capacity to others. So
while the merger will reduce the number of competitors in the area by one,
many others still will remain. Moreover, as indicated previously, the
implementation of the single system (combined UE and CIPS) open access
tariff should enhance opportunities for others (including marketers) that
wish to compete.
More fundamentally as concerns an analysis of this merger, UE's ability to
compete in short term capacity markets is limited because of its very small
(or nonexistent, depending upon how it is measured) quantity of uncommitted
capacity. Realistically, UE competes
<PAGE>
Exhibit No.___(RWF-1)
Page 51 of 100
in short term capacity markets today principally by using capacity
purchased from one utility to support sales to another and not by making
capacity sales out of its own uncommitted generation. In that sense it is
acting as a marketer of capacity owned or otherwise controlled by others.
CIPS also seeks to undertake these types of buy-and-resell transactions,
although CIPS also has some uncommitted capacity of its own which it seeks
to sell. Ease of entry is one of the most important factors to consider in
assessing whether a proposed merger is likely to create concerns about
market power. Where entry is relatively easy, such concerns should vanish.
With the advent of open access transmission tariffs, entry by those who
would market electric capacity on a buy-and-resell basis, as do both UE and
CIPS, is relatively easy. It requires access to those transmission tariffs,
knowledge of supply and demand sources, and perhaps an ability to recognize
various types of risk and provide mechanisms to hedge these, but it does
not require the types of large capital investments in generation or
transmission plant that in the past might have been used to argue that
entry was difficult. In short, there are potentially many entities that
could compete with UE or CIPS, or a merged UE/CIPS, in the marketing of
capacity on a simultaneous buy-and-resell basis, and so a merger of UE and
CIPS will not have a significant effect on the number of competitors.
Stated differently, with so many open access transmission tariffs in the
region, power marketing does not possess the characteristics of an activity
where there are likely to be realistic concerns about the exercise of
market power.
Q. PLEASE DESCRIBE THE LOAD AND RESOURCE POSITION OF UE AND CIPS.
<PAGE>
Exhibit No.___(RWF-1)
Page 52 of 100
A. UE forecasts a peak demand of 7,199 megawatts for summer 1996--both UE and
CIPS are summer peaking--and expects to have available 8,385 megawatts of
owned and purchased generating capacity to serve that demand. UE uses a
reserve margin of 18 percent for purposes of planning new resources but a
lower reserve margin of 15 percent for shorter term planning, up to
approximately one year. Based upon the 18 percent reserve margin, UE
therefore projects a deficit of 110 megawatts for summer of 1996. Based
upon the 15 percent reserve margin, UE projects surplus or uncommitted
capacity of 106 megawatts for summer 1996. UE's Preferred Resource Plan
shows that its requirements for additional resources through the year 2000
can be met by a combination of purchases from others, improvements at
existing plants, and DSM. It does not show requirements for additional
supply side resources until 2001, when the first of several 75 megawatt
combustion turbines is now projected to come on-line.
CIPS forecasts a peak demand of 2,261 megawatts for summer of 1996
consisting of native load (retail plus full requirements wholesale) demands
of 1,941 megawatts and reserved committed sales to other utilities of 320
megawatts. After netting its 271 megawatts of long term system
participation sales to Soyland, IMEA and WVPA, CIPS expects to have
available 2,766 megawatts of resources to meet that demand. CIPS's Electric
Energy Plan uses an 18 percent reserve margin for planning purposes but, as
is true for UE, it also is CIPS's policy to go below this level to 15
percent for shorter term planning purposes. Based upon the 18 percent
figure, CIPS therefore forecasts 98 megawatts of uncommitted capacity for
the summer of 1996. Using a lower reserve margin figure of 15 percent,
<PAGE>
Exhibit No.___(RWF-1)
Page 53 of 100
CIPS's uncommitted capacity rises to 166 megawatts for the summer of 1996.
In its most recent load and resource plan, CIPS's "most probable" or base
case scenario indicated no need for new supply or demand-side resources
throughout the 1996-2016 study period.
Q. DO OTHER IN-REGION UTILITIES EXPECT TO HAVE UNCOMMITTED CAPACITY DURING
THIS SAME TIME PERIOD?
A. Yes. Exhibit No. ___(RWF-7) shows the uncommitted capacity for UE, CIPS
and each other entity directly interconnected with either of them for 1996.
Total uncommitted capacity for all of these entities is 2,856 megawatts.
Using its 18 percent planning reserve margin, CIPS's share of this total is
3.4 percent. Using its 18 percent planning reserve margin, UE, as
indicated, has no uncommitted capacity.
Q. WHAT DO YOU CONCLUDE FROM EXHIBIT ___ (RWF-7)?
A. My principal conclusion is that, because UE has no uncommitted capacity
when that term is defined with respect to its 18 percent planning reserve
margin, this is not a merger that can increase the concentration of
uncommitted capacity in the region. Accordingly, to the extent that
concentration of uncommitted capacity is a useful measure for assessing the
ability to exercise market power in short term capacity markets, the merger
of UE and CIPS obviously is not one which presents concern.
Q. WHAT RESERVE MARGINS HAVE YOU USED TO DETERMINE THE AMOUNT OF UNCOMMITTED
CAPACITY HELD BY UTILITIES OTHER THAN UE AND CIPS IN PREPARING EXHIBIT ___
(RWF-7)?
<PAGE>
Exhibit No.___(RWF-1)
Page 54 of 100
A. I have used 18 percent for all of the utilities but one, although the
reason I have done so differs among utilities. The SPP generally requires
its members to hold a minimum capacity margin--total capacity less peak
demand divided by total capacity--of 15.25 percent. A capacity margin of
15.25 percent translates into a reserve margin--total capacity less peak
demand divided by peak demand--of 18 percent. MAPP requires that its
members hold a reserve margin of 15 percent at the time of actual system
peak. Because penalties apply if this level is not achieved, it is my
understanding that at least some MAPP members, on a planning basis, choose
to hold reserves above this level in order to protect against peaks
resulting from unusual weather conditions. For this reason I believe that a
number greater than 15 percent is appropriate for MAPP utilities. For
utilities in MAIN other than UE and CIPS, I have used an 18 percent reserve
margin as the minimum figure of the 18 to 22 percent range recommended by
MAIN's executive committee, as well as one which is consistent with the
levels I use for UE and CIPS which also are MAIN members. ECAR and TVA do
not set minimum planning reserve margins. Accordingly, for utilities in
ECAR and for TVA the 18 percent reserve margin represents a "default"
value. The only utility that I have not used an 18 percent reserve margin
for is SPA, which is a member of the SPP and directly interconnected with
UE. For hydroelectric-based systems, of which SPA is one, the SPP allows
its members to have capacity margins as low as 9 percent. A capacity margin
of 9 percent translates into a reserve margin of 9.9 percent, which is the
reserve margin I use for SPA.
<PAGE>
Exhibit No.___(RWF-1)
Page 55 of 100
Q. HOW WOULD THE FIGURES IN EXHIBIT ___ (RWF-7) CHANGE IF YOU USED THE LOWER
15 PERCENT RESERVE MARGIN WHICH UE AND CIPS USE FOR TIME PERIODS EXTENDING
LESS THAN ONE YEAR INTO THE FUTURE?
A. That information is shown in Exhibit ___ (RWF-8). For consistency in
preparing this exhibit, I have lowered the reserve margins of not only UE
and CIPS but also of the other utilities (except SPA where the 9.9 percent
reserve margin is unchanged). Thus, in this context, I am assuming that
just as UE and CIPS would be willing to drop below their 18 percent
planning reserve margins to facilitate short term sales that extend no more
than one year into the future, so too would other in-region utilities. With
the lower reserve margin, stand-alone UE shows surplus or uncommitted
capacity of 106 megawatts or 1.7 percent of the total held by UE, CIPS and
all directly interconnected utilities. With the lower reserve margin,
stand-alone CIPS shows surplus or uncommitted capacity of 166 megawatts or
2.6 percent of the total held by UE, CIPS and all directly interconnected
utilities. The postmerger share of Ameren is 4.2 percent.
Q. WHAT DO YOU CONCLUDE FROM EXHIBIT ___ (RWF-8)?
A. Exhibit ___ (RWF-8) indicates that UE does have some uncommitted capacity
when the lower 15 percent reserve margin is used, and therefore that,
because CIPS also has some uncommitted capacity, the merger will increase
concentration of uncommitted capacity in the region. However, the combined
postmerger share of UE and CIPS, 4.2 percent, is relatively small and far
below the 20 percent level which FERC in the past has used as a threshold
to demarcate situations that obviously present no concern about market
power.
<PAGE>
Exhibit No.___(RWF-1)
Page 56 of 100
Moreover, both Exhibits ___ (RWF-7) and ___(RWF-8) include uncommitted
capacity only from the merging partners and utilities directly
interconnected with one or both of them. Almost certainly this is too
narrow of a relevant market within which to assess the effects of the
proposed merger, because it does not include supplies that other utilities,
not directly interconnected with either of Applicants, could make available
to would-be purchasers. Because the merging parties control only relatively
small shares of uncommitted capacity when the computations incorporate only
a subset of potential suppliers, it necessarily follows that their combined
shares would be even lower if the market were appropriately broadened to
incorporate additional supplies that could be made available.
Q. WHAT DATA SOURCES DID YOU USE TO DEVELOP EXHIBITS ___ (RWF-7) AND ___ (RWF-
8)?
A. Data required to prepare Exhibits ___ (RWF-7) and ___ (RWF-8) include peak
demands, total generating capacity, and reserve margins for each utility.
Data on total generating capacity generally come from the OE-411 reports of
the regional reliability councils in which the utilities are located (i.e.,
ECAR, MAIN, MAPP, SERC and SPP) and, in some cases (including UE and CIPS),
from individual company load and resource reports. I used data from
individual firm load and resource reports for UE and CIPS because it was
more recent than that contained in MAIN's OE-411 report. Where
identifiable, I added to total generating capacity the capacity of units in
cold storage or inactive reserve if they were not already included. The
rationale for this adjustment is that such units presumably could be made
available to the marketplace if a firm that possesses market power sought
to exercise
<PAGE>
Exhibit No.___(RWF-1)
Page 57 of 100
it by restricting capacity and raising price. Data concerning peak demands
come from the same source as the total generating capacity data. Reserve
requirements were determined as described above. For utilities that are
winter peaking, I used forecast data for the winter 1995-1996 time period;
for utilities that are summer peaking, I used forecast data for summer
1996. Committed sales to other utilities were treated either as reductions
in determining total generating capacity or as increases to peak demand,
depending upon the nature of the sale and its treatment in the underlying
raw data source. Finally, CSW has two subsidiaries which operate in the SPP
and two which operate in the Electric Reliability Council of Texas (ERCOT)
region. Because ERCOT is not connected synchronously with SPP or other
regions, the data which I use for CSW reflects only its SPP operations.
However, supplies from the ERCOT companies are available to the SPP
companies over DC interconnections. Had I included CSW's ERCOT companies in
my analysis also, the measured shares for CIPS and UE would be lower than I
have shown.
Q. HAVE YOU DEVELOPED ADDITIONAL INFORMATION WHICH ADDRESSES THIS TOPIC?
A. Yes. I have examined how the merger affects concentration of uncommitted
capacity in various "first tier" markets as that expression has come to be
used. It is the first tier utilities connected to Applicants that, at least
in principle, are most likely to see their market opportunities altered by
the proposed merger. This is the type of analysis which FERC previously has
used in situations where market power was a potential concern.
Q. WHAT IS A FIRST TIER MARKET?
<PAGE>
Exhibit No.___(RWF-1)
Page 58 of 100
A. A first tier utility is a utility that is directly interconnected with UE
or CIPS or both. The "market" for each first tier utility, at a minimum,
consists of UE or CIPS or both, as appropriate, plus all other entities
with which the first tier is directly interconnected. It also has become
standard to include in such first tier markets utilities that are "one
wheel" away by virtue of an open access tariff that has been filed by
whatever firm is subject to the market power investigation at hand; in this
case, Ameren.
Consider the simple example shown on page one of Exhibit ___(RWF-9) where
the circled letters represent utilities, and the lines represent
interconnections between them. A and B propose to merge. First tier
utilities for A are F, G, H and, of course, B. First tier utilities for B
are C, D, E, F, H and, of course, A. The market for each first tier utility
consists of all entities with which it has direct interconnections. For
example, the first tier market for G consists of A, F, H, K and L.
Moreover, because G is interconnected with only one of the merging
partners, A, and not the other, B, its first tier market essentially is
unchanged by the merger of A and B. There are five entities with which it
can directly transact with or without a merger. This is not the case for F,
which is interconnected with both A and B. Premerger there are five
entities with which it can transact through direct interconnections (A, B,
E, G and L), whereas postmerger there are only four (merged A-B, E, G and
L). The previous discussion does not incorporate the effects of an open
access transmission tariff that A and B might file, which could expand the
trading opportunities for first tier utilities. For example, for F they
would now include merged A-B, E, G and L, as discussed above, but also C, D
and H. Page two of Exhibit ___ (RWF-9) shows how the various first tier
<PAGE>
Exhibit No.___(RWF-1)
Page 59 of 100
markets change as a result of an A-B merger and the merging parties' filing
of an open access transmission tariff.
Q. IS IT APPROPRIATE TO INCLUDE THE FIRST TIER UTILITY ON WHOM THE MARKET IS
CENTERED AS A PARTICIPANT IN ITS OWN FIRST TIER MARKET?
A. Yes. The presumed intention of the analysis is to measure shares of
capacity that might be available to compete to supply the utility in the
center. For many shorter term transactions such as economy energy, short
term capacity and energy, or operating reserves, more intensive use of the
center utility's own capacity will be a substitute for energy or capacity
and energy purchased from others, and therefore that center utility's
capacity ought to be incorporated into the analysis. In making its analysis
of whether or how much it might purchase from others, the buying utility
will trade off the costs of operating its own generation against the prices
offered by those other suppliers. This is the approach which FERC has used
previously. See Entergy at pages 61,773-74 where participants in each first
tier market appropriate for examining Entergy's request for market-based
pricing are identified. It is specifically stated that the "own generation"
of the entity in the center of each market is included.
Q. WHAT FIRST TIER MARKETS ARE APPROPRIATE FOR AN ASSESSMENT OF THE EFFECTS OF
A MERGER BETWEEN UE AND CIPS?
A. Those first tier markets are identified in Exhibit ___(RWF-10). This is a
27-page exhibit with each page covering one first tier market (e.g., the
market centered on AEP) and
<PAGE>
Exhibit No.___(RWF-1)
Page 60 of 100
identifying all participants in it. With the exception of EEI, which is
excluded for reasons discussed earlier, Exhibit ___(RWF-10) includes a
first tier market centered on each utility that is interconnected with UE,
CIPS or both.
Q. HAVE YOU PREPARED COMPUTATIONS WHICH ASSESS THE EFFECTS OF THE MERGER ON
CONCENTRATION OF UNCOMMITTED CAPACITY IN THESE FIRST TIER MARKETS?
A. Yes. Those computations are shown in Exhibits ___ (RWF-11) and ___ (RWF-
12). The difference between these two exhibits is that Exhibit ___ (RWF-11)
uses an 18 percent reserve margin for UE, CIPS and other utilities, while
Exhibit ___ (RWF-12) uses a lower 15 percent reserve margin. The rationale
for these different reserve margins is discussed above./3/ The two exhibits
are formatted similarly. Each of the first tier utilities is listed along
the left, and the four columns contain summary share data concerning each
of these markets. The first column shows UE's share of uncommitted capacity
in each first tier market premerger. Because, as discussed, UE has no
uncommitted capacity when the 18 percent reserve margin is used, this
figure is always zero in Exhibit ___ (RWF-11). The second column shows the
premerger share of CIPS. The third column shows the postmerger share of
Ameren without expanding the market to incorporate the effects of the
Ameren Tariffs, while the fourth column shows Ameren's share after the
effects of the
- --------------------
/3/ The only exceptions are SPA and Manitoba Hydro (MH), which is in NSP's
first tier market. In both Exhibits ___(RWF-11) and ___ (RWF-12), I use a
9.9 percent reserve margin for SPA for reasons discussed above. I use a 10
percent reserve margin for MH in both exhibits, which is MAPP's minimum
requirement for a hydro-based system.
<PAGE>
Exhibit No.___(RWF-1)
Page 61 of 100
Ameren Tariffs are incorporated. The numbers in Column (4) necessarily are
less than or equal to those in column (3).
Q. WHAT DATA SOURCES HAVE YOU USED TO PREPARE EXHIBITS ___ (RWF-11) AND ___
(RWF-12)?
A. The data used in the preparation of these two exhibits generally is the
same as that described above concerning Exhibits ___ (RWF-7) and ___ (RWF-
8). Additionally, for some of the smaller systems included in certain first
tier markets, data on total generating capacity and peak demands came from
the Electrical World Directory of Electric Power Producers, 1995 (EWD).
Interconnections used to define first tier markets were determined from the
EWD as supplemented by information provided by UE and CIPS. As I did for
Exhibits ___ (RWF-7) and ___ (RWF-8), I included only CSW's SPP operations
in these computations and not those in ERCOT. Moreover, because of the
"fence," I have not incorporated TVA's uncommitted capacity in the analyses
except for utilities that are inside that fence.
Q. PLEASE EXPLAIN THESE TWO EXHIBITS WITH AN EXAMPLE.
A. Consider AEC which is shown on the first line of Exhibits ___(RWF-11) and
___(RWF-12). From page 1 of Exhibit ___(RWF-10) we see that premerger AEC
has interconnections with UE as well 15 other systems, but not with CIPS.
Participants in the first tier market centered on AEC therefore include AEC
and each of these 16 other systems. Because UE has no uncommitted capacity
when the 18 percent reserve margin is
<PAGE>
Exhibit No.___(RWF-1)
Page 62 of 100
used, Column (1) of Exhibit ___(RWF-11) indicates that UE controls zero
percent of the uncommitted capacity held by all firms in this first tier
market. From Column (1) of Exhibit ___(RWF-12) we see that UE's figure is
3.5 percent when the 15 percent reserve margin is used. For CIPS the
comparable premerger numbers, shown in Column (2), are zero in both cases
because CIPS and AEC are not interconnected. The merged firm, Ameren,
controls 5.7 percent of the uncommitted capacity in the first tier market
centered on AEC using the 18 percent reserve margin and 8.6 percent using
the 15 percent reserve margin. These figures are shown in the third column
of Exhibits ___(RWF-11) and ___ (RWF-12) respectively and are before the
effects of the Ameren Tariff have been incorporated. The Ameren Tariff will
allow AEC to transact with several additional entities beyond those
included in its first tier market. Those additional entities also are
identified in Exhibit ___(RWF-10) and, for AEC, include AEP, CILCO,
CINergy, CE, IP, NIPSCO, SIPCO, Soyland, WVPA, IMEA, IMPA and Springfield,
IL. Column (4) of Exhibit ___(RWF-11) indicates that the merged firm's
share of uncommitted capacity in this expanded market is only 4.6 percent
using the 18 percent reserve margin. Column (4) of Exhibit ___ (RWF-12)
indicates that the merged firm's share in this expanded market is 5.7
percent using the 15 percent reserve margin.
Q. WHAT DO EXHIBITS ___ (RWF-11) AND ___(RWF-12) INDICATE?
A. In the past FERC has used a threshold figure of 20 percent to distinguish
between situations where generation dominance clearly is not a concern and
situations where it potentially might be. These two exhibits indicate that
in all cases, no matter which reserve margin is
<PAGE>
Exhibit No.___(RWF-1)
Page 63 of 100
used, the merged firm's share of uncommitted capacity falls far below the
20 percent threshold level after incorporating the effects of the open
access tariff. Of course, as indicated, when the 18 percent reserve margin
is used, UE has no uncommitted capacity anyway. This means that the merger
could not increase the concentration of uncommitted capacity in any first
tier market and that, even if the 20 percent threshold were exceeded, it
would not demarcate a merger-related concern.
Q. DO YOU HAVE ANY COMMENTS CONCERNING THE USE OF FIRST TIER MARKETS TO
ADDRESS CONCENTRATIONS OF UNCOMMITTED GENERATING CAPACITY?
A. Yes. First tier markets so defined represent a relatively conservative way
to determine relevant geographic markets. As a result they produce market
share figures for UE and CIPS that almost certainly are much too high. This
is because they exclude capacity that is more than "one wheel" away from
the center utility, which in some cases is capacity that probably ought to
be included. Furthermore, this "traditional" approach does not even include
all capacity that is only "one wheel" away from the center utility.
Q. PLEASE EXPLAIN HOW THIS "TRADITIONAL" APPROACH DOES NOT INCLUDE ALL
CAPACITY THAT IS ONLY ONE WHEEL AWAY FROM THE CENTER UTILITY.
A. The computations supporting Exhibits ___(RWF-11) and ___ (RWF-12) include
as market participants (i) the center utility; (ii) all direct
interconnections of the center utility including UE and/or CIPS as
appropriate premerger and both UE and CIPS postmerger; and (iii) all other
entities that can be reached under the Ameren Tariffs. The analyses do
<PAGE>
Exhibit No.____(RWF-1)
Page 64 of 100
not include, however, other utilities that might be accessible under open
access tariffs that already have been filed by utilities directly
interconnected to the center utility other than Applicants--such as AEP,
CE, CILCO, CSW, Entergy, KCPL, KU, MEC and WR. Were such other open access
tariffs incorporated into the analyses, as they should be, Ameren's share
of the uncommitted capacity in all of these first tier markets would be
below the levels shown in Exhibits ___ (RWF-11) and ___ (RWF-12).
Q. IS IT APPROPRIATE TO INCLUDE THESE ADDITIONAL UTILITIES IN THE FIRST TIER
MARKET ANALYSES?
A. Yes. These additional utilities are just as close to the center utility as
are utilities accessible under the Ameren Tariffs. Thus, just as there is
only one intervening transmission system between the center utility and a
utility accessible via the Ameren Tariffs, there is only one intervening
transmission system between the center utility and each other system
accessible under the open access tariff of any other directly
interconnected utility. Symmetry requires that a "one wheel market" be
defined to incorporate all open access tariffs directly available to the
center utility and not just that of Applicants.
Q. CAN YOU EXPLAIN THIS WITH AN EXAMPLE?
A. Yes. Refer to Exhibit ___ (RWF-13). Each of the circled numbers represents
utilities and the lines between them represent interconnections. Utility 1
is interconnected with Utilities 2, 9 and 10. Utility 10, which is also
interconnected with Utilities 11 and 12, has an open access transmission
tariff on file. Utilities 2 and 3 propose to merge and, concurrently with
their FERC application, file an open access transmission tariff that
includes all direct
<PAGE>
Exhibit No.___(RWF-1)
Page 65 of 100
interconnections of either party as receipt and delivery points. These
other interconnections, as shown in Exhibit ___(RWF-13), are Utilities 4,
5, 6, 7 and 8, as well as, of course, Utility 1. Accordingly, postmerger, a
"one wheel" market centered on Utility 1 is as follows:
1 The center utility
merged 2-3 Direct interconnection of center utility
9 Direct interconnection of center utility
10 Direct interconnection of center utility
4 Accessible under 2-3's open access tariff
5 Accessible under 2-3's open access tariff
6 Accessible under 2-3's open access tariff
7 Accessible under 2-3's open access tariff
8 Accessible under 2-3's open access tariff
11 Accessible under 10's open access tariff
12 Accessible under 10's open access tariff
The important point to stress with this example is that Utilities 11 and 12
are just as close to Utility 1, the market center, as are Utilities 4, 5,
6, 7 and 8 which are accessible under the merged firm's open access tariff.
They are each one wheel away. Accordingly, if it is proper to include
Utilities 4, 5, 6, 7 and 8 in the first tier market, it likewise must also
be proper to include Utilities 11 and 12.
Q. HAVE YOU PREPARED SUMMARY EXHIBITS WHICH INCORPORATE THIS PRINCIPLE FOR THE
FIRST TIER MARKETS IN THIS CASE?
A. No. While I believe that it would be appropriate to do so, I also believe
that it would be superfluous. The merged firm's share of uncommitted
capacity in each of the first tier markets falls far below the 20 percent
level which FERC in the past has used as a threshold to distinguish
situations where market power may be a concern even without properly
<PAGE>
Exhibit No.___(RWF-1)
Page 66 of 100
redefining those markets to include utilities accessible under existing
open access tariffs of entities other than Ameren. Because the 20 percent
screening requirement already has been met, there is no need to subject
these markets to further analyses in order to determine whether market
power concerns might be present. If the merged firm's share already falls
below 20 percent when the markets have been defined too narrowly, it
obviously will fall even further below 20 percent when the market is
appropriately expanded to incorporate additional supplies located within
one wheel of the center.
Q. HAVE YOU PREPARED WORKPAPERS WHICH SUPPORT YOUR COMPUTATIONS IN EXHIBITS
___ (RWF-7), ___ (RWF-8), ___ (RWF-11), AND ___(RWF-12)?
A. Yes. Workpapers attached to my testimony include photocopies of the raw
data used as the basis for the computations, a summary listing of the
database extracted from those raw materials, and summary sheets for each
first tier market identifying and providing data for each participant.
Q. HAVE YOU SEPARATELY INCLUDED UE'S AND CIPS'S REQUIREMENTS CUSTOMERS IN YOUR
ANALYSES?
A. Not directly. However, the merged firm's post open access tariff share of a
first tier market centered on any of these entities will be the same as its
share of the first tier market centered on Columbia or Springfield, IL (or
some of the other first tier utilities), because the same set of market
participants is involved in all cases. Thus, from Column (4) of Exhibits
___ (RWF-11) and ___ (RWF-12), after incorporating the effects of the
Ameren
<PAGE>
Exhibit No.__(RWF-1)
Page 67 of 100
Tariffs, the merged firm's share of uncommitted capacity for markets
centered on these requirements customers is 7.4 percent when the 18 percent
reserve requirement is used and 9.2 percent when the 15 percent reserve
requirement is used.
Q. ARE THERE OTHER INDICATIONS THAT SHORT TERM CAPACITY IS AVAILABLE FROM
SUPPLIERS OTHER THAN UE AND CIPS?
A. Yes. In the fall of 1994 UE sought proposals to provide (principally)
short term capacity from nearly 60 regional utilities. In response it
received offers to supply over 1,000 megawatts for the summer of 1995 and
nearly 1,200 megawatts for the summer of 1996. The solicitation resulted in
a purchase of capacity by UE from CIPS.
Q. ARE THERE ANY OTHER IMPORTANT CONSIDERATIONS INVOLVED IN EXAMINING SHORT
TERM CAPACITY MARKETS?
A. Yes. While I do not believe that, when properly examined, the merger of UE
and CIPS presents the opportunity for the exercise of market power in short
term capacity markets, I think that it is important to stress that, even if
it existed, the exercise of market power in short term capacity markets
does not present the same concerns that the exercise of market power in
other markets might, such as those for longer term capacity. For one
thing, because of the very nature of surplus in this business, any adverse
effects that do exist will be relatively short-lived. Moreover, the
surplus capacity that might support a strong position in short term
capacity markets usually is something that suppliers seek to avoid rather
than obtain. Those holding large surpluses are usually those whose demand
forecasts
<PAGE>
Exhibit No.__(RWF-1)
Page 68 of 100
which formed the basis for their generating capacity additions
were most at odds with actual occurrences. When the surplus can be
marketed, it is often sold at prices far below those which can be supported
by regulatory cost-of-service principles. More importantly, because the
short term market consists largely of sales from existing surpluses, the
actual exercise of market power in this market would have, at most, only
minimal efficiency consequences and produce only transitory redistributive
effects. However undesirable these consequences may appear, they pale in
significance next to the possible distortions from the exercise of market
power in long term capacity markets where billions of dollars of new
investment may be undertaken. It is these latter markets therefore that
ought to figure more prominently in any investigation about the potential
creation of market power from this merger.
Q. HAVE YOU CONSIDERED WHETHER A MERGER OF UE AND CIPS COULD RAISE PRICES IN
SHORT TERM POWER MARKETS BY FACILITATING COLLUSION AMONG SELLERS?
A. Yes. This is a relatively remote possibility. For one thing, coordinating
policies becomes more difficult as the number of entities expands. While
there already are many traditional utilities in the region that can compete
with UE and CIPS, the emergence of marketers greatly expands the pool of
entities that would be required for coordinating policies. Also, capacity
(with associated energy) is not a homogenous product, and many variations
among suppliers' offerings are plausible (e.g., in firmness, energy pricing
and points of delivery). These variations make it difficult for suppliers
to coordinate pricing and output and for cheaters to be detected. Such
conditions undermine collusion.
<PAGE>
Exhibit No.__(RWF-1)
Page 69 of 100
Q. YOUR DISCUSSION OF THE POSSIBLE EFFECTS OF A MERGER OF UE AND CIPS ON SHORT
TERM CAPACITY MARKETS HAS FOCUSED ON SELLER MARKET POWER ONLY. HAVE YOU
ALSO CONSIDERED WHETHER THE MERGER COULD INCREASE OR FACILITATE THE
EXERCISE OF BUYER MARKET POWER?
A. Yes. This is a concern that can be dispensed with quickly. As indicated,
CIPS contemplates no new resource additions until at least 2006. This
makes it very unlikely that a stand-alone CIPS would be seeking to purchase
short term capacity during this time period in order to meet the demands of
its native load customers. If CIPS is not likely to be a purchaser in this
market, the merger cannot reasonably be said to increase buyer market
power. Of course, CIPS (and UE as well) may seek to purchase capacity for
remarketing purposes rather than to serve native load. But there are
obviously many other entities that might also purchase capacity for
remarketing purposes, and so there should be no merger-induced concerns
about monopsony power in short term capacity markets.
Q. PLEASE SUMMARIZE YOUR CONCLUSIONS ABOUT THE EFFECTS OF A MERGER BETWEEN UE
AND CIPS ON SHORT TERM CAPACITY MARKETS.
A. A merger of UE and CIPS should not present concerns about the exercise of
market power in regional short term capacity markets.
On a stand-alone basis, UE's participation as a seller in short term
capacity markets is limited to the remarketing of capacity purchased from
others, or sales that extend less than one year into the future. For types
of transactions where a stand-alone UE would not be a
<PAGE>
Exhibit No.__(RWF-1)
Page 70 of 100
potential seller, a merger of UE and CIPS of course does not remove an
independent seller from the market. The elimination of one firm that buys
and resells capacity should not create competitive concerns, because entry
into the resale business is relatively easy, and therefore many other
actual or potential suppliers remain. Moreover, even when we focus only
upon short term sales which extend less than one year into the future, a
type of sale for which a stand-alone UE presumably could compete, the
merged firm's share of uncommitted capacity in first tier markets falls
short of FERC's traditional threshold levels for determining whether there
is any potential concern about market power. Applicants' filing of a single
system transmission tariff including all of UE's and CIPS's direct
interconnections as potential receipt and delivery points reinforces the
conclusion that there is no merger-induced concern about market power in
short term capacity markets.
B. LONG TERM CAPACITY
------------------
Q. PLEASE REPEAT YOUR DESCRIPTION OF THE MARKET FOR LONG TERM CAPACITY.
A. The long term capacity market encompasses capacity sales which extend far
enough into the future that new capacity can be constructed to compete for
the sale. Thus, it includes both existing surpluses, where they are
sufficiently large and permanent to support long term sales, as well as
repowering of existing units and new capacity that might be constructed.
Potential suppliers include UE, CIPS, other in-region or adjacent regional
utilities and those who would construct Qualifying Facilities and other
nonutility generation.
<PAGE>
Exhibit No.__(RWF-1)
Page 71 of 100
Q. IS INFORMATION ABOUT MARKET SHARES LIKELY TO BE USEFUL IN ASSESSING THE
LIKELIHOOD THAT THE MERGED FIRM MIGHT EXERCISE MARKET POWER IN LONG TERM
CAPACITY MARKETS?
A. No. This is an industry where historically the largest suppliers have been
vertically integrated, meaning that they own generation, transmission and
distribution facilities. It is also an industry where exclusive retail
service territories predominate. Accordingly, aggregate measures, such as
shares of existing generating capability within a region held by particular
firms, are more likely to be indicative of the relative size of exclusive
retail service territories than suggestive of any one firm's ability to
compete in long term capacity markets. Moreover, what is important for
long term capacity markets is who will be constructing what new generating
capacity in the future. I know of no way to make reasonable projections on
this topic unless, not very usefully, we confine ourselves to projects that
are relatively advanced in their gestation process.
Q. HOW THEN WOULD YOU BEGIN THE PROCESS OF ASSESSING WHETHER A MERGER OF UE
AND CIPS IS LIKELY TO CREATE A FIRM THAT POSSESSES MARKET POWER IN A LONG
TERM CAPACITY MARKET?
A. As a practical matter, I would be suspicious about claims that any one
entity, however dominant its existing generation and transmission system,
possessed market power in such a long term market, unless the claim was
narrowly focused upon truly "transmission dependent" utilities that did not
have open access or other transmission services available to them. The
ability to undertake new construction, both of generation and transmission,
should mitigate a market power inference in most situations.
<PAGE>
Exhibit No. ___(RWF-1)
Page 72 of 100
The dramatic emergence of NUGs in recent years reinforces this view. In
recent years more than 50 percent of the new generation in this country has
come from NUGs, as opposed to traditional utility sources. Utility after
utility issuing RFPs for new capacity consistently has received offers that
far exceeded the supply blocks sought. This trend began before the passage
of the National Energy Policy Act of 1992 (NEPA), which includes provisions
about transmission access and Exempt Wholesale Generators and, obviously,
before FERC issued its transmission NOPR. NEPA and FERC's NOPR can only
reinforce this trend.
FERC has recognized that market power in long term bulk power markets is
unlikely (Kansas City Power & Light Company, 67 FERC (P)61,183, hereafter
KCPL) but still considered whether various entry barriers might be present.
Entry barriers could include: (i) control of transmission; (ii) control of
sites at which new generation might be constructed; (iii) control of fuel
supplies; or (iv) control of fuel transport facilities. Such entry
barriers, if present and significant, presumably could support an inference
that market power might be present in long term capacity markets.
The discussion in Section IV indicates that the merger of UE and CIPS will
not provide the merged firm with control over transmission which will
enable it to exercise market power. Most importantly, the proposed open
access transmission tariff will provide those interested in constructing
new generation capacity the certain knowledge that they can obtain cost-
based transmission service for long time periods under terms and conditions
found by
<PAGE>
Exhibit No.___(RWF-1)
Page 73 of 100
FERC to be appropriate. Combining two transmission systems under a single
transmission tariff, if anything, should facilitate entry by new
generators.
Mr. Moorman and Ms. Borkowski discuss the potential for control of sites at
which new generating capacity might be constructed. Mr. Moorman indicates
that, while CIPS has not had the need to examine site availability for many
years, several sites were available the last time such a study was required
but also, more generally, that the characteristics of its service territory
suggest the availability of numerous sites for those who would wish to
construct new capacity. Ms. Borkowski testifies that recent studies
performed by UE conclude there are many potential sites in Missouri at
which new generation might be constructed which are not controlled by UE.
Based upon this testimony, I conclude that UE and CIPS do not control sites
for new generation in their service territories such that they could block
entry by new competitors.
Mr. Pettit, Mr. Moorman, and Ms. Borkowski address fuel supply issues. Both
UE and CIPS operate local gas distribution systems, but Mr. Pettit
testifies that CIPS purchases greater than 99 percent of its gas supply and
that UE purchases 100 percent of its gas supply. The amount which is
provided from owned fields therefore is minuscule. Mr. Pettit further
testifies that a new generator that wished to purchase its gas supply from
UE's or CIPS's gas distribution system, rather than from a producer or
marketer, could do so, presumably at a negotiated discount rate. Mr.
Moorman testifies that the only fuel supplies which CIPS controls (other
than the gas used by its local distribution system) are either
<PAGE>
Exhibit No.___(RWF-1)
Page 74 of 100
those on site at its generating stations or those that have been contracted
for the purpose of fueling those stations. Ms. Borkowski testifies that UE
does not own or have a financial interest in any of the entities that
supply it with either coal or oil. Based upon this testimony, I conclude
that UE and CIPS do not own fuel supplies that could be used to block entry
by their would-be competitors.
Mr. Pettit, Mr. Moorman and Ms. Borkowski also address fuel transport. Mr.
Pettit testifies that new gas-fired generators would be able to receive
local transport service over the UE and CIPS local gas distribution systems
if they desired and capacity were available. Mr. Pettit also testifies that
there are six interstate pipelines which traverse CIPS's service territory
and four which traverse that of UE. Rather than receiving local
transportation from UE or CIPS, new gas-fired generators presumably could
locate in proximity to these pipelines and avoid entirely the need for
local transport. Mr. Moorman testifies that the only fuel transport
facilities which CIPS owns (other than its gas distribution system) are
rail cars which are used to bring coal to two of its generating stations
and tracks that are inside the boundaries of those stations. It does not
own any other rail, barge or trucking facilities. Ms. Borkowski provides
similar testimony concerning UE, i.e., that it owns rail cars used to
deliver coal to its generating stations and rail tracks at its generating
stations, but no other rail, truck or barge facilities used to transport
fuel to its generating stations. Ms. Borkowski also testifies that EEI,
through a subsidiary, owns rail cars and a three-mile rail spur that are
used just to deliver coal to the Joppa Plant. Based upon this testimony, I
<PAGE>
Exhibit No.___(RWF-1)
Page 75 of 100
conclude that UE and CIPS do not own fuel transport facilities that could
be used to thwart entry by new generating entities.
Q. YOUR DISCUSSION OF THE LONG TERM CAPACITY MARKET CONCERNS WHETHER THE
MERGED FIRM MIGHT BE ABLE TO EXERCISE MARKET POWER AS A SELLER OF LONG TERM
CAPACITY, AND CONCLUDES THAT IT COULD NOT. HAVE YOU SEPARATELY CONSIDERED
WHETHER THE MERGED FIRM COULD EXERCISE MARKET POWER AS A PURCHASER OF SUCH
CAPACITY?
A. Yes. Such a possibility seems very remote indeed. Even after the merger,
Ameren will account for only approximately 6.5 percent of total load in a
region defined to include it and all utilities interconnected with either
merging partner. Even if a potential supplier were forced to deal only in
this region, which seems unlikely, Ameren will comprise only a small
portion of total demand. Accordingly, those seeking to market long term
capacity readily could turn to other potential purchasers. Moreover, if the
merged entity sought to depress the price paid for output, most entities
considering construction of new capacity could relocate and deal with other
potential purchasers. This relocation, obviously, would have to occur
before significant site-specific investments had been made. Beyond this,
any residual fears that the merged entity might be able to exercise
monopsony power over would-be developers, for example those that for some
reason are limited in where they can locate, should be allayed by the open
access tariff which the merged firm is filing. The developers can market
their output to others if the merged firm seeks to depress price or impose
overly burdensome terms and conditions.
<PAGE>
Exhibit No.___(RWF-1)
Page 76 of 100
C. NONFIRM ENERGY
--------------
Q. PLEASE REPEAT YOUR DESCRIPTION OF THE MARKET FOR NONFIRM ENERGY.
A. Nonfirm energy encompasses a variety of closely substitutable interchange
transactions that generating utilities engage in principally to improve the
economics of dispatch. A buyer whose own capacity resources are sufficient
to accommodate its needs nevertheless may choose to purchase nonfirm energy
from another supplier, if that other supplier can provide energy to it at a
lower delivered price than the purchaser's own incremental generating cost.
Whether through ordinary bilateral transactions or more formalized broker
or power pool arrangements, virtually all generating utilities engage in
this type of transaction to some extent, sometimes as buyers and sometimes
as sellers. Actual or potential market participants also include marketers
who buy from one generating entity and sell to another.
Economy energy is the most recognizable type of nonfirm energy transaction
and frequently is provided under split savings pricing rules. Close
substitutes for economy energy are the replacement or substitute energy
transactions which utilities in some regions use, where prices are based
upon incremental cost plus a modest adder (e.g., 10 percent), and "term" or
"general purpose" energy transactions where "up to" prices provide
substantial flexibility for buyers and sellers to converge on market-level
prices. Also substitutable are very short term--daily, weekly, monthly, and
even seasonal--capacity plus energy transactions where the buyer does not
need additional capacity to meet its reliability goals but, through its
purchase, is able to obtain lower cost energy than that
<PAGE>
Exhibit No.___(RWF-1)
Page 77 of 100
which is available from its own generating units. The total purchase
price--a modest demand charge plus an incremental cost-based energy
charge--is less than the incremental generating costs which the buyer
would incur if it generated from its own units.
Q. ARE THERE SUBSTITUTE PRODUCTS FOR NONFIRM ENERGY?
A. Yes. Most obviously, any utility that is a buyer of nonfirm energy proper,
as distinguished from a short term capacity substitute, must have available
its own generating capability to draw upon if the nonfirm supply is
interrupted. This generation acts as an important force policing the prices
which those selling nonfirm energy may charge. Buyers retain the option to
generate from their own sources if sellers attempt to raise prices. Energy
taken from longer term purchases can serve precisely the same purpose. More
generally, as I described earlier, there is broad substitutability among
individual bulk power products in the sense that utilities may use varying
mixes of these products to develop the firm power product which they need
to sell to their customers.
Q. WHO ARE THE BUYERS AND SELLERS OF NONFIRM ENERGY?
A. Virtually all generating utilities participate as both buyers and sellers
in nonfirm energy markets. Whether they are sellers or buyers at a
particular point in time will depend upon relative costs, but can change as
a result of load level changes, outages and other factors. Some may be
predominately net sellers while others may be predominately net buyers. As
described above, both UE and CIPS purchase large amounts of energy to
support sales to others. UE tends to purchase heavily from entities located
to the north and west of it--e.g.,
<PAGE>
Exhibit No.___(RWF-1)
Page 78 of 100
NSP, MEC, KCPL--where coal generation costs are less. However, it also may
purchase from utilities located to the east (e.g., CIPS and IP) when
conditions dictate, such as when the 1993 floods restricted transportation
of coal to certain of its generating stations. UE sells large quantities to
EEI for resale by EEI to the USEC enrichment plant. It also sells large
quantities of energy to Entergy to displace gas fired generation on that
system and at times for resale by Entergy to other utilities. For these
sales, UE competes not only with other electricity suppliers but also with
those who sell gas to Entergy. During summer peaking conditions, however,
flows may reverse as it becomes economic to move gas fired generation from
south to north. UE then serves as a purchaser and, sometimes, reseller for
those transactions. In recent years, CIPS has purchased energy principally
from CE to the north and PSI/CINergy to the east. For sales its principal
customers have been EEI and TVA to the south and UE to the west.
Q. ARE UE AND CIPS ACTUAL OR POTENTIAL COMPETITORS FOR SALES OF NONFIRM
ENERGY?
A. Yes, but there also are many other competitors in the nonfirm markets in
which UE and CIPS sell.
Q. HOW HAVE YOU PROCEEDED TO ANALYZE THE EFFECTS OF THE MERGER ON NONFIRM
ENERGY MARKETS?
A. I have done two things. First, for the same first tier markets discussed
above, I have computed the merged firm's share of total generating
capacity. FERC in the past has used this "as a measure of capacity that may
be available for nonfirm and shorter term sales"
<PAGE>
Exhibit No. ___ RWF-1
p.79 of 100
(KCPL at page 61,556, line 11), although at the same time recognizing its
obvious defect of failing to incorporate native load demands before the
computations are made. Second, I have analyzed data on nonfirm and
substitutable energy or capacity and energy transactions during 1993 and
1994.
Q. PLEASE DESCRIBE YOUR ANALYSIS OF TOTAL GENERATING CAPACITY IN FIRST TIER
MARKETS.
A. The first tier markets and participants in them are the same as for the
analysis of uncommitted capacity in first tier markets discussed above.
The results are summarized in Exhibit ___ (RWF-14). Underlying data and
other material supporting this exhibit are contained in my workpapers. I
relied on the same raw data sources as I did for my computations reported
above concerning uncommitted capacity and treated CSW and TVA in the same
way. I define total generating capacity as owned capacity less, as
appropriate, the net of capacity purchases and sales. Exhibit ___ (RWF-14)
is formatted precisely the same as are Exhibits ___ (RWF-11) and ___ (RWF-
12). The utilities on whom each first tier market is centered are listed on
the left. Then, Columns (1) and (2) provide the premerger shares of UE and
CIPS, respectively, of total capacity in each first tier market. Columns
(3) and (4) provide the postmerger shares of Ameren, the former before the
effects of the open access tariff have been incorporated and the latter
after those effects have been incorporated.
Q. WHAT DO YOU CONCLUDE FROM EXHIBIT __ (RWF-14)?
<PAGE>
Exhibit No. ___ (RWF-1)
p.80 of 100
A. Exhibit ___ (RWF-14) indicates that, in all instances but one, the merged
firm's share of total generating capacity in first tier markets falls below
the 20 percent level which FERC has used in the past to determine whether
there is any possible concern about market power. Accordingly, we need not
consider these other markets further. The figure exceeds 20 percent only
for the first tier market centered on WR, where it is 25.4 percent.
Q. DOES THIS 25.4 PERCENT FIGURE FOR THE FIRST TIER MARKET CENTERED ON WR
SUGGEST POSSIBLE CONCERN ABOUT MERGER-INDUCED INCREASES IN MARKET POWER?
A. No. WR is interconnected with only one of the merging parties, and so the
merger does not take away any direct trading opportunities that were
available to it premerger. Second, when the first tier market centered on
WR is expanded to include entities accessible under open access tariffs of
other utilities connected to WR, as it should be for reasons discussed
above, Ameren's share drops below 20 percent. When the first tier market
centered on WR is expanded to include entities accessible under the open
access tariffs of CSW and KCPL, both of which are directly interconnected
with WR, the merged firm's share drops to 12.2 percent. This result is
shown in Exhibit ___ (RWF-15). Accordingly, when properly computed, the
merged firm's share of total capacity in all first tier markets falls below
FERC's 20 percent threshold.
Q. PLEASE DESCRIBE YOUR ANALYSIS OF NONFIRM AND SUBSTITUTABLE ENERGY OR
CAPACITY AND ENERGY SALES DURING 1993 AND 1994.
<PAGE>
Exhibit No. ___ (RWF-1)
page 81 of 100
A. I have used publicly available data (i.e., Form 1 or equivalent) on nonfirm
energy (and substitute short term capacity and energy) sales by UE, CIPS
and interconnected utilities to develop market shares and HHIs concerning
the merging partners and the effects of the proposed merger.
Q. WHAT GEOGRAPHIC MARKET DID YOU EXAMINE FOR NONFIRM ENERGY SALES?
A. Just as it is difficult to draw clean boundaries between products which
should and should not be included in a relevant product market, it likewise
can be difficult to determine precise and unambiguous geographic market
bounds. For example, through displacement, energy can move relatively long
distances. One utility may buy nonfirm energy from suppliers located to the
north of its system and resell it to the south, to other utilities who may
do much the same thing, i.e., buy in the north and sell in the south, etc.
Prices for nonfirm energy may tend to move in the same direction over very
broad areas, which could suggest that a broad relevant geographic market
definition ought to be employed. The approach which I have employed uses a
relatively narrow geographic market--UE, CIPS and their first tier
utilities--as a screening device. If it can be shown that the merger
presents no market power concerns under such a narrow geographic market
definition, it obviously follows that the merger would not present market
power concerns if the market were defined more broadly to include
additional participants such as described in Mr. Moorman's and Ms.
Borkowski's testimony.
Q. PLEASE DESCRIBE THE RESULTS OF YOUR ANALYSIS.
<PAGE>
Exhibit No. ___ (RWF-1)
page 82 of 100
A. The results are shown in Exhibit ___ (RWF-16) and ___ (RWF-17), each of
which is formatted in the same way. The former pertains to 1993, while the
latter pertains to 1994. Column (1) identifies the seller, Column (2) lists
the sales of nonfirm energy or closely substitutable products, in
gigawatthours, made by each seller in 1993 or 1994 as appropriate, and
Column (3) converts those gigawatthour figures into shares of the total
sales made by all first tier utilities. Column (4) squares the market
shares as is required for the HHI computation. The Column (4) figures sum
to provide the premerger HHI. At the bottom I show the HHI increase
resulting from the merger as well as the postmerger HHI. Mathematically the
merger-induced HHI increase is equal to two times the premerger UE percent
times the premerger CIPS percent. Thus, in Exhibit ___ (RWF-16), UE's
premerger percent is 8.5 while that for CIPS is 6.2 percent. This converts
to a merger-induced HHI increase of 105, i.e., 8.5 x 6.2 x 2 = 105. As can
be seen, for both years studied the postmerger HHI is less than 1,000,
portraying a market that is unconcentrated under the Merger Guidelines. As
indicated previously, mergers in unconcentrated markets "ordinarily require
no further analysis" under the Merger Guidelines. I also note that for both
years the combined shares of the two firms--14.7 percent in 1993 and 15.7
percent in 1994--fall below threshold levels for concern for single firm
market shares.
Q. WHAT DATA HAVE YOU USED IN THE COMPILATION OF EXHIBITS ___ (RWF-16) AND
___ (RWF-17)?
A. I used data filed by the utilities in their Form 1 (or equivalent) annual
reports. The compilations include all items from the raw data sources
except those that clearly do not
<PAGE>
Exhibit No. ___ (RWF-1)
page 83 of 100
represent nonfirm or closely substitutable transactions, e.g., those which
are labeled as requirements sales, long term unit sales, or long term or
intermediate term firm sales. Where one utility is shown as making a sale
to another, I include only data on the transaction from the seller's annual
report or the buyer's annual report, but not from both. In this regard, I
use the expression transaction cautiously, recognizing that the raw data
will record as one single annual transaction a number of different sales or
purchases that occurred at different times and prices throughout each one-
year reporting period.
Q. DO YOU HAVE ANY ADDITIONAL COMMENTS ON THE ANALYSES CONTAINED IN EXHIBITS
___ (RWF-16) AND ___ (RWF-17)?
A. Yes. While the analyses contained in these two exhibits do not indicate any
merger-induced concern about market power in nonfirm energy markets, they
nevertheless contain data which significantly overstates the importance of
both UE and CIPS in these markets. Were the data appropriately adjusted,
the influence of UE and CIPS would be far less than shown in these two
exhibits. Accordingly, the merger-induced HHI increase also would be less.
Q. PLEASE EXPLAIN.
A. As I indicated earlier, most of the nonfirm energy sales of both UE and
CIPS are supported by energy simultaneously purchased from others. With
such transactions UE and CIPS in effect bundle transmission services along
with risk-bearing and aggregation services. While such transactions are
important, including them in Exhibits ___ (RWF-16) and ___
<PAGE>
Exhibit No.___(RWF-1)
page 84 of 100
(RWF-17) has the effect of overstating both the total market size as well
as, more importantly for the analyses here, the individual shares of UE and
CIPS. In effect, there is a double count, because the transactions are
included both as a sale from another supplier to UE or CIPS, and then also
as a sale from UE or CIPS to another purchaser. More properly these
transactions ought to be included only once. This double count causes the
size of the total market to be overstated. Moreover, the individual shares
of both UE and CIPS also are overstated. The purpose of the analyses here
is to address principally whether the merger might create an inordinate
concentration of generation such that market power might be exercised.
Accordingly, we should seek to attribute these transactions to the parties
whose generation was used, and not to UE or CIPS which served in
"middleman" roles.
Q. PLEASE PROVIDE AN EXAMPLE.
A. Assume that during a particular hour CE sells 500 megawatts to CIPS which
CIPS in turn resells to EEI. The development of Exhibits ___ (RWF-16) and
___ (RWF-17) will have considered this as both a sale by CE and a sale by
CIPS. Accordingly, transactions totaling 1,000 megawatts will be used in
determining total market size, and 500 megawatts of sales will be
attributed to each of CE and CIPS. A more realistic view is that there has
been only a single transaction of 500 megawatts for which CE is the seller
and EEI is the buyer. CIPS has functioned principally as a middleman,
providing transmission and risk-bearing services, but not as either a
generator or consumer of the 500 megawatts.
<PAGE>
Exhibit No.__(RWF-1)
Page 85 of 100
Q. DOES THIS DEFICIENCY ALSO AFFECT THE DATA FOR UTILITIES INCLUDED IN YOUR
ANALYSES OTHER THAN UE AND CIPS?
A. Yes. However, the raw data used in preparing Exhibits ___ (RWF-17) and ___
(RWF-18) do not contain a means to identify and therefore eliminate
simultaneous buy-and-resale transactions. It is possible to infer,
however, that for most utilities included in my analyses these types of
transactions will be much less significant than they are for UE and CIPS or
that, if they are significant, it still would be wrong to seek to eliminate
them. Some of the utilities included in the analysis actually purchase
relatively little energy from others. And so while there may not be
publicly available data which tags specific purchase-for-resell
transactions, by logic the amount cannot be large. Some of the utilities
included in the analysis are not as well situated between selling and
buying utilities as are UE and CIPS, and so transmission across their
systems, in the form of simultaneous buy-and-resell transactions, is not as
desirable. Other utilities are located at the periphery of the region
collectively encompassed by the utilities included in Exhibits ___ (RWF-16)
and ___ (RWF-17). While they may engage in frequent buy-and-resell
transactions, the utilities from whom they buy are not likely to be
included in the market as it has been defined for these exhibits, i.e., UE,
CIPS and their first tier utilities. Accordingly, their buy-and-resell
transactions do not represent a double count of transactions already
included as another utility's sales. Were these transactions to be
eliminated as sales by the intermediate buying-and-reselling utility, they
would inappropriately disappear from the computations entirely.
<PAGE>
Exhibit No.__(RWF-1)
Page 86 of 100
Q. PLEASE PROVIDE AN EXAMPLE.
A. In testimony filed in support of its application to merge with Wisconsin
Electric Power Company, NSP states that it purchases energy from utilities
to the north and west of it to support energy sales to utilities to the
south and east of it. Its largest energy suppliers in recent years have
been MH and the Basin Electric Power Cooperative (Basin), and the largest
purchaser from it has been UE. Neither MH nor Basin is included among the
suppliers identified in Exhibits ___ (RWF-16) and ___ (RWF-17).
Accordingly, if we were to eliminate purchase-and-resell transactions from
NSP's sales--if we had the ability to do this, which we do not--we would
have improperly removed them from the computations entirely.
Q. ARE THERE ANY OTHER UTILITIES INCLUDED IN EXHIBITS ___ (RWF-16) AND ___
(RWF-17) THAT DO ENGAGE IN BUY-AND-RESELL TRANSACTIONS THAT COULD REPRESENT
A SIGNIFICANT DOUBLE COUNT IN THESE TWO EXHIBITS?
A.. I do not have data to address this question directly. However, it is
possible to make some reasonable inferences. AEC's Form 1 equivalents
report relatively large purchases from MAPP utilities to the north and from
KCPL in the SPP. They also report relatively large sales to Entergy to the
south. UE also has interconnections with KCPL and MAPP utilities, as well
as Entergy, and makes purchases from KCPL and the MAPP utilities to support
its sales to Entergy. Having interconnections that are similar in this
respect, it would not be at all unreasonable to infer that AEC uses
purchases to support its interchange sales in a fashion that is similar to
what UE does. Likewise, IP is interconnected with both CE and
<PAGE>
Exhibit No.__(RWF-1)
Page 87 of 100
EEI, and its Form 1s report relatively large purchases of energy from CE
and relatively large sales to both TVA and EEI. It is probably reasonable
to infer that, just as does CIPS, IP purchases energy from CE for
simultaneous resale to EEI and TVA.
Q. DO YOU HAVE ANY ADDITIONAL COMMENTS ON EXHIBITS ___ (RWF-16) AND ___ (RWF-
17)?
A. Yes. There is another reason that these exhibits overstate any market power
concerns that otherwise might be suggested by the merger. The data used to
derive these exhibits reflect only transactions that actually occurred and
not alternatives that buyers might have available to defeat any merger-
created ability to raise nonfirm energy prices. These alternatives include
both energy supplied from the buyer's own generation as well as energy that
might have been, but was not, purchased from another supplier. However, if
the merged firm sought to raise price, buyers by definition could turn to
their own generation alternatives in an attempt to counter that would-be
price increase. They also presumably could turn to other suppliers. I
also note that, because the data are historical, they do not reflect any
competition enhancing effects that flow from Ameren's proposed open access
transmission tariffs or those filed late last year by MEC. To the extent
that these tariffs broaden the scope of the appropriate geographic markets
and/or increase the number of participants in those markets, it necessarily
follows that historical concentration data overstate the likely effects of
the merger.
<PAGE>
Exhibit No.__(RWF-1)
Page 88 of 100
Q. EARLIER YOU STATED THAT MERGERS COULD RAISE MARKET POWER CONCERNS IF THEY
FACILITATED COLLUSION AMONG SELLERS. IS SUCH COLLUSION AMONG SELLERS
LIKELY IN NONFIRM ENERGY MARKETS?
A. No. One reason is that this is an industry where all market participants
are likely to be very well informed about both demand levels and the
various features (fuel prices, heat rates, major outages) which determine
sellers' costs. They ought to be able to estimate relatively accurately
what the market-clearing price for nonfirm energy is likely to be, and
therefore determine whether the price which suppliers seek from them is
greater than that level. This can help determine whether collusion is
present. A second reason is that, depending upon various conditions,
individual entities are likely to participate in the market both as buyers
and sellers. There is less incentive to participate in a price increasing
conspiracy as a seller if the increased prices work to your disadvantage at
times when you are a buyer.
Q. HAVE YOU ALSO CONSIDERED WHETHER THE MERGER OF UE AND CIPS IS LIKELY TO
CREATE CONCERNS ABOUT MONOPSONY POWER IN NONFIRM ENERGY MARKETS?
A. Yes. The same common sense considerations mentioned earlier suggest that a
merger between UE and CIPS is unlikely to present concerns about monopsony
power in nonfirm energy markets. The merging parties represent only a
small percentage of potential demand in the region of which they are a
part. Moreover, with so many other possible buying entities within the
region and the availability of transmission service under the merged firm's
open access tariff--and the open access tariffs of several other directly
interconnected utilities--would-be energy sellers need not rely upon making
sales just to
<PAGE>
Exhibit No.__(RWF-1)
Page 89 of 100
the merged entity. Hypothetically, if the merged entity seeks to restrict
purchases and reduce the price that it pays for energy, the aggrieved
would-be sellers can simply market their energy elsewhere. They have
numerous opportunities to do so. In such circumstances, it is implausible
that buyer market power concerns will be present with a merger between UE
and CIPS.
Q. PLEASE SUMMARIZE YOUR CONCLUSIONS ABOUT THE EFFECTS OF THE MERGER ON
NONFIRM ENERGY MARKETS.
A. A merger of UE and CIPS should not present concerns about the exercise of
market power in regional nonfirm energy markets. Both UE and CIPS are
active participants in these markets, both as buyers and sellers, and so
the merger necessarily will reduce the number of participants by one.
However, many other participants still will remain in these markets, both
as buyers and sellers. Moreover, even when the geographic scope of the
market is defined relatively narrowly to include only UE and CIPS and their
first tier utilities, aggregate measures of historical transactions and
total generating capacity fall below threshold levels for concern about
market power. Residual concerns about market power should be mitigated by
the open access transmission tariff that Applicants are filing, as well as
the open access transmission tariffs that several other regional utilities
have filed in recent years. Concern that the merged entity might be able
to exercise buyer market power in nonfirm energy markets should be
mitigated by the large number of potential buying utilities in the region,
the several open access transmission tariffs now on file, and the merged
firm's relatively small share of total demand in the region.
<PAGE>
Exhibit No.__(RWF-1)
Page 90 of 100
D. OTHER CONSIDERATIONS
Q. ARE THERE ANY ADDITIONAL TOPICS THAT YOU WISH TO ADDRESS CONCERNING WHETHER
A MERGER OF UE AND CIPS IS LIKELY TO CREATE MARKET POWER IN REGIONAL BULK
POWER MARKETS?
A. Yes. Various information presented above, relating to interconnections and
market share and concentration indexes derived from historical or
contemporaneous data, suggest that this is not a merger that presents
competitive concerns for wholesale bulk power markets. I believe that this
is a conclusion that can only be reinforced by certain of the changes that
now are underway in the industry, e.g., opening up of transmission systems
under open access transmission tariffs, proliferation of NUGs and
competitive bidding systems, and the potentially increasing role of
marketers. Indeed, as I have indicated, the merger actually presents an
opportunity for enhancement of wholesale bulk power market competition
because of the concomitant filing of the consolidated (one system)
transmission tariff. This expands the pool of utilities accessible for a
single transmission charge. While short term and nonfirm markets may
become more competitive as a result, a more important implication
ultimately may be easier entry for those who would construct new generation
capacity. Most of the NUG capacity that has come on-line in this country
to date has been contracted to a single buyer under a long term
arrangement. By increasing the pool of potential buyers and therefore
decreasing market risk, the consolidated open access tariff may make it
more likely that NUGs are constructed whose output is not entirely under
contract, i.e., what are sometimes referred to as "merchant" plants. This
can expand the role of the market in decisions about constructing new
capacity. When NUG capacity is
<PAGE>
Exhibit No.__(RWF-1)
Page 91 of 100
constructed as a result of a utility's RFP process, it is a centralized
utility (with regulatory oversight) planning process that will have
determined the timing and amount of such capacity, and probably influenced
other characteristics as well such as fuel type, location and technology.
When merchant plants are constructed, it is the marketplace rather than a
central planning process that will have determined their attributes.
Q. SEVERAL OTHER ELECTRIC UTILITY MERGERS HAVE OCCURRED OR BEEN ANNOUNCED
RECENTLY. DOES YOUR ANALYSIS INCORPORATE TRENDS TOWARD INCREASING
COMPETITION IN THE INDUSTRY?
A. Several mergers already have taken place among utilities interconnected
with Applicants. These include the merger of Iowa Power Inc. and Iowa
Public Service Company to form MPSI; the merger of MPSI and IIGE to form
MEC; the merger of Iowa Southern Utilities and Iowa Electric Light & Power
into IES; the merger of KG&E and Kansas Power and Light Company to form WR;
the merger of Entergy and Gulf States Utilities; and the merger of PSI and
Cincinnati Gas & Electric to form CINergy. My analyses--concerning number
of interconnections, uncommitted and total capacity and nonfirm energy
transactions--reflect all of these consolidations which have already taken
place and conclude that a merger between UE and CIPS does not present
significant competitive concerns. Moreover, as indicated, I believe that
many changes now underway in the industry, whose effects do not fully
manifest themselves in my analyses, can only reinforce such a conclusion.
However, I have not sought to incorporate the effects of mergers which
might take place in the future, nor do I believe that it is possible or
appropriate to do so. It is not possible to do so because I do not know
what mergers might take place in the future.
<PAGE>
Exhibit No.__(RWF-1)
Page 92 of 100
Properly assessing the effects of any merger requires an analysis of the
specific facts which such merger presents and is not something that can be
done on a generic basis absent reference to those facts. Moreover, it is
not appropriate to seek to incorporate the effects of mergers which may
occur in the future, because of the very significant risk that an attempt
to speculate on what conditions might arise in the future will cause
benefits that might be available now, from this merger, to be sacrificed
because of future harms which may or may not arise. Far better, I think, is
to assess this merger now on its merits, and then to assess any mergers
that may in the future be proposed on their merits as perceived at the time
they are proposed. Market power concerns which then are believed to be
present can be addressed at the time those future mergers are proposed. If
significant market power concerns are believed to be present, those future
mergers can be conditioned as appropriate or rejected. But we need not
speculate now on the extent to which such concerns then may be present or
how any such presence should affect the review of this merger.
VI. RETAIL COMPETITION ISSUES
Q. HAVE YOU SOUGHT TO EXAMINE WHETHER THE PROPOSED MERGER WILL CREATE OR
ENHANCE MARKET POWER FOR SALES OF ELECTRICITY TO RETAIL CUSTOMERS?
A. Yes.
Q. PLEASE DESCRIBE THAT EXAMINATION.
<PAGE>
Page 93 of 100
A. There generally are four types of retail electric competition which can be
hypothesized to exist--franchise competition, yardstick competition,
locational or customer competition, and fringe area competition. I have
examined each individually and concluded that the merger is not likely to
affect the prospects for such competition significantly. As a threshold
matter, the rates charged by UE (in Missouri and Illinois premerger and in
Missouri postmerger) and CIPS (in Illinois) are constrained by state
regulators. By itself this should greatly reduce any fear that a merger of
UE and CIPS will create or enhance market power in retail markets for
electricity.
Q. WHAT IS FRANCHISE COMPETITION?
A. Franchise competition is competition for the right to be the exclusive
electric supplier within a predefined area.
Q. WILL A MERGER OF UE AND CIPS SIGNIFICANTLY AFFECT PROSPECTS FOR FRANCHISE
COMPETITION?
A. No. Instances of franchise competition usually involve an existing or
potential municipal distribution system and a nearby investor-owned
utility, and so it is almost definitional that the merger of two vertically
integrated investor-owned utilities will not significantly affect the
prospects for it. Any franchise competition that, but for the merger, would
take place between UE or CIPS and an actual or potential municipal
distribution system, still can take place postmerger between that actual or
potential municipal distribution system and the merged entity.
<PAGE>
Page 94 of 100
Q. WHAT IS YARDSTICK COMPETITION?
A. Yardstick competition usually refers to a striving by utilities to rank
more favorably in comparative evaluations (of rates, costs or other
performance measures) made by their regulators.
Q. WILL A MERGER OF UE AND CIPS SIGNIFICANTLY AFFECT PROSPECTS FOR YARDSTICK
COMPETITION?
A. No. Because both UE and CIPS provide retail service in Illinois, the merger
in principle might reduce the prospects for yardstick competition in
Illinois if it were true that Illinois's regulators were able to use only
Illinois utilities in any yardstick or performance comparisons that they
wanted to make. This is because the merger will reduce the number of
vertically integrated IOUs selling electricity in Illinois. (No similar
concerns would be faced by Missouri regulators because only UE, and not
CIPS, provides service at retail in Missouri.) However, this does not
appear to present a significant problem. The electric utility industry can
be distinguished by the wide array of data on costs, price and operations
which is available publicly. Accordingly, regulators seeking to make
yardstick comparisons need not be confined to a sample that includes only
utilities under their jurisdiction but can include utilities nationwide if
they so desire. Indeed, such larger samples generally will produce more
meaningful performance comparisons anyway. Because the universe of
utilities available for comparative purposes is so large, the merger
<PAGE>
Page 95 of 100
of two, even if they both serve in a single state, does not significantly
affect the scope of useful comparisons which can be made.
Q. WHAT IS LOCATIONAL OR CUSTOMER COMPETITION?
A. Locational or customer competition usually refers to efforts by electric
suppliers to keep their prices low so they can induce relatively large
electricity consumers to locate or expand operations in their service
territory as opposed to the service territory of another supplier.
Q. WILL A MERGER BETWEEN UE AND CIPS SIGNIFICANTLY AFFECT PROSPECTS FOR
LOCATIONAL COMPETITION?
A. No. By logic, locational competition can be significant only for the
relatively small grouping of customers whose electricity purchases comprise
a relatively high percentage of their total costs. But where electric costs
are important, customers have the incentive to shop over relatively broad
areas, in some cases nationwide and beyond. Area development professionals
at both UE and CIPS recognize that in most cases energy costs, including
natural gas, are a relatively insignificant locational determinant. They
also recognize that an individual "prospect's" alternatives to locating in
their service territory will vary from case to case but, where they are
known, are likely to encompass broad multistate regions. The merger of two
IOUs within such broad areas should not significantly reduce prospects for
locational competition.
<PAGE>
Page 96 of 100
Q. WHAT IS FRINGE AREA COMPETITION?
A. Fringe area competition refers to competition to serve individual customers
located near the boundaries of the service territories of more than one
supplier.
Q. WILL A MERGER OF UE AND CIPS SIGNIFICANTLY AFFECT PROSPECTS FOR FRINGE
COMPETITION?
A. No. Because the retail service territories of most electric suppliers tend
to be well defined and exclusive, customers located at a particular site
generally do not have a choice of suppliers. As a result, this form of
retail competition usually is not significant in this country. More
particularly as concerns this merger, the retail electric service
territories of CIPS and UE for the most part do not abut, and so there is
little prospect for fringe area competition between the two anyway. The
limited area where they do abut, near the town of Grafton, Illinois, is
rural in nature, and it is my understanding that there are no existing
electricity customers in this area which have the option of selecting
between service by UE and CIPS. Of course, any fringe area competition that
might exist between either of the two and a cooperative or municipal system
still could take place after the merger occurs.
Q. WILL THE MERGER OF UE AND CIPS AFFECT INTERFUEL COMPETITION BETWEEN GAS AND
ELECTRICITY AT THE RETAIL LEVEL?
A. Both UE and CIPS provide both gas and electricity at retail. It is my
understanding that there is no overlap between the area where UE sells
electricity at retail and the area where CIPS sells electricity at retail,
and no overlap between the area where UE sells gas at retail and the area
where CIPS sells gas at retail. Accordingly, the merger will not eliminate
<PAGE>
Page 97 of 100
direct electricity versus electricity nor gas versus gas competition
between the two. However, it is also my understanding that there are
several communities in and around Grafton, Illinois, with approximately 900
customers in total, where CIPS sells electricity at retail and UE sells gas
at retail. As part of the merger transaction, these retail gas customers of
UE will become retail gas customers of CIPS. In theory, therefore, the
merger will eliminate the opportunity that these customers have to select
between alternative suppliers for applications where natural gas and
electricity are competitive. Because of the small number of such
customers--there are only 900 such customers, whereas the two companies
together have more than 1,700,000 gas and electric customers--and
the regulatory protections which exist concerning supply to them, this
merger-induced reduction in possible competition seems insignificant.
VII. VERTICAL ISSUES
Q. ARE THERE ANY SIGNIFICANT VERTICAL CONCERNS PRESENTED BY THE PROPOSED
MERGER?
A. No.
Q. PLEASE EXPLAIN.
A. Principal areas for concern about potential vertical-related effects of a
merger of electric utilities appear to relate to any ability that might be
present for the merged firm to favor itself or its affiliates in the terms
and conditions on which access to key inputs is granted, where such
favorable access terms might harm its competitors. Of course, by logic, for
this
<PAGE>
Page 98 of 100
to represent a merger-induced concern, it must be one that is created or
enhanced as a result of the merger and not something which existed
previously. In any case, the possibility for such favoritism does not
appear to be present here.
As indicated, concurrently with their merger application, Applicants are
filing open access transmission tariffs designed to comply with FERC's
requirements as set forth in its transmission NOPR. While I believe that
wholesale bulk power markets in the region are competitive and will remain
so postmerger, as discussed above, the functional unbundling requirement
contained in the NOPR and Applicants' tariffs should go a long way toward
assuaging residual fears that the merged entity will be able to use its
transmission ownership to exercise market power in these markets. I am
aware, of course, that some industry observers believe that competitive
concerns are inherent in the vertically integrated structure which
predominates in the industry today, where generation and transmission are
combined under common ownership. These observers would impose more radical
solutions to the competitive problems which they perceive than the "mere"
functional unbundling requirement that is contained in FERC's NOPR,
including "corporate unbundling" or the creation of "independent system
operators" that would dispatch generation assets and control access to
transmission. Whatever the merits of such arguments, however, I do not
believe that they either relate to, or will be altered as a result of, a
merger of UE and CIPS. A merger of UE and CIPS is not a merger which
creates or exacerbates competitive problems in wholesale bulk power
markets, and those who wish to propose radical structural changes for the
industry must look beyond the facts presented by
<PAGE>
Page 99 of 100
this merger to find support for their positions. If it is desirable to
restructure the industry in the fashion which some suggest, that will be
true whether or not CIPS and UE merge. Moreover, if such restructurings are
not desirable in the absence of a merger between UE and CIPS, they will not
become desirable just because the merger occurs.
Because both Applicants own natural gas distribution systems, a potential
concern could arise that they will provide gas sales or gas transport
services for their own electric generation facilities or those of their
affiliates on more favorable terms than for electric generation facilities
of their competitors, and that the merger might enhance their ability to do
so or increase the benefits realizable from such actions. Because CIPS does
not generate any electricity from gas, and because UE generates only a very
limited amount, this concern, if valid at all, would apply principally to
future generation capacity. In any case, the concern seems misplaced for a
merger between UE and CIPS. As discussed in Mr. Pettit's testimony, it is
not likely that competing generators would seek to buy gas directly from UE
or CIPS, but in any case the maximum rates which UE and CIPS can charge are
set by state regulators. As also discussed in Mr. Pettit's testimony, there
are six interstate natural gas pipelines that run through CIPS's territory
and four that run through UE's territory. A developer wishing to construct
a new gas-fired power plant presumably would seek to locate in proximity to
one (or more) of these pipelines, thus avoiding costs for transporting gas
across CIPS's or UE's distribution system. Moreover, even if it wished to
connect directly to the UE or CIPS distribution system rather than one of
the interstate pipelines, it could receive local transport service because
regulators in both Illinois and
<PAGE>
Page 100 of 100
Missouri require the provision of open access transmission service. It does
not appear possible, therefore, that the merged firm will be able to block
supply or transport of natural gas to its would-be competitors and thereby
favor any of its own yet-to-be-constructed natural gas generators.
Q. HAVE YOU CONSIDERED WHETHER THERE ARE OTHER BUSINESS INTERESTS OF EITHER UE
OR CIPSCO THAT COULD CREATE MARKET POWER CONCERNS AS A RESULT OF THE
MERGER?
A. Other business interests of UE are identified in Mr. Rainwater's testimony.
Other business interests of CIPS are identified in Mr. Koertner's
testimony. For UE these business interests include EEI and Union Electric
Development Corporation (UEDC). For CIPSCO they include EEI and CIPSCO
Investment Company. I have already discussed EEI. Mr. Rainwater indicates
that UEDC owns civic-related projects in the UE service area. It is not
apparent to me how ownership of civic-related projects could create
concerns about market power resulting from the merger. Mr. Koertner
describes CIPSCO Investment Company as a company that manages nonutility
investments including leveraged leases, marketable securities and energy
projects. It is my understanding that some of these investments involve
interests in electric generating projects, but also that in all cases
CIPSCO is a passive investor with no ability to make decisions affecting
the level or dispatch of the project's output. I do not believe that these
investment activities suggest potential competitive concerns arising from
the merger of UE and CIPS.
Q. DOES THIS CONCLUDE YOUR TESTIMONY?
A. Yes.
<PAGE>
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL REGULATORY COMMISSION
DISTRICT OF COLUMBIA ) SS.
Central Illinois Public Service Company
Union Electric Company ) Docket No. ER96-____-000
AFFIDAVIT OF RODNEY FRAME
I, Rodney Frame, being duly sworn, depose and say that the statements
contained in the Prepared Testimony of Rodney Frame on behalf of Union Electric
Company and Central Illinois Public Service Company in this proceeding are true
and correct to the best of my knowledge, information and belief, and I hereby
adopt said testimony as if given by me in formal hearing, under oath.
Signed this 22nd day of December, 1995
/s/ Rodney Frame
--------------------------------
Rodney Frame
SUBSCRIBED AND SWORN to before me this 22nd day of December, 1995
/s/ Rosalind Brown
- ---------------------
Notary Public
My Commission Expires:
September 30, 1999
- ---------------------
<PAGE>
<TABLE>
<CAPTION>
TABLE OF EXHIBITS
<S> <C>
Exhibit No. __ (RWF-1)..............................Prepared Direct Testimony of Rodney Frame
Exhibit No. __ (RWF-2).................................................Resume of Rodney Frame
Exhibit No. __ (RWF-3)..................................................List of Abbreviations
Exhibit No. __ (RWF-4)........................................Interconnections of UE and CIPS
Exhibit No. __ (RWF-5)................................Postmerger Interconnections of Entities
Interconnected with Both UE and CIPS
Exhibit No. __ (RWF-6)..........................Interchange Sales and Purchases for Utilities
Interconnected with Both UE and CIPS 1991-1994
Exhibit No. __ (RWF-7)..........Uncommitted Capacity of UE, CIPS and Interconnected Utilities
18% Reserve Margin for UE and CIPS
Exhibit No. __ (RWF-8)..........Uncommitted Capacity of UE, CIPS and Interconnected Utilities
15% Reserve Margin for UE and CIPS
Exhibit No. __ (RWF-9)...................................................First Tier Utilities
Exhibit No. __ (RWF-10).....................................First Tier Market Centered on AEC
Exhibit No. __ (RWF-11)..........Ameren's Share of Uncommitted Capacity in First Tier Markets
18% Reserve Margin 1996
Exhibit No. __ (RWF-12)..........Ameren's Share of Uncommitted Capacity in First Tier Markets
15% Reserve Margin 1996
Exhibit No. __ (RWF-13).............................Defining First Tier Markets Symmetrically
Exhibit No. __ (RWF-14)................Ameren's Share of Total Capacity in First Tier Markets
Exhibit No. __ (RWF-15).....................Total Capacity in One Wheel Market Centered on WR
Exhibit No. __ (RWF-16).........Nonfirm Energy Sales by UE, CIPS and Interconnected Utilities
All Transactions - 1993
Exhibit No. __ (RWF-17).........Nonfirm Energy Sales by UE, CIPS and Interconnected Utilities
All Transactions - 1994
</TABLE>
<PAGE>
Exhibit No. ___ (RWF-2)
Page 1 of 9
RODNEY FRAME
National Economic Research Associates, Inc.
1800 M Street, N.W.
Suite 600 South
Washington, D.C. 20036
(202) 466-3510
Mr. Frame graduated from George Washington University and pursued graduate
work there under a National Science Foundation Traineeship. His areas of
specialization were public finance and urban economics. He completed all
requirements for his Ph.D. degree with the exception of the thesis.
Before joining NERA, he was a senior economist at Transcomm, Inc., where he
directed a number of projects concerning market structure and ratemaking in the
telecommunications industry, competition among electric utilities, and postal
ratemaking.
At NERA he has consulted with electric utility clients on a variety of
matters including retail competition, bulk power markets and competition,
transmission access and pricing, partial requirements ratemaking, contractual
terms for wholesale service, contracting for nonutility generation and retail
wheeling. A substantial portion of the work has been in conjunction with
litigated antitrust and Federal Energy Regulatory Commission proceedings. Much
of his recent work has involved transmission access and pricing issues, topics
on which he currently advises several investor-owned utilities.
Mr. Frame frequently speaks before electric industry groups on competition-
related topics. He has testified in federal and local courts, before federal
and state regulatory commissions, and before the Commerce Commission of New
Zealand.
<PAGE>
Exhibit No. ___ (RWF-2)
Page 2 of 9
EDUCATION:
George Washington University
B.B.A. 1970
George Washington University
Completed all requirements for Ph.D. in economics except thesis,
1970-1973
EMPLOYMENT:
1990- National Economic Research Associates, Inc.
Vice President. Has participated in projects dealing with retail
competition between utilities, bulk power markets, electric utility
mergers, transmission access and pricing, partial requirements
ratemaking, contractual terms for wholesale service, bidding for new
capacity (including that supplied by conservation), least-cost
planning and retail wheeling. Principal clients have been investor-
owned electric utilities. Has testified in federal and local courts,
before federal and state regulatory commissions and before the
Commerce Commission of New Zealand and has spoken before various
industry and client study groups.
1984-1989 Senior Consultant.
1975-1984 Transcomm, Inc.
Senior Economist. Worked on a variety of projects concerning market
structure, pricing and cost development in regulated industries.
Clients included the U.S. Departments of Commerce, Defense and Energy,
the Nuclear Regulatory Commission, the State of Oregon, bulk mailers
and various communications equipment manufacturers and service
providers. Participated in numerous federal and state regulatory
proceedings and was principal investigator for a multi-year Department
of Energy study addressing various aspects of electric utility
competition.
1974-1975 Independent Economic Consultant
Advised telephone equipment manufacturers concerning cost and rate
development for competitive telephone offerings, analyzed alternative
travel agent compensation arrangements and examined nonbank activity
by bank holding company firms.
1973-1974 Program of Policy Studies in Science and Technology
Research Staff.
1973 Urban Institute
Research Staff.
<PAGE>
Exhibit No. ___ (RWF-2)
Page 3 of 9
SELECTED REPORTS AND SPEECHES
"Moving From Here to There: Some Implications for Electric Transmission," speech
presented to the Infocast Power Industry Forum, Palm Springs, California,
February 17, 1995.
"What Does 'Comparability' Really Mean?," speech presented to The Federal Energy
Bar Association, Washington, D.C., November 17, 1994.
"Recent Developments in North American Electric Generation Capacity Procurement
Systems," with Mahim Chellappa, prepared for ElectricitJ de France (EDF), Paris,
France, August 1994.
"Current Transmission Topics" and "Trans Alta's Unbundled Rate Proposal,"
presented to the Canadian Electrical Association, Montreal, PQ, Canada, May 9,
1994.
"Retail Wheeling Issues," speech presented to the Edison Electric Institute
National Accounts Workshop, Atlanta, Georgia, February 7, 1994.
"Retail Wheeling: Doing It the Right Way," speech presented to the Retail
Wheeling Conference, Denver, Colorado, November 8, 1993.
"Retail Wheeling," speech presented to the Missouri Valley Electric Association
Division Conference, Kansas City, Missouri, October 22, 1993.
"An Economic Perspective on Current Transmission Pricing Issues," speech
presented to the Edison Electric Institute 1993 Fall Legal Committee Meeting,
Minneapolis, Minnesota, October 7, 1993.
"Comments on Transmission Reform Proposals," report prepared for the Edison
Electric Institute, October 1993.
"Sunk Transmission Cost Recovery Issues," report prepared for The Electricity
Industry Committee, New Zealand, September 1, 1993.
"Characteristics of a 'Good' Retail Wheeling System," speech presented to the
Second Annual Electricity Conference sponsored by Executive Enterprises, Inc.,
Washington, D.C., April 21-22, 1993.
"Characteristics of a 'Good' Retail Wheeling System," speech presented to the
Electric Utility Business Environment Conference sponsored by Electric Utility
Consultants, Inc., Denver, Colorado, March 16-17, 1993.
"Change in the Industry," seminar presentation on privatization and service
unbundling presented to Ontario Hydro management and special strategy task
force, Ontario, Canada, February 3, 1993.
"The U.S. Experience and What Is To Come," speech presented to NERA Seminar on
Competition in the Regulated Industries (Electric/Telecommunications), Rye Town
Hilton, Rye Town, New York, October 30, 1992.
<PAGE>
Exhibit No. ___ (RWF-2)
Page 4 of 9
"Emerging Transmission Pricing Issues," speech presented to Electric Utility
Consultants, Inc.'s 3rd Annual Transmission & Wheeling Conference, Chicago,
Illinois, September 22-23, 1992. .
"Emerging Transmission Pricing Issues," speech presented to Executive
Enterprises, Inc., 1992 Electricity Conference: Restructuring the Electricity
Industry, Washington, D.C., September 15-16, 1992.
"Opportunity Cost Pricing for Electric Transmission: An Economic Assessment,"
report prepared for Edison Electric Institute, June 1992.
"A Pragmatic Look at Open Access," presented to DOE/NARUC Workshop on
Electricity Transmission, Stockbridge, Massachusetts, June 2, 1992.
"Some Thoughts About Open Access," presented to EMA's Issues and Outlook Forum,
Atlanta, Georgia, May 5, 1992.
"Transmission Access and Pricing: What Does A Good 'Open Access' System Look
Like," NERA Working Paper #14, January 1992.
"Transmission Access: How Should We Proceed?" speech presented to the Second
Annual Transmission and Wheeling Conference, Denver, Colorado, November 21,
1991.
"Evaluation of Qualifying Facility Proposals," prepared for Florida Power
Corporation, March 1991.
"Design of Capacity Procurement Systems," prepared for ElectricitJ de France,
January 1991.
"Issues in the Design of Generating Capacity Procurement Systems," prepared for
TransAlta Utilities, January 1991.
"A Critique and Evaluation of the Large Public Power Council's Transmission
Access and Pricing Proposal," prepared for Edison Electric Institute, December
1990.
"The Effects of a Premature Shutdown of the Trojan Nuclear Power Plant,"
prepared for Portland General Electric Company, October 1990.
"Can We Implement Reasonable Transmission Pricing and Access Procedures?"
presented to the Edison Electric Institute System Planning Committee, Dallas,
Texas, October 24, 1990.
"An Examination of the Proper Role for Utilities in Promoting Conservation
Expenditures," prepared for Public Service Electric & Gas Company with T. Scott
Newlon, 1990.
"Issues in the Design of Competitive Bidding Systems," presented at the
Pennsylvania Electric Association System Planning Meeting," 1990.
<PAGE>
Exhibit No. ___ (RWF-2)
Page 5 of 9
"Should We Use Opportunity Cost Pricing for Transmission?" presented to the
Edison Electric Institute Interconnection Arrangements Committee, 1990.
"Issues Concerning Selection Criteria Development for Capacity RFPs," prepared
for the Bonneville Power Administration, 1990.
"Nonutility Generators and Bonneville Power Administration Resource Acquisition
Policy," prepared for the Bonneville Power Administration, with David L.
Weitzel, 1990.
"An Evaluation of Resource Solicitation Alternatives," prepared for the
Bonneville Power Administration, 1990.
"Recent Changes in the Electric Power Industry and Pressures on the Transmission
System," presented at seminar "Competitive Electricity: Why the Debate?"
sponsored by the Electricity Consumers Resource Council, 1988.
"Some Thoughts on New Transmission Access and Pricing Proposals," presented at
conference "Transmission Pricing and Access: Reinventing the Wheel," sponsored
by Cogeneration and Independent Power Coalition of America and American
Cogeneration Association, 1988.
"Approaching the Transmission Access Debate Rationally," Transmission Research
Group Working Paper Number 1, with Joe D. Pace, 1987.
"The Essential Facilities Doctrine," NERA, 1985.
"The Nuclear Regulatory Commission's Antitrust Review Process: An Analysis of
the Impacts," Transcomm, Inc., prepared for the U.S. Department of Energy, 1981.
"Competitive Aspects of Utility Involvement in Cogeneration and Solar Programs,"
Transcomm, Inc., prepared for the U.S. Department of Energy, 1981.
"An Appraisal of Antitrust Review Extension in the Context of Small Utility Fuel
Use Act Compliance," Transcomm, Inc., prepared for the U.S. Department of
Energy, 1980.
"Analysis of Proposed License Conditions with Respect to Antitrust
Deficiencies," Transcomm, Inc., prepared for the U.S. Nuclear Regulatory
Commission, 1978.
"Analysis of NRC Staff's Proposed License Conditions for Midland Units,"
Transcomm, Inc., prepared for the U.S. Nuclear Regulatory Commission, 1978.
<PAGE>
Exhibit No. ___ (RWF-2)
Page 6 of 9
TESTIMONY
Prepared testimony on behalf of Northeast Utilities before the Federal Energy
Regulatory Commission in Northeast Utilities Service Company, Docket No. ER95-
1686-000, concerning FERC's generation dominance standard in support of
Northeast Utilities' request for market-based pricing authority, November 13,
1995.
Sur-reply affidavit on behalf of Rochester Gas & Electric before the U.S.
District Court, Western District of New York, in Kamine/Besicorp Allegany L.P.
v. Rochester Gas & Electric Corporation, Case No. 95-CIV-6045L, in response to
motion by Kamine/Besicorp Allegany L.P. for a preliminary injunction, July 10,
1995.
Prepared Supplemental Rebuttal Testimony on Transmission NOPR Issues on behalf
of Florida Power & Light Company before the Federal Energy Regulatory Commission
in Florida Power & Light Company, Docket Nos. ER93-465-000, et al., addressing
transmission NOPR issues raised by FERC Staff and Intervenors, May 19, 1995.
Prepared Direct Testimony on Transmission NOPR Issues on behalf of Florida Power
& Light before the Federal Energy Regulatory Commission in Florida Power & Light
Company, Docket Nos. ER93-465-000, et al., concerning the effects of FERC's
recent Notice of Proposed Rulemaking on issues in FPL's ongoing case, April 25,
1995.
Affidavit on behalf of Rochester Gas & Electric before the U.S. District Court,
Western District of New York, in Kamine/Besicorp Allegany L.P. v. Rochester Gas
& Electric Corporation, Case No. 95-CIV-6045L, in support of its opposition to a
request by Kamine/Besicorp Allegany L.P. for a temporary restraining order,
March 9, 1995.
Testimony on behalf of Virginia Power before the Circuit Court of the City of
Richmond in Case No. LW-730-4, Doswell Limited Partnership v. Virginia Electric
Power Company concerning the level of fixed gas transportation costs associated
with the proxy unit which forms the basis for Virginia Power's payments to
Doswell, March 2, 1995.
Prepared Rebuttal Testimony on behalf of American Electric Power Service
Corporation before the Federal Energy Regulatory Commission in Docket Nos. ER93-
540-001 addressing issues concerning FERC's new comparability standard and its
implications for AEP transmission service offerings, January 17, 1995.
<PAGE>
Exhibit No. ___ (RWF-2)
Page 7 of 9
Deposition on behalf of El Paso Electric Company and Central and South West
Services, Inc. before the Federal Energy Regulatory Commission in Docket Nos.
EC94-7-000 and ER94-898-000 concerning "comparability" and other transmission
issues, December 22, 1994.
Prepared Rebuttal Testimony on behalf of Florida Power & Light Company before
the Federal Energy Regulatory Commission in Florida Power & Light Company,
Docket Nos. ER93-465-000, et al. concerning market power and competitive issues,
comparability and other transmission issues, wholesale electric service tariff
revisions, and issues concerning interchange contract revisions, December 16,
1994.
Prepared Rebuttal Testimony on behalf of El Paso Electric Company and Central
and South West Services, Inc., before the Federal Energy Regulatory Commission,
Dockets Nos. EC94-7-000 and ER94-898-000, concerning network transmission
service and point-to-point transmission service, December 12, 1994.
Prepared Direct Testimony on behalf of Midwest Power Systems, Inc. and Iowa-
Illinois Gas and Electric Company before the Federal Regulatory Commission,
Docket No. EC95-4-000, concerning competitive issues raised by their proposed
merger to form MidAmerican Energy Company, November 10, 1994.
Deposition on behalf of Florida Power Corporation in Orlando Cogen (I), Inc., et
al., v. Florida Power Corporation, Case No. 94-303-CIV-ORL-18, US District Court
in and for the Middle District of Florida, Orlando Division, involving a
contract dispute between FPC and one of its NUG suppliers, August 30, 1994.
Prepared Direct Testimony on Comparability Issues on behalf of Florida Power &
Light Company in Florida Power & Light Company, Docket Nos. ER93-465-000 and
ER93-922-000 concerning a discussion of the differences between types of
transmission services, usage of transmission systems by their owners,
transmission services that FPL provides, and how those services compare and
contrast with FPL's own uses of the transmission system, August 5, 1994.
Prepared Answering Testimony on behalf of Florida Power & Light Company in
Florida Power & Light Company, Docket Nos. ER93-465-000 and ER93-922-000
concerning (1) whether municipal systems should receive billing credits for
certain transmission facilities which they own which were argued to be part of
an "integrated" transmission grid, and (ii) FPL's obligation to sell wholesale
power under its Nuclear Regulatory Commission antitrust license conditions, July
7, 1994.
Deposition on behalf of Virginia Electric & Power Co. in re: Doswell Limited
Partnership v. Virginia Electric & Power Co., Case No. LW-730-4, Circuit Court
for the City of Richmond, involving an alleged fraud and breach of contract
relating to payments by VEPCO to one of its NUG suppliers, April 5, 1994.
<PAGE>
Exhibit No. ___ (RWF-2)
Page 8 of 9
Prepared Final Rebuttal Testimony on behalf of Central Louisiana Electric
Company before the Federal Energy Regulatory Commission in Docket No. ER93-498-
000, examining an allegation of predatory pricing, March 16, 1994.
Prepared Rebuttal Testimony on behalf of Central Louisiana Electric Company
before the Federal Energy Regulatory Commission in Docket No. ER93-498-000,
examining an allegation of a municipal joint action agency that Central
Louisiana's contract to provide bulk power service to a new municipal system
customer constituted predatory pricing, December 23, 1993.
"Comments on the Commerce Commission's Draft Determination Concerning Trans
Power's Proposal to Recover Fixed/Sunk Transmission Costs," testimony prepared
at the request of The Electricity Industry Committee, New Zealand, November 30,
1993.
Prepared Direct Testimony on behalf of Florida Power & Light Company in Florida
Power & Light Company, Docket Nos. ER93-465-000 and ER93-922-000 concerning
competitive implications of wholesale tariff revisions, interchange contract
revisions and a proposed "open access" transmission tariff, November 26, 1993.
Deposition on behalf of Florida Power and Light in Florida Municipal Power
Agency v. Florida Power & Light Co. Case No. 92-35-CIV-ORL-22 concerning damage
related issues, July 21 and 22, 1993.
Affidavit on behalf of Florida Power and Light in Florida Municipal Power Agency
v. Florida Power & Light Co. Case No. 93-25-CIV-ORL-22 concerning damaged
related issues, July 14, 1993.
Prepared Direct Testimony on behalf of the Detroit Edison Company In the Matter
of the Application of the Association of Businesses Advocating Tariff Equity for
Approval of an experimental retail wheeling tariff for Consumers Power Company,
Case No. U-10143, and In the Matter on the Commission's own motion, to consider
approval of an experimental retail wheeling tariff for The Detroit Edison
Company, Case No. U-10176 before the Michigan Public Service Commission, March
1, 1993.
Deposition on behalf of Florida Power and Light in Florida Municipal Power
Agency v. Florida Power & Light Co. Case No. 92-35-CIV-ORL-22, February 25,
1993.
Affidavit on behalf of Iowa Power Inc. and Iowa Public Service Company, Federal
Energy Regulatory Commission, Concerning the Competitive Effects of a Merger of
the Two Companies, 1991.
<PAGE>
Exhibit No. ___ (RWF-2)
Page 9 of 9
Testimony on behalf of Defendants Union Electric and Missouri Utilities, in City
of Malden, Missouri v. Union Electric Company and Missouri Utilities Company,
U.S. District Court, Eastern District of Missouri, Southeastern Division, Civil
Action No. 83-2533-C, 1988.
Testimony on behalf of Defendant Union Electric in City of Kirkwood, Missouri v.
Union Electric Company, U.S. District Court, Eastern District of Missouri,
Eastern Division, Civil Action No. 86-1787-C-6 (deposition testimony), 1987.
Testimony on behalf of Defendant Union Electric in Citizens Electric Company v.
Union Electric Company, U.S. District Court, Eastern District of Missouri,
Eastern Division, Civil Action No. 83-2756C(c), 1986.
Testimony on behalf of Advo-System, Inc., before the Postal Rate Commission,
Docket No. R84-1, Concerning Rates for Third Class Mail, 1984.
Testimony on behalf of D/FW Signal, Inc., before the Federal Communications
Commission, Docket No. CC83-945, Concerning Cellular Telephone Service in
Dallas-Fort Worth, 1983.
Testimony on behalf of the Department of Defense, before the Montana Public
Service Commission, Docket No. 82.2.8, Concerning Telephone Service Rate
Structure, 1982.
Testimony on behalf of Multnomah County, before the Public Utility Commissioner
of Oregon, Docket UF 3565, Concerning Telephone Service Rate Structure.
Testimony on behalf of the Louisiana Consumer League, before the Louisiana
Public Service Commission, Docket No. U-14078, Concerning Marginal Cost Pricing
for Louisiana Power and Light Company, 1979.
Testimony on behalf of the State of Oregon, City of Portland, and County of
Multnomah, before the Public Utility Commissioner of Oregon, Dockets UF3342 and
UF3343, concerning Rates for Centrex and ESSX Telephone Service, 1978.
December, 1995
<PAGE>
Exhibit No.____(RWF-3)
Page 1 of 3
LIST OF ABBREVIATIONS
AEC Associated Electric Cooperative, Inc.
AECC Arkansas Electric Cooperative Corporation
AEP American Electric Power Company, Inc.
Ames Ames Municipal Electric System
AP Alabama Power Company
APL Arkansas Power & Light Company
APS Allegheny Power Service Corporation
Atlantic Atlantic Municipal Utilities
Basin Basin Electric Power Cooperative
Big Rivers Big Rivers Electric Corporation
BPU Kansas City Board of Public Utilities
Cajun Cajun Electric Power Cooperative, Inc.
CBPC Corn Belt Power Cooperative
CE Commonwealth Edison Company
Cedar Falls Cedar Falls Utilities
Centerior Centerior Energy Corporation
Central Iowa Central Iowa Power Cooperative
CILCO Central Illinois Light Company
CINergy CINergy
CIPS Central Illinois Public Service Company
CLECO Central Louisiana Electric Company, Inc.
Columbia Columbia Water & Light Department
Consumers Consumers Power Company
CPA Cooperative Power Association
CPC Central Power Electric Cooperative, Inc.
CPL Carolina Power & Light Company
CSW Central and South West Corporation
Dahlberg Dahlberg Light & Power Company
DPC Dairyland Power Cooperative
DPL The Dayton Power & Light Company
Duke Duke Power Company
Duquesne Duquesne Light Company
ECAR East Central Area Reliability Coordination Agreement
EEI Electric Energy, Inc.
EKPC East Kentucky Power Cooperative, Inc.
Eldridge Eldridge Municipal Light Department
Empire Empire District Electric Company
Entergy Entergy Corporation
EPI Entergy Power, Inc.
ERCOT Electricity Reliability Counsel of Texas
ETEC East Texas Electric Cooperative
FP&L Florida Power & Light Company
Geneseo Geneseo Municipal Utilities
GP Georgia Power Company
GRDA Grand River Dam Authority
Gulf Gulf Power Company
Harlan Harlan Municipal Utilities
Heartland Heartland Consumers Power District
<PAGE>
Exhibit No.____(RWF-3)
Page 2 of 3
Hoosier Hoosier Energy Rural Electric Cooperative
IES IES Industries, Inc.
IIGE Iowa-Illinois Gas & Electric Company
IM Indiana Michigan Power Company
IMEA Illinois Municipal Electric Agency
IMPA Indiana Municipal Power Agency
Independence Independence Power & Light Department
IP Illinois Power Company
IPL Indianapolis Power & Light Company
IPW Interstate Power Company
KAMO KAMO Power
KCPL Kansas City Power & Light Company
KGE Kansas Gas & Electric Company
KU Kentucky Utilities
Lafayette Lafayette Utilities System
LEPA Louisiana Energy Power Authority
LES Lincoln Electric System
LGE Louisville Gas & Electric Company
MAIN Mid-America Interconnected Network
MAPP Mid-Continent Area Power Pool
MBMPA Missouri Basin Municipal Power Agency
MEAN Municipal Energy Agency of Nebraska
MEC MidAmerican Energy Company
Midwest Midwest Energy, Inc.
Minnkota Minnkota Power Cooperative, Inc.
Miss P Mississippi Power Company
MoPub Missouri Public Service Company
MPL Minnesota Power & Light Company
MPSI Midwest Power Systems, Inc.
Mt. Carmel Mt. Carmel Public Utility Company
Muscatine Muscatine Power and Water
NCPC North Central Power Co., Inc.
NIPSCO Northern Indiana Public Service Company
NPPD Nebraska Public Power District
NSP Northern States Power Company
NTEC Northeast Texas Electric Cooperative, Inc.
NWPS Northwestern Public Service Company
OE Ohio Edison Company
OGE Oklahoma Gas & Electric Company
OMPA Oklahoma Municipal Power Authority
OPPD Omaha Public Power District
OTP Otter Tail Power Company
OVEC Ohio Valley Electric Company
Owensboro Owensboro Municipal Utilities
Plaquemine Plaquemine City Light & Water Department
PSI PSI Energy, Inc.
PSO Public Service Company of Oklahoma
Richmond Richmond Power & Light
Savannah Savannah Electric and Power Company
SERC Southeastern Electric Reliability Council Region
Sho-Me Sho-Me Power Corp.
SIGECO Southern Indiana Gas & Electric Company
<PAGE>
Exhibit No.____(RWF-3)
Page 3 of 3
Sikeston Sikeston Board of Municipal Utilities
SIPCO Southern Illinois Power Cooperative
SJLP St. Joseph Light & Power Company
SMEPA South Mississippi Electric Power Association
SMMPA Southern Minnesota Municipal Power Agency
Southern The Southern Company
Soyland Soyland Power Cooperative, Inc.
SPA Southwestern Power Administration
SPP Southwest Power Pool
Springfield, IL Springfield City Water, Light & Power
Springfield, MO Springfield City Utilities
SRMPA Sam Rayburn Municipal Power Agency
Sunflower Sunflower Electric Power Corporation, Inc.
SWEPCO Southwestern Electric Power Company
SWPS Southwestern Public Service Company
TVA Tennessee Valley Authority
UE Union Electric Company
UPA United Power Association
USEC United States Enrichment Corporation
Utilicorp Utilicorp United, Inc.
VEPCO Virginia Electric and Power Company
WAPA Western Area Power Administration
Waverly Waverly Light & Power
WEPCO Wisconsin Electric Power Company
West Plains West Plains Electric Cooperative, Inc.
WF Western Farmers Electric Cooperative
WPL Wisconsin Power & Light Company
WPPI Wisconsin Public Power Inc. System
WPSC Wisconsin Public Service Corporation
WR Western Resources
WVPA Wabash Valley Power Association
<PAGE>
Exhibit No.___(RWF-4)
Page 1 of 2
INTERCONNECTIONS OF UE AND CIPS
<TABLE>
<CAPTION>
UTILITIES INTERCONNECTED UTILITIES INTERCONNECTED WITH
WITH UE CIPS
- - - - - - - - - - - - - - - - - - - DIRECT - - - - - - - - - - - - - - - - - - -
<S> <C>
AEC* CE*
CIPS* CILCO*
Columbia* Springfield*
EEI* EEI*
IES* IES* (1998)
IP* IMEA*
KCPL* IMPA*
MEC* IP*
MoPub* IM/AEP*
SPA* NIPSCO*
TVA* PSI/CINergy*
Soyland*
SIPCO*
UE*
TVA*
WVPA*
- - - - - - - - - - - - - - - - - CONTRACTUAL ONLY - - - - - - - - - - - - - - - -
APL/Entergy KU
IPW
KGE/WR
KU
NSP
PSO/CSW
SJLP*
</TABLE>
Utilities with asterisk (*) are potential receipt and delivery points under
merged firms' open access tariffs.
Utilities in bold are interconnected with both UE and CIPS.
NOTE: See Exhibit___(RWF-3) for explanation of abbreviations.
<PAGE>
EXHIBIT NO. __ (RWF-4)
Page 2 of 2
INTERCONNECTIONS OF UE AND CIPS
[GRAPH APPEARS HERE]
Page 2 to Exhibit RWF-4 of Mr. Frame's testimony consists of a schematic
drawing of the interconnections of UE and CIPS. This exhibit will be provided to
the Commission upon request.
<PAGE>
Exhibit No.___(RWF-5)
POSTMERGER INTERCONNECTIONS OF
ENTITIES INTERCONNECTED WITH BOTH
UE AND CIPS
<TABLE>
<CAPTION>
ENTITY POSTMERGER INTERCONNECTIONS
- ------ ---------------------------
<S> <C>
IES (8)* Merged Entity, AEC, CBPC, Central Iowa, MEC, IPW,
NSP, WAPA
IP (9) Merged Entity, AEP, CE, CILCO, KU, MEC, SIPCO,
Springfield, TVA
KU (10) Merged Entity, AEP, Big Rivers, CINergy, EKPC, IP,
LGE, OVEC, Owensboro, TVA
TVA (11) Merged Entity, AEP, Big Rivers, CPL, Duke, EKPC,
Entergy, IP, KU, LGE, Southern
</TABLE>
See Exhibit No.___(RWF-3) for a list of abbreviations.
*IES is interconnected with UE both directly and through the East Line
Agreement. CIPS has a limited purpose interconnection now with IES and will add
an additional interconnection in 1998.
Note: List of entities interconnected with both UE and CIPS excludes EEI.
Also, EEI is not listed as a separate interconnection of IP, KU and TVA for
reasons explained in text.
<PAGE>
Exhibit ___ (RWF-6)
INTERCHANGE SALES AND PURCHASES
FOR UTILITIES INTERCONNECTED
WITH BOTH UE AND CIPS
1991-1994
<TABLE>
<CAPTION>
IES IP KU TVA*
----- ------ ----- ------
<S> <C> <C> <C> <C>
TOTAL INTERCHANGE SALES (GWH) 9,212 9,726 643 16,986
SALES TO UE (%) 10.6 2.5 2.8 5.8
SALES TO CIPS (%) 0 1.2 2.1 10.5
SALES TO UE/CIPS COMBINED (%) 10.6 3.7 4.9 16.3
TOTAL INTERCHANGE PURCHASES (GWH) 7,432 12,478 4,674 17,686
PURCHASES FROM UE (%) 31.5 17.6 20.6 7.2
PURCHASES FROM CIPS (%) 0 0.6 1.8 0.9
PURCHASES FROM UE/CIPS COMBINED(%) 31.5 18.2 22.4 8.1
</TABLE>
*DATA FOR TVA COVER ONLY 1992-1994.
<PAGE>
<TABLE>
<CAPTION>
Exhibit__(RWF-7)
UNCOMMITTED CAPACITY
OF UE, CIPS AND INTERCONNECTED UTILITIES
18% RESERVE MARGIN*
1996 1996 Share
(1)/Sum:(1)
(1) (2)
========== ===========
UE 0 MW 0.0%
CIPS 98 3.4
==========================================
<S> <C> <C>
AMEREN 98 3.4
AEC 342 12.0
AEP 0 0.0
CE 117 4.1
CILCO 0 0.0
CINergy 0 0.0
Columbia 3 0.1
CSW 112 3.9
Entergy 180 6.3
IES 0 0.0
IMEA 0 0.0
IMPA 0 0.0
IP 207 7.2
IPW 89 3.1
KCPL 163 5.7
KU 103 3.6
MEC 219 7.7
MoPub 56 2.0
NIPSCO 68 2.4
NSP 341 12.0
SIPCO 52 1.8
SJLP 2 0.1
Soyland 0 0.0
SPA 0 0.0
Springfield, IL 0 0.0
TVA 551 19.3
WR 153 5.4
WVPA 0 0.0
-------- --------
TOTAL 2,856 MW 100%
</TABLE>
SOURCES:
1995 ECAR OE-411
1995 MAIN OE-411
1995 MAPP OE-411
1995 SERC OE-411
1995 SPP OE-411
CIPS: Exhibit No.___(GWM-2)
Data provided by MidAmerican Energy Company
Data provided by IES Utilities
Union Electric, Energy Resource Plan, June 1995
*Computations use 18 percent reserve margins
for all utilities except SPA, where it is 9.9 percent
<PAGE>
Exhibit ___(RWF-8)
UNCOMMITTED CAPACITY
OF UE, CIPS AND INTERCONNECTED UTILITIES
15% RESERVE MARGIN*
1996 1996 Share
(1)/Sum:(1)
(1) (2)
============= =============
UE 106 MW 1.7%
CIPS 166 2.6
===============================================
AMEREN 272 4.2
AEC 423 6.6
AEP 103 1.6
CE 679 10.6
CILCO 18 0.3
CINergy 254 4.0
Columbia 9 0.1
CSW 323 5.0
Entergy 715 11.2
IES 0 0.0
IMEA 0 0.0
IMPA 0 0.0
IP 318 5.0
IPW 120 1.9
KCPL 254 4.0
KU 205 3.2
MEC 324 5.1
MoPub 87 1.4
NIPSCO 150 2.3
NSP 544 8.5
SIPCO 59 0.9
SJLP 13 0.2
Soyland 0 0.0
SPA 0 0.0
Springfield, IL 0 0.0
TVA 1,253 19.6
WR 281 4.4
WVPA 0 0.0
-------- --------
TOTAL 6,402 MW 100%
SOURCES:
1995 ECAR OE-411
1995 MAIN OE-411
1995 MAPP OE-411
1995 SERC OE-411
1995 SPP OE-411
CIPS: Exhibit No.___(GWM-2)
Data provided by MidAmerican Energy Company
Data provided by IES Utilities
Union Electric, Energy Resource Plan, June 1995
*Computations use 15 percent reserve margins
for all utilities except SPA, where it is 9.9 percent
<PAGE>
EXHIBIT __ (RWF-9)
PAGE 1 OF 2
FIRST TIER UTILITIES
[GRAPH APPEARS HERE]
Page 1 of Exhibit RWF-9 to Mr. Frame's testimony consists of a schematic
diagram of first-tier utilities. This diagram will be provided to the
Commission upon request.
<PAGE>
Exhibit ___ (RWF _ 9)
Page 2 of 2
FIRST TIER UTILITIES
<TABLE>
<CAPTION>
POSTMERGER POSTMERGER
A'S FIRST PREMERGER MARKET/BEFORE MARKET/AFTER
TIER UTILITIES MARKET OPEN ACCESS OPEN ACCESS
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C>
B N/A N/A N/A
F A, B, E, G, L A-B, E, G, L A-B, C*, D*, E, G, H*, L
G A, F, H, K, L A-B, F, H, K, L A-B, C*, D*, E*, F, H, K, L
H A, B, C, G, I, J A-B, C, G, I, J A-B, C, D*, E*, F*, G, I, J,
</TABLE>
<TABLE>
<CAPTION>
POSTMERGER POSTMERGER
B'S FIRST PREMERGER MARKET/BEFORE MARKET/AFTER
TIER UTILITIES MARKET OPEN ACCESS OPEN ACCESS
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C>
A N/A N/A N/A
C B, D, H, I, N A-B, D, H, I, N A-B, D, E*, F*, G*, H, I, N
D B, C, E, M A-B, C, E, M A-B, C, E, F*, G*, H*, M
E B, D, F, M A-B, D, F, M A-B, C*, D, F, G*, H*, M
F A, B, E, G, L A-B, E, G, L A-B, C*, D*, E, G, H*, L
H A, B, C, G, I, J A-B, C, G, I, J A-B, C, D*, E*, F*, G, I, J
</TABLE>
* Utilities added as a result of open acces tariff
<PAGE>
Exhibit__(RWF-10)
Page 1 of 27
FIRST TIER MARKET CENTERED ON
AEC
Participants Relationship
====================== ====================
AEC Center
UE First Tier (Pre Merger)
CSW First Tier
Empire First Tier
Entergy First Tier
IES First Tier
KCPL First Tier
MEC First Tier
MoPub First Tier
SJLP First Tier
WR First Tier
Columbia First Tier
GRDA First Tier
LES First Tier
NPPD First Tier
OPPD First Tier
SPA First Tier
AMEREN First Tier (Post Merger)
AEP AMEREN Open Access Tariff
CILCO AMEREN Open Access Tariff
CINergy AMEREN Open Access Tariff
CE AMEREN Open Access Tariff
IP AMEREN Open Access Tariff
NIPSCO AMEREN Open Access Tariff
SIPCO AMEREN Open Access Tariff
Soyland AMEREN Open Access Tariff
WVPA AMEREN Open Access Tariff
IMEA AMEREN Open Access Tariff
IMPA AMEREN Open Access Tariff
Springfield, IL AMEREN Open Access Tariff
<PAGE>
Exhibit ___(RWF-10)
Page 2 of 27
FIRST TIER MARKET CENTERED ON
AEP
Participants Relationship
================== ===================
AEP Center
CIPS First Tier (Pre Merger)
APS First Tier
CPL First Tier
Centerior First Tier
CINergy First Tier
CE First Tier
Consumers First Tier
DPL First Tier
Duke First Tier
Duquesne First Tier
IP First Tier
IPL First Tier
KU First Tier
NIPSCO First Tier
OE First Tier
VEPCO First Tier
EKPC First Tier
OVEC First Tier
Richmond First Tier
TVA First Tier
AMEREN First Tier (Post Merger)
CILCO AMEREN Open Access Tariff
IES AMEREN Open Access Tariff
KCPL AMEREN Open Access Tariff
MEC AMEREN Open Access Tariff
MoPub AMEREN Open Access Tariff
SJLP AMEREN Open Access Tariff
AEC AMEREN Open Access Tariff
SIPCO AMEREN Open Access Tariff
Soyland AMEREN Open Access Tariff
WVPA AMEREN Open Access Tariff
Columbia AMEREN Open Access Tariff
IMEA AMEREN Open Access Tariff
IMPA AMEREN Open Access Tariff
Springfield, IL AMEREN Open Access Tariff
SPA AMEREN Open Access Tariff
<PAGE>
Exhibit ___(RWF-10)
Page 3 of 27
FIRST TIER MARKET CENTERED ON
CE
Participants Relationship
=================== ===================
CE Center
CIPS First Tier (Pre Merger)
AEP First Tier
CILCO First Tier
IP First Tier
IPW First Tier
MEC First Tier
NIPSCO First Tier
WEPCO First Tier
WPL First Tier
AMEREN First Tier (Post Merger)
CINergy AMEREN Open Access Tariff
IES AMEREN Open Access Tariff
KCPL AMEREN Open Access Tariff
MoPub AMEREN Open Access Tariff
SJLP AMEREN Open Access Tariff
AEC AMEREN Open Access Tariff
SIPCO AMEREN Open Access Tariff
Soyland AMEREN Open Access Tariff
WVPA AMEREN Open Access Tariff
Columbia AMEREN Open Access Tariff
IMEA AMEREN Open Access Tariff
IMPA AMEREN Open Access Tariff
Springfield, IL AMEREN Open Access Tariff
SPA AMEREN Open Access Tariff
<PAGE>
Exhibit ___(RWF-10)
Page 4 of 27
FIRST TIER MARKET CENTERED ON
CILCO
Participants Relationship
================== ===================
CILCO Center
CIPS First Tier (Pre Merger)
CE First Tier
IP First Tier
Springfield, IL First Tier
AMEREN First Tier (Post Merger)
AEP AMEREN Open Access Tariff
CINergy AMEREN Open Access Tariff
IES AMEREN Open Access Tariff
KCPL AMEREN Open Access Tariff
MEC AMEREN Open Access Tariff
MoPub AMEREN Open Access Tariff
NIPSCO AMEREN Open Access Tariff
SJLP AMEREN Open Access Tariff
AEC AMEREN Open Access Tariff
SIPCO AMEREN Open Access Tariff
Soyland AMEREN Open Access Tariff
WVPA AMEREN Open Access Tariff
Columbia AMEREN Open Access Tariff
IMEA AMEREN Open Access Tariff
IMPA AMEREN Open Access Tariff
SPA AMEREN Open Access Tariff
<PAGE>
Exhibit ___(RWF-10)
Page 5 of 27
FIRST TIER MARKET CENTERED ON
CINergy
Participants Relationship
================= ===================
CINergy Center
CIPS First Tier (Pre Merger)
AEP First Tier
DPL First Tier
IPL First Tier
KU First Tier
LGE First Tier
NIPSCO First Tier
SIGECO First Tier
EKPC First Tier
Hoosier First Tier
OVEC First Tier
WVPA First Tier
IMPA First Tier
AMEREN First Tier (Post Merger)
CILCO AMEREN Open Access Tariff
CE AMEREN Open Access Tariff
IES AMEREN Open Access Tariff
IP AMEREN Open Access Tariff
KCPL AMEREN Open Access Tariff
MEC AMEREN Open Access Tariff
MoPub AMEREN Open Access Tariff
SJLP AMEREN Open Access Tariff
AEC AMEREN Open Access Tariff
SIPCO AMEREN Open Access Tariff
Soyland AMEREN Open Access Tariff
Columbia AMEREN Open Access Tariff
IMEA AMEREN Open Access Tariff
Springfield, IL AMEREN Open Access Tariff
SPA AMEREN Open Access Tariff
<PAGE>
Exhibit ___(RWF-10)
Page 6 of 27
FIRST TIER MARKET CENTERED ON
Columbia
Participants Relationship
================== ===================
Columbia Center
UE First Tier (Pre Merger)
AEC First Tier
AMEREN First Tier (Post Merger)
AEP AMEREN Open Access Tariff
CILCO AMEREN Open Access Tariff
CINergy AMEREN Open Access Tariff
CE AMEREN Open Access Tariff
IES AMEREN Open Access Tariff
IP AMEREN Open Access Tariff
KCPL AMEREN Open Access Tariff
MEC AMEREN Open Access Tariff
MoPub AMEREN Open Access Tariff
NIPSCO AMEREN Open Access Tariff
SJLP AMEREN Open Access Tariff
SIPCO AMEREN Open Access Tariff
Soyland AMEREN Open Access Tariff
WVPA AMEREN Open Access Tariff
IMEA AMEREN Open Access Tariff
IMPA AMEREN Open Access Tariff
Springfield, IL AMEREN Open Access Tariff
SPA AMEREN Open Access Tariff
<PAGE>
Exhibit ___(RWF-10)
Page 7 of 27
FIRST TIER MARKET CENTERED ON
CSW
Participants Relationship
================== ===================
CSW Center
UE First Tier (Pre Merger)
CLECO First Tier
Empire First Tier
Entergy First Tier
OGE First Tier
SWPS First Tier
AECC First Tier
WF First Tier
WR First Tier
AEC First Tier
GRDA First Tier
Springfield, MO First Tier
SPA First Tier
AMEREN First Tier (Post Merger)
<PAGE>
Exhibit ___(RWF-10)
Page 8 of 27
FIRST TIER MARKET CENTERED ON
Entergy
Participants Relationship
================= ===================
Entergy Center
UE First Tier (Pre Merger)
CLECO First Tier
CSW First Tier
Southern First Tier
AEC First Tier
Cajun First Tier
Lafayette First Tier
Plaquemine First Tier
TVA First Tier
AMEREN First Tier (Post Merger)
<PAGE>
Exhibit_(RWF-10)
Page 9 of 27
FIRST TIER MARKET CENTERED ON
IES
Participants Relationship
=================== ===================
IES Center
CIPS First Tier (Pre Merger, 1998)
UE First Tier (Pre Merger)
IPW First Tier
MEC First Tier
NSP First Tier
AEC First Tier
CBPC First Tier
Central Iowa First Tier
WAPA First Tier
AMEREN First Tier (Post Merger)
AEP AMEREN Open Access Tariff
CE AMEREN Open Access Tariff
CILCO AMEREN Open Access Tariff
CINergy AMEREN Open Access Tariff
IP AMEREN Open Access Tariff
KCPL AMEREN Open Access Tariff
MoPub AMEREN Open Access Tariff
NIPSCO AMEREN Open Access Tariff
SJLP AMEREN Open Access Tariff
SIPCO AMEREN Open Access Tariff
Soyland AMEREN Open Access Tariff
WVPA AMEREN Open Access Tariff
Columbia AMEREN Open Access Tariff
IMEA AMEREN Open Access Tariff
IMPA AMEREN Open Access Tariff
Springfield, IL AMEREN Open Access Tariff
SPA AMEREN Open Access Tariff
<PAGE>
Exhibit_(RWF-10)
Page 10 of 27
FIRST TIER MARKET CENTERED ON
IMEA
Participants Relationship
=================== ===================
IMEA Center
CIPS First Tier (Pre Merger)
AMEREN First Tier (Post Merger)
AEP AMEREN Open Access Tariff
CILCO AMEREN Open Access Tariff
CINergy AMEREN Open Access Tariff
CE AMEREN Open Access Tariff
IES AMEREN Open Access Tariff
IP AMEREN Open Access Tariff
KCPL AMEREN Open Access Tariff
MEC AMEREN Open Access Tariff
MoPub AMEREN Open Access Tariff
NIPSCO AMEREN Open Access Tariff
SJLP AMEREN Open Access Tariff
AEC AMEREN Open Access Tariff
SIPCO AMEREN Open Access Tariff
Soyland AMEREN Open Access Tariff
WVPA AMEREN Open Access Tariff
Columbia AMEREN Open Access Tariff
IMPA AMEREN Open Access Tariff
Springfield, IL AMEREN Open Access Tariff
SPA AMEREN Open Access Tariff
<PAGE>
Exhibit_(RWF-10)
Page 11 of 27
FIRST TIER MARKET CENTERED ON
IMPA
Participants Relationship
=================== ===================
IMPA Center
CIPS First Tier (Pre Merger)
CINergy First Tier
IPL First Tier
KU First Tier
LGE First Tier
NIPSCO First Tier
SIGECO First Tier
Hoosier First Tier
WVPA First Tier
AMEREN First Tier (Post Merger)
AEP AMEREN Open Access Tariff
CILCO AMEREN Open Access Tariff
CE AMEREN Open Access Tariff
IES AMEREN Open Access Tariff
IP AMEREN Open Access Tariff
KCPL AMEREN Open Access Tariff
MEC AMEREN Open Access Tariff
MoPub AMEREN Open Access Tariff
SJLP AMEREN Open Access Tariff
AEC AMEREN Open Access Tariff
SIPCO AMEREN Open Access Tariff
Soyland AMEREN Open Access Tariff
Columbia AMEREN Open Access Tariff
IMEA AMEREN Open Access Tariff
Springfield, IL AMEREN Open Access Tariff
SPA AMEREN Open Access Tariff
<PAGE>
Exhibit_(RWF-10)
Page 12 of 27
FIRST TIER MARKET CENTERED ON
IP
Participants Relationship
=================== ===================
IP Center
CIPS First Tier (Pre Merger)
UE First Tier (Pre Merger)
AEP First Tier
CILCO First Tier
CE First Tier
KU First Tier
MEC First Tier
SIPCO First Tier
Springfield, IL First Tier
TVA First Tier
AMEREN First Tier (Post Merger)
CINergy AMEREN Open Access Tariff
IES AMEREN Open Access Tariff
KCPL AMEREN Open Access Tariff
MoPub AMEREN Open Access Tariff
NIPSCO AMEREN Open Access Tariff
SJLP AMEREN Open Access Tariff
AEC AMEREN Open Access Tariff
Soyland AMEREN Open Access Tariff
WVPA AMEREN Open Access Tariff
Columbia AMEREN Open Access Tariff
IMEA AMEREN Open Access Tariff
IMPA AMEREN Open Access Tariff
SPA AMEREN Open Access Tariff
<PAGE>
Exhibit__(RWF-10)
Page 13 of 27
FIRST TIER MARKET CENTERED ON
IPW
Participants Relationship
=================== ===================
IPW Center
UE First Tier (Pre Merger)
CE First Tier
DPC First Tier
IES First Tier
KCPL First Tier
MEC First Tier
NSP First Tier
SJLP First Tier
CBPC First Tier
Central Iowa First Tier
SMMPA First Tier
OPPD First Tier
AMEREN First Tier (Post Merger)
<PAGE>
Exhibit__(RWF-10)
Page 14 of 27
FIRST TIER MARKET CENTERED ON
KCPL
Participants Relationship
=================== ===================
KCPL Center
UE First Tier (Pre Merger)
Empire First Tier
IPW First Tier
MEC First Tier
MoPub First Tier
NSP First Tier
SJLP First Tier
WR First Tier
AEC First Tier
BPU First Tier
Independence First Tier
LES First Tier
NPPD First Tier
OPPD First Tier
AMEREN First Tier (Post Merger)
AEP AMEREN Open Access Tariff
CILCO AMEREN Open Access Tariff
CINergy AMEREN Open Access Tariff
CE AMEREN Open Access Tariff
IES AMEREN Open Access Tariff
IP AMEREN Open Access Tariff
NIPSCO AMEREN Open Access Tariff
SIPCO AMEREN Open Access Tariff
Soyland AMEREN Open Access Tariff
WVPA AMEREN Open Access Tariff
Columbia AMEREN Open Access Tariff
IMEA AMEREN Open Access Tariff
IMPA AMEREN Open Access Tariff
Springfield, IL AMEREN Open Access Tariff
SPA AMEREN Open Access Tariff
<PAGE>
Exhibit__(RWF-10)
Page 15 of 27
FIRST TIER MARKET CENTERED ON
KU
Participants Relationship
=================== ===================
KU Center
CIPS First Tier (Pre Merger)
UE First Tier (Pre Merger)
AEP First Tier
CINergy First Tier
IP First Tier
LGE First Tier
EKPC First Tier
OVEC First Tier
Big Rivers First Tier
Owensboro First Tier
TVA First Tier
AMEREN First Tier (Post Merger)
<PAGE>
Exhibit___(RWF-10)
Page 16 of 27
FIRST TIER MARKET CENTERED ON
MEC
<TABLE>
<CAPTION>
Participants Relationship
=============== =========================
<S> <C>
MEC Center
UE First Tier (Pre Merger)
CE First Tier
IES First Tier
IP First Tier
IPW First Tier
KCPL First Tier
Muscatine First Tier
NSP First Tier
SJLP First Tier
CBPC First Tier
Central Iowa First Tier
AEC First Tier
Ames First Tier
Atlantic First Tier
Cedar Falls First Tier
Eldridge First Tier
Geneseo First Tier
Harlan First Tier
LES First Tier
Waverly First Tier
NPPD First Tier
OPPD First Tier
WAPA First Tier
AMEREN First Tier (Post Merger)
AEP AMEREN Open Access Tariff
CILCO AMEREN Open Access Tariff
CINergy AMEREN Open Access Tariff
MoPub AMEREN Open Access Tariff
SIPCO AMEREN Open Access Tariff
Soyland AMEREN Open Access Tariff
WVPA AMEREN Open Access Tariff
Columbia AMEREN Open Access Tariff
IMEA AMEREN Open Access Tariff
IMPA AMEREN Open Access Tariff
Springfield, IL AMEREN Open Access Tariff
SPA AMEREN Open Access Tariff
</TABLE>
<PAGE>
Exhibit__(RWF-10)
page 17 of 27
FIRST TIER MARKET CENTERED ON
MoPub
Participants Relationship
=================== ========================
MoPub Center
UE First Tier (Pre Merger)
Empire First Tier
KCPL First Tier
WR First Tier
AEC First Tier
KAMO First Tier
Independence First Tier
AMEREN First Tier (Post Merger)
AEP AMEREN Open Access Tariff
CILCO AMEREN Open Access Tariff
CINergy AMEREN Open Access Tariff
CE AMEREN Open Access Tariff
IES AMEREN Open Access Tariff
IP AMEREN Open Access Tariff
MEC AMEREN Open Access Tariff
NIPSCO AMEREN Open Access Tariff
SJLP AMEREN Open Access Tariff
SIPCO AMEREN Open Access Tariff
Soyland AMEREN Open Access Tariff
WVPA AMEREN Open Access Tariff
Columbia AMEREN Open Access Tariff
IMEA AMEREN Open Access Tariff
IMPA AMEREN Open Access Tariff
Springfield, IL AMEREN Open Access Tariff
SPA AMEREN Open Access Tariff
<PAGE>
<TABLE>
<CAPTION>
Exhibit__(RWF-10)
Page 18 of 27
FIRST TIER MARKET CENTERED ON
NIPSCO
Participants Relationship
=================== =========================
<S> <C>
NIPSCO Center
CIPS First Tier (Pre Merger)
AEP First Tier
CINergy First Tier
CE First Tier
Consumers First Tier
AMEREN First Tier (Post Merger)
CILCO AMEREN Open Access Tariff
IES AMEREN Open Access Tariff
IP AMEREN Open Access Tariff
KCPL AMEREN Open Access Tariff
MEC AMEREN Open Access Tariff
MoPub AMEREN Open Access Tariff
SJLP AMEREN Open Access Tariff
AEC AMEREN Open Access Tariff
SIPCO AMEREN Open Access Tariff
Soyland AMEREN Open Access Tariff
WVPA AMEREN Open Access Tariff
Columbia AMEREN Open Access Tariff
IMEA AMEREN Open Access Tariff
IMPA AMEREN Open Access Tariff
Springfield, IL AMEREN Open Access Tariff
SPA AMEREN Open Access Tariff
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Exhibit__(RWF-10)
Page 19 of 27
FIRST TIER MARKET CENTERED ON
NSP
Participants Relationship
=================== ======================
<S> <C>
NSP Center
UE First Tier (Pre Merger)
Dahlberg First Tier
IES First Tier
IPW First Tier
KCPL First Tier
MEC First Tier
MH First Tier
MPL First Tier
NCPC First Tier
NWPS First Tier
OPPD First Tier
OTP First Tier
SJLP First Tier
UPA First Tier
WEPCO First Tier
WPL First Tier
WPSC First Tier
Basin First Tier
CPA First Tier
CPC First Tier
DPC First Tier
Minnkota First Tier
Heartland First Tier
MBMPA First Tier
SMMPA First Tier
WAPA First Tier
AMEREN First Tier (Post Merger)
</TABLE>
<PAGE>
Exhibit__(RWF-10)
Page 20 of 27
FIRST TIER MARKET CENTERED ON
SIPCO
<TABLE>
<CAPTION>
Participants Relationship
=================== ===================
<S> <C>
SIPCO Center
CIPS First Tier (Pre Merger)
IP First Tier
AMEREN First Tier (Post Merger)
AEP AMEREN Open Access Tariff
CILCO AMEREN Open Access Tariff
CINergy AMEREN Open Access Tariff
CE AMEREN Open Access Tariff
IES AMEREN Open Access Tariff
KCPL AMEREN Open Access Tariff
MEC AMEREN Open Access Tariff
MoPub AMEREN Open Access Tariff
NIPSCO AMEREN Open Access Tariff
SJLP AMEREN Open Access Tariff
AEC AMEREN Open Access Tariff
Soyland AMEREN Open Access Tariff
WVPA AMEREN Open Access Tariff
Columbia AMEREN Open Access Tariff
IMEA AMEREN Open Access Tariff
IMPA AMEREN Open Access Tariff
Springfield, IL AMEREN Open Access Tariff
SPA AMEREN Open Access Tariff
</TABLE>
<PAGE>
Exhibit_(RWF-10)
Page 21 of 27
FIRST TIER MARKET CENTERED ON
SJLP
Participants Relationship
=================== ===================
SJLP Center
UE First Tier (Pre Merger)
IPW First Tier
KCPL First Tier
MEC First Tier
AEC First Tier
Independence First Tier
LES First Tier
NPPD First Tier
NSP First Tier
OPPD First Tier
AMEREN First Tier (Post Merger)
AEP AMEREN Open Access Tariff
CILCO AMEREN Open Access Tariff
CINergy AMEREN Open Access Tariff
CE AMEREN Open Access Tariff
IES AMEREN Open Access Tariff
IP AMEREN Open Access Tariff
MoPub AMEREN Open Access Tariff
NIPSCO AMEREN Open Access Tariff
SIPCO AMEREN Open Access Tariff
Soyland AMEREN Open Access Tariff
WVPA AMEREN Open Access Tariff
Columbia AMEREN Open Access Tariff
IMEA AMEREN Open Access Tariff
IMPA AMEREN Open Access Tariff
Springfield, IL AMEREN Open Access Tariff
SPA AMEREN Open Access Tariff
<PAGE>
Exhibit_(RWF-10)
Page 22 of 27
FIRST TIER MARKET CENTERED ON
Soyland
Participants Relationship
=================== =========================
Soyland Center
CIPS First Tier (Pre Merger)
AMEREN First Tier (Post Merger)
AEP AMEREN Open Access Tariff
CILCO AMEREN Open Access Tariff
CINergy AMEREN Open Access Tariff
CE AMEREN Open Access Tariff
IES AMEREN Open Access Tariff
IP AMEREN Open Access Tariff
KCPL AMEREN Open Access Tariff
MEC AMEREN Open Access Tariff
MoPub AMEREN Open Access Tariff
NIPSCO AMEREN Open Access Tariff
SJLP AMEREN Open Access Tariff
AEC AMEREN Open Access Tariff
SIPCO AMEREN Open Access Tariff
WVPA AMEREN Open Access Tariff
Columbia AMEREN Open Access Tariff
IMEA AMEREN Open Access Tariff
IMPA AMEREN Open Access Tariff
Springfield, IL AMEREN Open Access Tariff
SPA AMEREN Open Access Tariff
<PAGE>
Exhibit_(RWF-10)
Page 23 of 27
FIRST TIER MARKET CENTERED ON
SPA
Participants Relationship
==================== =========================
SPA Center
UE First Tier (Pre Merger)
CSW First Tier
OGE First Tier
Empire First Tier
AEC First Tier
WF First Tier
AMEREN First Tier (Post Merger)
AEP AMEREN Open Access Tariff
CILCO AMEREN Open Access Tariff
CINergy AMEREN Open Access Tariff
CE AMEREN Open Access Tariff
IES AMEREN Open Access Tariff
IP AMEREN Open Access Tariff
KCPL AMEREN Open Access Tariff
MEC AMEREN Open Access Tariff
MoPub AMEREN Open Access Tariff
NIPSCO AMEREN Open Access Tariff
SJLP AMEREN Open Access Tariff
SIPCO AMEREN Open Access Tariff
Soyland AMEREN Open Access Tariff
WVPA AMEREN Open Access Tariff
Columbia AMEREN Open Access Tariff
IMEA AMEREN Open Access Tariff
IMPA AMEREN Open Access Tariff
Springfield, IL AMEREN Open Access Tariff
<PAGE>
Exhibit ___(RWF-10)
Page 24 of 27
FIRST TIER MARKET CENTERED ON
Springfield, IL
Participants Relationship
==================== ====================
Springfield, IL Center
CIPS First Tier (Pre Merger)
CILCO First Tier
IP First Tier
AMEREN First Tier (Post Merger)
AEP AMEREN Open Access Tariff
CINergy AMEREN Open Access Tariff
CE AMEREN Open Access Tariff
IES AMEREN Open Access Tariff
KCPL AMEREN Open Access Tariff
MEC AMEREN Open Access Tariff
MoPub AMEREN Open Access Tariff
NIPSCO AMEREN Open Access Tariff
SJLP AMEREN Open Access Tariff
AEC AMEREN Open Access Tariff
SIPCO AMEREN Open Access Tariff
Soyland AMEREN Open Access Tariff
WVPA AMEREN Open Access Tariff
Columbia AMEREN Open Access Tariff
IMEA AMEREN Open Access Tariff
IMPA AMEREN Open Access Tariff
SPA AMEREN Open Access Tariff
<PAGE>
Exhibit___(RWF-10)
Page 25 of 27
FIRST TIER MARKET CENTERED ON
TVA
<TABLE>
<CAPTION>
Participants Relationship
=============== =========================
<S> <C>
TVA Center
CIPS First Tier (Pre Merger)
UE First Tier (Pre Merger)
AEP First Tier
CPL First Tier
Duke First Tier
Entergy First Tier
IP First Tier
LGE First Tier
KU First Tier
Southern First Tier
Big Rivers First Tier
EKPC First Tier
AMEREN First Tier (Post Merger)
CE AMEREN Open Access Tariff
CILCO AMEREN Open Access Tariff
CINergy AMEREN Open Access Tariff
IES AMEREN Open Access Tariff
KCPL AMEREN Open Access Tariff
MEC AMEREN Open Access Tariff
MoPub AMEREN Open Access Tariff
NIPSCO AMEREN Open Access Tariff
SJLP AMEREN Open Access Tariff
AEC AMEREN Open Access Tariff
SIPCO AMEREN Open Access Tariff
Soyland AMEREN Open Access Tariff
WVPA AMEREN Open Access Tariff
Columbia AMEREN Open Access Tariff
IMEA AMEREN Open Access Tariff
IMPA AMEREN Open Access Tariff
Springfield, IL AMEREN Open Access Tariff
SPA AMEREN Open Access Tariff
</TABLE>
<PAGE>
Exhibit__(RWF-10)
Page 26 of 27
FIRST TIER MARKET CENTERED ON
WR
<TABLE>
<CAPTION>
Participants Relationship
=================== ========================
<S> <C>
WR Center
UE First Tier (Pre Merger)
CSW First Tier
Empire First Tier
KCPL First Tier
Midwest First Tier
MoPub First Tier
OGE First Tier
WestPlains First Tier
AEC First Tier
BPU First Tier
OPPD First Tier
AMEREN First Tier (Post Merger)
</TABLE>
<PAGE>
Exhibit __(RWF-10)
Page 27 of 27
FIRST TIER MARKET CENTERED ON
WVPA
Participants Relationship
=================== ===================
WVPA Center
CIPS First Tier (Pre Merger)
CINergy First Tier
IMPA First Tier
IPL First Tier
KU First Tier
LGE First Tier
NIPSCO First Tier
SIGECO First Tier
Hoosier First Tier
AMEREN First Tier (Post Merger)
AEP AMEREN Open Access Tariff
CILCO AMEREN Open Access Tariff
CE AMEREN Open Access Tariff
IES AMEREN Open Access Tariff
IP AMEREN Open Access Tariff
KCPL AMEREN Open Access Tariff
MEC AMEREN Open Access Tariff
SJLP AMEREN Open Access Tariff
AEC AMEREN Open Access Tariff
SIPCO AMEREN Open Access Tariff
Soyland AMEREN Open Access Tariff
Columbia AMEREN Open Access Tariff
IMEA AMEREN Open Access Tariff
Springfield, IL AMEREN Open Access Tariff
SPA AMEREN Open Access Tariff
<PAGE>
Exhibit_(RWF-11)
AMEREN'S SHARE OF UNCOMMITTED CAPACITY
FIRST TIER MARKETS
18% RESERVE MARGIN
1996
<TABLE>
<CAPTION>
Pre Merger Post Merger
------------------------------------- -----------------------------------------
AMEREN Share
With Open
First Tier Market Centered On UE Share CIPS Share AMEREN Share Access Tariff
================================ ================= ================= ================== ==================
<S> <C> <C> <C> <C>
(%) (%) (%) (%)
(1) (2) (3) (4)
AEC 0.0% 0.0% 5.7% 4.6%
- ------------------------------------------------------------------------------------------------------------------------------------
AEP 0.0 3.7 3.7 2.8
- ------------------------------------------------------------------------------------------------------------------------------------
CE 0.0 11.4 11.4 6.6
- ------------------------------------------------------------------------------------------------------------------------------------
CILCO 0.0 23.2 23.2 7.4
- ------------------------------------------------------------------------------------------------------------------------------------
CINergy 0.0 14.0 14.0 5.3
- ------------------------------------------------------------------------------------------------------------------------------------
Columbia 0.0 0.0 22.2 7.4
- ------------------------------------------------------------------------------------------------------------------------------------
CSW 0.0 0.0 4.9 4.9
- ------------------------------------------------------------------------------------------------------------------------------------
Entergy 0.0 0.0 6.1 6.1
- ------------------------------------------------------------------------------------------------------------------------------------
IES 0.0 0.0 8.7 5.5
- ------------------------------------------------------------------------------------------------------------------------------------
IMEA 0.0 100.0 100.0 7.4
- ------------------------------------------------------------------------------------------------------------------------------------
IMPA 0.0 18.2 18.2 5.8
- ------------------------------------------------------------------------------------------------------------------------------------
IP 0.0 7.3 7.3 4.9
- ------------------------------------------------------------------------------------------------------------------------------------
IPW 0.0 0.0 9.1 9.1
- ------------------------------------------------------------------------------------------------------------------------------------
KCPL 0.0 0.0 5.0 4.1
- ------------------------------------------------------------------------------------------------------------------------------------
KU 0.0 8.2 8.2 8.2
- ------------------------------------------------------------------------------------------------------------------------------------
MEC 0.0 0.0 4.6 4.4
- ------------------------------------------------------------------------------------------------------------------------------------
MoPub 0.0 0.0 11.4 6.4
- ------------------------------------------------------------------------------------------------------------------------------------
NIPSCO 0.0 34.7 34.7 7.4
- ------------------------------------------------------------------------------------------------------------------------------------
NSP 0.0 0.0 3.6 3.6
- ------------------------------------------------------------------------------------------------------------------------------------
SIPCO 0.0 27.5 27.5 7.4
- ------------------------------------------------------------------------------------------------------------------------------------
SJLP 0.0 0.0 5.9 4.5
- ------------------------------------------------------------------------------------------------------------------------------------
Soyland 0.0 100.0 100.0 7.4
- ------------------------------------------------------------------------------------------------------------------------------------
SPA 0.0 0.0 6.9 4.3
- ------------------------------------------------------------------------------------------------------------------------------------
Springfield, IL 0.0 32.2 32.2 7.4
- ------------------------------------------------------------------------------------------------------------------------------------
TVA 0.0 7.7 7.7 4.3
- ------------------------------------------------------------------------------------------------------------------------------------
WR 0.0 0.0 5.5 5.5
- ------------------------------------------------------------------------------------------------------------------------------------
WVPA 0.0 18.2 18.2 6.0
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
<TABLE>
Exhibit__(RWF-12)
AMEREN'S SHARE OF UNCOMMITTED CAPACITY
FIRST TIER MARKETS
15% RESERVE MARGIN
1996
Pre Merger Post Merger
-------------------------------------- -------------------------------------------
AMEREN Share
With Open
First Tier Market Centered On UE Share CIPS Share AMEREN Share Access Tariff
==================================== ============ ============== ================ ================
(%) (%) (%) (%)
(1) (2) (3) (4)
<S> <C> <C> <C> <C>
AEC 3.5% 0.0% 8.6% 5.7%
- ------------------------------------------------------------------------------------------------------------------------------------
AEP 0.0 2.8 4.5 3.8
- ------------------------------------------------------------------------------------------------------------------------------------
CE 0.0 7.8 12.2 8.2
- ------------------------------------------------------------------------------------------------------------------------------------
CILCO 0.0 14.0 21.1 9.2
- ------------------------------------------------------------------------------------------------------------------------------------
CINergy 0.0 10.7 16.4 7.1
- ------------------------------------------------------------------------------------------------------------------------------------
Columbia 19.7 0.0 38.6 9.2
- ------------------------------------------------------------------------------------------------------------------------------------
CSW 3.2 0.0 7.9 7.9
- ------------------------------------------------------------------------------------------------------------------------------------
Entergy 2.7 0.0 6.6 6.6
- ------------------------------------------------------------------------------------------------------------------------------------
IES 6.8 0.0 15.7 7.4
- ------------------------------------------------------------------------------------------------------------------------------------
IMEA 0.0 100.0 100.0 9.2
- ------------------------------------------------------------------------------------------------------------------------------------
IMPA 0.0 14.1 21.2 7.6
- ------------------------------------------------------------------------------------------------------------------------------------
IP 3.3 5.1 8.4 6.2
- ------------------------------------------------------------------------------------------------------------------------------------
IPW 5.0 0.0 11.8 11.8
- ------------------------------------------------------------------------------------------------------------------------------------
KCPL 3.8 0.0 9.3 6.0
- ------------------------------------------------------------------------------------------------------------------------------------
KU 3.8 6.0 9.8 9.8
- ------------------------------------------------------------------------------------------------------------------------------------
MEC 3.1 0.0 7.6 6.6
- ------------------------------------------------------------------------------------------------------------------------------------
MoPub 8.6 0.0 19.5 8.2
- ------------------------------------------------------------------------------------------------------------------------------------
NIPSCO 0.0 10.9 16.7 8.7
- ------------------------------------------------------------------------------------------------------------------------------------
NSP 3.0 0.0 7.4 7.4
- ------------------------------------------------------------------------------------------------------------------------------------
SIPCO 0.0 30.6 42.0 9.2
- ------------------------------------------------------------------------------------------------------------------------------------
SJLP 4.7 0.0 11.1 6.6
- ------------------------------------------------------------------------------------------------------------------------------------
Soyland 0.0 100.0 100.0 9.2
- ------------------------------------------------------------------------------------------------------------------------------------
SPA 5.6 0.0 13.1 6.3
- ------------------------------------------------------------------------------------------------------------------------------------
Springfield, IL 0.0 33.1 44.8 9.2
- ------------------------------------------------------------------------------------------------------------------------------------
TVA 2.7 4.2 6.9 4.4
- ------------------------------------------------------------------------------------------------------------------------------------
WR 4.1 0.0 10.0 10.0
- ------------------------------------------------------------------------------------------------------------------------------------
WVPA 0.0 14.1 21.2 7.8
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
EXHIBIT NO. __ (RWF-13)
DEFINING FIRST TIER MARKETS SYMMETRICALLY
[GRAPH APPEARS HERE]
This exhibit consists of a schematic diagram that will be provided to the
Commission upon request.
<PAGE>
Exhibit_(RWF-14)
AMEREN'S SHARE OF TOTAL CAPACITY
FIRST TIER MARKETS
<TABLE>
<CAPTION>
Pre Merger Post Merger
--------------------------- ----------------------------------
AMEREN Share
With Open
First Tier Market Centered On UE Share CIPS Share AMEREN Share Access Tariff
=============================== ========== ============ ============== ===============
(%) (%) (%) (%)
(1) (2) (3) (4)
<S> <C> <C> <C> <C>
AEC 12.8% 0.0% 16.3% 8.2%
- ----------------------------------------------------------------------------------------------------------
AEP 0.0 1.5 5.7 5.1
- ----------------------------------------------------------------------------------------------------------
CE 0.0 4.0 14.3 10.7
- ----------------------------------------------------------------------------------------------------------
CILCO 0.0 8.8 28.1 11.7
- ----------------------------------------------------------------------------------------------------------
CINergy 0.0 4.6 16.2 9.7
- ----------------------------------------------------------------------------------------------------------
Columbia 68.9 0.0 74.7 11.7
- ----------------------------------------------------------------------------------------------------------
CSW 12.9 0.0 16.4 16.4
- ----------------------------------------------------------------------------------------------------------
Entergy 7.3 0.0 9.5 9.5
- ----------------------------------------------------------------------------------------------------------
IES 27.2 0.0 33.2 10.4
- ----------------------------------------------------------------------------------------------------------
IMEA 0.0 88.2 96.8 11.7
- ----------------------------------------------------------------------------------------------------------
IMPA 0.0 8.9 28.4 10.4
- ----------------------------------------------------------------------------------------------------------
IP 8.5 2.8 11.3 8.8
- ----------------------------------------------------------------------------------------------------------
IPW 15.4 0.0 19.5 19.5
- ----------------------------------------------------------------------------------------------------------
KCPL 19.5 0.0 24.3 9.6
- ----------------------------------------------------------------------------------------------------------
KU 9.3 3.1 12.4 12.4
- ----------------------------------------------------------------------------------------------------------
MEC 12.5 0.0 16.0 10.2
- ----------------------------------------------------------------------------------------------------------
MoPub 35.1 0.0 41.8 10.9
- ----------------------------------------------------------------------------------------------------------
NIPSCO 0.0 4.0 14.3 10.8
- ----------------------------------------------------------------------------------------------------------
NSP 15.4 0.0 19.5 19.5
- ----------------------------------------------------------------------------------------------------------
SIPCO 0.0 36.2 69.6 11.7
- ----------------------------------------------------------------------------------------------------------
SJLP 24.0 0.0 29.5 10.2
- ----------------------------------------------------------------------------------------------------------
Soyland 0.0 90.2 97.4 11.7
- ----------------------------------------------------------------------------------------------------------
SPA 28.5 0.0 34.6 10.0
- ----------------------------------------------------------------------------------------------------------
Springfield, IL 0.0 30.4 63.8 11.7
- ----------------------------------------------------------------------------------------------------------
TVA 5.0 1.6 6.6 5.0
- ----------------------------------------------------------------------------------------------------------
WR 20.4 0.0 25.4 25.4
- ----------------------------------------------------------------------------------------------------------
WVPA 0.0 8.9 28.4 10.5
- ----------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
Exhibit__(RWF-15)
<TABLE>
<CAPTION>
TOTAL CAPACITY IN ONE WHEEL MARKET
CENTERED ON WR
Total
Capacity
Trading Partner 1996
============================ ========
<S> <C>
(1) (2)
I Center Utility
--------------
WR 5,159 MW
II Directly Interconnected Merger Partner(s)
-----------------------------------------
UE 8,385 MW
III Other Interconnections
----------------------
CSW 8,420 MW
Empire 997
KCPL 3,720
Midwest 272
MoPub 1,263
OGE 6,237
WestPlains 514
------------------------------------------------
AEC 3,557
------------------------------------------------
BPU 619
------------------------------------------------
OPPD 1,968
------
Total (I + II + III) 41,111 MW
IV Other Merger Partner
--------------------
CIPS 2,766 MW
V Additional Utilities Accessible Under Open
------------------------------------------
Access Tariff of CSW & KCPL
---------------------------
Entergy 21,209 MW
IPW 1,310
MEC 4,347
NSP 8,311
SJLP 422
SWPS 3,939
-------------------------------------------------
AECC 1,946
WF 1,226
-------------------------------------------------
GRDA 789
Independence 348
LES 604
Springfield, MO 753
-------------------------------------------------
NPPD 2,033
SPA 643
Total (I + II + III + IV + V) 91,757 MW
-----------------------------------------------------
UE Premerger Share (a) : 20.4%
CIPS Premerger Share (b) : 0.0%
Merged Entity Share
Before CSW & KCPL Tariff (c) : 25.4%
After CSW & KCPL Tariff (d) : 12.2%
(a) :[8,385/41,111]*100
(b) :[0/41,111]*100
(c) :[(8,385+2,776)/43,887]*100
(d) :[(8,385+2,776)/91,767]*100
-----------------------------------------------------
</TABLE>
<PAGE>
Exhibit__(RWF-16)
NON FIRM ENERGY SALES BY
UE, CIPS AND INTERCONNECTED UTILITIES
ALL TRANSACTIONS
1993
<TABLE>
<CAPTION>
<S> <C> <C> <C>
------------------------------------------------------------
SELLER Sales Share HHI
------------------------------------------------------------
(1) (2) (3) (4)
------------------------------------------------------------
CE 10,605 GWH 14.5% 210
------------------------------------------------------------
AEP 10,052 13.7 188
------------------------------------------------------------
TVA 6,818 9.3 87
------------------------------------------------------------
NSP 6,338 8.7 75
------------------------------------------------------------
UE 6,230 8.5 72
------------------------------------------------------------
IP 4,762 6.5 42
------------------------------------------------------------
CINergy 4,730 6.5 42
------------------------------------------------------------
CIPS 4,505 6.2 38
------------------------------------------------------------
Entergy 3,479 4.8 23
------------------------------------------------------------
KCPL 3,343 4.6 21
------------------------------------------------------------
MEC 3,333 4.6 21
------------------------------------------------------------
WR 2,398 3.3 11
------------------------------------------------------------
AEC 2,028 2.8 8
------------------------------------------------------------
IES 1,885 2.6 7
------------------------------------------------------------
KU 773 1.1 1
------------------------------------------------------------
NIPSCO 689 0.9 1
------------------------------------------------------------
CSW 581 0.8 1
------------------------------------------------------------
CILCO 203 0.3 0
------------------------------------------------------------
IPW 117 0.2 0
------------------------------------------------------------
SIPCO 114 0.2 0
------------------------------------------------------------
MoPub 107 0.1 0
------------------------------------------------------------
SJLP 92 0.1 0
------------------------------------------------------------
IMEA 33 0.0 0
------------------------------------------------------------
Springfield, IL 12 0.0 0
------------------------------------------------------------
WVPA 2 0.0 0
------------------------------------------------------------
IMPA 0 0.0 0
------------------------------------------------------------
Pre Merger Total 73,228 GWH 100% 846
------------------------------------------------------------
------------------------------------------------------------
Increase in HHI [2 * UE Share * CIPS Share] 105
------------------------------------------------------------
------------------------------------------------------------
Post Merger Total 951
------------------------------------------------------------
</TABLE>
Source: Workpapers
<PAGE>
EXHIBIT (RWF-17)
NON FIRM ENERGY SALES BY
UE, CIPS AND INTERCONNECTED UTILITIES
ALL TRANSACTIONS
1994
<TABLE>
<CAPTION>
----------------------------------------------------
SELLER Sales Share HHI
(1) (2) (3) (4)
<S> <C> <C> <C>
----------------------------------------------------
AEP 7,688 GWH 11.8% 139
----------------------------------------------------
CE 6,976 10.7 114
----------------------------------------------------
UE 6,443 9.9 97
----------------------------------------------------
TVA 6,314 9.7 94
----------------------------------------------------
CINergy 4,878 7.5 56
----------------------------------------------------
NSP 4,841 7.4 55
----------------------------------------------------
KCPL 4,207 6.4 42
----------------------------------------------------
IP 3,797 5.8 34
----------------------------------------------------
CIPS 3,767 5.8 33
----------------------------------------------------
AEC 3,405 5.2 27
----------------------------------------------------
Entergy 3,404 5.2 27
----------------------------------------------------
KU 2,214 3.4 11
----------------------------------------------------
MEC 1,895 2.9 8
----------------------------------------------------
WR 1,698 2.6 7
----------------------------------------------------
IES 1,137 1.7 3
----------------------------------------------------
CSW 1,001 1.5 2
----------------------------------------------------
CILCO 359 0.5 0
----------------------------------------------------
IPW 277 0.4 0
----------------------------------------------------
NIPSCO 253 0.4 0
----------------------------------------------------
SIPCO 249 0.4 0
----------------------------------------------------
SJLP 222 0.3 0
----------------------------------------------------
MoPub 158 0.2 0
----------------------------------------------------
Springfield, IL 52 0.1 0
----------------------------------------------------
IMEA 44 0.1 0
----------------------------------------------------
WVPA 12 0.0 0
----------------------------------------------------
Pre Merger Total 65,290 GWH 100% 751
----------------------------------------------------
----------------------------------------------------
Increase in HHI [2* UE Share* CIPS Share] 114
----------------------------------------------------
----------------------------------------------------
Post Merger Total 864
----------------------------------------------------
Source: Workpapers
</TABLE>
<PAGE>
Exhibit D-2.1
BEFORE THE PUBLIC SERVICE COMMISSION
STATE OF MISSOURI
In the matter of the Application of Union Electric )
Company for an order authorizing: (1) certain )
merger transactions involving Union Electric )
Company; (2) the transfer of certain Assets, Real ) Case No. EM-96-149
Estate, Leased Property, Easements and Contractual )
Agreements to Central Illinois Public Service )
Company; and (3) in connection therewith, certain )
other related transactions. )
APPLICATION
-----------
COMES NOW Union Electric Company ("UE"), a Missouri corporation, and for
its Application to the Missouri Public Service Commission ("Commission"),
pursuant to Chapter 393, RSMo. 1994, and 4 CSR 240-2.060(3) & (4), for an order
authorizing: (1) certain merger transactions involving Union Electric Company;
(2) the transfer of certain Assets, Real Estate, Leased Property, Easements and
Contractual Agreements; and (3) in connection therewith, certain other related
transactions, respectfully states as follows:
1. UE is a Missouri corporation, in good standing in all respects, with
its principal office and place of business located at 1901 Chouteau Avenue, St.
Louis, Missouri 63103. UE is engaged in providing electric, gas and steam
heating services in portions of Missouri as a public utility under the
jurisdiction of the Commission. UE is also engaged in providing electric and
gas service in portions of Illinois. There is already on file with the
Commission a certified copy of UE's Articles of Incorporation and Certificate of
Corporate Good Standing (see MPSC Case No. EA-87-105) and said documents are
incorporated herein by reference and made a part hereof for all purposes.
<PAGE>
2. CIPSCO Incorporated ("CIPSCO") is an Illinois corporation and the
parent corporation to its wholly-owned subsidiary Central Illinois Public
Service Company ("CIPS"). CIPS is an electric and gas utility in the State of
Illinois and is an Illinois corporation. In addition, CIPSCO is the parent
corporation to its wholly-owned subsidiary CIPSCO Investment Company ("CIPSCO
Investment"). CIPSCO Investment is an Illinois corporation and manages
approximately $100 million in non-utility investments.
3. Arch Merger, Inc. ("Arch Merger") is a newly formed Missouri
Corporation and a wholly-owned subsidiary of Ameren Corporation ("Ameren").
Ameren is also a newly formed Missouri corporation which is owned 50 percent by
UE and 50 percent by CIPSCO. Arch Merger and Ameren were formed for the purpose
of facilitating the merger.
4. Pleadings, notices, orders and other correspondence concerning this
Application and proceeding should be addressed to:
Steven R. Sullivan
Attorney
Union Electric Company
P.O. Box 149 (MC 1310)
1901 Chouteau Ave.
St. Louis, MO 63166
5. Pursuant to the terms and conditions of the "Agreement and Plan of
Merger" between UE and CIPSCO dated August 11, 1995 (the "Agreement"), a copy of
which is attached to the testimony of Mr. Gary L. Rainwater and is being filed
simultaneously herewith, Arch Merger will be merged with and into UE, and CIPSCO
will be merged with and into Ameren. The final resulting corporate structure
will be that UE, CIPS and CIPSCO Investment will become wholly-owned
subsidiaries of Ameren (collectively, the
2
<PAGE>
"Merger Transactions"). The Merger Transactions are intended to result in a
tax-free exchange and will be accounted for as a "pooling of interests".
6. As a result of the Merger Transactions, each outstanding share of UE
Common Stock will be converted into the right to receive one share of Ameren
Common Stock, and each outstanding share of CIPSCO Common Stock will be
converted into the right to receive 1.03 shares of Ameren Common Stock. After
the Mergers, Ameren will become a registered public utility holding company
under the Public Utility Holding Company Act of 1935.
7. Subject to the terms and conditions of the Agreement, UE will
transfer to CIPS certain Assets, Real Estate, Leased Property, Easements and
Contractual Agreements (collectively herein described as "Assets") which Assets
generally constitute UE's retail electric and gas systems located in the State
of Illinois which are necessary or useful in the performance of UE's duties to
the Illinois public within its Illinois service territory with respect to the
provision of retail electric and gas service (the "Transfer Transaction"). A
list of the Assets being transferred is attached hereto as Schedule A and is
incorporated herein by reference. The transfer does not include any of UE's
electric transmission or generating assets located in the State of Illinois and
does not include any assets located in the State of Missouri.
8. The transfer of the Assets by UE to CIPS will be at depreciated cost
or "book value" so that no gain or loss will result from the transaction. As
consideration for the Transfer Transaction, UE and CIPS will enter into a System
Support Agreement for the sale
3
<PAGE>
of approximately 600 mW (a portion being firm and non-firm) and related energy
and an amendment to the Interconnection Agreement between UE, Illinois Power and
CIPS. The System Support Agreement and amendment to the Interconnection
Agreement will be submitted to the Federal Energy Regulatory Commission ("FERC")
for approval. The System Support Agreement will provide for sales of electricity
substantially equivalent to the customer load for the Illinois customers of UE
being transferred to CIPS and will be for a minimum term of 30 years.
Accordingly, no detriment to Missouri ratepayers will result from the Transfer
Transaction.
9. The Transfer and Merger Transactions will not result in any immediate
change in UE's Missouri electric or gas rates.
10. The Transfer Transaction and Merger Transactions are not detrimental
to the public interest because: (1) UE anticipates that the combined savings
achieved in the first ten years following consummation of these transactions
will amount to $590 million, a substantial portion of which will be realized in
Missouri; (2) the transfer of the Assets will not result in any increased costs
to UE's Missouri customers, since UE's power pool costs now allocated to
Illinois customers will remain with Illinois customers through a wholesale power
sale to CIPS; and (3) the transfer of the Assets will not result in any reduced
level of service or reliability for those retail customers presently being
served by UE in Missouri subject to the jurisdiction of the Commission.
11. The $590 million in savings will be achieved primarily through: (1)
eliminating duplication in corporate and administrative services; (2) joint
dispatch (i.e., dispatching UE
4
<PAGE>
and CIPS electric generation as though it were a single system); and (3)
decreased gas reserve margins and lower pipeline demand charges.
12. The costs necessary to complete the above-referenced transactions and
to create the anticipated $590 million in savings over the first ten years
following completion of the merger amount to approximately $273 million. The
vast majority of these costs have occurred or will occur within the first two
years following completion of the merger. UE requests that a ratable portion of
these costs be offset against merger savings attributable to the Company's
Missouri electric and gas operations and that the remaining merger savings be
shared equally with ratepayers during the first 10 years following the merger.
UE and CIPS will seek comparable cost of service treatment in Illinois and at
the FERC. UE requests no specialized treatment for the merger-related savings
that will occur following this initial ten-year period.
13. As a result of the Transfer Transaction and related System Support
Agreement between UE and CIPS, UE will seek FERC approval to transfer the future
nuclear decommissioning trust funding obligations which are currently the
responsibility of the UE's Illinois electric customers to its FERC-regulated
wholesale customers. UE and CIPS will also enter into a Joint Dispatch agreement
which will govern the joint dispatch of their generating systems and a General
Services agreement governing the performance of intercompany services. The Joint
Dispatch Agreement and System Support Agreement will both be filed with FERC.
The General Services Agreement will be filed with the SEC.
14. A certified copy of the resolutions of the Board of Directors of UE
authorizing
5
<PAGE>
the consummation of the transactions contemplated by this Application is
attached hereto as Schedule B and made a part hereof.
15. UE's balance sheet and income statement, with adjustments showing the
results of the transfer of the Illinois properties, is attached hereto as
Schedule C and made a part hereof for all purposes.
16. None of the assets to be transferred are located within the State of
Missouri. Therefore, the proposed transaction will have no impact on the tax
revenues of the political subdivisions in Missouri in which any of UE's
structures, facilities or equipment are located.
17. Regulatory approvals of the proposed merger, transfer and assignment
of the Assets and various other matters will be sought from the FERC, the
Illinois Commerce Commission, the Nuclear Regulatory Commission, and the
Securities Exchange Commission. The merger is subject to the review of the
Federal Trade Commission and Department of Justice.
18. Closing of the sale will take place as promptly as possible after all
regulatory approvals are obtained; provided, however, that the parties have
proposed December 31, 1996, as the closing date. If all regulatory approvals
have been received, the parties would close sooner than December 31, 1996.
Although the projected closing is more than one year away, UE and CIPS desire to
close on the Transfer Transaction and Merger Transactions as promptly as
possible and, therefore, UE respectfully requests that this Application be
expedited to the extent possible under the Commission's schedule. In order to
facilitate a 1996 closing, and in light of the fact that some federal agencies
will not act on an
6
<PAGE>
application until all state approvals have been received, UE respectfully
requests an Order of this Commission no later than May 1, 1996.
WHEREFORE, UE respectfully requests that the Commission issue its order:
(a) Authorizing UE to perform in accordance with the terms and conditions
of the Agreement;
(b) Authorizing the Merger Transactions;
(c) Approving as reasonable and prudent the consideration received by UE
from CIPS for the Assets;
(d) Authorizing UE to transfer the Assets (as listed on Schedule A hereto)
to CIPS, which Assets generally constitute UE's Illinois-based franchise, works
or system as are necessary or useful in the performance of UE's duties to the
public within the Illinois service territory with respect to the provision of
retail electric and gas service in Illinois, but excluding any of UE's
transmission or generating assets located in the State of Illinois;
(e) Authorizing UE to offset a ratable portion of the merger costs against
merger savings attributable to the Company's Missouri electric and gas
operations and to share equally with ratepayers the remaining merger savings
during the 10 years following the merger;
(f) Authorizing UE to enter into, execute and perform in accordance with
the terms of all other documents reasonably necessary and incidental to the
performance of the transactions which are the subject of the Agreement and this
Application; and
(g) Granting such other relief as deemed necessary to accomplish the
purposes
7
<PAGE>
of the Agreement and this Application and to consummate the sale, transfer and
assignment of the Assets and related transactions.
UE respectfully requests that this Application be processed as
expeditiously as possible. Both UE and CIPS are anxious to close as promptly as
possible and plan to do so as soon as all necessary regulatory approvals are
obtained.
Respectfully submitted,
UNION ELECTRIC COMPANY
/s/ Steven R. Sullivan
------------------------------
Steven R. Sullivan
Joseph H. Raybuck
James J. Cook
Attorneys for
Union Electric Company
P.O. Box 149 (M/C 1310)
St. Louis, MO 63166
PH: (314) 554-2514
PH: (314) 554-2976
PH: (314) 554-2237
FAX: (314) 554-4014
8
<PAGE>
VERIFICATION
------------
STATE OF MISSOURI )
) SS
CITY OF ST. LOUIS )
Donald E. Brandt, first being duly sworn, states that he is the Senior Vice
President of Finance & Corporate Services of Union Electric Company and that he
has read the above and foregoing document and states that the allegations
contained therein are true and correct to the best of his information, knowledge
and belief.
/s/ Donald E. Brandt
-----------------------------
Donald E. Brandt
IN WITNESS WHEREOF, I have set my hand and affixed my official seal on this
2nd day of November, 1995.
G.L. Waters
------------------------------
Notary Public
My Commission Expires: 3/16/99
-------------------
9
<PAGE>
EXHIBIT D-2.3
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF MISSOURI
In the matter of the application of )
Union Electric Company for an order )
authorizing (1) certain merger )
transactions involving Union )
Electric Company; (2) the transfer )
of certain assets, real estate, ) Case No. EM-96-149
leased property, easements and )
contractual agreements to Central )
Illinois Public Service Company; )
and (3) in connection therewith, )
certain other related transactions. )
- --------------------------------------------------------------------------------
STIPULATION AND AGREEMENT
- --------------------------------------------------------------------------------
Dated: July 12, 1996
<PAGE>
TABLE OF CONTENTS
1. Approval of the Merger .................................................. 1
2. Merger Premium .......................................................... 2
3. Merger Benefits and Savings ............................................. 2
4. Transaction and Transition Costs ........................................ 2
5. Retail Wheeling Experiment .............................................. 3
6. Rate Reduction .......................................................... 5
7. New Experimental Alternative Regulation Plan (New Plan) ................. 7
8. State Jurisdictional Issues ............................................ 22
a. Access to Books, Records and Personnel............................ 22
b. Voluntary and Cooperative Discovery Practices .................... 23
c. Accounting Controls............................................... 23
d. Contracts Required to be Filed with the SEC....................... 24
e. Electric Contracts Required to be Filed with the
FERC.............................................................. 25
f. Gas Contracts Required to be Filed with the FERC.................. 26
g. No Pre-Approval of Affiliated Transactions........................ 27
h. Contingent Jurisdictional Stipulation -- FERC..................... 27
i. Contingent Jurisdictional Stipulation -- SEC...................... 28
9. Staff Conditions To Which UE Has Agreed................................. 29
10. System Support Agreement................................................ 33
11. Commission Rights....................................................... 34
12. Staff Rights............................................................ 34
13. No Acquiescence......................................................... 36
14. Negotiated Settlement................................................... 36
15. Provisions Are Interdependent........................................... 37
i
<PAGE>
16. Prepared Testimony.................................................... 37
17. Waive Rights to Cross Examination, etc. .............................. 38
18. Operative Dates....................................................... 39
Attachment A: PROCEDURES TO DETERMINE RATE REDUCTION
Attachment B: PROCEDURES FOR SHARING CREDITS FROM THE NEW THREE-YEAR
EXPERIMENTAL ALTERNATIVE REGULATION PLAN
Attachment C: RECONCILIATION PROCEDURE
Attachment D: CONTINGENT JURISDICTIONAL STIPULATION -- SEC AND FERC
ii
<PAGE>
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF MISSOURI
In the matter of the application of )
Union Electric Company for an order )
authorizing (1) certain merger )
transactions involving Union )
Electric Company; (2) the transfer )
of certain assets, real estate, ) Case No. EM-96-149
leased property, easements and )
contractual agreements to Central )
Illinois Public Service Company; )
and (3) in connection therewith, )
certain other related transactions. )
STIPULATION AND AGREEMENT
-------------------------
As a result of discussions among the parties to Case No. EM-96-149, the
signatories hereby submit to the Missouri Public Service Commission
("Commission") for its consideration and approval the following, including
actions to be taken by Union Electric Company ("UE") and the other signatories
in settlement of the above styled case:
1. Approval of the Merger
The signatories agree that the Commission should approve the merger as
requested in UE's filing dated November 7, 1995, on the basis that, subject to
the conditions and modifications set forth below, said merger is not detrimental
to the public interest.
1
<PAGE>
2. Merger Premium
UE shall not seek to recover the amount of any asserted merger premium in
rates in any Missouri proceeding. UE has identified this amount as $232 million.
3. Merger Benefits and Savings
UE shall retain the right to state, in future proceedings, alleged benefits
of the merger but UE commits to forego any additional specific adjustments to
cost of service related to the merger savings or any claim to merger savings
other than the adjustments to cost of service and claims to merger savings
resulting from the Commission's approval of this document or the benefits and
savings which would occur through regular ratemaking treatment or the current
Experimental Alternative Regulation Plan ("ARP") or the new Experimental
Alternative Regulation Plan ("the New Plan") effective July 1, 1998 pursuant to
this document.
4. Transaction and Transition Costs
Actual prudent and reasonable merger transaction and transition costs
(estimated to be $71.5 million, which reflects the total Ameren Corporation
("Ameren") estimated merger costs presented to the Commission Staff ("Staff")
and Office of the Public Counsel ("OPC") in the UE/CIPSCO, Inc. Merger
Implementation Plan, less executive severance pay of $1.6 million,
2
<PAGE>
but including costs incurred in 1995) shall be amortized over ten years
beginning the date the merger closes. The annual amortization of merger
transaction and transition costs will be the lesser of: (1) the Missouri
jurisdictional portion of the total Ameren amount of $7.2 million; or (2) the
Missouri jurisdictional portion of the total Ameren unamortized amount of actual
merger transaction and transition costs incurred to date. No rate base treatment
of the unamortized costs will be included in the determination of rate base for
any regulatory purposes in Missouri.
5. Retail Wheeling Experiment
As a result of settlement negotiations, UE commits that it will propose and
file with the Commission an experimental retail wheeling pilot program for 100
MW of electric power, to be available to all major classes of Missouri retail
electric customers, as soon as practical, but no later than March 1, 1997. The
commitment to file such a pilot program for Commission consideration and
determination covered by this provision is made by UE alone. Prior to filing
its proposal with the Commission, UE will seek substantive input from Missouri
retail electric customers, Staff, OPC and others (including, but not limited to,
Trigen - St. Louis Energy Corp. and Missouri Retailers Association). If
permitted by the Commission's Order, UE shall
3
<PAGE>
implement the retail wheeling pilot program as approved by the Commission so as
to allow power purchase transactions to commence within sixty (60) days of the
effective date of the Commission's Order or as soon as practicable thereafter,
but in no event before the merger closes (except with the consent of UE and the
approval of the Commission).
The commitment covered by this provision should not be construed as
concurrence or acquiescence by the signatories in the specifics of the retail
wheeling pilot program which will be filed by UE, the details of which are to be
determined by UE based in part on a consideration of the substantive input
referred to above. The non-objection of signatories to UE's commitment to file a
retail wheeling pilot program should not be construed as a waiver of the
signatories' right to contest the proposed retail wheeling pilot program before
the Commission; nor are the signatories precluded from seeking a writ of review,
appealing a Commission Order or pursuing any other appropriate legal remedy. The
signatories agree not to attempt to enjoin the Commission from considering and
issuing an Order respecting UE's proposal. UE commits not to appeal the
Commission's Order establishing a retail wheeling pilot program unless said
Order is significantly different from the UE filing and UE is materially and
adversely affected
4
<PAGE>
thereby. Furthermore, Commission approval of the instant Stipulation And
Agreement containing this provision is not intended by the signatories to be
read as a Commission pronouncement of any sort respecting retail wheeling either
in general, as public policy, or in specific, as a regulatory mechanism.
If such a retail wheeling pilot program is instituted, matters which affect
the calculation of where UE falls on the "Sharing Grid" of the ARP or the New
Plan may arise which will need to be resolved by agreement of the signatories to
this Stipulation And Agreement, or by the Commission if agreement cannot be
reached.
A signatory to this Stipulation And Agreement shall be made a party in the
retail wheeling pilot program proceeding, as a matter of right, if it so
requests.
6. Rate Reduction
Earnings monitoring in Case No. EO-96-14 will result in a general change in
rates charged and revenues collected after August 31, 1998. The change in
revenues collected will be equal to the average annual total revenues credited
to customers during the three ARP years ending June 30, 1998, adjusted to
reflect normal weather. The procedures to determine the adjustment to the
annual credits for the three years comprising the ARP are set forth in
Attachment A appended hereto. Any rate reduction shall be spread
5
<PAGE>
within and among revenue classes on the basis of the Commission decision in Case
No. EO-96-15, which is the UE customer class cost of service and comprehensive
rate design docket created as a result of Case No. ER-95-411. In the event that
a Commission decision has not been reached in Case No. EO-96-15, the parties
will jointly or severally propose to the Commission a basis or bases on which a
rate reduction may be spread on an interim basis within and among the classes
pending issuance of the Commission's decision in Case No. EO-96-15.
UE will make a good faith effort to provide the earnings report for the
final sharing period in Case No. ER-95-411 in time to implement this rate
reduction on September 1, 1998. In the event the earnings data is not
available, or in the event the review process of the earnings data or the
weather normalization review process does not allow for a September 1, 1998
effective date, the following will occur: An additional credit, equal to the
excess revenues billed between September 1, 1998 and the effective date of the
rate reduction, will be made. Said credit will be made at the same time and
pursuant to the same procedures as the Sharing Credits in Case Nos. ER-95-411
and EO-96-14. If no Sharing Credits are to be made for the third Sharing Period
in Case Nos. ER-95-411
6
<PAGE>
and EO-96-14, the excess revenue credit will be made as expeditiously as
possible.
UE shall file tariff sheets for Commission approval consistent with this
Section.
7. New Experimental Alternative Regulation Plan (New Plan)
a. The New Plan will be instituted July 1, 1998 at the end of the ARP
created in Case No. ER-95-411. In its Report And Order approving this
Stipulation And Agreement, the Commission shall create a new docket
to facilitate the New Plan ("New Plan Docket"). All signatories to
this Stipulation And Agreement shall be made parties to the New Plan
Docket, as intervenors or as a matter of right, as will the parties
to Case No. EO-96-14 who are not parties to Case No. EM-96-149,
without the necessity of taking further action. (There are three such
parties: (1) Asarco Inc. and the Doe Run Co.; (2) Cominco American;
and (3) Missouri Retailers Association.)
7
<PAGE>
b. The following Sharing Grid is to be utilized as part of the New Plan:
================================================================================
Earnings Level Sharing Sharing
(Missouri Retail Electric Operations) Level Level
- --------------------------------------------------------------------------------
UE Customer
- --------------------------------------------------------------------------------
1. Up to and including 12.61% 100% 0%
Return on Equity (ROE)
- --------------------------------------------------------------------------------
2. That portion of earnings greater 50% 50%
than 12.61% up to and including
14.00% ROE
- --------------------------------------------------------------------------------
3. That portion of earnings greater 10% 90%
than 14.00% up to and including
16.00% ROE
- --------------------------------------------------------------------------------
4. That portion of earnings greater 0% 100%
than 16.00% ROE
================================================================================
c. The New Plan will be in effect for a full three year period. For purposes
of this New Plan, there shall be three (3) "Sharing Periods." The first
Sharing Period shall be from July 1, 1998 through June 30, 1999; the
second, from July 1, 1999 through June 30, 2000; and the third, from July
1, 2000 through June 30, 2001. UE may not file an electric rate increase
case, and Staff, OPC and other signatories may not file, encourage or
assist others to file a rate reduction case through June 30, 2001, unless:
8
<PAGE>
i. UE's return on common equity falls below 10.00% for a twelve
month Sharing Period (calculated as indicated in Attachment C
appended hereto); or
ii. An event occurs which would have a major effect on UE, such as,
an act of God, a significant change in the federal or state tax
laws, a significant change in federal or state utility law or
regulation (but not including the retail wheeling pilot project
described in Section 5), or an extended outage or shutdown of a
major generating unit(s).
In the event UE files an electric rate increase case, any
sharing credits due for the current or prior Sharing Period will
remain the obligation of UE, and the New Plan shall terminate at the
conclusion of the then current Sharing Period.
In the event any signatory files a rate reduction case, any
sharing credits due for the current or prior Sharing Period will
remain the obligation of UE, and the parties to that case will
recommend to the Commission whether the New Plan should remain in
effect as currently structured, be modified or terminated.
9
<PAGE>
In the event that a significant change in federal or state
utility law or regulation (but not including the retail wheeling pilot
project described in Section 5) occurs, nothing herein shall prohibit
any signatory from filing for Commission consideration a customer
class cost of service and comprehensive rate design proposal, either
as a part of or separate from a rate increase or rate reduction case;
provided that any party may oppose such filing and shall not be deemed
to have consented either to the establishment of a new docket to
consider such request or to the proposals of the party making such
request.
Upon any termination of the New Plan pursuant to the foregoing,
the signatories will have no further obligation under this Section 7.
d. Except as set out immediately above in Subsection c. and below in
Subsection h. and Subsection i., UE's rates resulting from this
Stipulation And Agreement will continue in effect throughout the three
year New Plan period, and thereafter, until changed as a result of a
rate increase case, a rate reduction case, or other
10
<PAGE>
appropriate Commission action, for example, as contemplated by
Subsection g. below.
e. Monitoring of the New Plan will be based on UE supplying to Staff and
OPC, on a timely basis, the reports and data identified below. These
reports and data must be provided as part of the New Plan. Other
signatories to this Stipulation And Agreement may also participate in
the monitoring of the New Plan, and receive the reports and data,
after executing appropriate documents assuring the confidential
treatment of the information provided. Staff, OPC and the other
signatories participating in the monitoring of the New Plan may follow
up with data requests, meetings and interviews, as required, to which
UE will respond on a timely basis. UE will not be required to develop
any new reports, but information presently being recorded and
maintained by UE may be requested. The reports and data that must be
provided include the following:
i. Annual operating and construction budgets and any
updates/revisions with explanations/reasons for
updates/revisions;
11
<PAGE>
ii. Monthly operating budgets and any updates/revisions with
explanations/reasons for updates/revisions;
iii. Annually - explanation of significant variances between budgets
and actual;
iv. Monthly Financial & Statistical (F&S) reports;
v. Directors reports;
vi. Current chart of accounts;
vii. Monthly surveillance reports;
viii. Quarterly reports/studies of rate of return on rate base
including supporting workpapers;
ix. Annual summary of major accruals.
f. The sharing of earnings in excess of 12.61%, as contemplated by the
Sharing Grid set out above, is to be accomplished by the granting of a
credit to UE's Missouri retail electric customers by applying credits
to customers' bills in the same manner as applied in Case No. ER-95-
411, and as set forth in Attachment B. A notice to customers
explaining the Sharing Credits will accompany customers' bills on
which the Sharing Credits will appear. UE will submit the proposed
language for such notice to the Staff and the OPC for their review.
12
<PAGE>
i. The return on common equity for determination of "sharing" will
be calculated by using the methodology set out in Attachment C,
Reconciliation Procedure, appended hereto.
ii. Staff, OPC and UE have conferred and determined what items,
based on prior Commission Orders, should be excluded from the
calculation of UE's return on equity. These items are
identified in Attachment C.
iii. The twelve month period used to determine credits will be the
immediately preceding Sharing Period.
iv. Within 90 days after the conclusion of a Sharing Period, a
preliminary earnings report, along with a proposed "Sharing
Report" will be submitted by UE. A final earnings report and
proposed Sharing Report will be filed in the New Plan Docket
within 105 days after the end of the Sharing Period. The final
earnings report will provide the actual results of the Sharing
Period to be examined.
v. UE's earnings will be adjusted to normalize the effects of any
sharing credits from the Sharing
13
<PAGE>
Period which are reflected in the earnings for that period.
Earnings will not be adjusted for the rate reduction described
in "Section 6. Rate Reduction" of this Stipulation And
Agreement.
vi. If Staff, OPC or other signatories find evidence that operating
results have been manipulated to reduce amounts to be shared
with customers or to misrepresent actual earnings or expenses,
Staff, OPC or other signatories may file a complaint with the
Commission requesting that a full investigation and hearing be
conducted regarding said complaint. UE shall have the right to
respond to such request and present facts and argument as to
why an investigation is unwarranted.
vii. UE, Staff, OPC and other signatories reserve the right to bring
issues which cannot be resolved by them, and which are related
to the operation or implementation of the New Plan, to the
Commission for resolution. Examples include disagreements as to
the mechanics of calculating the monitoring report, alleged
violations of the Stipulation And
14
<PAGE>
Agreement, alleged manipulations of earnings results, or
requests for information not previously maintained by UE. An
allegation of manipulation could include significant variations
in the level of expenses associated with any category of cost,
where no reasonable explanation has been provided. The
Commission will determine in the first instance whether a
question of manipulation exists and whether that question
should be heard by it.
viii. Staff, OPC and other signatories have the right to present to
the Commission concerns over any category of cost that has been
included in UE's monitoring results and has not been included
previously in any ratemaking proceeding.
ix. Differences among UE, Staff, OPC and other signatories will be
brought to the Commission's attention for guidance as early in
the process as possible.
x. A final report will be filed within 105 days after the Sharing
Period (or the first business day thereafter). Signatory
parties to this
15
<PAGE>
Stipulation And Agreement will have thirty (30) days after a
final report is filed to provide notice that there may be areas
of disagreement not previously brought to the attention of the
Commission that need to be resolved.
g. In the final year of the New Plan, UE, Staff, OPC and other
signatories to this Stipulation And Agreement shall meet to review the
monitoring reports and additional information required to be provided.
By February 1, 2001, UE, Staff and OPC will file, and other
signatories may file their recommendations with the Commission as to
whether the New Plan should be continued as is, continued with changes
(including new rates, if recommended) or discontinued. Copies of the
recommendations shall be served on all parties to UE's New Plan
Docket. As previously noted herein, the rates resulting from this
Stipulation And Agreement will continue in effect after the three year
New Plan period until UE's rates are changed as a result of a rate
increase case, a rate reduction case, or other appropriate Commission
action.
h. After July 1, 1998, any party may file with the Commission a request
for consideration of changes in rate
16
<PAGE>
design and/or other tariff provisions which it would be appropriate
for the Commission to consider outside the context of a customer class
cost of service and comprehensive rate design docket or a rate case;
provided, however, that no change will result in any shift of revenues
among classes before July l, 2001; and provided further that if a
request for consideration of changes in rate design and/or other
tariff provisions is filed, any party may oppose such request and
shall not be deemed to have consented to the establishment of a new
docket to consider such request or to the proposals of the party
making such request.
A change in rate design and/or other tariff provisions is not
considered by the signatories to this Stipulation And Agreement as
constituting a shift of revenues among customer classes if it will
result in a customer or customers being charged lower rates but will
not result in either (1) a major decrease in revenues to UE
(respecting which UE is precluded by this section from recovering from
other customers at any time while the New Plan is in effect) or (2) a
significant reduction in the credits that would otherwise be available
for
17
<PAGE>
distribution. It may be argued by a signatory to this Stipulation And
Agreement that the cumulative effect of multiple changes in rate
design and/or other tariff provisions which results in either (1) a
major decrease in revenues to UE (respecting which UE is precluded
from recovering from other customers at any time while the New Plan is
in effect), or (2) a significant reduction in credits that would
otherwise be available for distribution, constitutes a shift of
revenues among customer classes and, therefore, the proposed change(s)
is precluded.
How revenues foregone by UE as a result of a change in rate
design and/or other tariff provisions will be treated for purposes of
the New Plan Reconciliation Procedure (Attachment C), which impacts
the calculation of where UE falls on the Sharing Grid, will be
determined on a case-by-case basis by agreement of the signatories to
this Stipulation And Agreement, or by the Commission if agreement
cannot be reached. Furthermore, such foregone revenues shall not be
excluded from any calculation of UE's return on common equity for
purposes of determining whether UE may file an electric rate
18
<PAGE>
increase under the terms of this Stipulation And Agreement or increase
its Missouri retail electric service rates to reflect a Commission
Order authorizing an increase in UE's annual nuclear decommissioning
expense/funding from its then current level.
This section is not intended to preclude presentation to the
Commission and Commission resolution of disputes respecting the proper
application of UE's tariffs; nor is this section intended to preclude
presentation to the Commission and Commission resolution of a proposed
major decrease in revenues to UE, and/or significant reduction in
credits that would otherwise be available for distribution, requested
as a result of a situation which will have a significant adverse
impact on one or more of UE's customers and which, as a consequence,
will also have a significant adverse impact on UE and its customers;
provided that any party may oppose such request and shall not be
deemed to have consented to the establishment of a new docket to
consider such request or to the proposals of the party making such
request.
19
<PAGE>
i. UE will file its cost of nuclear decommissioning study with the
Commission as required by September 1, 1999. If the Commission Order
in that proceeding results in a decrease in annual nuclear
decommissioning expense/funding from its then current level, UE's
Missouri retail electric service rates will not be changed to reflect
the decrease in expense/funding. Instead, nuclear decommissioning
expense/funding will be decreased (effective as of the date provided
in the nuclear decommissioning cost Order) with the total difference,
i.e., 100% of the pro-rated difference, between the lower
expense/funding level and the then current level, being treated as a
credit to each Sharing Period of the New Plan as provided for in
Attachment C hereto. If no sharing occurs for a Sharing Period for
which there is a decrease in the nuclear decommissioning
expense/funding level, then the decrease in the nuclear
decommissioning expense/funding for that Sharing Period will be
carried over to the subsequent Sharing Period. Since the difference
between the prospective lower expense/funding level and the then
current level will be treated as a credit in each Sharing Period and
the
20
<PAGE>
difference will be carried over to the subsequent Sharing Period
if no sharing occurs for the current Sharing Period, no decrease in
the then current expense level will be reflected in the calculation of
UE's ROE in determining sharing under the New Plan, pursuant to
Attachment C.
If the Commission Order in the nuclear decommissioning
proceeding results in an increase in expense/funding above its then
current level, for purposes of determining the implementation of a
rate increase only, the increased expense will be annualized in
calculating UE's return on equity for the earliest possible Sharing
Period for which a preliminary earnings/proposed sharing report has
not yet been filed at the time of the issuance of the Commission Order
in the nuclear decommissioning docket. If UE's return on common equity
(ROE) on this basis is less than 10.00% (calculated as indicated in
Attachment C appended hereto), then the increased expense will result
in an increase in UE's Missouri retail electric service rates as
allowed by Section 393.292 RSMo. 1994. If UE's ROE on the above basis
exceeds 10.00%, then the increased
21
<PAGE>
expense will not result in any increase in UE's Missouri retail
electric service rates; however, the actual amount of increased
expense (unannualized) will be reflected in the calculation of UE's
ROE in determining sharing under the New Plan.
In any case, the Commission shall include language in its 1999
Callaway decommissioning case Report And Order substantially similar
to that used in Case No. EO-94-81, specifically finding that the
Callaway decommissioning costs are included in UE's then current cost
of service and are reflected in its then current electric service
rates for ratemaking purposes.
All signatories will be notified of UE's filing of its 1999
nuclear decommissioning cost case.
8. State Jurisdictional Issues
a. Access to Books, Records and Personnel. UE and its prospective
holding company, Ameren, agree to make available to the Commission, at
reasonable times and places, all books and records and employees and
officers of Ameren, UE and any affiliate or subsidiary
22
<PAGE>
of Ameren shall have the right to object to such production of records
or personnel on any basis under applicable law and Commission rules,
excluding any objection that such records and personnel are not
subject to Commission jurisdiction by operation of the Public Utility
Holding Company Act of 1935 ("PUHCA"). In the event that rules
imposing any affiliate guidelines regarding access to books, records
and personnel applicable to similarly situated electric utilities in
Missouri are adopted, then UE, Ameren and each affiliate or subsidiary
thereof shall become subject to the same rules as such other similarly
situated electric utilities in lieu of this paragraph.
b. Voluntary and Cooperative Discovery Practices. UE, Ameren and any
affiliate or subsidiary thereof agree to continue voluntary and
cooperative discovery practices.
c. Accounting Controls. UE, Ameren and each of its affiliates and
subsidiaries shall employ accounting and other procedures and controls
related to cost allocations and transfer pricing to ensure and
facilitate full review by the Commission and to protect against cross-
subsidization of non-UE Ameren businesses by UE's retail
23
<PAGE>
customers. In the event that rules imposing any affiliate guidelines
regarding accounting controls applicable to similarly situated
electric utilities in Missouri are adopted, then UE, Ameren and each
affiliate or subsidiary thereof shall become subject to the same rules
as such other similarly situated electric utilities in lieu of this
paragraph.
d. Contracts Required to be Filed with the SEC. All contracts,
agreements or arrangements, including any amendments thereto, of any
kind between UE and any affiliate, associate, holding, mutual service,
or subsidiary company within the same holding company system, as these
terms are defined in 15 U.S.C. (S) 79b, as subsequently amended,
required to be filed with and/or approved by the Securities and
Exchange Commission ("SEC") pursuant to PUHCA, as subsequently
amended, shall be conditioned upon the following without modification
or alteration: UE and Ameren and each of its affiliates and
subsidiaries will not seek to overturn, reverse, set aside, change or
enjoin, whether through appeal or the initiation or maintenance of any
action in any forum, a decision or order of the Commission which
pertains to
24
<PAGE>
recovery, disallowance, deferral or ratemaking treatment of any
expense, charge, cost or allocation incurred or accrued by UE in or as
a result of a contract, agreement, arrangement or transaction with any
affiliate, associate, holding, mutual service or subsidiary company on
the basis that such expense, charge, cost or allocation has itself
been filed with or approved by the SEC or was incurred pursuant to a
contract, arrangement, agreement or allocation method which was filed
with or approved by the SEC.
e. Electric Contracts Required to be Filed with the FERC. All wholesale
electric energy or transmission service contracts, tariffs, agreements
or arrangements, including any amendments thereto, of any kind,
including the Joint Dispatch Agreement, between UE and any Ameren
subsidiary or affiliate required to be filed with and/or approved by
the Federal Energy Regulatory Commission ("FERC"), pursuant to the
Federal Power Act("FPA"), as subsequently amended, shall be
conditioned upon the following without modification or alteration: UE
and Ameren and each of its affiliates and subsidiaries will not seek
to overturn, reverse, set aside, change or enjoin, whether
25
<PAGE>
through appeal or the initiation or maintenance of any action in any
forum, a decision or order of the Commission which pertains to
recovery, disallowance, deferral or ratemaking treatment of any
expense, charge, cost or allocation incurred or accrued by UE in or as
a result of a wholesale electric energy or transmission service
contract, agreement, arrangement or transaction on the basis that such
expense, charge, cost or allocation has itself been filed with or
approved by the FERC, or was incurred pursuant to a contract,
arrangement, agreement or allocation method which was filed with or
approved by the FERC.
f. Gas Contracts Required to be Filed with the FERC. All gas supply,
storage and/or transportation service contracts, tariffs, agreements
or arrangements, including any amendments thereto, of any kind between
UE and any Ameren subsidiary or affiliate required to be filed with
and/or approved by the FERC, pursuant to the Natural Gas Act ("NGA"),
as subsequently amended, shall be conditioned upon the following
without modification or alteration: UE and Ameren and each of its
affiliates and subsidiaries will not seek to overturn, reverse, set
26
<PAGE>
aside, change or enjoin, whether through appeal or the initiation or
maintenance of any action in any forum, a decision or order of the
Commission which pertains to recovery, disallowance, deferral or
ratemaking treatment of any expense, charge, cost or allocation
incurred or accrued by UE in or as a result of a gas supply, storage
and/or transportation service contract, agreement, arrangement or
transaction on the basis that such expense, charge, cost or allocation
has itself been filed with or approved by the FERC or was incurred
pursuant to a contract, arrangement, agreement or allocation method
which was filed with or approved by the FERC.
g. No Pre-Approval of Affiliated Transactions. No pre-approval of
affiliated transactions will be required, but all filings with the SEC
or FERC for affiliated transactions will be provided to the Commission
and the OPC. The Commission may make its determination regarding the
ratemaking treatment to be accorded these transactions in a later
ratemaking proceeding or a proceeding respecting any alternative
regulation plan.
h. Contingent Jurisdictional Stipulation -- FERC. In the exclusive event
that any court with jurisdiction over UE,
27
<PAGE>
Ameren or any of its affiliates or subsidiaries issues an opinion or
order which invalidates a decision or order of the Commission
pertaining to recovery, disallowance, deferral or ratemaking treatment
of any expense, charge, cost or allocation incurred or accrued by UE
on the basis that such expense, charge, cost, or allocation has itself
been filed with or approved by the FERC, then the Contingent
Jurisdictional Stipulation, attached hereto as Attachment D, shall
apply to FERC filings according to its terms, at the option of the
Commission.
i. Contingent Jurisdictional Stipulation -- SEC. In the exclusive event
that any court with jurisdiction over UE, Ameren or any of its
affiliates or subsidiaries issues an opinion or order which
invalidates a decision or order of the Commission pertaining to
recovery, disallowance, deferral or ratemaking treatment of any
expense, charge, cost or allocation incurred or accrued by UE on the
basis that such expense, charge, cost, or allocation has itself been
filed with or approved by the SEC, then the Contingent Jurisdictional
Stipulation, attached hereto as Attachment D, shall apply to SEC
filings according to its terms, at the option of the Commission.
28
<PAGE>
Commitments covered by the provisions of this Section 8 should not be
construed as concurrence or acquiescence by UtiliCorp United Inc., The
Empire District Electric Company, Missouri Gas Energy, Kansas City Power &
Light Company or Trigen - St. Louis Energy Corp. in any of these
provisions.
9. Staff Conditions To Which UE Has Agreed
a. UE agrees to abide by the Stipulation And Agreement in Case No. GR-93-
106, including, but not limited to, the following:
i. UE agrees it will meet with the Staff, at the Staff's request,
prior to the commencement of the Staff's audit of each future
UE Actual Cost Adjustment ("ACA") filing, to discuss the
activities of UE during the applicable ACA period.
ii. UE agrees to prepare a written study or analysis of: (i) each
material natural gas-related contract decision; and (ii) each
major FERC decision materially affecting UE in proceedings of
pipelines providing service to UE and final FERC regulations
which materially affect UE. Subject to applicable legal
privileges, UE agrees
29
<PAGE>
to provide such document to the Staff upon its request during
the applicable ACA audit.
iii. UE agrees to continually monitor its participation before the
FERC as a member of the Panhandle Customer Group and not join
in Group activities in instances when, in UE's judgment, its
interests are not adequately protected.
iv. The Staff may make evaluations of and propose adjustments to
post-FERC Order 636 restructured services and related costs
during the applicable ACA audit.
b. UE shall continue to provide to the Staff monthly surveillance reports
in the same format which is currently being utilized in submittals to
the Staff (or in some other mutually agreeable format), so that the
Staff can continue to monitor UE's Missouri jurisdictional electric
and natural gas earnings levels.
c. On a quarterly basis, Ameren and UE shall provide the Commission with
a report detailing UE's proportionate share of Ameren: (i) total
consolidated assets; (ii) total consolidated operating revenues; (iii)
total
30
<PAGE>
operating and maintenance expense; and (iv) total consolidated number
of employees.
d. The data associated with the hour-by-hour After-The-Fact Resource
Allocation which will be performed pursuant to the Joint Dispatch
Agreement will be archived in an electronic format and submitted to
the Staff annually.
e. The Commission shall have access to all financial information on all
affiliates, subsidiaries or divisions, regulated or non-regulated, and
any future utility or non-utility affiliate, subsidiary or division of
Ameren or an Ameren affiliate, subsidiary or division, necessary to
calculate an estimate of the stockholders' required return on equity
(ROE) for Ameren on a consolidated basis and then a differentiated ROE
for each affiliate, subsidiary or division, including UE, on a stand-
alone basis.
f. UE will provide the historical hourly generation data required by
Commission rule 4 CSR 240-20.080 in electronic format accessible by a
spreadsheet program. UE will provide the historical purchase power
data and interchange sales data required by Commission rule 4 CSR 240-
20.080 in hard copy until it is available in
31
<PAGE>
electronic format accessible by a spreadsheet program. UE expects by
July 1, 1997 this purchase power data and interchange sales data to be
available in electronic format accessible by a spreadsheet program
when the centralized control center completes modifications to the
energy management computer system to accommodate joint dispatch.
g. UE agrees that respecting the General Services Agreement ("GSA"), the
Staff and other proper parties, in the context of UE's general rate
filings and/or alternative regulation plans, retain the right to bring
concerns to the Commission and propose adjustments, if necessary,
regarding the GSA's rate impact on Missouri customers, and the
Commission retains jurisdiction to consider and adopt such
adjustments. (See also Sections 8.d. and 8.g. above concerning state
jurisdictional issues.)
32
<PAGE>
10. System Support Agreement
The signatories other than the Missouri Industrial Energy Consumers
("MIEC") agree that the 10-year System Support Agreement ("SSA"), as described
in Ms. Maureen A. Borkowski's Supplemental Direct Testimony, pages 1 to 3,
should be approved by the Commission pursuant to the following conditions.
First, the approval of the 10-year SSA shall not be construed as approval
by the Commission or the signatories for the capacity and energy addressed in
the 10-year SSA to be allocated to Missouri jurisdictional ratepayers.
Second, regarding the appropriateness of the future utilization of the
capacity and energy addressed in the SSA for serving UE's Missouri customers:
a. UE will undertake an integrated resource planning process at the
appropriate time in the future to determine if the capacity and energy
used to serve its then former Illinois customers should, in UE's
judgment, serve the Missouri jurisdiction.
b. In UE's ongoing consideration of purchase power opportunities for
native system load that periodically become available, it will
evaluate, on an equivalent basis, the costs and risks of: (i)
purchase power
33
<PAGE>
opportunities; (ii) energy and capacity that is no
longer needed or will no longer be needed to serve UE's then
former Illinois customers; and (iii) newly-constructed capacity.
c. UE will provide the results of and workpapers supporting the analysis
performed pursuant to Subsections a. and b. above to the Staff, OPC
and MIEC.
d. The Commission has the authority in any future ratemaking proceedings
to allocate the capacity and energy addressed in the SSA.
11. Commission Rights
Nothing in this Stipulation And Agreement is intended to impinge or
restrict in any manner the exercise by the Commission of any statutory right,
including the right of access to information, and any statutory obligation.
12. Staff Rights
If requested by the Commission, the Staff shall have the right to submit to
the Commission a memorandum explaining its rationale for entering into this
Stipulation And Agreement. Each party of record shall be served with a copy of
any memorandum and shall be entitled to submit to the Commission, within five
(5) days of receipt of the Staff's memorandum, a responsive memorandum which
34
<PAGE>
shall also be served on all parties. All memoranda submitted by the parties
shall be considered privileged in the same manner as are settlement discussions
under the Commission's rules, shall be maintained on a confidential basis by all
parties, and shall not become a part of the record of this proceeding or bind or
prejudice the party submitting such memorandum in any future proceeding or in
this proceeding whether or not the Commission approves this Stipulation And
Agreement. The contents of any memorandum provided by any party are its own and
are not acquiesced in or otherwise adopted by the other signatories to this
Stipulation And Agreement, whether or not the Commission approves and adopts
this Stipulation And Agreement.
The Staff also shall have the right to provide, at any agenda meeting at
which this Stipulation And Agreement is noticed to be considered by the
Commission, whatever oral explanation the Commission requests, provided that the
Staff shall, to the extent reasonably practicable, provide the other parties
with advance notice of when the Staff shall respond to the Commission's request
for such explanation once such explanation is requested from the Staff. The
Staff's oral explanation shall be subject to public disclosure, except to the
extent it refers to matters that are
35
<PAGE>
privileged or protected from disclosure pursuant to any Protective Order issued
in this case.
13. No Acquiescence
None of the signatories to this Stipulation And Agreement shall be deemed
to have approved or acquiesced in any question of Commission authority,
accounting authority order principle, cost of capital methodology, capital
structure, decommissioning methodology, ratemaking principle, valuation
methodology, cost of service methodology or determination, depreciation
principle or method, rate design methodology, cost allocation, cost recovery, or
prudence, that may underlie this Stipulation And Agreement, or for which
provision is made in this Stipulation And Agreement.
14. Negotiated Settlement
This Stipulation And Agreement represents a negotiated settlement. Except
as specified herein, the signatories to this Stipulation And Agreement shall not
be prejudiced, bound by, or in any way affected by the terms of this Stipulation
And Agreement: (a) in any future proceeding, (b) in any proceeding currently
pending under a separate docket; and/or (c) in this proceeding should the
Commission decide not to approve this Stipulation And Agreement in the instant
proceeding, or in any way condition its
36
<PAGE>
approval of same, or should the merger with CIPSCO not be consummated.
15. Provisions Are Interdependent
The provisions of this Stipulation And Agreement have resulted from
negotiations among the signatories and are interdependent. In the event that the
Commission does not approve and adopt the terms of this Stipulation And
Agreement in total, it shall be void and no party hereto shall be bound,
prejudiced, or in any way affected by any of the agreements or provisions
hereof.
16. Prepared Testimony
The prepared testimonies and schedules of the following witnesses shall be
received into evidence without the necessity of these witnesses taking the
witness stand:
Union Electric Company:
-----------------------
Charles W. Mueller (Direct Testimony)
Donald E. Brandt (Direct and Surrebuttal Testimonies)
Thomas J. Flaherty (Direct and Surrebuttal Testimonies)
Warner L. Baxter (Direct, Supplemental Direct, Second
Supplemental Direct, Surrebuttal and Supplemental
Surrebuttal Testimonies)
Douglas W. Kimmelman (Direct Testimony)
Maureen A. Borkowski (Direct, Supplemental Direct and
Surrebuttal Testimonies)
Jerre E. Birdsong (Direct and Surrebuttal Testimonies)
Gary L. Rainwater (Direct and Surrebuttal Testimonies)
Craig D. Nelson (Surrebuttal Testimony)
James A. Reid (Surrebuttal Testimony)
37
<PAGE>
Commission Staff:
-----------------
Daniel I. Beck (Rebuttal and Supplemental Rebuttal
Testimonies)
David W. Elliott (Rebuttal Testimony)
Cary G. Featherstone (Rebuttal Testimony)
Charles R. Hyneman (Rebuttal Testimony)
Thomas M. Imhoff (Rebuttal Testimony)
Tom Y. Lin (Rebuttal Testimony)
Jay W. Moore (Rebuttal Testimony)
Mark L. Oligschlaeger (Rebuttal Testimony)
James D. Schwieterman (Rebuttal and Supplemental Rebuttal
Testimonies)
Michael J. Wallis (Rebuttal Testimony)
Office of Public Counsel:
-------------------------
Russell W. Trippensee (Rebuttal Testimony)
Mark Burdette (Rebuttal Testimony)
Ryan Kind (Rebuttal and Cross-Surrebuttal Testimonies)
Missouri Industrial Energy Consumers:
-------------------------------------
Maurice Brubaker (Direct Testimony)
17. Waive Rights to Cross Examination, etc.
In the event the Commission accepts the specific terms of this Stipulation
And Agreement, the signatories waive their respective rights to cross-examine
witnesses; their respective rights to present oral argument and written briefs
pursuant to Section 536.080.1 RSMo. 1994; their respective rights to the reading
of the transcript by the Commission pursuant to Section 536.080.2 RSMo. 1994;
and their respective rights to judicial review pursuant to Section 386.510 RSMo.
1994. This waiver applies only to a
38
<PAGE>
Commission Report And Order issued in this proceeding, and does not apply to any
matters raised in any subsequent Commission proceeding, or any matters not
explicitly addressed by this Stipulation And Agreement.
18. Operative Dates
The following sections of this Stipulation And Agreement shall become
operative upon approval of this agreement by the Commission: Sections 1-5 and 8-
17.
The following sections shall become operative at the expiration of the ARP
on June 30, 1998: Sections 6-7.
Respectfully submitted,
OFFICE OF THE PUBLIC COUNSEL UNION ELECTRIC COMPANY/CIPSCO
By /s/ Lewis R.Mills, Jr. By /s/ James J. Cook
--------------------------- ---------------------------
Lewis R. Mills, Jr. (#35275) James J. Cook (#22697)
Deputy Public Counsel Associate General Counsel
P.O. Box 7800 P. O. Box 149, MC 1310
Jefferson City, MO 65102 St. Louis, MO 63166
(573) 751-4857 (314) 554-2237
39
<PAGE>
STAFF OF THE MISSOURI ANHEUSER-BUSCH, INC., ET AL.
PUBLIC SERVICE COMMISSION (MIEC)
By /s/ Steven Dottheim By /s/ Robert C. Johnson
--------------------------- ---------------------------
Steven Dottheim (#29149) Robert C. Johnson (#15755)
Deputy General Counsel Michael R. Annis (#47374)
Aisha Ginwalla (#41608) Peper, Martin, et al.
Roger W. Steiner (#39586) 720 Olive Street, 24th Fl.
Assistant General Counsel St. Louis, MO 63101-2396
P.O. Box 360 (314) 421-3850
Jefferson City, MO 65102
(573) 751-7489
TRIGEN-ST. LOUIS ENERGY CORP. UTILICORP UNITED INC.
THE EMPIRE DISTRICT ELECTRIC CO.
By /s/ Richard W. French By /s/ James C. Swearengen
--------------------------- ---------------------------
Richard W. French (#27356) James C. Swearengen (#21510)
French & Stewart Brydon, Swearengen & England
1001 Cherry St., Suite 302 P.O. Box 456
Columbia, MO 65201 Jefferson City, MO 65102
(573) 499-0635 (573) 635-7166
MISSOURI GAS ENERGY, A DIVISION LACLEDE GAS COMPANY
OF SOUTHERN UNION COMPANY
Will not sign, and will not
support or oppose -- letter
By /s/ Gary W. Duffy By to follow.
---------------------------- ------------------------------
Gary W. Duffy (#24905) Michael C. Pendergast (#31763)
Brydon, Swearengen & England Laclede Gas Company
England 720 Olive St., Room 1520
P.O. Box 456 St. Louis, MO 63101
Jefferson City, MO 65102 (314) 342-0532
(573) 635-7166
40
<PAGE>
STATE OF MISSOURI ILLINOIS POWER COMPANY
OFFICE OF ATTORNEY GENERAL
Will not sign, and will not
support or oppose -- letter
By /s/ Jeremiah W. Nixon By to follow. By SD
---------------------------- ---------------------------
Jeremiah W. Nixon Paul S. DeFord (#29509)
Daryl R. Hylton (#35605) Lathrop & Gage
Office of Attorney General 2345 Grand Blvd., Suite 2500
P.O. Box 899 Kansas City, MO 64108
Jefferson City, MO 65102 (816) 460-5827
(573) 751-1143
INTERNATIONAL BROTHERHOOD OF KANSAS CITY POWER & LIGHT CO.
ELECTRICAL WORKERS
LOCALS 702, 309, 1455, AND 2 By /s/ James Fischer
---------------------------
Will not sign, and will not James Fischer (#27543)
support or oppose -- see Attorney at Law
By letter this date. By SD 101 W. McCarty, Suite 215
--------------------------- Jefferson City, MO 65101
Marilyn S. Teitelbaum (573) 636-6758
(#26074)
Schuchat, Cook & Werner
1221 Locust St., 2nd Floor
St. Louis, MO 63101
(314) 621-2626
DATED: 7/12/96 SD
-----------
41
<PAGE>
[LETTERHEAD OF SCHUCHAT, COOK & WERNER LETTERHEAD APPEARS HERE]
Mr. David L. Rauch, Executive Secretary
Missouri Public Service Commission
P.O. Box 360
Jefferson City, MO 65102
RE: Case No. EM-96-149
Dear Mr. Rauch:
Intervenors IBEW, Locals 702, 1455, 309 and 2 do not concur or acquiesce in
the Stipulation and Agreement in the above mentioned case, but they are not in
opposition to it either. Furthermore, they are not requesting a hearing.
I am enclosing 14 copies of this letter for distribution. If you have any
questions, please contact me.
Sincerely,
/s/ Marilyn S. Teitelbaum
Marilyn S. Teitelbaum
MST: jim
Enclosures
cc: Parties of Record
Judge Joseph Derque
Steve Dottheim
Mike Datillo, Local 1455
Jim Berger, Local 309
Dave White, Local 2
Danny Miller, Local 702
<PAGE>
Service list for: Lewis R. Mills, Jr.
Case No. EM-96-149 Office of the Public Counsel
Updated: 7-12-96 P.O. Box 7800
Jefferson City, MO 65102
James J. Cook James C. Swearengen
Union Electric Company Brydon, Swearengen & England
1901 Chouteau Avenue 312 E. Capitol
P.O. Box 149 (M/C 1310) P.O. Box 456
St. Louis, MO 63103 Jefferson City, MO 65102
Richard W. French Marilyn S. Teitelbaum
French & Stewart Schuchat, Cook & Werner
1001 E. Cherry Street 1221 Locust Street
Suite 302 2nd Floor
Columbia, MO 65201 St. Louis, MO 63103
Michael C. Pendergast Gary W. Duffy
Laclede Gas Company Brydon, Swearengen & England
720 Olive Street 312 E. Capitol Avenue
Room 1530 P.O. Box 456
St. Louis, MO 63101 Jefferson City, MO 65102
Robert C. Johnson/Diana M. Schmidt Paul S. DeFord
Peper, Martin, Jensen, Maichel and Hetlage Lathrop & Norquist, L.C.
720 Olive Street 2345 Grand Blvd.
24th Floor Suite 2500
St. Louis, MO 64141-9679 Kansas City, MO 64108
Jeremiah W. Nixon/Daryl R. Hylton James M. Fischer
Attorney General's Office Mutual Savings Bank
221 W. High Street 1001 W. McCarty, Suite 215
P.O. Box 899 Jefferson City, MO 65101
Jefferson City, MO 65102
Susan B. Cunningham
Kansas City Power & Light Co.
1201 Walnut Street
P.O. Box 418679
Kansas City, MO 64141-9679
<PAGE>
Attachment A.
Page 1 of 6
PROCEDURES TO DETERMINE RATE REDUCTION
1. For each month, the Hourly Electric Load Model (HELM) will be used to
estimate actual and weather normalized sales by calendar months for the
following rate sub-classes (Missouri retail only):
. residential;
. commercial small general service;
. industrial small general service;
. commercial large general service;
. commercial small primary service; and
. commercial large primary service.
2. UE's Corporate Planning Department will utilize the following load research
data in the HELM model for the specified "Sharing Periods":
Sharing Period Load Research Data
---------------------------- -----------------------
July 1, 1995 - June 30, 1996 24 months ending:
Sepember 30, 1995
July 1, 1996 - June 30, 1997 24 months ending:
September 30, 1995
July 1, 1997 - June 30, 1998 24 months ending:
September 30, 1996
3. For the 12 months ended June 30, 1996 Sharing Period, UE's Corporate
Planning Department will use its current version of the HELM model. To the
extent that this version is modified during the "Sharing Periods" ending
June 30, 1997 and June 30, 1998, all signatories to the Stipulation And
Agreement in Case No. EM-96-149 will be provided in writing the following
information within 30 days of the effective date of the change to the model
as determined by UE's Corporate Planning Department:
. description of the changes made;
. reasons for the changes; and
<PAGE>
Attachment A.
Page 2 of 6
. effective date of the changes to the HELM model for purposes of
calculating the Annual Weather-Normalized Credit.
For purposes of calculating the Annual Weather-Normalized Credit, all
changes to the HELM model, as well as other changes to the data and
assumptions utilized in the HELM model, will be incorporated prospectively
from the effective date of the change.
4. Monthly, the difference between normal weather energy sales and actual
energy sales by rate sub-class, as determined in Step 1 above, will be
calculated (Missouri only). These amounts represent the impact of weather
on sales during that period.
5. In order to determine the impact that deviations from normal weather had on
revenues, the amounts calculated in Step 4 will be multiplied by the rate
components specified below of the Missouri electric rates for that rate
class in effect for service on the first day of the month. The summer rate
will be applied in June through September.
The winter rate will be applied in October through May. The sum of the rate
sub-class revenue adjustments will be the total weather adjustment to
revenues for that month. The following rate components will be used for
each rate class:
<TABLE>
<CAPTION>
Rate Class Rate Component
---------------------------- ------------------------------------
<S> <C>
Residential Summer 1(M) Energy Charge - All kWh
Winter 1(M) Energy Charge -
Initial Block (first 750
kWh)
Small General Service Summer 2(M) Energy Charge - All
kWh
Winter 2(M) Energy Charge - Base
Use
</TABLE>
<PAGE>
Attachment A.
Page 3 of 6
<TABLE>
<S> <C> <C>
. Large General Service Summer 3(M) Energy Charge - Over
350 kWh per kW
Winter 3(M) Energy Charge - Over
350 kWh per kW
. Small Primary Service Summer 4(M) Energy Charge - Over
350 kWh per kW
Winter 4(M) Energy Charge - Over
350 kWh per kW
. Large Primary Service Summer 11(M) Energy Charge - All
kWh
Winter 11(M) Energy Charge - All kWh
</TABLE>
Exhibit I hereto reflects the specific rates expected to be utilized to
perform this calculation.
6. In order to determine the impact that weather had on fuel costs, the amount
calculated in Step 4 will first be factored up for line losses and then
will be multiplied by the average cost of fuel per kWh. The average cost of
fuel will be calculated utilizing information from UE's Monthly Financial
and Statistical Report (F&S). Total fossil fuel cost (from F&S Schedule C6-
1 - Total Electric Fuel Burned Less Nuclear and Handling Costs) plus the
cost of purchased power (F&S Schedule C4-1) will represent total fuel
costs. Total generation (from F&S Schedule C5-2 - Total Steam Generation
Plus Total Combustion Turbine and Diesel Generation) plus the purchased
power (F&S Schedule C4-2, including Regulating Energy) will represent total
output (expressed in kWhs). The total fuel cost divided by total output
will equate to the average fuel cost per kWh. To the extent that the
referenced schedules change in format or content, comparable reports will
be developed, maintained and supplied to the appropriate signatories.
<PAGE>
Attachment A.
Page 4 of 6
7. Steps 1, 4, 5 and 6 will be performed monthly during the Sharing Period.
The sum of the twelve months will represent the "adjustment to revenues and
fuel costs."
8. The "adjustment to revenues and fuel costs" calculated in Step 7 will be
added to or deducted from revenues and fuel costs used in determining the
"actual" credit under the Stipulation And Agreement in Case No. ER-95-411
for the particular Sharing Period. These adjusted revenues and fuel costs
will be used to calculate the Annual Weather-Normalized Credit for the
sharing period using the procedures used to calculate the "actual" credit.
9. If the "actual" credit calculated under the Stipulation And Agreement in
Case No. ER-95-411 for any Sharing Period is zero, the Annual Weather-
Normalized Credit will be zero for that Sharing Period.
10. The Annual Weather-Normalized Credit cannot be a "negative" amount for any
Sharing Period. Under this circumstance, the Annual Weather-Normalized
Credit for that Sharing Period will be zero.
11. The Rate Reduction will be calculated as the average of the Annual Weather-
Normalized Credits for each of the three sharing periods. (The divisor
will always be three, even if one or more of the Annual Weather-Normalized
Credits is zero).
<PAGE>
Attachment A.
Page 5 of 6
Exhibit I
Page 1 of 2
MISSOURI ELECTRIC RATES
EFFECTIVE AUGUST 1, 1995
Rate Class Rate per kWh
--------------------------- ------------
. Residential - Summer 8.271c
. Residential - Winter 5.998c
. Small General Service - Summer 8.22c
. Small General Service - Winter 6.13c
. Large General Service - Summer 4.09c
. Large General Service - Winter 2.96c
. Small Primary Service - Summer 3.76c
. Small Primary Service - Winter 2.73c
. Large Primary Service - Summer 2.69c
. Large Primary Service - Winter 2.38c
<PAGE>
Attachment A
Page 6 of 6
Exhibit I
Page 2 of 2
MISSOURI ELECTRIC RATES
(TO BE USED FOR JULY 1995 ONLY)
Rate Class Rate per kWh
-------------------------- ------------
. Residential - Summer 8.439c
. Small General Service - Summer 8.38c
. Large General Service - Summer 4.17c
. Small Primary Service - Summer 3.83c
. Large Primary Service - Summer 2.74c
<PAGE>
Attachment B.
Page 1 of 3
PROCEDURES FOR SHARING CREDITS FROM THE NEW THREE-YEAR
EXPERIMENTAL ALTERNATIVE REGULATION PLAN
A. Eligibility Requirements for Sharing Credits
Any Missouri retail electric customer whose account is active as of the
date of billing during the "credit application period," as defined below in
B., shall be eligible for a credit. Customer accounts which are inactive
as of the date of billing during the "credit application period" are
ineligible for any credit.
B. Determination of the Credit Application and Calculation Periods
The "credit application period" shall be the UE monthly billing period
during which the credit will be applied to an eligible customer's bill for
electric service. The "credit calculation period" will be the twelve UE
billing months prior to the month before the credits first appear on
customers' bills. For example, if the credit first appears on customers'
bills in the October 1999 billing period, then the credit calculation
period would be the twelve UE billing months of September 1998 - August
1999.
C. Determination of Applicable Credit Period Kilowatt-hours
The applicable credit calculation period kilowatt-hours for all eligible
customers shall be the total sales billed by UE to each eligible customer's
current premises during the entire 12-month credit calculation period, as
defined above in B., without regard to each customer's occupancy date of
such premises.
D. Determination of Per Kilowatt-hour Credit
The credit per kilowatt-hour will be calculated by dividing the total
dollar amount to be credited by the total applicable credit calculation
period kilowatt-hours, as defined in C. above, for all eligible Missouri
retail accounts.
<PAGE>
Attachment B.
Page 2 of 3
E. Determination of Individual Customer Credit
Each individual active customer's credit will be calculated by multiplying
the per kilowatt-hour credit, as defined in D. above, by the eligible
customer's applicable credit calculation period kilowatt-hours as defined
in C. above.
F. Treatment of Any Difference Between the Actual Amount Credited to Customers
and the Sharing Credits Amount
1. If the difference between the actual amount credited to eligible
customers and the sharing credits amount is less than $1 million, this
credit amount will be carried over and be an adjustment to eligible
customers' share of earnings in the subsequent sharing period.
2. If the difference between the actual amount credited to eligible
customers and the sharing credits amount is $1 million or greater, an
additional credit will be made as soon as reasonably possible for an
under-credit. If an over-credit of $1 million or more is made, the
over-credit will be treated as in the paragraph immediately above.
G. Treatment of Sharing Credits
1. If the calculation of UE's return on common equity indicates that
sharing credits are to be granted and the amount for the sharing
period is $1 million or greater, or the amount for the sharing period
plus any amount carried over from a prior sharing period is $1 million
or greater, then credits will be made to eligible customers for that
sharing period.
2. If the calculation of UE's return on common equity indicates that
sharing credits are to be granted, but the amount is less than $1
million or the amount for the sharing period plus any amount carried
over from a prior sharing period is less than $1 million, said amount
will be carried over and be an adjustment to eligible customers' share
of earnings in the subsequent sharing period.
<PAGE>
Attachment B.
Page 3 of 3
3. The signatories to this Stipulation And Agreement will determine the
disposition of any accumulated balance of credits that is less than $1
million at the end of the third year of the New Plan.
4. Any accumulated balance of credits that is $1 million or greater at
the end of the third year of the New Plan will result in credits to
customers' bills.
<PAGE>
Attachment C.
Page 1 of 9
RECONCILIATION PROCEDURE
1. The period used in determining sharing will be a year ending June 30. An
earnings report will be filed with the Commission and submitted to all
parties to this agreement by one hundred and five (105) days after the end
of each year of the New Experimental Alternative Regulation Plan ("the New
Plan"). The earnings report will be in accordance with this Attachment C
and Schedule 1 hereto.
2. The earnings report will reflect the following:
a. UE's Missouri electric net operating income and common equity return
(ROE) will be based upon year ending June 30 operating revenues,
expenses and average rate base.
The Missouri electric allocation factors shown in Schedule 1 hereto
will be calculated and applied consistent with past UE rate
proceedings and will be updated for each Sharing Period of the New
Plan.
Any sale of emission allowances shall be reflected above-the-line in
the ROE calculation.
b. The annual depreciation expense will be based upon the depreciation
rates in effect at December 31, 1994.
c. The Company will make the following income statement adjustments which
have been traditionally made in UE rate proceedings:
. Normalize the expense of refueling the Callaway nuclear plant to
provide an annual expense level.
. Synchronize gross receipts tax expense with amounts included in
revenues.
. Eliminate $250,000 of goodwill advertising.
. Include interest on customer deposits and the residential
insulation programs.
<PAGE>
Attachment C.
Page 2 of 9
. Exclude the cost, net of refunds, for nuclear replacement power
insurance.
. Eliminate differences between the provision for and the actual
bad debt charges.
. Exclude lobbying expenses. (Edison Electric Institute dues.)
. Allocate system revenues, including revenues from interruptible
sales, consistent with the treatment in Case No. EC-87-114.
d. Net operating income will be normalized for the effect of any prior
year "sharing" credits.
e. Net operating income will reflect changes in the recovery of nuclear
decommissioning costs ordered by the Commission as provided in Section
7.i. of this Stipulation And Agreement.
f. The earnings report will utilize:
. The direct assignment, as ordered in Case No. EC-87-114, of the
Callaway plant costs disallowed in Case No. ER-85-160.
. Staff's rate base offsets for income tax and interest expense, as
calculated in past UE rate proceedings.
. Coal inventory equal to a 75-day supply and a 13-month average
for all other non-nuclear fuel, materials and supplies, and
prepayments.
. Nuclear fuel inventory reflecting an 18-month average of the
unspent fuel in the reactor core.
. Staff's traditional calculation of the interest deduction for
income taxes.
<PAGE>
Attachment C.
Page 3 of 9
. A cash working capital rate base offset of $24 million.
. Average the beginning and ending period capital structures and
embedded costs for determining the average weighted costs of debt
and preferred stock. (See also attached Schedule 1, page 1.)
. Staff's traditional calculation of income tax (refer to the
income tax calculation in Case No. EC-87-114).
. Staff's position regarding the calculation of Pension and OPEB
expense as exemplified in the St. Louis County Water Company
rate case, Case No. WR-95-145.
. The amortization of transaction and transition costs as set forth
in Section 4 of the Stipulation and Agreement in Case No. EM-96-
149.
g. The earnings level upon which sharing is based are those described in
items 2.a. through 2.f. above. UE/Staff/OPC reserve the right to
petition the Commission for resolution of disputed issues relating to
the operation or implementation of this Plan.
<PAGE>
Attachment C.
Page 4 of 9
Schedule 1
Page 1 of 6
UNION ELECTRIC COMPANY
CAPITAL STRUCTURE AND
EMBEDDED COST OF DEBT AND PREFERRED
<TABLE>
<CAPTION>
BEGINNING OF SHARING PERIOD
(i) (ii) (iii) (iv)
Capital Structure Embedded Wgtd Avg
-----------------
(Dollars) % Cost Cost
---------- ------ -------- --------
<S> <C> <C> <C>
Common Stock Equity* N/A N/A
Preferred Stock col. (ii)
Long-Term Debt times
Short-Term Debt (if applicable) col. (iii)
--------------
Total Capitalization
-------------
Return Portion Related to Debt and Preferred Sum col. (iv)
END OF SHARING PERIOD
(v) (vi) (vii) (viii)
Capital Structure Embedded Wgtd Avg
-----------------
(Dollars) % Cost Cost
---------- ------ -------- --------
Common Stock Equity* N/A N/A
Preferred Stock col. (vi)
Long-Term Debt times
Short-Term Debt (if applicable) col. (vii)
--------------
Total Capitalization Ret
-----------
</TABLE>
Portion
Related to Debt and Preferred Sum col.(viii)
Return Portion Related to Debt and Preferred
Average Beginning and End of Sharing Period [_____________]
Average Common Stock Equity*
Beginning and End of Sharing Period (%) [_____________]
<PAGE>
Attachment C.
Page 5 of 9
Schedule 1
Page 2 of 6
* Since common dividends payable at the end of a quarter and preferred
dividends payable during the subsequent quarter are removed from common equity
in their entirety during the first month of every quarter, the balance for
common stock equity for the end of the first or second month in each quarter (if
used as the beginning or end of the sharing period) should be adjusted from
actual book value. The balance for the end of the first month in the quarter
should be adjusted by adding back two-thirds of the quarterly preferred and
common dividend. The balance for the end of the second month in the quarter
should be adjusted by adding back one-third of the quarterly preferred and
common dividend.
<PAGE>
Attachment C.
Page 6 of 9
Schedule 1
Page 3 of 6
UNION ELECTRIC COMPANY
12 MONTHS ENDED XX / XX / XX
<TABLE>
<CAPTION>
TOTAL MISSOURI
ELECTRIC JURISDICTIONAL
------------- --------------
<S> <C> <C>
Plant in Service $ $
Reserve for Depreciation
---------------- --------------
Net Plant
Add:
Fuel and Materials & Supplies
Cash Working Capital -
Prepayments
Less:
Income Tax Offset (Staff Method)
Interest Expense Offset (Staff Method)
Customer Advances
Customer Deposits
Accumulated Deferred Income Taxes:
Account 190
Account 282
---------------- --------------
(A) Total Rate Base $ $
(B) Net Operating Income $ $
(C) Return on Rate Base ((B)/(A)) % %
(D) Return Portion Related to Debt & Preferred % %
(E) Return Portion Related to
Common Equity ((C)-(D)) % %
(F) Equity Percentage of Capital Structure % %
(G) Achieved Cost of Common Equity ((E)/(F)) % %
</TABLE>
<PAGE>
Attachment C.
Page 7 of 9
Schedule 1
Page 4 of 6
UNION ELECTRIC COMPANY
12 MONTHS ENDED XX / XX / XX
<TABLE>
<CAPTION>
TOTAL MISSOURI
ELECTRIC JURISDICTIONAL
------------- --------------
<S> <C> <C>
Operating Revenues $ $
Operating & Maintenance Expenses:
Production:
Fixed Allocation
Variable Allocation
Directly Assigned
-------------- --------------
Total Production Expenses
Transmission Expenses (Fixed)
Distribution Expenses (Distr. Plant)
Customer Accounting Expenses (Direct)
Customer Serv. & Info. Expenses (Direct)
Sales Expenses (Direct)
Administrative & General Expenses:
Directly Assigned
Labor Allocation
-------------- --------------
Total Administrative & General Expenses
-------------- --------------
Total Operating & Maintenance Expenses
-------------- --------------
Depreciation & Amortization Expense:
Fixed Allocation
Labor Allocation
Directly Assigned
-------------- --------------
Total Depreciation & Amortization Expense
-------------- --------------
Taxes Other than Income Taxes:
Fixed Allocation
Variable Allocation
Labor Allocation
Directly Assigned
-------------- --------------
Total Taxes Other than Income Taxes
-------------- --------------
Income Taxes:
Federal Income Taxes
Environmental Tax (Net Plant)
Missouri State Income Tax
Other States' Income Taxes
-------------- --------------
Total Income Taxes
-------------- --------------
Net Operating Income $ $
</TABLE>
<PAGE>
Attachment C.
Page 8 of 9
Schedule 1
Page 5 of 6
CALCULATION OF CUSTOMER SHARING CREDITS
FOR UNION ELECTRIC COMPANY
<TABLE>
<CAPTION>
Customer
Earned Return on Common Stock Equity Scenarios Sharing Credits
------------------------------------------------- ---------------
<S> <C>
A. If Earned Return on Common Stock Equity is (less than) 10.000%, then:
no sharing occurs and Union Electric Company has the option
to file a rate increase case before the Missouri Public Service
Commission.
B. If Earned Return on Common Stock Equity is = to or (greater than) 10.00%
and is (less than) or = to 12.61%, then: $ XX
no sharing occurs.
C. If Earned Return on Common Stock Equity is (greater than) 12.61% and is
(less than) or = to 14.00%, then: $ XX
that portion of Earned Return on Common Stock Equity between
12.61% and 14.00% is shared with 50% being retained by Union
Electric Company and 50% being credited to Union Electric
Company's Missouri retail electric customers.
If [G] (greater than) 12.61% and
(less than) or = to 14.00%, then: [([G] - 12.61%) * 50% * ([A] * [F])]
If [G] (greater than) 14.00%, then: [(14.00% - 12.61%) * 50% * ([A] * [F])]
D. If Earned Return on Common Stock Equity is (less than) 14.00%
and is (less than) or = to 16.00%, then: $ XX
that portion of Earned Return on Common Stock Equity between
14.00% and 16.00%, along with the 50% portion addressed above,
is shared with 10% being retained by Union Electric Company
and 90% being credited to Union Electric Company's Missouri
retail electric customers.
If [G] (greater than) 14.00% and
(less than) or = to 16.00%, then: [([G] - 14.00%) * 90% * ([A] * [F])]
If [G] (less than) 16.00%, then: [(16.00% - 14.00%) * 90% * ([A] * [F])]
E. If Earned Return on Common Stock Equity is (greater than) 16.00%, then: $ XX
that portion of Earned Return on Common Stock Equity above
16.00%, along with the 50% and 90% portions addressed above, is
credited to Union Electric Company's Missouri retail electric customers.
If [G] (greater than) 16.00%, then: [[G] - 16.00%) * 100% * ([A] * [F])]
--------------
CUSTOMER SHARING CREDITS $ XX
Associated Income Tax Expense Reduction $ XX
{Customer Sharing Credits * [(1/(1 - Effective Tax Rate)) - 1]}
Effective tax rate was 38.3886% as of 6/30/94.
TOTAL CUSTOMER SHARING CREDITS $ XX
</TABLE>
<PAGE>
Attachment C.
Page 9 of 9
Schedule 1
Page 6 of 6
UNION ELECTRIC COMPANY
12 MONTHS ENDED XX / XX / XX
ALLOCATION FACTORS
------------------
<TABLE>
<CAPTION>
TOTAL MISSOURI
ELECTRIC JURISDICTIONAL
------------ ---------------
<S> <C> <C>
Fixed 100.00% %
Variable 100.00% %
Nuclear 100.00% %
Distribution 100.00% %
Mo. Distribution Plant 100.00% %
Labor 100.00% %
Net Plant 100.00% %
Operating Revenues 100.00% %
Operating Expenses 100.00% %
</TABLE>
<PAGE>
Attachment D.
Page 1 of 8
CONTINGENT JURISDICTIONAL STIPULATION
1.0 APPLICABILITY
-------------
1.1 Principles stated in this Contingent Jurisdictional Stipulation
("Jurisdictional Stipulation") shall govern the situations described
in Sections 8.h. and 8.i. of the Stipulation And Agreement.
1.2 Changes to this Jurisdictional Stipulation may be proposed from time-
to-time by Union Electric Company ("UE" or "Company"), the Commission
Staff or the OPC, subject to the approval of the Commission;
provided, however, that UE, the Staff and the OPC shall meet and
discuss any such proposed changes prior to the submission of such
changes to the Commission by UE, the Commission Staff or the OPC.
2.0 DEFINITIONS
-----------
When used in this Jurisdictional Stipulation, the following terms shall
have the respective meanings set forth below:
2.1 "Affiliate" means an Entity that is UE's Holding Company, a Subsidiary
of UE, a Subsidiary of UE's Holding Company (other than UE), or other
subsidiary within the Holding Company organization.
2.2 "Affiliate Contract" means an Affiliate Operating Contract, an
Affiliate Sales Contract, an Affiliate Surety Contract, a Section 205
Contract, a Service Agreement or an amendment to any such contract.
2.3 "Affiliate Operating Contract" means a contract, other than a Section
205 Contract, between UE and one or more of its Affiliates providing
for the operation of any part of UE's generating, transmission and/or
distribution facilities by such Affiliate(s).
2.4 "Affiliate Sales Contract" means a contract, other than an Affiliate
Operating Contract or a Section 205 Contract, between UE and one or
more of its Affiliates involving the purchase of Assets, Goods or
Services.
<PAGE>
Attachment D.
Page 2 of 8
2.5 "Affiliate Surety Contract" means a contract between UE and one or
more of its Affiliates involving the assumption by UE of any
liability as a guarantor, endorser, surety, or otherwise in respect
of any security or contract of an Affiliate.
2.6 "Assets" means any land, plant, equipment, franchises, licenses, or
other right to use assets.
2.7 "Commission" means the Missouri Public Service Commission or any
successor governmental agency.
2.8 "Commission Staff" or "Staff" means the staff of the Missouri Public
Service Commission.
2.9 "Entity" means a corporation or a natural person.
2.10 "FERC" means the Federal Energy Regulatory Commission, or any
successor governmental commission.
2.11 "Goods" means any goods, inventory, materials, supplies, appliances,
or similar property (except electric energy and capacity).
2.12 "Non-Utility Affiliate" means an Affiliate which is neither a public
utility nor a Utility Service Company.
2.13 "OPC" means the Office of the Public Counsel.
2.14 "Review Period" means a period of ninety (90) consecutive calendar
days commencing on the first day immediately following the date that
UE, Ameren Corporation or Ameren Services Company submits an
Affiliate Contract to the Commission for the Commission Staff's
review. Any part of the Review Period for a particular Affiliate
Contract may be waived by agreement of UE, the Commission Staff and
the OPC.
2.15 "SEC" means the United States Securities and Exchange Commission, or
any successor governmental agency.
2.16 "Section 205 Contract" means an interconnection, interchange,
pooling, operating, transmission, power sale or ancillary power
services contract or similar
<PAGE>
Attachment D.
Page 3 of 8
entered into between UE and an Affiliate and subject to regulation by
the FERC pursuant to (S) 205 of the Federal Power Act, 15 U.S.C. (S)
824d, or any successor statute.
2.17 "Service Agreement" means the agreement entered into between UE,
CIPSCO and Ameren Services Company under which Services are provided
by Ameren Services Company to UE and CIPSCO.
2.18 "Services" means the performance of activities having value to one
party, such as managerial, financial, accounting, legal, engineering,
construction, purchasing, marketing, auditing, statistical,
advertising, publicity, tax, research, and other similar services.
2.19 "Subsidiary" means any corporation 10 percent or more of whose voting
capital stock is controlled by another Entity; Subsidiaries of UE are
those corporations in which UE owns directly or indirectly (or in
combination with UE's other Affiliates) 10 percent or more of such
corporation's voting capital stock.
2.20 "UE's Holding Company" means Ameren Corporation or its successor in
interest.
2.21 "Utility Affiliate" means an Affiliate of UE which is also a public
utility.
2.22 "Utility Service Company" means an Affiliate whose primary business
purpose is to provide administrative and general or operating
services to UE and Utility Affiliate(s).
3.0 AFFILIATE CONTRACTS REQUIRED TO BE FILED WITH THE SEC
-----------------------------------------------------
The following will apply to Affiliate Contracts that are required to be
filed with the SEC.
3.1 Prior to filing any such Affiliate Contract with the SEC or the
Commission, UE will submit to the Commission Staff, the OPC and
appropriate parties requesting a copy, a copy of the Affiliate
Contract which it proposes to file with the SEC and the Commission.
<PAGE>
Attachment D.
Page 4 of 8
3.1.1 If the Commission Staff clears the contract for filing, or
does not object to it, and no objections from affected
parties are submitted to UE (with a copy to the Commission
Staff) during the Review Period for such contract, UE may
file such contract with the SEC and the Commission. The
contract will become effective upon the receipt of all
necessary regulatory authorizations and will continue in
effect until it is terminated pursuant to its terms or is
amended or superseded, subject to the receipt of all
necessary regulatory authorizations.
3.1.2 If during or upon the expiration of the Review Period for
such contract, the Commission Staff recommends that the
Commission reject, disapprove or establish a proceeding to
review such contract, or if an objection(s) is submitted to
UE (with a copy to the Commission Staff) by an affected party
(or parties), UE may file the contract with the Commission,
but shall not file the contract with the SEC until at least
(30) days after the date that it is filed with the
Commission; provided, that both such filings shall disclose
the Commission Staff's recommendation or the objection(s)
regarding the contract; provided, further, that if the
Commission, within twenty (20) days after the contract is
filed, institutes a proceeding to review such contract, UE
shall not file the contract with the SEC unless and until UE
receives a Commission Order which resolves issues raised with
regard to the contract and which does not reject or
disapprove the contract. The contract will become effective
upon the receipt of all necessary regulatory authorizations
and will continue in effect until it is terminated pursuant
to its terms or is amended or superseded, subject to the
receipt of all necessary authorizations.
3.2 After the Affiliate Contract has been filed with the Commission, the
Commission may in accordance with Missouri law reject or disapprove
the contract, and upon such rejection or disapproval:
<PAGE>
Attachment D.
Page 5 of 8
3.2.1 If such contract has not yet been accepted or approved by the
SEC, UE will, as soon as possible, file to seek to withdraw
its filing requesting SEC acceptance or approval of such
contract; or
3.2.2 If such contract has been accepted or approved by the SEC and
none of the other contracting parties are Utility Affiliates
subject to any other state utility regulatory commission's
jurisdiction, UE will:
a. terminate such contract according to its terms; or
b. at its sole option, take such steps as are necessary to
cause such contract to be amended in order to remedy the
Commission's adverse findings with respect to such
contract; UE will refile such amended contract with both
the Commission and the SEC; such amendment will become
effective only upon the receipt of all necessary
regulatory authorizations, and the previous contract (to
the extent already in effect) will remain in effect until
such authorizations are received; if the SEC does not
finally accept or approve such amendment within 1 year
from the date of UE's filing of such amendment with the
SEC, UE will, upon request of the Commission, terminate
the contract according to its terms.
3.2.3 If such contract has been accepted or approved by the SEC and
one or more of the other contracting parties are Utility
Affiliates subject to another state utility regulatory
commission's jurisdiction, UE will make a good faith effort
to terminate, amend or modify such contract in a manner which
remedies the Commission's adverse findings with respect to
such contract. UE will request to meet with representatives
from the affected state commissions and make a good faith
attempt to resolve any differences in their respective
interests regarding the subject
<PAGE>
Attachment D.
Page 6 of 8
contract. If agreement can be reached to terminate, amend, or
modify the contract in a manner satisfactory to the
contracting parties and the representatives of each state
commission, UE shall file such amended contract with the
Commission and the SEC under the procedure set forth in this
Section 3. If no agreement can be reached satisfactory to
each contracting party and to each affected state commission,
after good faith negotiations, UE has no further obligations
under this Jurisdictional Stipulation. Nothing herein
affects, modifies or alters in any way the rights and duties
of the Commission under applicable state and federal law.
4.0 AFFILIATE CONTRACTS REQUIRED TO BE FILED WITH THE FERC
------------------------------------------------------
The following will apply to Affiliate Contracts that are required to be
filed with the FERC.
4.1 Prior to filing any Affiliate Contract with the FERC or the
Commission, UE will submit to the Commission Staff, the OPC and
appropriate parties requesting a copy, a copy of the Affiliate
Contract which it proposes to file with the FERC and the Commission.
4.1.1 If the Commission Staff clears the contract for filing, or
does not object thereto, and no objections from affected
parties are submitted to UE (with a copy to the Commission
Staff) during the Review Period for such contract, UE may
file such contract with the FERC and the Commission. The
contract will become effective upon the receipt of all
necessary regulatory authorizations and will continue in
effect until it is terminated pursuant to its terms or is
amended or superseded, subject to the receipt of all
necessary regulatory authorizations.
4.1.2 If during or upon the expiration of the Review Period for
such contract, the Commission Staff recommends that the
Commission reject, disapprove or establish a proceeding to
review such contract, or if any objection(s) is submitted to
UE (with a
<PAGE>
Attachment D.
Page 7 of 8
copy to the Commission Staff) by an affected party (or
parties), UE may file the contract with the Commission, but
shall not file the contract with the FERC until at least
thirty (30) days after the date that it is filed with the
Commission; provided, that both such filings shall disclose
the Commission Staff's recommendation or the objection(s)
regarding the contract; provided, further, that if the
Commission, within twenty (20) days after the contract is
filed, institutes a proceeding to review such contract, UE
shall not file the contract with the FERC unless and until UE
receives a Commission Order which resolves issues raised with
regard to the contract and which does not reject or
disapprove the contract. The contract will become effective
upon the receipt of all necessary regulatory authorizations
and will continue in effect until it is terminated pursuant
to its terms or is amended or superseded, subject to the
receipt of all necessary regulatory authorizations.
4.2 After the Affiliate Contract has been filed with the Commission, the
Commission may in accordance with Missouri law reject or disapprove
the contract, and upon such rejection or disapproval:
4.2.1 If such contract has not yet been accepted or approved by the
FERC, UE will, as soon as possible, file to seek to withdraw
its filing requesting FERC acceptance or approval of such
contract; or
4.2.2 If such contract has been accepted or approved by the FERC
and none of the other contracting parties are Utility
Affiliates subject to any other state utility regulatory
commission's jurisdiction, UE will:
a. terminate such contract according to its terms; or
b. at its sole option, take such steps as are necessary to
cause such contract to be
<PAGE>
Attachment D.
Page 8 of 8
amended in order to remedy the Commission's adverse
findings with respect to such contract; UE will refile
such amended contract with the Commission and the FERC;
such amendment will become effective only upon the
receipt of all necessary regulatory authorizations, and
the previous contract (to the extent already in effect)
will continue in effect until such authorizations are
received; if the FERC does not finally accept or approve
such amendment within one year from the date of UE's
filing of such amendment with the FERC, UE will, upon
request of the Commission, terminate the contract
according to its terms.
4.2.3 If such contract has been accepted or approved by the FERC
and one or more of the other contracting parties are Utility
Affiliates subject to another state utility regulatory
commission's jurisdiction, UE will make a good faith effort
to terminate, amend or modify such contract in a manner which
remedies the Commission's adverse findings with respect to
such contract. UE will request to meet with representatives
from the affected state commissions and make a good faith
attempt to resolve any differences in their respective
interests regarding the subject contract. If agreement can be
reached to terminate, amend, or modify the contract in a
manner satisfactory to the contracting parties and the
representatives of each state commission, UE shall file such
amended contract with the Commission and the FERC under the
procedure set forth in this Section 4. If no agreement can be
reached satisfactory to each contracting party and each
affected state commission, after good faith negotiations, UE
has no further obligations under this Jurisdictional
Stipulation. Nothing herein affects, modifies or alters in
any way the rights and duties of the Commission under
applicable state and federal law.
<PAGE>
Exhibit D-3.1
STATE OF ILLINOIS
ILLINOIS COMMERCE COMMISSION
- --------------------------------------------------------------------------------
IN RE: :
:
CENTRAL ILLINOIS PUBLIC : Docket No. 95-0551
SERVICE COMPANY : ----
CIPSCO INCORPORATED :
UNION ELECTRIC COMPANY :
:
JOINT APPLICATION FOR APPROVAL :
OF MERGER AND REORGANIZATION :
- --------------------------------------------------------------------------------
JOINT APPLICATION
FOR
APPROVAL OF MERGER AND REORGANIZATION
-------------------------------------
Joseph H. Raybuck David J. Rosso
Steven R. Sullivan Christopher W. Flynn
Union Electric Company Thomas D. Brooks
1901 Chouteau Blvd. Jones, Day, Reavis & Pogue
P.O. Box 149 77 West Wacker
St. Louis, Missouri 63166 Suite 3500
(314) 554-2976 (voice) Chicago, Illinois 60601-1692
(314) 554-2514 (voice) (312) 782-3939 (voice)
(314) 554-4014 (fax) (312) 782-8585 (fax)
Attorneys for Union Attorneys for Central
Electric Company Illinois Public Service
Company and CIPSCO
Incorporated
November 6, 1995
<PAGE>
TABLE OF CONTENTS
-----------------
<TABLE>
<CAPTION>
PAGE
-----
<S> <C> <C>
I. EXECUTIVE SUMMARY......................................................................... 2
A. Organization of this Application...................................................... 2
B. Summary of the Transactions Constituting the
Merger and Reorganization............................................................. 2
C. Benefits of the Merger................................................................ 4
D. Statutory Requirements................................................................ 5
II. DESCRIPTION OF THE PARTIES................................................................ 6
A. UE.................................................................................... 6
B. CIPS.................................................................................. 6
C. CIPSCO................................................................................ 7
III. THE MERGER SATISFIES THE REQUIREMENTS OF SECTIONS
7-102 AND 7-204........................................................................... 7
A. Introduction: An overview of the regulatory
standards of Sections 7-102 and 7-204................................................. 7
1. Section 7-102..................................................................... 7
2. Section 7-204..................................................................... 8
B. The Proposed Merger Is Reasonable, Will
Convenience the Public, and Will Not Impair the
Provision of Public Utility Service in
Conformance with the Act.............................................................. 10
IV. REQUIREMENTS UNDER SECTION 7-204A FOR APPLICATION FOR
APPROVAL OF REORGANIZATION................................................................ 11
A. Names and corporate relationships of all
companies which are affiliated interests of the
public utility on the date the public utility
applies for reorganization and the name of any
parent or subsidiary corporation of the public
utility. (Section 7-204A(a)(1))...................................................... 11
B. A description of how the public utility plans to
reorganize. (Section 7-204A(a)(2))................................................... 12
C. Copies of the organization documents associated
with the reorganization, including articles of
incorporation or amendments to the articles of
incorporation of all companies including the
public utility and any affiliated interest
(Section 7-204A(a)(2)(i))............................................................. 12
D. Copies of any filings, including securities
filings, related to the reorganization made with
any agency of the state of Illinois or the
federal government. (Section 7-204A(a)(2)(ii))....................................... 12
E. The costs and fees attributable to the
reorganization. (Section 7-204A(a)(3)................................................ 14
F. The method by which management, personnel,
property, income, losses, costs and expenses
will be allocated between the public utility and
</TABLE>
i
<PAGE>
<TABLE>
<S> <C> <C>
any affiliated interest. (Section 7-204A(a)(4))................... 14
G. A copy of any proposed agreement between the
public utility and any person with which it will
be an affiliated interest at the time of the
application for reorganization. (Section
7-204A(a)(5))...................................................... 14
H. An identification of all public utility assets or information in
existence, such as customer lists, which the applicant plans to
transfer to or permit an affiliated interest to use, which
identification shall include a description of the proposed terms and
conditions under which the assets or information will be transferred
or used. (Section 7-204A(a)(6)).................................... 14
I. A copy of a forecast showing the capital
requirements of the public utility at the time
of the proposed reorganization. (Section
7-204A(a)(7))...................................................... 14
J. No public utility may permit the use of any
public utility employee's services by any
affiliated interest except by contract or
arrangement. No public utility may sell, lease,
transfer to or exchange with any affiliated
interest any property except by contract or
arrangement. (Section 7-204A(b)).................................. 14
V. AMEREN'S RELATIONSHIPS WITH ITS AFFILIATED INTERESTS
WILL BE CONSISTENT WITH THE PROVISIONS OF THE ACT...................... 15
A. Overview of corporate structure.................................... 15
B. Transactions involving affiliated interests
necessary to effect the merger and
reorganization which require Commission approval
pursuant to Sections 7-101, and 7-204A(b).......................... 15
C. Transactions Between CIPS and Other Ameren
Affiliates......................................................... 16
1. Provision of Services.......................................... 16
2. System Support Agreement....................................... 17
3. Joint Dispatch Agreement....................................... 18
VI. REQUEST FOR APPROVAL OF CAPITALIZATION PURSUANT TO
SECTION 6-103.......................................................... 18
VII. CERTIFICATES OF PUBLIC CONVENIENCE AND NECESSITY AND
FRANCHISES............................................................. 18
A. Request, pursuant to Section 8-508, to authorize
UE to discontinue providing retail electric and
gas service in the State of Illinois............................... 18
B. Request of the Applicants for Transfer of
Certificates of Public Convenience and Necessity
Issued Pursuant to Section 8-406................................... 19
C. Request for Approval of Transfer of Franchises..................... 20
D. Finding Regarding UE's Status Under the Act........................ 20
</TABLE>
ii
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C>
VIII. CIPS WILL FILE TARIFFS IN ACCORDANCE WITH SECTION
9-102.................................................................. 21
IX. REGULATORY TREATMENT OF MERGER-RELATED COSTS AND
SAVINGS................................................................ 22
X. DISPOSITION OF NUCLEAR DECOMMISSIONING TRUST........................... 22
XI. CONCLUSION............................................................. 23
</TABLE>
iii
<PAGE>
STATE OF ILLINOIS
ILLINOIS COMMERCE COMMISSION
IN RE: :
:
UNION ELECTRIC COMPANY :
CENTRAL ILLINOIS PUBLIC : Docket No. 95-0551
SERVICE COMPANY : ----
CIPSCO INCORPORATED :
:
JOINT APPLICATION FOR APPROVAL :
OF MERGER AND REORGANIZATION :
JOINT APPLICATION
FOR
APPROVAL OF MERGER AND REORGANIZATION
-------------------------------------
Union Electric Company ("UE"), a Missouri corporation, and Central Illinois
Public Service Company ("CIPS"), an Illinois corporation, are public utilities
subject to the Illinois Public Utilities Act, 220 ILCS 101, et seq. (the "Act").
Both UE and CIPS provide electric and gas utility service to the public in
Illinois. UE also provides electric and gas utility service in the State of
Missouri. CIPSCO Incorporated ("CIPSCO"), an Illinois corporation, is the
holding company parent of CIPS. UE, CIPS and CIPSCO (collectively "Applicants")
submit this Joint Application pursuant to Sections 7-102, 7-204 and 7-204A of
the Act, 220 ILCS 5/7-102, 5/7-204, 5/7-204A, seeking the Commission's approval
of their merger and reorganization (the "Merger"), and seek further relief
pursuant to Sections 6-103, 7-101, 7-203, 8-406, 8-508, 8-508.1 and 9-201 of the
Act. In support of their Joint Application, Applicants state:
<PAGE>
I. EXECUTIVE SUMMARY
A. ORGANIZATION OF THIS APPLICATION
This Application includes Attachment A and the supporting pre-filed direct
Testimony and Exhibits of Clifford L. Greenwalt, William A. Koertner, Gary L.
Rainwater, Craig D. Nelson, Gilbert W. Moorman, Jerre E. Birdsong, Lynda E.
Marlett, Robert J. Mill, Steven Pettit, Thomas J. Flaherty, Douglas W. Kimmelman
and John C. Guibert. Attachment A is a Cross Index that identifies the specific
information required by the Act and the page references in the Application,
Testimony or Exhibits that satisfy the requirement.
B. SUMMARY OF THE TRANSACTIONS CONSTITUTING THE MERGER AND REORGANIZATION
On August 11, 1995, CIPSCO and UE entered into an Agreement and Plan of
Merger (the "Merger Agreement"). A copy of the Merger Agreement accompanies the
Testimony of William A. Koertner as Exhibit WAK-2.
The Merger is a strategic alliance between the Applicants, under a common
holding company, Ameren Corporation ("Ameren"), a Missouri corporation. To
achieve this alliance, UE will merge with Arch Merger, Inc., a Missouri
corporation which is a wholly-owned subsidiary of Ameren. Ameren will merge
with CIPSCO, so that Ameren will be the parent of UE, CIPS and CIPSCO's other
direct subsidiary, CIPSCO Investment Corporation ("CIC"). A diagram of the
transactions constituting the Merger accompanies this Joint Application as
Appendix B. The resulting corporate structure is shown on Appendix C. Ameren
will operate as a
2
<PAGE>
registered holding company under the Public Utilities Holding Company Act of
1935 ("PUHCA").
Under the terms of the Merger, the Illinois operations and facilities
(other than UE's electric generating and transmission assets located in
Illinois) of both UE and CIPS will be owned and operated by CIPS, and the
Missouri operations and facilities of UE, in addition to UE's electric
generating and transmission plant located in Illinois, will be owned and
operated by UE. CIPS will, of course, remain fully subject to the Commission's
jurisdiction. UE, which will no longer provide retail utility service in
Illinois, will no longer be a public utility under the Act.
UE and CIPS will operate their combined electric transmission systems as a
single unit, and will jointly and centrally dispatch their combined electric
generation. UE and CIPS will also jointly dispatch their gas facilities, to the
extent consistent with the configurations of their systems.
CIPS will enter into an agreement with UE pursuant to which UE will provide
CIPS with the generation capacity and transmission plant with which to serve
UE's former Illinois service territory (the "System Support Agreement"). The
System Support Agreement is intended to maintain existing UE plant allocations
between Missouri and Illinois and avoid any unintended cost shifting between
jurisdictions as a result of the Merger.
UE and CIPS also contemplate the integration of many corporate functions in
order to realize efficiencies and
3
<PAGE>
economies. CIPS, UE and their affiliates will enter into arrangements for the
provision of services among affiliates, consistent with the requirements of
PUHCA. Such arrangements will be subject to the jurisdiction of, and will be
filed with, the Securities and Exchange Commission ("SEC"). A proposed form of
contract providing for such arrangements accompanies the testimony of Mr. Mill.
C. BENEFITS OF THE MERGER
Applicants estimate that the proposed Merger will produce cost savings of
approximately $590 million, in the first 10 years after the Merger is
consummated. Applicants will incur costs to achieve these savings of
approximately $19 million, plus transaction costs associated with the Merger
itself of approximately $22 million. In addition, to bring about the Merger, it
was necessary to incur a merger premium of approximately $232 million.
The cost savings and efficiencies that will be realized as a result of the
Merger will decrease CIPS' and UE's cost of rendering utility services from the
levels each would incur absent the Merger, thus providing a benefit to
customers, shareholders and the local economies that Applicants serve. Savings
associated with electric joint dispatch and lower gas transportation and
provision costs will be realized by Illinois ratepayers through operation of the
FAC and PGA. CIPS intends to file an electric base rate case for its existing
service territory no later than 12 months after the closing of the Merger
transaction and perhaps as early as mid-1996. In that case, CIPS
4
<PAGE>
will propose specific treatment of the cost savings resulting from, and the
costs associated with, the Merger. CIPS is also considering filing a base rate
case for its existing gas service territory; however, since virtually all of the
Merger-related savings associated with gas service will be flowed through the
PGA, such a filing is not necessary to flow savings to existing gas customers.
CIPS will file tariffs applicable to the former UE Illinois service
territory that will reflect rates essentially equivalent to those charged by UE
at the time of consummation of the Merger. Those tariffs will include an FAC
and PGA, through which ratepayers will see cost savings associated with electric
joint dispatch and lower gas transportation and provision costs.
D. STATUTORY REQUIREMENTS
The Merger requires the Commission's approval under several sections of the
Act, principally 7-102 and 7-204. As discussed, the Illinois customers of both
UE and CIPS will benefit from the proposed reorganization. Consequently, as
required by Section 7-102, Applicants have demonstrated that the Merger is
reasonable and will serve the public convenience. Further, as demonstrated in
this Application and by the accompanying Testimony and Exhibits, the proposed
Merger satisfies the five criteria set forth in Section 7-204 for findings of
fact to enable the Commission to conclude that the reorganization will not
adversely affect CIPS's ability to perform its duties under the Act, with
respect to both its current operations and as successor to UE's Illinois
operations.
5
<PAGE>
In preparing this Application, Applicants have complied with Section 7-
204A, which sets forth the minimum filing requirements for an application for
approval of a reorganization. In addition to requesting the Commission's
approval of the proposed Merger pursuant to Sections 7-102 and 7-204, this
Application seeks the approval, authorization, consent or waiver of the
Commission, as the case may be, for other matters incident to the proposed
Merger. These matters include such matters as transfers of assets, transfers of
certificates of public convenience and necessity, disposition of UE's nuclear
decommissioning trust, contracts, cost recovery and filing of tariffs.
II. DESCRIPTION OF THE PARTIES
A. UE
UE is a Missouri corporation which provides retail electric service to
approximately 1,060,000 customers in the State of Missouri, and 64,000 customers
in the State of Illinois; UE also provides retail natural gas service to
approximately 100,000 customers in Missouri and 18,000 customers in Illinois.
UE is the sole owner of Union Electric Development Corporation, and is a 40 per
cent owner of Electric Energy, Incorporated ("EEInc."). A description of UE,
its operations and affiliates is contained in the testimony of Gary L. Rainwater
at pages 2-3.
B. CIPS
CIPS is an Illinois corporation which provides electric retail service to
317,000 customers in Illinois, and provides retail natural gas service to
166,000 customers, all in Illinois. CIPS is a wholly-owned subsidiary of
CIPSCO. CIPS is a 20 per-
6
<PAGE>
cent owner of EEInc. A description of CIPS and its operations is contained in
the testimony of Clifford L. Greenwalt at pages 2-3.
C. CIPSCO
CIPSCO is an Illinois corporation which is the holding company parent of
CIPS and CIC. A description of CIPSCO is set forth in the testimony of Mr.
Greenwalt at pages 2-3; a description of the operations of CIC and its
subsidiaries is contained in Mr. Koertner's testimony at pages 16-17.
III. THE MERGER SATISFIES THE REQUIREMENTS OF SECTIONS 7-102 AND 7-204
A. INTRODUCTION: AN OVERVIEW OF THE REGULATORY STANDARDS OF SECTIONS 7-
102 AND 7-204
1. SECTION 7-102
Section 7-102 requires the Commission's approval for a number of
transactions by and between public utilities. In particular, Section 7-102
provides that:
* * *
(b) No public utility may purchase, lease, or in any other manner
acquire control, direct or indirect, over the franchises, licenses,
permits, plants, equipment, business or other property of any other public
utility;
(c) No public utility may assign, transfer, lease, mortgage, sell (by
option or otherwise), or otherwise dispose of or encumber the whole or any
part of its franchises, licenses, permits, plant, equipment, business, or
other property, but the consent and approval of the Commission shall not be
required for the sale, lease, assignment or transfer (1) by any public
utility of any tangible personal property which is not necessary or useful
in the performance of its duties to the public, or (2) by any railroad of
any real or tangible personal property;
(d) No public utility may by any means, direct or indirect, merge or
consolidate its franchises, licenses, permits, plants, equipment, business
or other property with that of any other public utility;
* * *
7
<PAGE>
220 ILCS 5/7-102(b), (c), (d).
Under Section 7-102, the Commission must find that the proposed Merger is
reasonable "and that the public will be convenienced thereby." The Commission
may make such a finding without a hearing. In Iowa-Illinois Gas and Electric
Co., Docket 94-0439 ("MidAmerican"), the Commission identified the factors it
will consider in assessing whether the public convenience would be served:
"[P]ublic convenience" must be read in the context of the specific
purposes of the Act, namely to provide the public with efficient
utility service at a reasonable cost. Our supreme court has stated
that the public convenience factor, when read in the context of the
Act, includes such factors as costs to customers, simplification of
utility service, operating costs, facilities planning and proximity of
service territories (Illinois Power Co. v. Illinois Commerce
Commission (1986), 111 Ill.2d 505, 96 Ill. Dec. 50, 490 N.E.2d 1255)
2. SECTION 7-204
Section 7-204 of the Act requires the Commission's approval of any
reorganization. The term "reorganization" is defined as "any transaction which,
regardless of the means by which it is accomplished, results in a change in the
ownership of a majority of the voting capital stock of an Illinois public
utility; or the ownership or control of any entity which owns or controls a
majority of the voting capital stock of a public utility." 220 ILCS 5/7-204.
Section 7-204 further provides that the "Commission shall not approve any
proposed reorganization if the Commission finds, after notice and hearing, that
the reorganization will adversely effect the utility's ability to
8
<PAGE>
perform its duties under this Act." Id. Thus, the Commission should approve
the Merger if there is no adverse effect on the utility's ability to perform its
duties under the Act. Furthermore, to protect the interests of the public
utility and its customers, the Commission, in approving the proposed
reorganization, may impose such terms, conditions or requirements as are
necessary.
Under Section 7-204, the Commission must find that:
1. the proposed reorganization will not diminish the utility's
ability to provide adequate, reliable, efficient, safe and least-cost
public utility service;
2. the proposed reorganization will not result in the unjustified
subsidization of non-utility activities by the utility or its customers;
3. costs and facilities are fairly and reasonably allocated between
utility and non-utility activities in such a manner that the Commission may
identify those costs and facilities which are properly included by the
utility for ratemaking purposes;
4. the proposed reorganization will not significantly impair the
utility's ability to raise necessary capital on reasonable terms or to
maintain a reasonable capital structure; and
5. the utility will remain subject to all applicable laws,
regulations, rules, decisions and policies governing the regulation of
Illinois public utilities.
9
<PAGE>
B. THE PROPOSED MERGER IS REASONABLE, WILL CONVENIENCE THE PUBLIC, AND
WILL NOT IMPAIR THE PROVISION OF PUBLIC UTILITY SERVICE IN CONFORMANCE
WITH THE ACT
As discussed in the testimony of Mr. Koertner and Mr. Flaherty, the Merger
discussed herein is expected to produce savings of approximately $590 million
over the next 10 years, with no diminution in the quality of service to
customers.
That the Merger is reasonable is also demonstrated by the accompanying
evidence, which provides ample support for the findings which the Commission
must make under Section 7-204:
1. The proposed reorganization will not diminish the utility's
ability to provide adequate, reliable, efficient, safe and least-cost
public service. (Section 7-204(a))
Refer to the Testimony of William A. Koertner at pages 14-15,
Gilbert W. Moorman at pages 6-7 and Steven Pettit at page 15.
2. The proposed reorganization will not result in the unjustified
subsidization of non-utility activities by the utility or its customers.
(Section 7-204(b))
Refer to the Testimony of William A. Koertner at pages 15-16,
Lynda E. Marlett at pages 8-9, and Robert J. Mill at pages 15-16,
and to Exhibit RJM-3.
3. Costs and facilities are fairly and reasonably allocated between
utility and non-utility activities in such a manner that the Commission may
identify those costs and facilities which are properly included by the
utility for ratemaking purposes. (Section 7-204(c))
10
<PAGE>
Refer to the Testimony of William A. Koertner at pages
15-16, Lynda E. Marlett at pages 8-9 and Robert J. Mill at pages
15-16.
4. The proposed reorganization will not significantly impair the
utility's ability to raise necessary capital on reasonable terms or to
maintain a reasonable capital structure. (Section 7-204(d))
Refer to the Testimony of William A. Koertner at pages 11-12 and
Craig D. Nelson at pages 7-9.
5. The utility will remain subject to all applicable laws,
regulations, rules, decisions and policies governing the regulation of
Illinois public utilities. (Section 7-204(e))
Refer to the Testimony of William A. Koertner at pages 15-16 and
Robert J. Mill at pages 16-17.
IV. REQUIREMENTS UNDER SECTION 7-204A FOR APPLICATION FOR APPROVAL OF
REORGANIZATION
As discussed above, Section 7-204A identifies the information that must be
provided in connection with a filing pursuant to Section 7-204.
A. NAMES AND CORPORATE RELATIONSHIPS OF ALL COMPANIES WHICH ARE
AFFILIATED INTERESTS OF THE PUBLIC UTILITY ON THE DATE THE PUBLIC
UTILITY APPLIES FOR REORGANIZATION AND THE NAME OF ANY PARENT OR
SUBSIDIARY CORPORATION OF THE PUBLIC UTILITY. (SECTION 7-204A(A)(1)).
Refer to the Testimony of Clifford L. Greenwalt at pages 2-3 and
to Exhibit WAK-5.
11
<PAGE>
B. A DESCRIPTION OF HOW THE PUBLIC UTILITY PLANS TO REORGANIZE. (SECTION
7-204A(A)(2))
Refer to the Testimony of Clifford L. Greenwalt at pages 4-5 and
to Exhibits CLG-2, CLG-3 and WAK-2.
C. COPIES OF THE ORGANIZATION DOCUMENTS ASSOCIATED WITH THE
REORGANIZATION, INCLUDING ARTICLES OF INCORPORATION OR AMENDMENTS TO
THE ARTICLES OF INCORPORATION OF ALL COMPANIES INCLUDING THE PUBLIC
UTILITY AND ANY AFFILIATED INTEREST. (SECTION 7-204A(A)(2)(I))
Refer to Exhibits WAK-2, CDN-7 and CDN-8.
D. COPIES OF ANY FILINGS, INCLUDING SECURITIES FILINGS, RELATED TO THE
REORGANIZATION MADE WITH ANY AGENCY OF THE STATE OF ILLINOIS OR THE
FEDERAL GOVERNMENT. (SECTION 7-204A(A)(2)(II))
Applicants will file with the Commission a copy of each future filing
with any agency of the State of Illinois, the State of Missouri or the
federal government which they may make in regard to the Merger. Applicants
anticipate making the following filings: (i) a Joint Application by UE and
CIPS for Authorization and Approval of Merger filed with the Federal Energy
Regulatory Commission ("FERC") pursuant to Section 203 of the Federal Power
Act ("FPA"); (ii) a Network Integration Service Tariff and a Point-to-Point
Transmission Service Tariff filed by UE and CIPS with FERC pursuant to
Section 205 of the FPA; (iii) a System Support Agreement between UE and
CIPS filed with FERC pursuant to Section 205 of the FPA; (iv) a Joint
Dispatch Agreement between UE and CIPS filed with FERC pursuant to Section
205 of the FPA; (v) a Notification and Report Form for Certain Mergers and
Acquisitions filed with the United States Department of Justice and the
Federal Trade Commission pursuant to the
12
<PAGE>
Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; (vi)
filings with the SEC for (a) registration of the exchange of Ameren common
stock for the common stock of CIPSCO and Union Electric pursuant to an S-4
Registration Statement, under the Securities Act of 1933, and (b) approval
of acquisition of securities and utility assets and other interests and
other matters under Sections 6, 7, 9, 10, and 11 of PUHCA, approval of
arrangements for provision of services among affiliates, and registration
of Ameren as a holding company under Section 5 of PUHCA; (vii) an
Application by UE with the Nuclear Regulatory Commission ("NRC") requesting
authorization for transfer, directly or indirectly, through transfer of
control, of the operating license, and all rights thereunder, for the
Callaway Nuclear Plant; and (viii) an Application by UE for Approval of
Merger pursuant to the Public Utilities Act of Missouri with the Missouri
Public Service Commission to grant approval of, inter alia, the merger of
UE with Arch Merger, Inc. The transmission tariffs and the Joint Dispatch
Agreement to be filed with FERC are discussed in Gilbert W. Moorman's
Testimony; the System Support Agreement and the arrangements for provision
of services among affiliates are discussed in Robert J. Mill's testimony.
Copies of these filings will be provided to the Commission concurrently
with making the filing or immediately thereafter.
13
<PAGE>
E. THE COSTS AND FEES ATTRIBUTABLE TO THE REORGANIZATION. (SECTION
7-204A(a)(3)
Refer to the Testimony of William A. Koertner at pages 9-10 and
to Exhibit GLR-5.
F. THE METHOD BY WHICH MANAGEMENT, PERSONNEL, PROPERTY, INCOME, LOSSES,
COSTS AND EXPENSES WILL BE ALLOCATED BETWEEN THE PUBLIC UTILITY AND
ANY AFFILIATED INTEREST. (SECTION 7-204A(a)(4))
Refer to the Testimony of Robert J. Mill at pages 15-16 and Lynda
E. Marlett at pages 6-9.
G. A COPY OF ANY PROPOSED AGREEMENT BETWEEN THE PUBLIC UTILITY AND ANY
PERSON WITH WHICH IT WILL BE AN AFFILIATED INTEREST AT THE TIME OF THE
APPLICATION FOR REORGANIZATION. (SECTION 7-204A(a)(5))
Refer to the Testimony of Robert J. Mill at pages 15-16 and
Gilbert W. Moorman at pages 14-15 and to Exhibits RJM-3 and
GWM-6.
H. AN IDENTIFICATION OF ALL PUBLIC UTILITY ASSETS OR INFORMATION IN
EXISTENCE, SUCH AS CUSTOMER LISTS, WHICH THE APPLICANT PLANS TO
TRANSFER TO OR PERMIT AN AFFILIATED INTEREST TO USE, WHICH
IDENTIFICATION SHALL INCLUDE A DESCRIPTION OF THE PROPOSED TERMS AND
CONDITIONS UNDER WHICH THE ASSETS OR INFORMATION WILL BE TRANSFERRED
OR USED. (SECTION 7-204A(a)(6))
None, except those identified on Exhibit GLR-3.
I. A COPY OF A FORECAST SHOWING THE CAPITAL REQUIREMENTS OF THE PUBLIC
UTILITY AT THE TIME OF THE PROPOSED REORGANIZATION. (SECTION
7-204A(a)(7))
Refer to the Testimony of Craig D. Nelson at pages 10-11 and to
Exhibit CDN-6.
J. NO PUBLIC UTILITY MAY PERMIT THE USE OF ANY PUBLIC UTILITY EMPLOYEE'S
SERVICES BY ANY AFFILIATED INTEREST EXCEPT BY CONTRACT OR ARRANGEMENT.
NO PUBLIC UTILITY MAY SELL, LEASE, TRANSFER TO OR EXCHANGE WITH ANY
AFFILIATED INTEREST ANY PROPERTY EXCEPT BY CONTRACT OR ARRANGEMENT.
(SECTION 7-204A(b))
Refer to the Testimony of Lynda E. Marlett at pages 8-9 and
Robert J. Mill at pages 15-16 and to Exhibit RJM-3.
14
<PAGE>
V. AMEREN'S RELATIONSHIPS WITH ITS AFFILIATED INTERESTS WILL BE CONSISTENT
WITH THE PROVISIONS OF THE ACT
A. OVERVIEW OF CORPORATE STRUCTURE
Ameren will operate as a registered holding company under PUHCA, and will
be the parent of UE, CIPS and CIC. CIC will continue to be the parent of
CIPSCO's other non-utility subsidiaries, and UE and CIPS will continue to hold
their respective interests in EEInc. UE will also continue to be the parent of
UED. As noted above, a chart showing the corporate structure after the Merger
accompanies this Application as Appendix C.
B. TRANSACTIONS INVOLVING AFFILIATED INTERESTS NECESSARY TO EFFECT THE
MERGER AND REORGANIZATION WHICH REQUIRE COMMISSION APPROVAL PURSUANT
TO SECTIONS 7-101, AND 7-204A(b)
Section 7-101(3), in relevant part, states:
No management, construction, engineering, supply, financial or similar
contract and no contract or arrangement for the purchase, sale, lease
or exchange of any property or for the furnishing of any service,
property or thing, hereafter made with any affiliated interest, ...
shall be effective unless it has first been filed with and consented
to by the Commission.
Section 7-204A(b) states:
No public utility may permit the use of any public utility employee's
services by any affiliated interest except by contract or arrangement.
No public utility may sell, lease, transfer to or exchange with any
affiliated interest any property except by contract or arrangement.
The contract or arrangement herein is subject to Commission review at
the discretion of the Commission, in the same manner as it may review
any other public utility and its affiliated interest.
As explained in the supporting testimony, some utility asset transfers, and
other transactions, will occur as part of the proposed Merger. Applicants
believe that by requesting the
15
<PAGE>
Commission to approve the Merger as described in the accompanying Testimony and
Exhibits and to authorize the transactions contemplated thereby, they have
placed before the Commission all transactions requiring Commission approval and
not otherwise exempt from Commission approval pursuant to 83 Ill. Adm. Code (S)
310.60 and that further requests for Commission approval would be unnecessary.
See MidAmerican, Ill. C.C. No. 94-0439 (May 3, 1995). Accordingly, the
Applicants believe that they are in compliance with Sections 7-101(3) and
7-204(b) of the Act.
C. TRANSACTIONS BETWEEN CIPS AND OTHER AMEREN AFFILIATES
1. PROVISION OF SERVICES
As indicated above, subsequent to the Merger, Applicants intend to
integrate various corporate functions. This could result in varying
arrangements, such as in CIPS and UE providing services to each other and other
affiliates, or in a service company providing services to the Ameren companies.
Applicants have prepared a form contract of a services agreement (the
"General Services Agreement"), which accompanies Mr. Mill's testimony.
Applicants intend to file such an agreement with the SEC for its approval. Under
PUHCA, the SEC has jurisdiction over affiliated interest transactions of public
utility affiliates of a registered holding company. PUHCA and the SEC's rules
generally require that such public utility affiliates provide services to each
other at cost. Applicants request that the Commission find that the principles
reflected in the General Services Agreement are reasonable and in the public
interest.
16
<PAGE>
In its Order on Reopening in Docket No. 86-0256, the proceeding in which
the Commission approved the formation of CIPS's holding company parent, the
Commission approved certain accounting procedures and found that each of CIPS'
affiliates should pay to CIPS an annual compensatory payment equal to five
percent of the dollar amount of "direct transactions" between CIPS and that
affiliate. In this context, the Commission defined affiliate to include "only
[CIPSCO] and any non-utility company a majority of whose stock is owned by
[CIPSCO]." Order on Reopening, p. 16. Applicants also request that, in
recognition of the new arrangements which will be required by the Merger, and
which will be subject to SEC approval, the Commission terminate the accounting
and allocation procedures it approved in Docket 86-0256, effective upon
consummation of the Merger.
2. SYSTEM SUPPORT AGREEMENT
As discussed above, upon consummation of the Merger, CIPS will succeed to
UE's electric and gas utility business in Illinois. UE's present Illinois
electric customers are served from UE's electric generating capacity. To permit
CIPS to absorb the load represented by former UE customers in Illinois, CIPS and
UE will enter into a System Support Agreement. Under that Agreement, UE will
provide CIPS with the amount of capacity presently allocated by UE to its
Illinois electric operations.
The System Support Agreement, which is discussed in detail in Mr. Mill's
testimony, requires the approval of, and will be filed with, FERC. Additionally,
Applicants request that this
17
<PAGE>
Commission make a finding that CIPS' entry into the agreement is prudent and
reasonable, and consent thereto.
3. JOINT DISPATCH AGREEMENT
CIPS and UE also intend to enter into a Joint Dispatch Agreement, pursuant
to which CIPS and UE will operate their combined generation and transmission
facilities as a single control area. The Joint Dispatch Agreement will be filed
with FERC. Applicants request that the Commission make a finding that CIPS'
entry into a Joint Dispatch Agreement with UE is prudent and reasonable, and
consent thereto.
VI. REQUEST FOR APPROVAL OF CAPITALIZATION PURSUANT TO SECTION 6-103
Section 6-103 provides that, in any reorganization of a public utility, the
amount of capitalization of the public utility, including all stocks and stock
certificates and bonds, notes and other evidences of indebtedness, shall be as
authorized by the Commission. The capital structure and forecasted capital
requirements of CIPS (the surviving Illinois public utility) immediately prior
and subsequent to effectuation of the Merger are discussed by Mr. Nelson in his
Testimony. Applicants request that the Commission approve CIPS' capitalization.
VII. CERTIFICATES OF PUBLIC CONVENIENCE AND NECESSITY AND FRANCHISES
A. REQUEST, PURSUANT TO SECTION 8-508, TO AUTHORIZE UE TO DISCONTINUE
PROVIDING RETAIL ELECTRIC AND GAS SERVICE IN THE STATE OF ILLINOIS
Except for certain transactions involving political subdivisions or
municipalities, Section 8-508 prohibits a public utility from abandoning or
discontinuing any service without the
18
<PAGE>
approval of the Commission. As described in this Application and the supporting
Testimony and Exhibits, upon consummation of the Merger, UE's Illinois utility
operations and assets (other than certain electric generating and transmission
plant) will be transferred to CIPS, and CIPS will provide electric and gas
service to the customers in Illinois who received such service from UE
immediately prior to the consummation of the Merger. At such time, CIPS will
commence providing service to those customers subject to essentially the same
rates, terms and conditions as offered by UE until such rates, terms and
conditions are changed by CIPS in accordance with the Act. The new Illinois
customers of CIPS will continue to receive adequate, reliable, efficient, safe
and least-cost public utility service after the Merger. Consequently, the
Applicants request, pursuant to Section 8-508, that the Commission permit UE to
discontinue service to its retail Illinois electric and gas customers, subject
to consummation of the proposed Merger.
B. REQUEST OF THE APPLICANTS FOR TRANSFER OF CERTIFICATES OF PUBLIC
CONVENIENCE AND NECESSITY ISSUED PURSUANT TO SECTION 8-406
Section 8-406 of the Act governs certificates of public convenience and
necessity. Section 8-406(e) further provides that any authorization or order
granted to a public utility by the Commission under the Electric Supplier Act,
220 ILCS 30/1, et seq., shall be deemed to be a certificate of public
convenience and necessity issued pursuant to Section 8-406.
UE holds numerous certificates of public convenience and necessity issued
pursuant to, or deemed to have been issued
19
<PAGE>
pursuant to, Section 8-406. Therefore, Applicants request that the Commission,
upon finding that the conditions exist for approval of the Merger pursuant to
Sections 7-102 and 7-204 and authorizing the Merger pursuant to such Sections,
also authorize the general transfer to CIPS of the certificates of public
convenience and necessity granted, or deemed to be granted, to UE pursuant to
Section 8-406, without requiring specific identification of each such
certificate.
C. REQUEST FOR APPROVAL OF TRANSFER OF FRANCHISES
Section 7-203 of the Act requires the Commission's approval of the
assignment or transfer of any "franchise, license, permit or right to own,
operate, manage or control any public utility." As discussed above, CIPS will
succeed to UE's electric and gas utility business in Illinois. Applicants
request that the Commission approve the transfer to CIPS of the franchises and
other similar rights which UE currently holds in Illinois, effective as of
closing of the Merger.
D. FINDING REGARDING UE'S STATUS UNDER THE ACT
Upon transfer of UE's electric and gas distribution assets, operations,
franchises and certificates to CIPS, UE will no longer have any retail customers
within Illinois. Further, UE will not hold itself out as providing retail
electric or gas utility service to the public in Illinois. Accordingly,
Applicants request that the Commission find that, effective as of closing of the
Merger, UE will not be a public utility within the meaning of Section 3-105 of
the Illinois Public Utilities Act. 220 ILCS 5/3-105 (1993).
20
<PAGE>
VIII. CIPS WILL FILE TARIFFS IN ACCORDANCE WITH SECTION 9-102
Section 9-102 requires every public utility to file with the Commission
schedules showing all rates, charges, classifications, rules and regulations
relating to any product, commodity or service provided by the public utility.
Upon consummation of the Merger, CIPS will adopt essentially the same rates,
charges, classifications, rules and regulations relating to electric and gas
service as UE had in effect prior to consummation of the Merger for service
provided by CIPS to the customers in the former UE Illinois service territory.
The new CIPS tariffs for service to that service territory are discussed in Mr.
Mill's testimony and will be filed with the Commission pursuant to Sections
9-102, 9-103 and 9-201. These tariffs will continue in effect until changed
pursuant to the Act and the rules promulgated thereunder.
Due to the exigencies of implementing the Merger upon receiving all
requisite shareholder and regulatory approvals, CIPS anticipates filing its
tariffs with the Commission less than 45 days before consummating the Merger.
Therefore, CIPS requests the Commission to exercise its authority under Section
9-201 to waive the 45 day notice requirement for the filing of tariffs and to
include in the order approving the Merger a provision authorizing CIPS to file
its tariffs as proposed herein not less than five days prior to consummating the
Merger, such date of consummating the Merger being the effective date of the
tariffs. See MidAmerican, Docket 94-0439 (May 3, 1995).
21
<PAGE>
IX. REGULATORY TREATMENT OF MERGER-RELATED COSTS AND SAVINGS
CIPS intends to file new electric base rates applicable to its present
service territory no later than 12 months after closing of the Merger, and
possibly as early as mid-1996. The rate filing will include an alternative
regulation plan and a proposal for reflecting in rates the effect of the Merger,
including cost savings, the costs to achieve those savings, transaction costs
and the merger premium. Specifically, CIPS intends to propose that, over the
first ten years following the Merger, Merger-related savings, net of the costs
to achieve, transaction costs and merger premium, be shared equally between the
shareholders and ratepayers. All Merger-related savings after that ten year
period would accrue to the sole benefit of the ratepayers. The proposal is
discussed in detail in the testimony of Mr. Rainwater. Applicants request that
the Commission find that this proposed treatment of the Merger-related costs and
cost savings is reasonable, and should be reflected in the alternative
regulation plan filed by CIPS.
X. DISPOSITION OF NUCLEAR DECOMMISSIONING TRUST
UE's rates in Illinois, as well as its wholesale rates and its rates in
Missouri, recognize nuclear decommissioning expenses. The amounts reflected in
cost of service are deposited quarterly in an external qualified trust. UE also
maintains a non-qualified trust, subject to this Commission's jurisdiction under
Section 8-508.1 of the Act. The amount collected by UE annually from Illinois
ratepayers is $355,000, and, as of June 30, 1995, a total of $5.7 million is
held in the Illinois
22
<PAGE>
subaccount of the external qualified trust. No funds are held in the non-
qualified trust.
As discussed above, once the Merger is consummated, UE will no longer
have an Illinois retail electric jurisdiction. Since the IRS requires that
contributions into a qualified trust must be included in the contributing
jurisdiction's cost of service, UE will no longer be able to place the annual
contribution from Illinois customers into the qualified trust.
As also discussed above, UE and CIPS propose to enter into a System
Support Agreement. That agreement provides, inter alia, for the payment by CIPS
to UE of nuclear decommissioning costs, which would be contributed to the
qualified trust quarterly in the FERC subaccount, because the System Support
Agreement is FERC jurisdictional.
Applicants request that, to the extent required by Section 8-508.1 of the
Act, the Commission authorize transfer of the balance of funds in the Illinois
subaccount, as of the date of the Merger, to the FERC subaccount in connection
with the UE-CIPS asset transfer. As discussed in Mr. Jerre Birdsong's
testimony, such a transfer of funds is reasonable and in the public interest.
XI. CONCLUSION
For the reasons stated above, Applicants respectfully request the
Commission to issue an order approving this Application. Specifically,
Applicants request the Commission to issue an order as follows:
23
<PAGE>
A. Pursuant to Section 7-102, authorizing CIPSCO to merge with
Ameren, and UE to merge with Arch Merger, Inc., with Ameren becoming the
holding company parent of UE and CIPS, and CIPS acquiring UE's Illinois
assets (other than electric generation and transmission assets) and
succeeding to UE's Illinois public utility business, all as set forth
herein;
B. Pursuant to Section 7-204, authorizing UE, CIPS and CIPSCO to
reorganize as set forth in this Application;
C. Pursuant to Sections 7-101, 7-102 and 7-204A, authorizing CIPS to
engage in transactions with affiliated interests as set forth in this
Application;
D. Finding that the cost allocation principles reflected in the
General Services Agreement are reasonable;
E. Finding that CIPS' entry into System Support Agreement is prudent
and reasonable and consenting thereto;
F. Finding that CIPS' entry into the Joint Dispatch Agreement is
prudent and reasonable and consenting thereto;
G. Pursuant to Section 6-103, approving the Merger capitalization of
CIPS, as set forth herein;
H. Pursuant to Section 8-508, authorizing UE to discontinue
providing retail electric and gas service in the State of Illinois as of
the date of closing of the proposed Merger;
24
<PAGE>
I. Pursuant to Section 8-406, generally transferring to CIPS all
certificates of public convenience and necessity issued by the Commission
pursuant to Section 8-406, or any similar provision of predecessor
statutes, to UE;
J. Pursuant to Section 7-203, transferring to CIPS all Illinois
franchises, licenses, permits or rights held by UE at the effective time
of the Merger;
K. Finding that, upon UE's discontinuance of retail electric and
gas service in Illinois, UE shall cease to be a public utility within
Section 3-105 of the Act;
L. Pursuant to Section 9-201, waiving the 45 day notice requirement
for the filing of the initial CIPS tariffs and authorizing CIPS to file
such tariffs not less than five days prior to the effective time of the
Merger which time shall be the effective time of the tariffs;
M. Finding that it is appropriate for CIPS to propose an alternative
regulation plan that would share between shareholders and ratepayers,
over a ten year period, Merger-related savings, net of costs to achieve,
transaction costs and the merger premium;
N. Terminating the conditions for transactions among CIPS and its
affiliates in Docket 86-0256, effective upon consummation of the Merger;
O. To the extent required by Section 8-508.1, approving the transfer
of funds in the Illinois subaccount
25
<PAGE>
of UE's nuclear decommissioning qualified external trust to the FERC
subaccount of that same trust; and
P. Authorizing Applicants' performance of such other and further
actions or transactions which are not contrary to the Act or the rules of
the Commission, or inconsistent with this Application, as may be necessary
and appropriate to carry out the actions and transactions proposed by this
Application.
Respectfully submitted,
CENTRAL ILLINOIS PUBLIC UNION ELECTRIC COMPANY
SERVICE COMPANY
CIPSCO INCORPORATED
/s/ Christopher W. Flynn /s/ Joseph H. Raybuck
By:_____________________________ By:_________________________
David J. Rosso Joseph H. Raybuck
Christopher W. Flynn Steven R. Sullivan
Thomas D. Brooks Union Electric Company
Jones, Day, Reavis & Pogue 1901 Chouteau Avenue
77 West Wacker P.O. Box 149
Suite 3500 St. Louis, Missouri 63166
Chicago, Illinois 60606-1692
Attorneys for Central Illinois Attorneys for Union
Public Service Company and Electric Company
CIPSCO, Incorporated
26
<PAGE>
Exhibit D - 4.1
February 23, 1996
U.S. Nuclear Regulatory Commission
Attn: Document Control Desk
Mail Station P1-137
Washington, D.C. 20555 ULNRC-03341
Gentlemen:
DOCKET NUMBER 50-483
CALLAWAY PLANT
REVISION TO FACILITY OPERATING LICENSE NO. NPF-30
-------------------------------------------------
Union Electric Company herewith transmits an application for amendment to
Facility Operating License No. NPF-30 for Callaway Plant.
Union Electric Company ("Union Electric") is the holder of Facility
Operating License No. NPF-30 ("the License") for Callaway Plant Unit No. 1
("Callaway"). It has entered into a merger agreement with CIPSCO Incorporated
which provides for Union Electric to become a wholly-owned operating company of
Ameren Corporation ("Ameren"), a registered public utility holding company under
the Public Utility Holding Company Act of 1935, as amended. By this Application,
Union Electric requests that the License be amended, pursuant to 10 C.F.R. (S)
50.90 to reflect Union Electric's status as an operating company subsidiary of
Ameren.
Attachments 1 and 2 contain the Application of Union Electric Company for
Amendment of License No. NPF-30 and Safety Evaluation, and the Proposed
Operating License Change in support of this amendment request, respectively. The
Application references four Exhibits: The Agreement and Plan of Merger, the
Ameren Corporation Unaudited Pro Forma Combined Condensed Balance Sheet, the
Significant Hazards Evaluation, and the Environmental considerations. This
change request has been approved by the Callaway Onsite Review Committee and the
Nuclear Safety Review Board.
We are requesting that the NRC Staff please expedite their review of this
submittal so that the requested
<PAGE>
U.S. Nuclear Regulatory Commission
Page 2
amendment will be issued by August 1996 to facilitate the completion of the
Merger.
If you have any questions concerning this matter, please contact me.
Very truly yours,
/s/ Donald F. Schnell
JMC:mas
Attachments: 1) Application for Amendment of License
and Safety Evaluation
(includes 4 Exhibits)
2) Proposed Operating License Change
<PAGE>
Attachment 1
ULNRC-03341
ATTACHMENT 1 CONTENTS
---------------------
1) APPLICATION FOR AMENDMENT AND SAFETY EVALUATION
PAGES 1 THRU 15
2) EXHIBIT 1 - AGREEMENT AND PLAN OF MERGER
3) EXHIBIT 2 - AMEREN CORPORATION BALANCE SHEET
4) EXHIBIT 3 - SIGNIFICANT HAZARDS CONSIDERATION
5) EXHIBIT 4 - ENVIRONMENTAL CONSIDERATION
<PAGE>
APPLICATION OF UNION ELECTRIC COMPANY FOR
AMENDMENT OF LICENSE NO. NPF-30 AND SAFETY EVALUATION
-----------------------------------------------------
I. INTRODUCTION
------------
Union Electric Company ("Union Electric") is the holder of Facility
Operating License No. NPF-30 ("License") for Callaway Plant Unit No. 1
("Callaway"). It has entered into a merger agreement with CIPSCO Incorporated
("CIPSCO") which provides for Union Electric to become a wholly-owned operating
company of Ameren Corporation ("Ameren"), a registered public utility holding
company under the Public Utility Holding Company Act of 1935, as amended ("the
1935 Act"). By this Application, Union Electric requests that the License be
amended, pursuant to 10 C.F.R. (S) 50.90 to reflect Union Electric's status as
an operating company subsidiary of Ameren.
The Agreement and Plan of Merger among Union Electric, CIPSCO, Ameren, and
Arch Merger, Inc., dated August 11, 1995 ("the Merger Agreement"), is attached
as Exhibit 1. Pursuant to the Merger Agreement, Union Electric, Central Illinois
Public Service Company ("CIPS") (CIPSCO's principal utility operating
subsidiary) and CIPSCO Investment Company (CIPSCO's subsidiary for conducting
non-utility businesses) will become wholly-owned operating subsidiaries of
Ameren.
Union Electric, a Missouri corporation, is the largest electric utility in
Missouri. It supplies electric service to customers in its service territories
in Missouri and Illinois having an estimated population of 2,600,000 within an
area of approximately 24,500 square miles, including the greater St. Louis area.
In addition, Union Electric supplies natural gas
<PAGE>
service to the public in ninety (90) Missouri communities, and in Alton,
Illinois and vicinity.
CIPSCO, an Illinois corporation, is the parent holding company of CIPS,
CIPSCO's principal utility operating subsidiary. CIPSCO conducts its non-utility
businesses through a second subsidiary, CIPSCO Investment Company ("CIC"), an
Illinois corporation. CIPS serves 317,000 retail electric customers and 166,000
natural gas customers in its 20,000 square mile central and southern Illinois
service territory having an estimated population of 820,000.
Ameren is a Missouri corporation fifty percent (50%) of which is owned by
each of Union Electric and CIPSCO. Ameren was formed by Union Electric and
CIPSCO for the purpose of effecting the transactions contemplated by the Merger
Agreement. After the merger, Ameren will be the holding company for Union
Electric, CIPS, and the other subsidiaries of CIPSCO. Ameren will be a public
utility holding company registered under the 1935 Act. The principal executive
office of Ameren will be located at 1901 Chouteau Avenue, St. Louis, Missouri
63103.
Arch Merger, Inc. is a Missouri corporation wholly-owned by Ameren which
was created to effect the Union Electric merger. It has no operations except as
contemplated by the Merger Agreement.
Callaway is a nuclear powered generating facility which is solely-owned and
operated by Union Electric in accordance with the License. After the merger,
Union Electric, as a subsidiary of Ameren, will continue to own and operate
Callaway.
2
<PAGE>
II. THE MERGER
----------
The Merger Agreement provides for two separate mergers ("the Merger").
A. The Union Electric Merger in which Arch Merger, Inc. will be merged
with and into Union Electric with Union Electric to be the surviving
corporation, and
B. The CIPSCO Merger in which CIPSCO will be merged with and into
Ameren with Ameren to be the surviving corporation.
The surviving corporate structure will have Ameren as the holding company
with Union Electric, CIPS and CIPSCO Investment Co. as subsidiaries.
Pursuant to the Merger Agreement, each outstanding share of Union Electric
Common Stock, with some exceptions as specified in Exhibit 1, will be exchanged
for one share of Ameren Common Stock. Each share of Union Electric Preferred
Stock, with some exceptions as specified in Exhibit 1, will remain outstanding
and unchanged. Each share of CIPSCO Common Stock, with some exceptions as
specified in Exhibit 1, will be exchanged for 1.03 shares of Ameren Common
Stock. As a result of the Merger, the common shareholders of Union Electric and
CIPSCO immediately prior to the Merger (except for the holders of Union Electric
Dissenting shares) will all be common shareholders of Ameren immediately upon
the consummation of the Mergers.
The Merger will have no effect on the operation of Callaway or the
provisions of its License. Union Electric will continue to own and operate
Callaway after the Merger, as required by the License.
3
<PAGE>
Proxy materials were distributed to the shareholders of Union Electric and
CIPSCO on November 13, 1995. Special meetings of the shareholders of Union
Electric and CIPSCO were held on December 20, 1995. The shareholders of both
companies approved the Merger Agreement.
In addition to this Application, other applications, reviews or proceedings
regarding the Merger are pending before the Federal Energy Regulatory Commission
("FERC"), the Missouri Public Service Commission ("MPSC"), and the Illinois
Commerce Commission ("ICC"). Also, an application will be filed in the near
future with the Securities and Exchange Commission ("SEC") regarding the Merger.
The information required to be included in an application to amend a
license pursuant to 10 C.F.R. (S) 50.90 is stated below./1/ This information
demonstrates that the requested consent is consistent with applicable provisions
of law, NRC regulations and NRC orders. Antitrust information is set forth in
Section V below.
III. DESCRIPTION OF PROPOSED CHANGE
------------------------------
The Merger requires no change in the design or operation of Callaway.
Furthermore, the Merger does not require any change to the Technical
Specifications for Callaway. However, after the Merger, Union Electric will
become a wholly-owned operating
- ------------
/1/ Since Union Electric will continue to own and operate Callaway after the
Merger, no transfer of the License is necessary pursuant to 10 C.F.R. (S) 50.80.
However, this application proposes an amendment to reflect in the License Union
Electric's status as an operating company subsidiary of Ameren.
4
<PAGE>
subsidiary of Ameren. Therefore, the Merger may be deemed to effect a change in
the control of the owner of Callaway, Union Electric. Accordingly, this
Application requests the License be amended to reflect the effective change in
control of the owner of Callaway, Union Electric, as a result of the Merger.
With regard to the amendment of the License, Union Electric specifically
requests the NRC to add a footnote after the words "Union Electric Company" in
Paragraph 1.A of NPF-30 which states:
"As of the closing of the Merger contemplated by the Agreement and Plan of
Merger, by and among Union Electric Company, CIPSCO Incorporated, Ameren
Corporation and Arch Merger, Inc., dated August 11, 1995, Union Electric
Company is a wholly-owned operating subsidiary of Ameren Corporation."
IV. GENERAL INFORMATION CONCERNING THE LICENSEE
-------------------------------------------
A. Name and Address of Current Licensee
------------------------------------
Union Electric Company
1901 Chouteau Avenue
P.O. Box 149
St. Louis, MO 63103
B. Name and Address of Proposed Licensee
-------------------------------------
After the Merger, Union Electric will continue to own and operate Callaway.
Union Electric's address will not change as a result of the Merger.
C. Description of Business or Occupation of Licensee
-------------------------------------------------
Following the Merger, Union Electric will continue to be engaged
principally in the generation, transmission, distribution, and retail and
wholesale sale of electricity in Missouri. Union Electric will also continue to
be engaged in the distribution and retail sale of natural gas in Missouri.
5
<PAGE>
D. Organization and Management of Licensee
---------------------------------------
Union Electric is an independent, investor-owned public utility, duly
organized and existing under the laws of the State of Missouri. Its corporate
headquarters is located in St. Louis, Missouri. Following the Merger, Union
Electric will become a wholly-owned operating subsidiary of Ameren and it shall
maintain its corporate headquarters in St. Louis.
The officers of Union Electric, all of whom are citizens of the United
States, can be reached at 1901 Chouteau Avenue, St. Louis, Missouri 63103.
Their names and titles are:
Charles W. Mueller President and
Chief Executive Officer
Donald E. Brandt Senior Vice President
Finance & Corporate Services
Robert O. Piening Senior Vice President
Power Operations
Donald F. Schnell Senior Vice President
Nuclear
Charles J. Schukai Senior Vice President
Customer Services
Paul A. Agathen Senior Vice President
Energy Supply Service
M. Patricia Barrett Vice President
Corporate Communications
Charles A. Bremer Vice President
Information Services
Donald W. Capone Vice President
Engineering & Construction
William J. Carr Vice President
Customer Services-Regional
6
<PAGE>
Jean M. Hannis Vice President
Human Resources
William E. Jaudes Vice President
General Counsel
R. Alan Kelley Vice President
Energy Supply
Michael J. Montana Vice President
Supply Service
Garry L. Randolph Vice President
Nuclear Operations
Gary L. Rainwater Vice President
Corporate Planning
Robert J. Schukai Vice President
Power Plants
William C. Shores Vice President
Customer Services-Metropolitan
Samuel E. Willis Vice President
Industrial Relations
Ronald C. Zdellar Vice President
Customer Services-Division Support
Jerre Birdsong Treasurer
Joseph M. Pfeifer Controller
James C. Thompson Secretary
The Directors of Union Electric, all of whom are citizens of the United
States, can all be reached c/o James C. Thompson, Secretary, Union Electric
Company, 1901 Chouteau Avenue, St. Louis, Missouri 63103. Their names are:
William E. Cornelius
Thomas A. Hays
Thomas H. Jacobsen
Richard A. Liddy
John Peters MacCarthy
Paul L. Miller, Jr.
7
<PAGE>
Charles W. Mueller
Robert H. Quenon
Harvey Saligman
Janet Weakley
The Merger Agreement provides that after the Merger, the Board of Directors
of Union Electric, as the surviving corporation in the Union Electric Merger,
shall initially consist of Mr. Charles W. Mueller (President and Chief Executive
Officer of Union Electric), Mr. Clifford L. Greenwalt (President and Chief
Executive Officer of CIPSCO) and such other nominees as shall be determined by
the company. When the remaining Directors of Union Electric are selected, Union
Electric will submit their names as part of the annual financial report provided
to the NRC pursuant to 10 C.F.R. 50.71(b). Furthermore, all Directors selected
will be citizens of the United States.
E. Class and Period of License Applied For
---------------------------------------
Union Electric seeks NRC consent that after the Merger, Union Electric will
continue to own and operate Callaway, as a wholly-owned operating company
subsidiary of Ameren. Therefore, Union Electric requests that its existing
Class 103 license, NPF-30, be amended to reflect Union Electric's status as an
operating company subsidiary of Ameren.
The Merger will have no change on the duration of the License.
F. Financial Aspects
-----------------
After the Merger, Union Electric remains committed to provide all funds
necessary for the safe operation, maintenance,
8
<PAGE>
repair, decontamination and decommissioning of Callaway in conformance with NRC
regulations, subject to the same conditions, terms, and obligations of the
License. After the Merger, Union Electric's financial ability to fund the above
costs will be equal to, or greater than, its ability without the Merger. The
Merger will result in cost efficiencies to help maintain competitive rates.
Ameren will be more effective in meeting the challenges of the increasingly
competitive environment in the utility industry than Union Electric standing
alone. The Merger will also result in integration of corporate and
administrative functions, reduced operating costs through joint dispatch of the
Union Electric and CIPS systems, purchasing economies, increased marketing
opportunities in the wholesale and interchange markets, a more diverse service
territory, and expanded management resources. The above synergies from the
Merger will result in substantial cost savings which will benefit both
shareholders and customers.
Because Union Electric's ability after the Merger to provide all necessary
funds for the safe operation, maintenance, repair, decontamination and
decommissioning of Callaway will be equal to, or greater than its ability
without the Merger, a full financial qualifications' review should not be
necessary as a result of the approval requested in this Application.
Nevertheless, the Ameren Corporation Unaudited Pro Forma Combined Condensed
Balance Sheet at September 30, 1995 is attached as Exhibit 2. This information
shows that Union
9
<PAGE>
Electric remains financially qualified to carry out its financial commitments
under the License after the Merger.
G. Regulatory Agencies
-------------------
The regulatory agencies which have jurisdiction over Union Electric's rates
and services are:
Missouri Public Service Commission
P.O. Box 360
Jefferson City, MO 65102
Illinois Commerce Commission
527 East Capitol Avenue
Springfield, IL 62706
Federal Energy Regulatory Commission
888 First Street, NE
Washington, DC 20426
H. Restricted Data
---------------
This Application does not contain any restricted data or other defense
information.
V. ANTITRUST CONSIDERATIONS
------------------------
The Merger is subject to a separate antitrust review by the FERC. In
addition, it is subject to reviews by the Department of Justice ("DOJ") or the
Federal Trade Commission ("FTC") and the expiration of the applicable waiting
period under the Hurt-Scott-Rodino Antitrust Improvement Act of 1976 as amended
(the "HSR Act"). Union Electric also intends to file an Application for
Authorization and Approval of the Mergers with the SEC early in 1996. Because
antitrust issues will be among the issues addressed by the FERC, the DOJ, and
the FTC as discussed above,
10
<PAGE>
the NRC may rely on those proceedings and need not conduct its own antitrust
review of the Merger.
The NRC's deferral to agencies having primary jurisdiction in these matters
is entirely consistent with Regulatory Guide 9.3, Regulatory Staff Position
Statement on Anti-Trust Matters, which states, in relevant part, as follows:
In general, reliance would be placed on the exercise of [FERC] and
state jurisdiction regarding the specific terms and conditions of the
sale of power, rates for transmission services and such matters as may
be within the scope of their jurisdiction.
Therefore, the NRC need not conduct an antitrust review of the Merger and
can conclude that the Merger will not result in a "significant change" in the
activities of Union Electric.
VI. EFFECTIVE DATE
--------------
As discussed above, the Merger requires the approval of the FERC, the SEC,
the MPSC, and the ICC. In addition, it is subject to review by the DOJ or the
FTC and the expiration of the applicable waiting period under the HSR Act. The
companies are working to complete the Merger in 1996. Therefore, Union Electric
is seeking to obtain all necessary regulatory approvals prior to that time.
Union Electric requests that the NRC review this request on a schedule that will
result in final action as promptly as possible, and in any event prior to August
1, 1996. The license amendment shall be effective on issuance and will be
implemented prior to the closing of the Merger.
VII. COMMUNICATIONS REGARDING THIS APPLICATION
-----------------------------------------
11
<PAGE>
All communications pertaining to this Application should be sent to:
Joseph E. Birk
Assistant to the Vice President
and General Counsel
Union Electric Company
P.O. Box 149 (MC 1301)
St. Louis, MO 63166
William B. Bobnar
Attorney
Union Electric Company
P.O. Box 149 (MC 1310)
St. Louis, MO 63166
Alan C. Passwater
Manager-Licensing & Fuels
Union Electric Company
P.O. Box 149 (MC 470)
St. Louis, MO 63166
VIII. TECHNICAL ASPECTS
-----------------
Union Electric is neither requesting changes in the design and/or operation
of Callaway nor any changes in the terms and conditions of the License or
Technical Specifications. After consummation of the Merger, Union Electric will
continue to operate and support Callaway using the existing organizational
structure and personnel. The Merger will be described in the Callaway Final
Safety Analysis Report ("FSAR"). In addition, no changes are required in the
Physical Security Plan, Safeguards Contingency Plan, or the Radiological
Emergency Response Plan ("RERP"). The proposed change to the Operating License
does not involve an unreviewed safety question because the operation of the
Callaway Plant with this change would not:
12
<PAGE>
A. Increase the probability of occurrence or the consequences of an accident
or malfunction of equipment important to safety previously evaluated in the
safety analysis report. The proposed change does not affect accident
initiators or assumptions. The radiological consequences of any accident
previously evaluated remain unchanged. The change is an administrative
change to reflect Union Electric's status as an operating company
subsidiary of Ameren.
B. Create the possibility for an accident or malfunction of a different type
than any previously evaluated in the safety analysis report. The proposed
change does not create any new accident initiators nor involve any
modifications or changes in the plant. The change is administrative and
reflects Union Electric's status as an operating company subsidiary of
Ameren.
C. Reduce the margin of safety as defined in the basis for any technical
specification. The proposed change does not reduce the margin of safety
assumed in any accident analysis or affect any safety limits. The change
is administrative and reflects Union Electric's status as an operating
company subsidiary of Ameren.
On the basis of the above discussions and the considerations presented in
the Significant Hazards Consideration (see Exhibit 3), the proposed change does
not adversely affect or endanger the health or safety of the general public or
involve a significant safety hazard.
13
<PAGE>
XI. ENVIRONMENTAL CONSIDERATIONS
----------------------------
Environmental considerations are addressed in Exhibit 4.
X. REQUEST FOR NRC ACTION
----------------------
Union Electric requests, for the reasons stated above, that the NRC approve
the proposed amendment request of the License which describes Union Electric as
a wholly-owned subsidiary of Ameren Corporation as being consistent with the
applicable provisions of law, regulations and orders issued by the NRC pursuant
thereto.
Respectfully submitted,
UNION ELECTRIC COMPANY
By /s/ Donald F. Schnell
---------------------
Donald F. Schnell
Senior Vice President
Nuclear
14
<PAGE>
STATE OF MISSOURI )
) SS
CITY OF ST. LOUIS )
Donald F. Schnell, of lawful age, being first duly sworn upon oath, says
that he is Senior Vice President-Nuclear and an officer of Union Electric
Company; that he has read the foregoing document and knows the content thereof;
that he has executed the same for and on behalf of said Company with full power
and authority to do so; and that the facts therein stated are true and correct
to the best of his knowledge, information and belief.
By /s/ Donald F. Schnell
---------------------
Donald F. Schnell
Senior Vice President
Nuclear
SUBSCRIBED and sworn to before me this 23rd day of February, 1996.
Signature
---------------------
Notary Public
<PAGE>
cc: T. A. Baxter, Esq.
Shaw, Pittman, Potts & Trowbridge
2300 N. Street, N.W.
Washington, D.C. 20037
M. H. Fletcher
Professional Nuclear Consulting, Inc.
19041 Raines Drive
Derwood, MD 20855-2432
L. Joe Callan
Regional Administrator
US Nuclear Regulatory Commission
Region IV
611 Ryan Plaza Drive
Suite 400
Arlington, TX 76011-8064
Senior Resident Inspector
Callaway Resident Office
US Nuclear Regulatory Commission
8201 NRC Road
Steedman, MO 65077
Kristine M. Thomas (2)
Office of Nuclear Reactor Regulation
US Nuclear Regulatory Commission
1 White Flint, North, Mail Stop 13E16
11555 Rockville Pike
Rockville, MD 20852-2738
Manager, Electric Department
Missouri Public Service Commission
P.O. Box 360
Jefferson City, MO 65102
Ron Kucera
Department of Natural Resources
P.O. Box 176
Jefferson City, MO 65102
<PAGE>
Exhibit 1
Exhibit 1 to the NRC Application is included as Annex A to Exhibit C-1 to the
U-1 Application.
<PAGE>
Exhibit 2
Exhibit 2 to the NRC Application appears as Exhibit FS-1
to the U-1 Application.
<PAGE>
Exhibit 3
SIGNIFICANT HAZARDS CONSIDERATION
---------------------------------
This amendment request revises Union Electric Company's Facility Operating
License No. NPF-30 for Callaway Plant to add a footnote after the words "Union
Electric Company" in Paragraph 1.A to indicate that Union Electric has entered
into a merger agreement with CIPSCO Incorporated which provides for Union
Electric to become a wholly-owned operating company of Ameren Corporation, a
registered public utility holding company under the Public Utility Holding
Company Act of 1935, as amended ("the 1935 Act"). This proposed request allows
amendment of the License, such that after the merger, Union Electric will
continue to own and operate Callaway Plant as an operating company subsidiary of
Ameren.
The proposed change to the Operating License does not involve a significant
hazards consideration because operation of Callaway Plant with this change would
not:
A. Involve a significant increase in the probability or consequences of an
accident previously evaluated. The proposed change does not affect
accident initiators or assumptions. The radiological consequences of any
accident previously evaluated remain unchanged. The change is an
administrative change to reflect Union Electric's status as an operating
company subsidiary of Ameren.
B. Create the possibility of a new or different kind of accident from any
previously evaluated. The proposed change does not reduce the margin of
safety assumed in any accident analysis or affect any safety limits. The
change is administrative and reflects Union Electric's status as an
operating company subsidiary of Ameren.
C. Involve a significant reduction in a margin of safety. The proposed change
does not reduce the margin of safety assumed in any accident analysis or
affect any safety limits. The change is administrative and reflects Union
Electric's status as an operating company subsidiary of Ameren.
As discussed above, the proposed change is strictly administrative in
nature and has no effect on plant operations. The change does not involve a
significant increase in the probability or consequences of an accident
previously evaluated or create the possibility of a new or different kind of
accident from any previously evaluated. This change does not result in a
significant reduction in a margin of safety. Therefore, it has been determined
that the proposed change does not involve a significant hazards consideration.
<PAGE>
Exhibit 4
ENVIRONMENTAL CONSIDERATIONS
----------------------------
This amendment application revises Union Electric Company's Facility
Operating License No. NPF-30 for Callaway Plant to add a footnote after the
words "Union Electric Company" in Paragraph 1.A. of the license to indicate that
Union Electric has entered into a merger agreement with CIPSCO Incorporated
which provides for Union Electric to become a wholly-owned operating company of
Ameren Corporation.
The proposed amendment does not involve changes with respect to the use of
facility components located within the restricted area, as defined in 10 C.F.R.
20. It is an administrative change to revise a license condition. Union Electric
has determined that the proposed amendment does not involve:
(1) A significant hazards consideration, as discussed in Exhibit 3 of this
amendment application;
(2) A significant change in the types or significant increase in the amounts of
any effluents that may be released offsite;
(3) A significant increase in individual or cumulative occupational radiation
exposure.
Accordingly, the proposed amendment meets the eligibility criteria for
categorical exclusion set forth in 10 C.F.R. 51.22(c)(9). Pursuant to 10 C.F.R.
51.22(b), no environmental impact statement or environmental assessment need be
prepared in connection with the issuance of this amendment.
<PAGE>
Attachment 2
ULNRC-03341
PROPOSED OPERATING LICENSE CHANGE
PARAGRAPH 1.A MARKUP
<PAGE>
UNITED STATES
NUCLEAR REGULATORY COMMISSION
WASHINGTON, D.C. 20555
UNION ELECTRIC COMPANY
----------------------
DOCKET NO. STN 50-483
---------------------
CALLAWAY PLANT UNIT NO. 1
-------------------------
FACILITY OPERATING LICENSE
--------------------------
License No. NPF-30
1. The Nuclear Regulatory Commission (the Commission) has found that:
A. The application for license filed by Union Electric Company/*/
(licensee), complies with the standards and requirements of the Atomic
Energy Act of 1954, as amended (the Act), and the Commission's
regulations set forth in 10 CFR Chapter 1, and all required
notifications to other agencies or bodies have been duly made;
B. Construction of the Callaway Plant, Unit No. 1 (the facility) has been
substantially completed in conformity with Construction Permit No.
CPPR-139 and the application, as amended, the provisions of the Act,
and the regulations of the Commission;
C. The facility will operate in conformity with the application, as
amended, the provisions of the Act, and the regulations of the
Commission;
D. There is reasonable assurance: (i) that the activities authorized by
this operating license can be conducted without endangering the health
and safety of the public, and (ii) that such activities will be
conducted in compliance with the Commission's regulations set forth in
10 CFR Chapter 1;
E. Union Electric Company is technically qualified to engage in the
activities authorized by this license in accordance with the Commis-
sion's regulations set forth in 10 CFR Chapter 1;
F. The licensee has satisfied the applicable provisions of 10 CFR Part
140 "Financial Protection Requirements and Indemnity Agreements," of
the Commission's regulations;
G. The issuance of this license will not be inimical to the common
defense and security or to the health and safety of the public;
/*/ As of the closing of the Merger contemplated by the Agreement and Plan
of Merger, by and among Union Electric Company, CIPSCO Incorporated,
Ameren Corporation and Arch Merger, Inc., dated August 11, 1995, Union
Electric Company is a wholly-owned operating subsidiary of Ameren
Corporation.
<PAGE>
April 24, 1996
U.S. Nuclear Regulatory Commission
Attn: Document Control Desk
Mail Station P1-137
Washington, D.C. 20555
Gentlemen: ULNRC-03370
DOCKET NUMBER 50-483
CALLAWAY PLANT
REVISION TO FACILITY OPERATING LICENSE NO. NPF-30
-------------------------------------------------
Union Electric Company transmits herewith an application requesting that
the Nuclear Regulatory Commission ("NRC") consent to transfer the Facility
Operating License for Callaway Plant.
Union Electric Company ("Union Electric") is the holder of Facility
Operating License No. NPF-30 ("the License") for Callaway Plant Unit No. 1
("Callaway"). It has entered into a merger agreement with CIPSCO Incorporated
which provides for Union Electric to become a wholly-owned operating company of
Ameren Corporation ("Ameren"), a registered public utility holding company under
the Public Utility Holding Company Act of 1935, as amended. On February 23,
1996, Union Electric filed an application to amend the License pursuant to 10
CFR 50.90. After reviewing that application, NRC staff determined that the
merger would also require a transfer of the License to reflect Union Electric's
status as a wholly-owned operating subsidiary of Ameren.
Therefore, enclosed is an application in which Union Electric seeks consent
of the NRC to transfer the License ("the Application"), pursuant to 10 CFR
50.80, such that after the merger Union Electric will continue to own and
operate the Callaway plant as a wholly-owned operating subsidiary of Ameren.
<PAGE>
U.S. Nuclear Regulatory Commission
ULNRC-03370
Page 2
In addition, NRC staff requested a copy of any Federal Energy Regulatory
Commission ("FERC") filings. Exhibit 5 to the Application is a copy of Union
Electric's FERC filings.
We also request that the NRC Staff expeditiously review this submittal so
that the NRC's consent to the proposed transfer is received by December 1996 to
facilitate the completion of the merger.
If you have any questions concerning this matter, please contact me.
Very truly yours,
/s/Donald F. Schnell
JMC:mas
Attachment: 1) Application for NRC Consent to
Transfer License NPF-30 including
Exhibit 5, the FERC merger filing.
<PAGE>
STATE OF MISSOURI )
) SS
CITY OF ST. LOUIS )
Donald F. Schnell, of lawful age, being first duly sworn upon oath, says
that he is Senior Vice President-Nuclear and an officer of Union Electric
Company; that he has read the foregoing document and knows the content thereof;
that he has executed the same for and on behalf of said Company with full power
and authority to do so; and that the facts therein stated are true and correct
to the best of his knowledge, information and belief.
By /s/ Donald F. Schnell
---------------------
Donald F. Schnell
Senior Vice President
Nuclear
SUBSCRIBED and sworn to before me this 24th day of April, 1996.
Signature
-----------------
Notary Public
<PAGE>
APPLICATION OF UNION ELECTRIC COMPANY FOR
NRC CONSENT TO TRANSFER OF LICENSE NO. NPF-30
---------------------------------------------
Union Electric Company ("Union Electric") is the holder of Facility
Operating License No. NPF-30 ("License") for Callaway Plant Unit No. 1
("Callaway"). It has entered into a merger agreement with CIPSCO Incorporated
("CIPSCO") which provides for Union Electric to become a wholly-owned operating
company of Ameren Corporation ("Ameren"), a registered public utility holding
company under the Public Utility Holding Company Act of 1935, as amended. By
this Application, Union Electric seeks an NRC order consenting to the transfer
of the License, such that after the merger Union Electric will continue to own
and operate the Callaway plant as a wholly-owned operating subsidiary of Ameren.
On February 23, 1996, Union Electric filed an application to amend the
License pursuant to 10 CFR 50.90 ("the Original Application"). After reviewing
the Original Application, NRC staff determined that the merger would also
require a transfer of the License to reflect Union Electric's status as a
wholly-owned operating subsidiary of Ameren. While it is true that the proposed
merger requires no change in the design or operation of Callaway, the merger
will make Union Electric a wholly-owned operating subsidiary of Ameren.
Therefore, the merger may be deemed to effect a change in the control of the
owner of Callaway, Union Electric. Accordingly, this Application requests the
consent of the NRC under 10 CFR 50.80 for transfer of the
<PAGE>
License to reflect the effective change in control of the owner of Callaway,
Union Electric, as a result of the merger.
The information required to be included in an application for transfer of a
license pursuant to 10 CFR 50.80 is contained in the Original Application, thus
the Original Application is incorporated by reference herein as if it were set
forth verbatim. This information demonstrates that the requested consent is
consistent with applicable provisions of law, NRC regulations and NRC orders.
While antitrust information is set forth in Section V of the Original
Application, Union Electric's Federal Energy Regulatory Commission ("FERC")
filing is attached as Exhibit 5/1/ to this application to aid the NRC in
conducting the antitrust review.
The merger requires the approval of the FERC, the Securities Exchange
Commission, the Missouri Public Service Commission, and the Illinois Commerce
Commission. In addition, it is subject to review by the Department of Justice
or the Federal Trade Commission and the expiration of the applicable waiting
period under the Hart-Scott-Rodino Act. The companies are working to complete
the merger in early 1997. Therefore, Union Electric is seeking to obtain all
necessary regulatory approvals prior to that time. Union Electric requests that
the NRC review this request for transfer of the License on a schedule that will
result in final action as promptly as possible, and in any event prior to
December 31, 1996.
- ------------
/1/ The Original Application, which as been incorporated herein by reference,
contained four exhibits.
<PAGE>
All communications pertaining to this Application should be sent to:
Joseph E. Birk
Assistant to the Vice President
and General Counsel
Union Electric Company
P.O. Box 149 (MC 1301)
St. Louis, MO 63166
William B. Bobnar
Attorney
Union Electric Company
P.O. Box 149 (MC 1310)
St. Louis, MO 63166
Alan C. Passwater
Manager-Licensing & Fuels
Union Electric Company
P.O. Box 149 (MC 470)
St. Louis, MO 63166
Union Electric requests, for the reasons stated above, that the NRC consent
to the transfer of the License under 10 CFR 50.80 to reflect the effective
change in control of the owner of Callaway, Union Electric. Union Electric also
requests that the NRC issue an order to effectuate said transfer.
Respectfully submitted,
UNION ELECTRIC COMPANY
By: /s/ Donald F. Schnell
----------------------------
Donald F. Schnell
Senior Vice President
Nuclear
<PAGE>
cc: T. A. Baxter, Esq.
Shaw, Pittman, Potts & Trowbridge
2300 N. Street, N.W.
Washington, D.C. 20037
M. H. Fletcher
Professional Nuclear Consulting, Inc.
19041 Raines Drive
Derwood, MD 20855-2432
L. Joe Callan
Regional Administrator
US Nuclear Regulatory Commission
Region IV
611 Ryan Plaza Drive
Suite 400
Arlington, TX 76011-8064
Senior Resident Inspector
Callaway Resident Office
US Nuclear Regulatory Commission
8201 NRC Road
Steedman, MO 65077
Kristine M. Thomas (2)
Office of Nuclear Reactor Regulation
US Nuclear Regulatory Commission
1 White Flint, North, Mail Stop 13E16
11555 Rockville Pike
Rockville, MD 20852-2738
Manager, Electric Department
Missouri Public Service Commission
P.O. Box 360
Jefferson City, MO 65102
<PAGE>
EXHIBIT E-8
UNION ELECTRIC COMPANY AND ITS SUBSIDIARIES
-------------------------------------------
UNION ELECTRIC COMPANY
Union Electric Development Corporation, 100%
Electric Energy, Inc., 40%
<PAGE>
EXHIBIT E-9
CIPSCO INCORPORATED AND ITS SUBSIDIARIES
----------------------------------------
CIPSCO INCORPORATED
Central Illinois Public Service Co., 100%
CIPS Energy, Inc., 100% (inactive)
Illinois Steam, Inc., 100% (inactive)
Electric Energy, Inc., 20%
CIPSCO Investment Co., 100%
CIPSCO Securities Co., 100%
CIPSCO Venture Co., 100%
Effingham Development Building II, L.L.C., 40%
CIPSCO Leasing Co., 100%
CLC Aircraft Leasing Co., 100%
CIPSCO Leasing Co. A, 100%
CIPSCO Leasing Co. B, 100%
CIPSCO Leasing Co. C, 100%
CIPSCO Energy Co., 100%
CEC-PGE-G Co., 1%
CEC-PGE-L Co., 50%
CEC-APL-G Co., 1%
CEC-APL-L Co., 50%
CEC-ACE-G Co., 1%
CEC-ACE-L Co., 99%
CEC-PSPL-L Co., 50%
CEC-PSPL-G Co., 1%
CEC-ACLP Co., 24.75%
CEC-MPS-L Co., 99%
CEC-MPS-G Co., 1%
<PAGE>
EXHIBIT G-1
AMEREN CORPORATION
UNAUDITED PRO FORMA COMBINED
FINANCIAL DATA SCHEDULE
(Thousands of Dollars Except Per Share Amounts)
Six Months Ended June 30, 1996
<TABLE>
<CAPTION>
Pro Forma Pro Forma
Caption Heading UE CIPSCO Adjustments Combined
--------------- ---------- ---------- ----------- ----------
<C> <S> <C> <C> <C> <C>
1 Total net utility plant $5,499,082 $1,462,022 $ 117,273 $7,078,377
2 Other property and investments 81,778 109,121 0 190,899
3 Total current assets 516,031 212,896 38,044 766,971
4 Total deferred charges 66,660 48,302 (2,660) 112,302
5 Balancing amount for total assets 701,612 43,339 0 744,951
6 Total assets 6,865,163 1,875,680 152,657 8,893,500
7 Common stock 510,619 356,812 (866,059) 1,372
8 Capital surplus, paid in 717,669 0 866,059 1,583,728
9 Retained earnings 1,060,716 293,135 0 1,353,851
10 Total common stockholders equity 2,289,004 649,947 0 2,938,951
11 Preferred stock subject to mandatory redemption 598 0 0 598
12 Preferred stock not subject to mandatory redemption 218,497 80,000 0 298,497
13 Long term debt, net 1,746,288 464,077 130,000 2,340,365
14 Short term notes 70,000 0 0 70,000
15 Notes payable 0 0 0 0
16 Commercial paper 0 38,482 0 38,482
17 Long term debt-current portion 45,000 15,000 0 60,000
18 Preferred stock-current portion 26 0 0 26
19 Obligations under capital leases 78,920 0 0 78,920
20 Obligations under capital leases-current portion 31,599 0 0 31,599
21 Balancing amount for capitalization and liabilities 2,385,231 628,174 22,657 3,036,062
22 Total capitalization and liabilities 6,865,163 1,875,680 152,657 8,893,500
23 Gross operating revenue 968,971 431,651 97,492 1,498,114
24 Federal and state income taxes expense 72,865 21,294 4,048 98,207
25 Other operating expenses 730,706 357,019 82,121 1,169,846
26 Total operating expenses 803,571 378,313 86,169 1,268,053
27 Operating income (loss) 165,400 53,338 11,323 230,061
28 Other income (loss), net 2,237 (985) (6,201) (4,949)
29 Income before interest charges 167,637 52,353 5,122 225,112
30 Total interest charges 63,550 17,389 5,122 86,061
31 Net income 97,462 33,100 0 130,562
32 Preferred stock dividends 6,625 1,864 0 8,489
33 Earnings available for common stock 97,462 33,100 0 130,562
34 Common stock dividends 127,655 35,092 8,772 171,519
35 Total annual interest charges on all bonds * 0 0 0 0
36 Cash flow from operations 215,692 89,693 11,734 317,119
37 Earnings per share-primary $0.95 $0.97 0 $0.95
38 Earnings per share-fully diluted $0.95 $0.97 0 $0.95
</TABLE>
* Required on fiscal year-end only
<PAGE>
Exhibit J-1
[PROPOSED FORM OF NOTICE]
SECURITIES AND EXCHANGE COMMISSION
(Release No. 35-___________)
Filings Under the Public Utility Holding Company Act of 1935 ("Act")
__________, 1996
Notice is hereby given that the following filing has been made with the
Commission pursuant to provisions of the Act and rules promulgated thereunder.
All interested persons are referred to the application/declaration for complete
statements of the proposed transaction(s) summarized below. The
application/declaration is available for public inspection through the
Commission's Office of the Public Reference.
Interested persons wishing to comment or request a hearing on the
application/declaration should submit their views in writing by November 15,
1996 to the Secretary, Securities and Exchange Commission, Washington, D.C.
20549, and serve a copy of the relevant application(s) and/or declaration(s) at
the address(es) specified below. Proof of service (by affidavit or, in case the
of an attorney at law, by certificates) should be filed with the request. Any
request for hearing shall identify specifically the issues of fact or law that
are disputed. A person who so requests will be notified of any hearing, if
ordered, and will receive a copy of any notice or order issued in the matter.
After said date, the application/declaration, as filed or as amended, may be
granted and/or permitted to become effective.
Ameren Corp. ("Ameren"), a Missouri corporation, 1901 Chouteau Avenue, St.
Louis, Missouri 63103, has filed an Application/Declaration ("Application")
pursuant to Sections 4, 5, 6, 7, 8, 9, 10, 11, 12, 13 and 21 of the Act
requesting authorization and approval of the proposed combination of Union
Electric Company ("UE") and CIPSCO Inc. ("CIPSCO"), pursuant to which (i) Ameren
will acquire, by merger, all of the issued and outstanding common stock of UE
and Central Illinois Public Service Company ("CIPS"), a wholly owned utility
subsidiary of CIPSCO, and acquire indirectly 60% of the outstanding common stock
of Electric Energy, Inc., ("EEI"), and (ii) UE and CIPS will become wholly owned
subsidiaries of Ameren (the "Transaction"). Following the consummation of the
Transaction, Ameren will register as a holding company under the Act. Ameren
also requests that the Commission approve (i) the establishment of Ameren
Services Corp. ("Ameren Services") in accordance with Rule 88 under the Act and
the acquisition by Ameren of all of the outstanding voting securities of Ameren
Services; (ii) the General Services Agreement among Ameren Services, Ameren,
CIPS, and CIPSCO Investment Company (currently a wholly owned subsidiary of
CIPSCO) ("CIPSCO Investment"), which serves as a holding company for certain
nonutility investments; (iii) the issuance of Ameren Common Stock (as defined
below) in connection with the Transaction; (iv) the issuance by Ameren (and/or
the acquisition by or on behalf of Ameren in open market transactions) of up to
19 million shares of
<PAGE>
Ameren Common Stock, over the period ending five years after the date of the
Commission's approving order in this docket, for purposes of certain employee
benefit and dividend reinvestment plans of UE, CIPSCO, CIPS and Ameren; (v) the
solicitation of proxies from the holders of Ameren Common Stock for approvals
deemed necessary or desirable in connection with the establishment or amendment
of employee benefit plans referred to in (iv); (vi) the acquisition by Ameren of
all of the outstanding voting securities of CIPSCO Investment; (vii) the
retention by Ameren of the gas properties of UE and CIPS and the continued
operation of UE and CIPS as combination utilities; (viii) the retention by
Ameren of the nonutility activities, businesses and investments of UE and CIPSCO
Investment and the making of certain similar investments over a period ending
five years after the date of the Commission's approving order in this docket;
(ix) the continuation of all outstanding intrasystem debt and guaranties; and
(x) the transfer by UE to CIPS of the Transferred Utility Facilities (defined
below) located in Illinois.
UE is a Missouri corporation also authorized to do business in Illinois and
is a public utility company. The principal business of UE is to provide electric
energy to customers in a 24,500 square mile area of Missouri and Illinois. UE's
Missouri electric service area includes the City of St. Louis and St. Louis
County, and all or portions of 65 other counties. Its Illinois service area
includes the cities of East St. Louis and Alton. In addition to the retail
electric business, UE serves 18 wholesale electric customers, all of which are
located in Missouri. Another business of Union Electric is to provide natural
gas service to customers in 23 Missouri counties and two Illinois counties. The
company also provides steam service in Jefferson City, Missouri.
As of June 30, 1996, UE provided retail electric service to approximately
1,069,000 customers in Missouri and 63,000 in Illinois. UE provides natural gas
service to approximately 102,000 customers in Missouri and 18,000 customers in
Illinois. As of June 30, 1996, UE had 6,167 employees in its two-state
operations.
There are two other interests which are held by UE and operated through
subsidiary corporations. UE is the sole stockholder of Union Electric
Development Corporation ("UEDC") (formerly known as Union Colliery), and UE owns
40 percent of the common stock of EEI. UEDC is used principally to own and
invest in energy related or civic and community development related investments
in the UE service area. EEI was formed in the early 1950s to provide electric
energy to a uranium enrichment plant located near Paducah, Kentucky. The
enrichment plant was originally operated by the Atomic Energy Commission and is
operated today by the United States Enrichment Corporation. EEI owns the Joppa
Plant, a 1,015 mW coal-fired power plant located near Joppa, Illinois, and six
161 kV transmission lines which transmit power from the Joppa Plant to the
Paducah enrichment plant. EEI's common stock is held by four utility companies:
UE, 40%; CIPS, 20%; and two unaffiliated utilities, Kentucky Utilities Company,
20%; and Illinois Power Company, 20%. EEI sells electricity to its sponsoring
utilities for resale. The uranium enrichment facility is its only end-user
customer. UE is an exempt public utility holding company pursuant to an order of
the Commission under Section 3(a)(2) of the Act.
2
<PAGE>
CIPSCO, incorporated under the laws of the State of Illinois in 1986, is an
exempt public utility holding company under Section 3(a)(1) of the Act. CIPSCO
owns all of the issued and outstanding common stock of CIPS. CIPS, an Illinois
corporation organized in 1902, supplies electricity and natural gas services in
a 20,000 square mile region of central and southern Illinois, rendering service
to approximately 319,000 retail electricity customers in 557 communities and
distributing natural gas to approximately 167,000 customers in 267 communities.
CIPS' utility service territory has an estimated population of 820,000 (about
seven percent of Illinois' population) and contains about 35% of the surface
area of Illinois. In addition, CIPS sells electricity in the wholesale and
interchange markets to such entities as Soyland Electric Cooperative, Illinois
Municipal Electric Agency, Wabash Valley Power Association, Inc., Mt. Carmel
Public Utility Company, individual municipal electric systems and other public-
and investor-owned electric systems. CIPS also owns 20 percent of the capital
stock of EEI. At June 30, 1996, CIPS had approximately 2,360 employees. CIPS is
an exempt holding company pursuant to Section 3(a)(2) of the Act.
Ameren was incorporated under the laws of the State of Missouri on August
7, 1995 as Arch Holding Corp. to become a holding company for UE and CIPS
following the Transaction and for the purpose of facilitating the Transaction.
Ameren has, and prior to the consummation of the Transaction will have, no
operations other than those contemplated by the Merger Agreement to accomplish
the Transaction. The authorized capital stock of Ameren consists of 400,000
shares of common stock and 100,000 shares of preferred stock par value $.01 per
share. Upon consummation of the Transaction, Ameren will be a public utility
holding company and will own all of the issued and outstanding common stock of
UE, CIPS and CIPSCO Investment. At present, the common stock of Ameren is owned
50% by UE and 50% by CIPSCO. No shares of Ameren preferred stock have been
issued.
Solely for the purpose of facilitating the Transaction, Arch Merger, Inc.
("Arch Merger") was incorporated under the laws of the State of Missouri on
August 5, 1995. Arch Merger has, and prior to the closing of the Transaction
will have, no operations other than the activities contemplated by the Merger
Agreement necessary to accomplish the transaction.
Prior to the consummation of the Transaction, Ameren Services will be
incorporated in Missouri to serve as the service company for the Ameren system
after the consummation of the Transaction. Ameren Services will provide UE and
CIPS, and the other companies of the Ameren system, with a variety of
administrative, management and support services. The authorized capital stock of
Ameren Services will consist of 1,000 shares of common stock, par value $.01 per
share. Upon consummation of the Transaction, all issued and outstanding shares
of Ameren Services will be held by Ameren. Ameren Services will enter into the
General Services Agreement with Ameren, UE, CIPS and CIPSCO Investment.
3
<PAGE>
Under the Merger Agreement executed by CIPSCO and UE on August 11, 1995,
upon receipt of all necessary approvals, the Transaction will be consummated by
merging CIPSCO into Ameren, with Ameren as the surviving corporation, and by
merging UE with Arch Merger, with UE as the surviving corporation.
After the Transaction is effective, Ameren will own 100% of the common
stock of two public utility subsidiaries, UE and CIPS, as well as 100% of the
common stock of CIPSCO Investment. UE will continue to own 40% of the common
stock of EEI and 100% of the common stock of UEDC. CIPS will continue to own 20%
of the common stock of EEI, and CIPSCO Investment will continue to own those
subsidiaries engaged in the unregulated nonutility investment business of
CIPSCO. Thus, EEI will be an affiliate and subsidiary of Ameren. The transaction
calls for a tax-free exchange of CIPSCO common stock. Pursuant to the Merger
Agreement, each outstanding share of CIPSCO common stock will be converted into
1.03 shares of Ameren Common Stock, par value $.01 per share ("Ameren Common
Stock"), and each outstanding share of UE common stock will be converted into
one share of Ameren Common Stock. The outstanding UE and CIPS preferred stock
will not be affected in the Transaction. Ameren is expected to have a total of
137,215,462 shares of Ameren Common Stock outstanding.
Following consummation of the Transaction, the headquarters of Ameren will
be in St. Louis, Missouri. The headquarters of the two utility subsidiaries will
remain in their current locations, UE's in St. Louis, and CIPS' in Springfield,
Illinois. Ameren Services will maintain offices in St. Louis and Springfield.
Ameren's utility subsidiaries will serve 1,451,005 electric customers and
285,403 natural gas customers in portions of Missouri and Illinois. Pursuant to
the Merger Agreement, UE expects to transfer its retail electric and gas
distribution utility assets located in Illinois (the "Transferred Utility
Facilities") to CIPS. As a result, after consummation of the Transaction, CIPS
is expected to begin providing service to the approximately 65,000 electric
customers and 18,000 gas customers currently served by UE in Illinois.
For the Commission, by the Division of Investment Management, pursuant to
delegated authority.
Secretary
4
<PAGE>
EXHIBIT K-1
UNION ELECTRIC COMPANY
&
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
ANALYSIS OF THE ECONOMIC IMPACT
OF A DIVESTITURE OF THE GAS OPERATIONS OF
UE AND CIPS
The management and staffs of UNION ELECTRIC COMPANY (UE) and CENTRAL ILLINOIS
PUBLIC SERVICE COMPANY (CIPS) conducted this study. The objective of this study
is to identify and quantify the economic effects on shareholders and customers
of divesting UE and CIPS of their natural gas assets and businesses.
SEPTEMBER 19, 1996
<PAGE>
TABLE OF CONTENTS
-----------------
<TABLE>
<CAPTION>
PAGE
----
<S> <C> <C>
SECTION I. EXECUTIVE SUMMARY AND CONCLUSIONS 1
SECTION II. GENERAL STUDY ASSUMPTIONS 4
SECTION III. NEWGAS-UE
A. OVERVIEW 6
B. ANALYSIS 7
C. SCHEDULE OF EXHIBITS 14
SECTION IV. NEWGAS-CIPS
A. OVERVIEW 31
B. ANALYSIS 32
C. SCHEDULE OF EXHIBITS 39
</TABLE>
<PAGE>
- --------------------------------------------------------------------------------
SECTION I. EXECUTIVE SUMMARY AND CONCLUSIONS
- --------------------------------------------------------------------------------
The management and staffs of Union Electric Company (UE) and Central Illinois
Public Service Company (CIPS) have conducted this "Analysis of the Economic
Impact of a Divestiture of the Gas Operations of UE and CIPS" (Study) to
determine the effects of spinning off each company's natural gas assets and
businesses into separate and distinct entities. The Study analyzes the
additional costs (from lost economies) that would be necessary to operate two
independent gas companies (called for the purpose of this Study NEWGAS-UE and
NEWGAS-CIPS), as well as any potential benefits that would accrue. All estimates
for NEWGAS-UE and NEWGAS-CIPS are based on UE and CIPS operating experience.
Where possible, estimates of the operating costs were compared to similar
investor-owned gas distribution companies in the Midwest.
The study evaluates the increased costs or "lost economies" associated with
divestiture of these business from two perspectives - shareholders and
customers. The effects on shareholders were calculated using the increased costs
caused by divestiture assuming no regulatory rate relief. The effects on
customers were calculated assuming recovery of additional costs through rate
increases.
SHAREHOLDERS
- ------------
The projected effects on the shareholders of the lost economies resulting from
the spin-off of UE's gas business into NEWGAS-UE and the spin-off of CIPS' gas
business into NEWGAS-CIPS are shown in Table I-1:
<TABLE>
<CAPTION>
=======================================================================================================
TABLE I-1
ANNUAL EFFECT OF LOST ECONOMIES ON SHAREHOLDERS
=======================================================================================================
NEWGAS-UE NEWGAS-CIPS TOTAL
=======================================================================================================
<S> <C> <C> <C>
Lost Economies $22,116,000 $36,317,000 $58,433,000
- -------------------------------------------------------------------------------------------------------
Lost Economies as a Percent of:
- -------------------------------------------------------------------------------------------------------
Total Gas Operating Revenue 25.19% 28.02% 26.88%
- -------------------------------------------------------------------------------------------------------
Total Gas Operating Revenue Deductions 27.48% 30.94% 29.54%
- -------------------------------------------------------------------------------------------------------
Gross Gas Income 301.47% 296.85% 298.64%
- -------------------------------------------------------------------------------------------------------
Net Gas Income 424.90% 423.62% 424.18%
- -------------------------------------------------------------------------------------------------------
In the Absence of Rate Relief:
- -------------------------------------------------------------------------------------------------------
Return on Rate Base -8.73% -15.93% -12.10%
- -------------------------------------------------------------------------------------------------------
Return on Net Plant -8.63% -13.17% -10.96%
=======================================================================================================
</TABLE>
In Table I-1, Lost Economies represents the increased costs, excluding income
taxes, to operate as a stand alone company. Total Gas Operating Revenue is the
sum of all gas revenues for the 12 months ended December 31, 1995. Total Gas
Operating Revenue
1
<PAGE>
Deductions include all purchased gas and gas withdrawn from storage, operation
and maintenance expenses, depreciation and taxes other than income taxes. Gross
Gas Income is the difference between Total Gas Operating Revenue and Total Gas
Operating Revenue Deductions. Net Gas Income is Gross Gas Income minus Income
Taxes. (See SECTION III.C. NEWGAS-UE Exhibit 1 and SECTION IV.C. NEWGAS-CIPS
Exhibit 1 for detailed information.)
GAS CUSTOMERS
- -------------
The projected effect on gas customers, assuming each organization is allowed
rate increases to recover lost economies and applicable income taxes, is shown
in Table I-2:
<TABLE>
<CAPTION>
============================================================================
TABLE I-2
ANNUAL EFFECT OF LOST ECONOMIES ON GAS CUSTOMERS
============================================================================
RATE REVENUE NEWGAS-UE NEWGAS-CIPS TOTAL
============================================================================
<S> <C> <C> <C>
Pre Spin-off $ 87,814,000 $129,611,000 $217,425,000
- ----------------------------------------------------------------------------
Post Spin-off $121,464,000 $170,293,000 $291,757,000
- ----------------------------------------------------------------------------
Dollar Increase $ 33,650,000 $ 40,682,000 $ 74,332,000
- ----------------------------------------------------------------------------
Percent Increase 38.32% 31.39% 34.19%
============================================================================
</TABLE>
(See SECTION III.C. NEWGAS-UE Exhibit 1 and SECTION IV.C. NEWGAS-CIPS Exhibit 1
for detailed information.)
ELECTRIC CUSTOMERS
- ------------------
In addition to the forgoing impacts, divesting the gas business would result in
rate increases of .73% for CIPS electric customers and .11% for UE electric
customers. This impact is due to each company transferring all common property
into the electric rate base, requiring rate increases to maintain the existing
rates of return.
CONCLUSIONS
- -----------
The economies that CIPS and UE realize from combined electric and gas operations
provide significant benefits to customers and shareholders. This Study
demonstrates that spinning off either gas division into a separate entity would
be inefficient due to lost economies, which would be passed on to gas customers,
electric customers and/or to shareholders. Without increased rates, the
immediate negative effect on shareholders' earnings would be substantial, making
ownership of shares in the NEWGAS companies unattractive.
The pass-through of increased costs to customers would cause significant
increases in gas rates, with no increase in the level or quality of service. The
rate increases required to operate the NEWGAS companies would total about
$74,332,000 (Table I-2). Such
2
<PAGE>
increases would make the NEWGAS companies less competitive at a time when
competition in the energy industry is rapidly increasing due to Federal Energy
Regulatory Commission (FERC) Order 636 and other FERC and state regulatory
initiatives. In addition, the NEWGAS companies would receive none of the
benefits expected to accrue from the proposed merger.
It is estimated there would be no substantial benefits from the divestiture of
the gas businesses for electric customers. Minimal savings could be achieved for
items such as data processing costs, and minimal personnel reductions could
occur in the combination gas and electric districts. These savings would be
offset by additional costs such as changing meter reading routes and modifying
data processing applications.
3
<PAGE>
================================================================================
SECTION II. GENERAL STUDY ASSUMPTIONS
================================================================================
The assumptions, information and data utilized for this Study are based on the
industry expertise and experience of the management and staffs of UE and CIPS.
Below are the major assumptions employed for this Study:
1. ORGANIZATION: Each of the organizations to be spun off would operate as an
independent, stand-alone, publicly held, regulated company. Each would have
all the necessary management personnel, along with facilities, equipment,
materials, supplies, etc., required to operate as a stand-alone company.
2. SYSTEM OPERATION & MAINTENANCE: The gas and electric systems would continue
to be operated and administered in the existing manner to insure safe and
reliable service. In addition, current system renewal programs would be
continued.
3. STAFFING: A sufficient number of employees would be included within each
spun-off company to ensure that customers receive the present level and
quality of service.
4. LABOR COSTS: Labor cost estimates were based upon assessments of work
assignments, using UE and CIPS wage structures. Senior management salary
estimates were based on industry averages.
5. NON-LABOR COSTS: These costs were estimated based upon actual costs incurred
by UE and CIPS for their gas businesses assuming the customers of NEWGAS-UE
and NEWGAS-CIPS would receive existing levels and quality of service.
6. COST PASS-THROUGH: Full pass-through to customers of increased costs due to
lost economies would be allowed in formal rate proceedings.
7. SPECIFIC LABOR ASSUMPTIONS:
a) Organization size and spans of control were estimated using existing UE
and CIPS structures, adjusted to recognize the broader functional
responsibilities that would exist in smaller companies.
b) Pensions and benefits were estimated as a percent of direct labor cost.
c) Employee benefits would be similar to the combined companies.
8. CAPITAL EXPENDITURE AND COST ASSUMPTIONS:
a) The accounting for direct and indirect capital expenditures would remain
the same as that currently used in the combined utilities.
b) The actual capital costs for the divested companies would be considerably
higher than those of UE and CIPS. Since gas purchases are highly
seasonal, the stand alone gas companies would experience great volatility
in their cash positions. At
4
<PAGE>
the same time the book values of the assets of these stand alone gas
companies would be much smaller than those of the combined utility
predecessors. As a result, the new companies would be perceived as riskier
and would be subject to higher borrowing rates. Because of the constraints
of the CIPS and UE mortgage indentures, the debt associated with the spun-
off facilities would have to be refinanced at today's rates.
9. TRANSITION COST ASSUMPTIONS: Costs such as the legal, investment banking,
filing and printing fees associated with the public spin-off of stock,
creation of new indenture agreements, negotiation of new service contracts
and costs to establish business processes would be incurred and amortized
appropriately.
10. TRANSACTIONS BETWEEN COMPANIES: All transactions and transfers between
NEWGAS-UE and UE, and between NEWGAS-CIPS and CIPS, would be arms-length
transactions based upon fair market values.
11. OTHER ASSUMPTIONS:
a) Facility costs would include separate headquarters, storerooms, and
office space for employees currently using facilities shared by the
electric and gas businesses.
b) To facilitate the assessment of financial effects, it was assumed the
costs for outsourcing and performing work in-house would be comparable.
c) Information Services work would be outsourced.
d) Additional equipment (i.e., vehicles, trenchers, heavy power operated
equipment) would be leased under an operating lease.
e) External auditing costs were estimated based on industry surveys.
f) Insurance costs were quotes based on protecting the gas utility against
losses and damages to leased properties used in its operations, as well
as injuries and damage claims.
g) Regulatory commission expenses would be similar to those currently
incurred in connection with formal cases before regulatory commissions
involving gas operations.
h) Potential costs for clean-up of environmental sites (coal gasification
plants) would be the same whether or not the gas businesses are spun
off. For this reason such costs were not considered in this Study.
5
<PAGE>
- --------------------------------------------------------------------------------
SECTION III.A. NEWGAS-UE OVERVIEW
- --------------------------------------------------------------------------------
Spinning off UE's gas operations into a separate stand-alone company (NEWGAS-UE)
would result in the following:
. NEWGAS-UE would need to establish service functions duplicating those at UE,
including treasury, financial planning, accounting, tax planning and
compliance, rates, risk management, employee benefits, marketing, legal,
customer service, regulatory and public affairs.
. Annual operating revenue deductions, exclusive of income taxes, for NEWGAS-UE
would be about 27% ($22.1 million) greater than UE's gas operating revenue
deductions. (SECTION III.C, Exhibit 1).
. NEWGAS-UE's customers would experience a rate increase of about 38% ($33.7
million) in order to provide a 11.15% rate of return for stockholders (SECTION
III.C, Exhibit 1).
. NEWGAS-UE would be at a competitive disadvantage because of high operating
expenses.
. There would be no substantial benefits for customers or stockholders.
6
<PAGE>
- --------------------------------------------------------------------------------
SECTION III.B. NEWGAS-UE ANALYSIS
- --------------------------------------------------------------------------------
The UE gas distribution system serves approximately 121,000 (as of December 31,
1995) customers over a 3,000 square mile area in Missouri and Illinois. There
are 2,578 miles of mains and 1,634 miles of service lines in the system. Natural
gas revenues for 1995 were $87.8 million on system throughput of 16.4 billion
cubic feet of gas.
UE operates as a tightly integrated company with many employees supporting both
gas and electric operations. Of UE's 6,190 employees (as of December 31, 1995),
only 143 devote 100% of their time to gas operations. Shared operations include
customer service personnel who deal with service requests for both gas and
electric customers, and meter readers who read both the electric and gas meters.
Additionally, UE provides the gas division's required services in the areas of
treasury, financial planning, accounting, tax planning and compliance, rates,
risk management, employee benefits, marketing, legal, customer service,
regulatory and public affairs. The shared gas/electric responsibilities of many
of UE's employees have enabled UE to provide quality service at a low cost.
ORGANIZATION STRUCTURE AND STAFFING IMPACT
- ------------------------------------------
The UE organization as of December 31, 1995, was used as a pattern for
developing the NEWGAS-UE organization structure. See SECTION III.C, Exhibit 5
for the proposed organization. Divesting the gas operations would eliminate the
effective use of SHARED STAFF to the detriment of both the gas and electric
operations. To operate the gas business on a stand-alone basis, 312 additional
employees would be required, in addition to the 143 employees mentioned above.
UE could expect very minimal staffing reductions in the electric business as a
result of a gas divestiture. SECTION III.C, Exhibit 6 shows the proposed
staffing, salaries, and wages summary, while Exhibit 2d shows that NEWGAS-UE
would incur an estimated net labor increase, including benefits, of $7,732,000.
Exhibit 7 shows that with this proposed staffing, NEWGAS-UE compares favorably
with other gas utilities in the number of customers per employee. The following
comments demonstrate some of the reasons for additional staffing:
UE's customers receive one bill for both gas and electric service and pay
with one check. When treasury personnel process the checks, automated
equipment posts both electric and gas payments to customers' accounts.
NEWGAS-UE would have to hire staff to handle gas payments that are now
handled at essentially no additional cost by UE. Spinning off the gas
operations would only minimally reduce the workload on UE's cash processing
personnel, since most gas customers also have electric service and would
still send a check monthly.
UE's meter readers read gas and electric meters in the same routes. NEWGAS-
UE would have to hire meter readers to re-trace the same routes to read the
gas meters.
7
<PAGE>
Spinning off the gas operations would not reduce the number of meter
readers needed by UE since their routes would remain essentially the same.
UE's Finance, Accounting and Corporate Services personnel maintain the
books of the Company and arrange for insurance. They arrange for long-term
financing and borrow short-term funds for operations. They maintain
stockholder records and perform various investor services. NEWGAS-UE would
require personnel to provide the same services. Spinning off the gas
operations would not provide any measurable savings for UE in the finance
and accounting area, since all the existing books and records of the
Company would remain essentially unchanged, insurance needs would be
similar, and staff time devoted to financing activities would not be
significantly reduced.
UE's Human Resources Division administers benefit and salary plans. NEWGAS-
UE would need to hire personnel to perform the same duties. Spinning off
the gas operations would not provide substantial savings to UE, because
each of UE's existing benefit and salary plans, and the associated
reporting requirements, would remain.
UE's Supply Service Division provides materials, supplies, transportation
equipment, etc. to operating divisions. NEWGAS-UE would need to hire
personnel to perform the same duties for gas operations. Spinning off the
gas operations would reduce the number of purchase orders handled by UE as
well as the amount of material handled and storage costs. However, the
quantities involved are a small percentage of the total, so few, if any,
staffing reductions could be effected and no facilities could be
eliminated, making the actual savings for UE minimal.
UE's engineering staff provides engineering expertise to operating
divisions. NEWGAS-UE would need to hire personnel to perform the same
duties. Spinning off the gas operations would reduce the workload on UE
engineering personnel, but since gas operations analysis is a small
percentage of their work, spread over a geographically dispersed area, UE
would not be able to eliminate any engineering positions.
UE's legal staff provides legal, regulatory and claims services for UE's
operating divisions. NEWGAS-UE would need to hire personnel to perform the
same duties. Since many legal issues are not divided into gas and electric
considerations, the amount of work performed by UE's legal department would
not decrease significantly, and there would be no staffing reductions.
8
<PAGE>
INDEPENDENT ACCOUNTANT IMPACT
- -----------------------------
UE hires independent accountants to audit the financial statements of the
Company. NEWGAS-UE would need to hire independent accountants to perform the
same duties. UE would not achieve any savings, since the existing level of work
for the independent accountants would remain the same.
INFORMATION TECHNOLOGY IMPACT
- -----------------------------
UE provides extensive information technology assistance to its operating and
support divisions. NEWGAS-UE would need to provide the same assistance to its
divisions. Hardware costs are reflective of the quantity of information to be
processed, so NEWGAS-UE's hardware and telecommunications costs would be
substantially less than UE's. Software costs are generally less dependent on
quantity and more dependent on function, so NEWGAS-UE's software costs would be
similar to UE's. See SECTION III. C, Exhibit 2b, which identifies a net increase
in cost for information services of $11,291,000.
Divesting the gas operations would eliminate opportunities for sharing
information technology resources to the detriment of both the gas and electric
operations:
NEWGAS-UE would be subject to the same regulatory accounting requirements
as UE, so similar general ledger, payroll distribution, fixed asset and
other accounting systems would be needed. It is estimated that the required
software would be similar to UE's and would cost about $4.8 million. UE
would retain all existing software, resulting in no software savings and UE
would expend considerable resources changing accounting systems to reflect
the divestiture of the gas business.
UE operates an integrated material management, purchasing and accounts
payable system. The system provides ordering, purchasing, tracking,
receiving, paying and inventory control functions. To maintain existing
levels of customer service, NEWGAS-UE would need a similar integrated
system, which would cost about $2.4 million. UE would require slightly less
data storage, producing negligible savings. There would be no software
savings since UE would require all existing software.
UE's investor services system handles stockholder and bondholder service
requests, makes dividend and bond payments and keeps track of unclaimed
checks and correspondence. NEWGAS-UE would need a system with similar
capabilities to maintain the current level of service to stockholders and
bondholders. Such a
9
<PAGE>
system would cost about $450,000. UE would retain the same number of
stockholders and bondholders, resulting in no savings.
UE's customer information system is extensively integrated with numerous
other systems, providing seamless flow of information and efficient
processing of customer service requests, payments and data updates. When
customers call, the system retrieves information and presents it to the
call-taker, requiring customers to spend less time on the line. The system
automatically handles customers' payments made by mail, electronically, at
pay stations or banks, or by charitable and government organizations. It
provides a multitude of services such as budget billing, installment
financing payments, combined billing for electric and gas, preferred pay
dates, etc. NEWGAS-UE would require a similar system to maintain the
current level of service to customers. Recently installed utility billing
systems have cost $25 - $50 million. Scaling down might be possible for a
small utility, making the estimated cost about $20 million. Since there
would be fewer customer records to process, UE would require less data
storage, postage, forms, etc., saving about $180,000 annually. UE would
expend considerable resources to final bill existing combination
gas/electric customers and re-establish the electric accounts.
UE maintains a distribution operations job management system that receives
and tracks customer requests for service or work, maintains the status of
jobs for customer inquiries, automatically bills the customer for work
completed and provides accurate accounting and work order control. NEWGAS-
UE would need a similar system, costing about $4,000,000, to maintain
current levels of customer service. UE would no longer process gas
customers but data storage savings would be insignificant.
UE maintains pension management software that provides valuation of the
retirement plan for accounting purposes, maintains records of retirees,
accumulates information for active employees for pension calculations and
interfaces with payroll systems to maintain accurate information. NEWGAS-UE
would need a similar system, costing about $100,000, to maintain current
levels of benefits to employees. The assumed reduction of about 143
employees who perform only gas related work would have a minimal effect on
UE's data storage requirements, providing insignificant savings.
UE maintains a sophisticated human resources, payroll, scheduling, time
entry and absence tracking system. The system provides scheduling for time
worked, vacation and other allowed time. It tracks absences and
automatically updates records and restores sick leave bank balances. It
provides distributed entry of time worked and the associated accounting.
The system provides for the reporting of
10
<PAGE>
information to government, regulatory and other agencies. NEWGAS-UE would
need a similar system. UE's system cost more than $6 million to develop.
Since the UE system includes processes required only for electric
generating plant operations, NEWGAS-UE could use simpler software,
estimated at about $4,000,000. Processing 143 fewer employees would provide
insignificant savings for UE.
UE Information Technology personnel maintain the above systems. To maintain
similar systems, it is estimated NEWGAS-UE would expend about $2,150,000
annually. NEWGAS-UE software maintenance would cost about three-fourth's of
UE's cost since some systems would not exist in a gas-only company. Because
all of the existing systems would remain, UE would achieve no maintenance
savings by spinning off the gas operations.
UE maintains communications networks, telephone services, radio systems,
etc. To maintain similar systems, NEWGAS-UE would need personnel and
equipment costing about $2,380,000 annually. Due to fewer employees and
locations, NEWGAS-UE would spend an amount estimated at 10 percent of UE's
costs. UE would achieve minimal savings because the number of locations
would remain the same, although slightly less equipment (e.g. telephones)
would be needed because there would be a few less employees at some
locations.
UE maintains a data center to serve all of the above systems. To operate
similar systems, NEWGAS-UE would need a similar data center, costing about
$3,700,000 annually. There would be no equipment or manpower savings for
UE, since all existing systems would remain.
INSURANCE COSTS
- ---------------
UE obtains property, liability, directors and officers, workers compensation and
other insurance. NEWGAS-UE would require similar policies, at similar costs. See
SECTION III.C, Exhibit 2c, which shows an estimated increase in insurance cost
of $342,000 to NEWGAS-UE. Since all coverages would remain in effect, UE would
experience no savings for insurance.
OFFICE AND CREW FACILITIES COSTS
- --------------------------------
UE maintains combined electric and gas office and crew facilities at several
locations. NEWGAS-UE would need facilities for office and crew personnel at each
of the existing combined electric/gas locations. See SECTION III.C, Exhibit 2e,
which identifies $1,062,347 in additional office and crew facilities costs.
Since UE would still operate the
11
<PAGE>
electric system, the existing office and crew facilities would still be needed
at each location.
TRANSPORTATION AND MOTORIZED EQUIPMENT COSTS
- --------------------------------------------
UE maintains transportation and motorized equipment used by both gas and
electric crew and support personnel. NEWGAS-UE would need to obtain similar
equipment for gas operations. NEWGAS-UE's additional transportation cost would
be about $375,590 as identified in SECTION III.C, Exhibit 2g. Since vehicle
needs correlate closely with personnel needs, it is estimated that the reduction
in equipment to be achieved by UE would equal the additional equipment required
by NEWGAS-UE, except for vehicles used by meter readers to read both electric
and gas meters. UE would still need about the same number of meter reader
vehicles currently used in the combination gas and electric districts, but the
costs currently allocated to the gas business would be absorbed by the electric
customers, resulting in increased annual meter reading vehicle costs to UE of
about $38,297.
TRANSITION COSTS
- ----------------
The divestiture of the gas operations of UE and the creation of a stand-alone
gas company would be a complex legal and financial transaction that would
involve substantial transition costs. These costs would include legal and
financial advising fees, and the services of independent accountants, actuaries
and other consultants. Real estate services would be needed to procure
facilities. Several hundred personnel would have to be hired and trained.
Benefit plans would need to be established. The estimated transition costs of
$11,031,000 for NEWGAS-UE were developed by calculating the average of such
costs incurred in several other publicly reported business spin-offs. See
SECTION III.C, Exhibit 2f.
COST OF CAPITAL
- ---------------
The effective cost of capital for the stand-alone gas business was based upon
capitalization ratios of UE's capital structure as of December 31, 1995, and
estimated current costs of debt and equity, which average about 11.15%. See
SECTION III.C, Exhibit 4 for detailed information.
CONCLUSION
- ----------
The Study concludes that a separate gas distribution company would require 455
full-time employees, an increase of approximately 218% over the number of
employees currently devoted to UE gas operations full-time. Based upon the
assumptions set forth in SECTION II and the staffing requirements of the
organizational structure, increased
12
<PAGE>
annual costs (excluding Federal and State income taxes) for NEWGAS-UE are
projected to be $22,116,000.
The exhibits (SECTION III.C) that follow show the economic effects of operating
UE's gas division as a separate entity.
13
<PAGE>
================================================================================
SECTION III.C. NEWGAS-UE SCHEDULE OF EXHIBITS
================================================================================
<TABLE>
<CAPTION>
EXHIBIT NO. EXHIBIT TITLE
- --------------------------------------------------------------------------------
<S> <C>
1 Income Statement, Proforma Adjustments & Revenue
Requirement
2 Estimated Additional Operating Expenses
2a Estimated External Audit Fees Based on Survey Data
2b Estimated Information Services Costs
2c Estimated Increased Cost of Insurance Coverage
2d Estimated Net Labor Increase, Including Benefits
2e Estimated Operating Lease Facilities and Furniture
Costs
2f Estimated Transition Costs
2g Estimated Net Increase in Transportation &
Motorized Equipment Expense
3 Rate Base
4 Cost of Capital
5 Corporate Structure
6 Salaries and Wages Summary
7 Comparable Investor Owned Gas Companies (Customers
Per Employee Ratios)
8 Estimated Executive Salaries
9 UE's Electric Rate Base & Rate of Return
</TABLE>
14
<PAGE>
NEWGAS-UE EXHIBIT 1
NEWGAS-UE INCOME STATEMENT
PROFORMA ADJUSTMENTS & REVENUE REQUIREMENT
(In Thousands of Dollars)
<TABLE>
<CAPTION>
Existing
UE Gas
Company Revenue
Year Ending Proforma Proformed Requirement
12/31/95 Adjustments (1) NEWGAS-UE Increase (2)
=========== ================ ========= ============
<S> <C> <C> <C> <C>
Operating Revenue: $ 87,814 $ - $ 87,814 $121,464
Operating Revenue Deductions:
Purchased Gas $ 47,189 $ 47,189 $ 47,189
Gas Withdrawn From Storage $ 4,062 $ 4,062 $ 4,062
O & M $ 16,822 $21,713 $ 38,535 $ 38,535
Depreciation $ 4,722 $ 4,722 $ 4,722
Taxes Other Than Income $ 7,683 $ 403 $ 8,086 $ 8,086
-------- ------- -------- --------
Total Operating Revenue Deductions $ 80,478 $22,116 $102,594 $102,594
-------- ------- -------- --------
Gross Gas Income $ 7,336 $(14,780) $ 18,870
Federal & State Income Taxes (3) $ 2,131 $ (4,286) $ 5,472
-------- -------- --------
Net Gas Income $ 5,205 $(10,494) $ 13,398
======== ======== ========
Rate Base (4) $124,816 $120,161 $120,161
======== ======== ========
Indicated Rate of Return 4.17% -8.73% 11.15%(5)
======== ======== ========
</TABLE>
(1) See Exhibit 2 for a detailed summary of proforma adjustments.
(2) An increase of $33,650,000 or 38.32% in Revenue is required to achieve a
rate of return of 11.15%. For the purposes of this Study, gross receipts taxes
were not considered since both the resulting revenue and taxes (revenue
deduction) would nullify any impact from this calculation.
(3) For twelve months ended 12/31/95, UE's effective Federal & State Income
Taxes were 29.0% of gross gas income. This effective tax rate was used to
calculate taxes for the Proformed NEWGAS-UE and Revenue Requirement Increase
columns.
(4) See Exhibit 3.
(5) The effective rate of return is assumed to be the weighted cost of capital
per Exhibit 4.
15
<PAGE>
NEWGAS-UE EXHIBIT 2
NEW GAS-UE
ESTIMATED ADDITIONAL OPERATING EXPENSES
PROFORMA ADJUSTMENTS
(In Thousands of Dollars)
<TABLE>
<CAPTION>
Exhibit
Reference
Number Amount
========= ========
<S> <C> <C>
External Auditing Costs 2a $ 210
Information Services (Outsourced) 2b $11,291
Insurance Premiums 2c $ 342
Labor & Benefits 2d $ 7,732
Leased Facilities/Furniture 2e $ 1,062
Transition Costs (Amortized) 2f $ 1,103
Transportation & Work equipment 2g $ 376
-------
Total Additional Expenses $22,116
Less: FICA and Unemployment Insurance 2d $ 403
-------
TOTAL ADDITIONAL O & M EXPENSES $21,713
=======
</TABLE>
16
<PAGE>
NEWGAS-UE EXHIBIT 2a
NEWGAS-UE EXTERNAL AUDITOR COSTS
ESTIMATED EXTERNAL AUDIT FEES BASED ON SURVEY DATA
PROFORMA ADJUSTMENT
<TABLE>
<CAPTION>
<S> <C>
Surveys comparing External Audit Fees Amount
===================================== ========
Average fee for Utility companies with less than 300,000 Customers in 1994 $191,000
Average fee for Peer Group comparison with less than 300,000 Customers in 1994 $188,000
--------
Average of External Audit Fee Surveys $189,500
Average Audit Fee for Pension Plans with less than 5,000 employees $ 38,693
--------
Total Estimated Annual Audit Fees for NEWGAS-UE $228,193
Less: External Audit Fees Allocated to Gas operations in 1995 $ 18,000
--------
Net Estimated Annual Audit Fees Increase for NEWGAS-UE $210,193
========
</TABLE>
Sources: Illinois Power Audit Fee Peer Group Comparison - 1994
American Gas Association/Edison Electric Institute External Audit
Fees - October 1995
17
<PAGE>
NEWGAS-UE EXHIBIT 2b
NEWGAS-UE INFORMATION SERVICES
ESTIMATED INFORMATION SERVICES COSTS
PROFORMA ADJUSTMENT
(In Thousands of Dollars)
<TABLE>
<CAPTION>
<S> <C>
Software Application Costs: Amount
=========================== ========
General Ledger/Capital Projects/Asset Management/Accounts Payable $ 4,800
Payroll Distribution $ 250
Investor Services $ 450
Customer Information System (CIS) $20,000
Computer Telephone Integration System (CTI) $ 1,000
Distribution Operating Job Management (DOJM) $ 4,000
Materials Management Information System (MMIS) $ 2,400
Pension Manager $ 100
Payroll/Human Resource System $ 3,000
Time Reporting $ 1,000
Miscellaneous $ 1,500
-------
Total Software Application Costs $38,500
-------
Annual System Operating Costs
-----------------------------
Data Processing $ 3,700
Software Maintenance and Support $ 2,153
Telecommunciations $ 2,380
-------
Total Annual System Operating Costs $ 8,233
-------
Estimated Cost to Outsource Information Services
------------------------------------------------
Annualized Software Application Costs (10 year amortization) $ 3,850
Total Annual System Operating Costs $ 8,233
-------
Total Annual Cost to Outsource Information Services $12,083
Less: Information Services Expenses Allocated to Gas Operations
in 1995 $ 792
-------
Net Increase in Cost for Information Services $11,291
=======
</TABLE>
18
<PAGE>
NEWGAS-UE EXHIBIT 2c
NEWGAS-UE
ESTIMATED INCREASED COST OF INSURANCE COVERAGE
PROFORMA ADJUSTMENT
<TABLE>
<CAPTION>
Estimated
Limits Stand Alone Net Increase to
Coverage (Millions) Deductible Premium Cost NEWGAS-UE
- -------------------------- ---------- ----------- ------------ ---------------
<S> <C> <C> <C> <C>
Property $ 5 $ 250,000 $ 21,000
General Liability $ 60 $ 250,000 $ 213,000
Auto Liability $ 1 $ - $ 50,000
Directors & Officers Liability $ 10 $ 250,000 $ 75,000
Workers Compensation Statutory $ 350,000 $ 61,000
Fiduciary Liability $ 5 $ 5,000 $ 10,000
Crime (Fidelity) $ 5 $ 5,000 $ 10,000
----------
Total NEWGAS-UE Premium $ 440,000
Less: 1995 Insurance Cost Allocated to UE Gas Operations $ 98,000
----------
Net Increase in Insurance Costs for NEWGAS-UE $ 342,000
==============
</TABLE>
Source: Premiums are based on estimated cost quotations obtained by UE
Secretary's Department, Insurance Division.
19
<PAGE>
NEWGAS-GAS UE EXHIBIT 2d
NEWGAS-UE
ESTIMATED NET LABOR INCREASE, INCLUDING BENEFITS
PROFORMA ADJUSTMENT
(In Thousands of Dollars)
<TABLE>
<S> <C> <C> <C>
Total Estimated Salaries and Wages for NEWGAS-UE (Exhibit 6) $ 21,776
Less: Amount for Construction & Removals (31.3%)-(1) $ 6,816
--------
Total Estimated NEWGAS-UE Salaries & Wages Charged to O & M $ 14,960
Less: 1995 UE Gas Salaries & Wages Charged to O & M $ 9,515
--------
Increase in NEWGAS-UE Salaries & Wages Charged to O & M $ 5,445
Benefits (2):
Employee Life, Hospitalization, savings plans, etc. $ 1,198
Pension Plan $ 495
FICA & Unemployment Insurance $ 403
Other $ 191
--------
Total Benefits $ 2,287
--------
NEWGAS-UE Net Labor Increase, Including Benefits $ 7,732
========
</TABLE>
(1) Amount of labor allocated to construction and removal is based on the
actual amount spent by UE in 1995.
(2) Benefit costs were estimated base upon the cost (as a percentage of
payroll) currently budgeted by UE:
<TABLE>
<S> <C>
Life, Hospitalization, savings plans, post employment benefit, etc. 22.00%
Pension Plan 9.10%
FICA & Unemployment Insurance 7.40%
Other 3.50%
-----
Total 42.00%
=====
</TABLE>
20
<PAGE>
NEWGAS-UE EXHIBIT 2e
NEWGAS-UE
ESTIMATED OPERATING LEASE FACILITIES AND FURNITURE COSTS
PROFORMA ADJUSTMENT
<TABLE>
<CAPTION>
-----------------------------------------------------------
Office Space Calculation
-----------------------------------------------------------
Management Office Space ------ ------------
& Staff Needs in Cost Per Total Works Total Leased
Employee Square Feet Square Foot Office Space Hqtrs. Facilities
Count (1) (2) Cost (3) Cost
----------------------------------------------------------- ------ ------------
<S> <C> <C> <C> <C> <C> <C>
General Office:
Jefferson City, Mo. 207 63,756 $8.00 $510,048 - $ 510,048
Southeast District (MO):
Cape Girardeau 13 4,004 $6.00 $ 24,024 $38,400
Chaffee 0 - $ - $17,000
Dexter 0 - $ - $38,400
-------
Total $ 117,824
Alton District (IL): 10 3,080 $9.00 $ 27,720 $38,400 $ 66,120
Wentzville District (MO):
Louisiana 9 2,772 $5.50 $ 15,246 $17,000
Troy 0 - $ - $17,000
-------
Total $ 49,246
Little Dixie District (MO):
Boonville 0 - $ - $17,000
Centralia 0 - $ - $17,000
Columbia 17 5,236 $9.00 $ 47,124 $ -
Mexico 0 - $ - $38,400
Moberly 0 - $ - $38,400
-------
Total $ 157,924
Capital District (MO):
Jefferson City 12 3,696 $8.00 $ 29,568 $38,400
Versailles 0 - $ - $17,000
-------
Total $ 84,968
Estimated Office Furniture Operating Lease Expense For All Areas: $ 259,000
----------
NEWGAS-UE FACILITIES - GRAND TOTAL $1,245,130
Less: Current allocated costs for gas facilities $ 182,783
----------
NET NEWGAS-UE FACILITIES COST: $1,062,347
==========
</TABLE>
(1) An average of 308 square feet per employee was used based on past Company
experience.
(2) Information from UE's Real Estate Department found the cost per square foot
per annum averaged $5.50 in Louisiana, $6 in Cape Girardeau, $8 in Jefferson
City, and $9 in Alton and Columbia.
(3) This includes space for construction and service supervision, staff,
materials and supplies, and vehicles and equipment. Annual lease costs were
based on actual appraised values of utility facilities capable of accommodating
applicable staff, materials & equipment. Columbia is the only city having a UE
headquarters facility already dedicated to gas operations.
21
<PAGE>
NEWGAS-UE EXHIBIT 2f
NEWGAS-UE ESTIMATED TRANSITION COSTS
PROFORMA ADJUSTMENT
Transition costs required to establish a new corporation would include the
following:
Legal fees
Financial advisory fees
Consulting services of independent accountants, actuaries, and others
Real estate services for acquisitions
Hiring and training costs to staff newly created positions
Benefit plans established
Data Conversion
Transition costs for NEWGAS-UE were estimated based upon an average of the
following published transition costs for other corporate spin-offs:
<TABLE>
<CAPTION>
Transition
Original Corporation Spin-off Company Costs(000)
-------------------- ---------------- ----------
<S> <C> <C>
Baxter International Caremark $ 13,300
Adolph Coors ACX Technologies $ 7,200
Dial Corporation GFC Financial $ 13,000
Union Carbide Praxair $ 11,000
Ryder Avial $ 9,000
Price Costco Price Enterprises $ 15,250
Humana Galen $ 15,000
Honeywell Aliant $ 4,500
----------
Average Transition Costs of the Above Companies $ 11,031
----------
Annual amortization of Transition Costs for NEWGAS-UE (10%) $ 1,103
==========
</TABLE>
Source: Transition costs reported in SEC Form 10-K filings.
22
<PAGE>
NEWGAS-UE EXHIBIT 2g
NEWGAS-UE
ESTIMATED NET INCREASE IN TRANSPORTATION & MOTORIZED EQUIPMENT EXPENSE
PROFORMA AJDUSTMENT
<TABLE>
<CAPTION>
General Office(GO)\Pool Southeast District Alton District
----------------------- -------------------- --------------------
Rate Per Est. Annual Est. Annual Est. Annual
Description Month Number Cost Number Cost Number Cost
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
GO\Pool Vehicles - Standard $470 6 $33,840
- ------------------------------------------------------------------------------------------------------------------------------
GO\Pool Vehicles - Compact $442 6 $31,824
- ------------------------------------------------------------------------------------------------------------------------------
Manager $470 1 $ 5,640 1 $ 5,640
- ------------------------------------------------------------------------------------------------------------------------------
Operations Superintendent $442 1 $ 5,304 1 $ 5,304
- ------------------------------------------------------------------------------------------------------------------------------
Construction Supervisor $442 3 $ 15,912 2 $ 10,608
- ------------------------------------------------------------------------------------------------------------------------------
Distribution Supervisor $442 1 $ 5,304 0 $ -
- ------------------------------------------------------------------------------------------------------------------------------
Supervising Engineer $442 1 $ 5,304 1 $ 5,304
- ------------------------------------------------------------------------------------------------------------------------------
Engineer $442 1 $ 5,304 0 $ -
- ------------------------------------------------------------------------------------------------------------------------------
Engineer Assistant $505 2 $ 12,120 0 $ -
- ------------------------------------------------------------------------------------------------------------------------------
Office Manager $442 1 $ 5,304 0 $ -
- ------------------------------------------------------------------------------------------------------------------------------
Meter Reader $505 5 $ 30,300 2 $ 12,120
- ------------------------------------------------------------------------------------------------------------------------------
Customer Service Advisor $442 1 $ 5,304 1 $ 5,304
- ------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------
Other transportation &
- ------------------------------------------------------------------------------------------------------------------------------
Motorized Equipment
- ------------------------------------------------------------------------------------------------------------------------------
Not Indicated Above $ - $319,272 $188,040
- ------------------------------------------------------------------------------------------------------------------------------
NEWGAS-UE TOTAL $65,664 $415,068 $232,320
- ------------------------------------------------------------------=======------------------========------------------========-
- ------------------------------------------------------------------------------------------------------------------------------
Less: Amount Charged to Gas Operations in 1995
- ------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------
NET INCREASE IN TRANSPORTATION & MOTORIZED EQUIPMENT EXPENSE FOR NEWGAS-UE
- ------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Wentzville District Little Dixie District Capital District
---------------------- --------------------- ---------------------
Est. Annual Est. Annual Est. Annual GRAND
Description Number Cost Number Cost Number Cost TOTAL
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
GO\Pool Vehicles - Standard
- --------------------------------------------------------------------------------------------------------------------------------
GO\Pool Vehicles - Compact
- --------------------------------------------------------------------------------------------------------------------------------
Manager 1 $ 5,640 1 $ 5,640 $ 5,640
- --------------------------------------------------------------------------------------------------------------------------------
Operations Superintendent 1 $ 5,304 1 $ 5,304 1 $ 5,304
- --------------------------------------------------------------------------------------------------------------------------------
Construction Supervisor 3 $ 15,912 4 $ 21,216 4 $ 21,216
- --------------------------------------------------------------------------------------------------------------------------------
Distribution Supervisor 1 $ 5,304 3 $ 15,912 2 $ 10,608
- --------------------------------------------------------------------------------------------------------------------------------
Supervising Engineer 1 $ 5,304 1 $ 5,304 1 $ 5,304
- --------------------------------------------------------------------------------------------------------------------------------
Engineer 0 $ - 1 $ 5,304 1 $ 5,304
- --------------------------------------------------------------------------------------------------------------------------------
Engineer Assistant 1 $ 6,060 3 $ 18,180 2 $ 12,120
- --------------------------------------------------------------------------------------------------------------------------------
Office Manager 1 $ 5,304 1 $ 5,304 1 $ 5,304
- --------------------------------------------------------------------------------------------------------------------------------
Meter Reader 2 $ 12,120 7 $ 42,420 3 $ 18,180
- --------------------------------------------------------------------------------------------------------------------------------
Customer Service Advisor 1 $ 5,304 1 $ 5,304 1 $ 5,304
- --------------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------------
Other transportation &
- --------------------------------------------------------------------------------------------------------------------------------
Motorized Equipment
- --------------------------------------------------------------------------------------------------------------------------------
Not Indicated Above $119,724 $683,244 $335,340
- --------------------------------------------------------------------------------------------------------------------------------
NEWGAS-UE TOTAL $185,976 $813,132 $429,624 $2,141,784
- ----------------------------------------------------========------------------========------------------========----------------
- --------------------------------------------------------------------------------------------------------------------------------
Less: Amount Charged to Gas Operations in 1995 $1,766,194
- --------------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------------
NET INCREASE IN TRANSPORTATION & MOTORIZED EQUIPMENT EXPENSE FOR NEWGAS-UE $ 375,590
- --------------------------------------------------------------------------------------------------------------------------------
</TABLE>
Note: Projected costs based on management's assessment of transportation &
equipment needs and operating & maintenance experience.
23
<PAGE>
NEWGAS-UE RATE EXHIBIT 3
<TABLE>
<CAPTION>
NEWGAS-UE
RATE BASE
(In Thousands of Dollars)
<S> <C> <C> <C>
Existing
UE Gas
Company Reduction
Year Ending For Common
12/31/95 Plant (1) NEWGAS-UE
------------ ----------- ------------
Gas Plant In Service $ 179,985 $ (5,738) $ 174,247
Reserve For Depreciation $ 53,744 $ (1,083) $ 52,661
------------ ----------- ------------
Net Plant $ 126,241 $ (4,655) $ 121,586
Materials & Supplies $ 11,892 $ 11,892
Prepayments $ 236 $ 236
Customer Advances $ (937) $ (937)
Accumulated Deferred Income Taxes $ (12,616) $ (12,616)
------------ ----------- ------------
TOTAL RATE BASE $ 124,816 $ (4,655) $ 120,161
=========== ========== ===========
(1) Mainly buildings and equipment jointly used by the electric and gas
departments. Under a divestiture, all common property would go with the electric
company.
</TABLE>
24
<PAGE>
NEWGAS-UE EXHIBIT 4
<TABLE>
<CAPTION>
NEWGAS-UE
STAND-ALONE COST OF CAPITAL
Capitalization Cost Weighted
Type of Capital Ratios Component Cost
- ------------------------ -------------- --------- --------
<S> <C> <C> <C>
Long Term Debt 41.00% 8.41% 3.448%
Preferred 5.10% 8.41% 0.429%
Common Equity 53.90% 13.50% 7.277%
--------
Weighted Cost of Capital 11.15%
========
</TABLE>
Note: Capitalization ratios are based on the total UE capital structure as of
12/31/95. Debt and equity were estimated at current costs.
Current cost of debt and preferred = 30 year, 10 Year No Call first mortgage
bond @ 7.91% (all-in-cost) + 50 basis points
Bond and preferred stock rate provided on April 19, 1996 by Smith Barney.
25
<PAGE>
NEWGAS-UE EXHIBIT 5
NEWGAS-UE
Organization Chart
President & CEO
Vice President - Customer Service
Manager - Customer Service Support
Manager - Southeast District
Manager - Illinois District
Manager - Wentzville District
Manager - Little Dixie District
Manager - Corporate Communications
Manager - Gas Supply
Manager - Gas Marketing
Manager - Capital District
Vice President - Corporate Services
Manager - Purchasing
Manager - Stores
Manager - Motor Transportation
Manager - Real Estate & Facilities
Manager - Corporate Planning
General Counsel
Associate General Counsel - Regulatory
Associate General Counsel - Claims
Vice President - Finance
Manager - Accounting
Manager - Tax
Manager - Internal Audit
Secretary/Treasurer
Manager - Investor Relations
Manager - Treasury Operations
Assistant Secretary - Insurance & Records
Vice President - Human Resources
Manager - Employment Services
Manager - Industrial Relations
26
<PAGE>
NEWGAS-UE EXHIBIT 6
NEWGAS-UE
SALARIES AND WAGES SUMMARY (In Thousands of Dollars)
<TABLE>
<CAPTION>
Totals
---------------------------
Employees Salaries/Wages Employees Salaries/Wages
--------- -------------- --------- --------------
<S> <C> <C> <C> <C>
Executive Staff & Secretarial Support 14 $ 995
Customer Service Division:
Customer Service Support 40 $ 1,912
Gas Supply 6 $ 365
Gas Marketing 7 $ 344
Southeast District 45 $ 1,996
Illinois District 33 $ 1,547
Wentzville District 25 $ 1,145
Little Dixie District 101 $ 4,331
Capital District 44 $ 2,061
Corporate Communications 2 $ 105
--------- --------------
Customer Service Division Total 303 $ 13,806
Corporate Services Division:
Purchasing 6 $ 365
Stores 9 $ 450
Motor Transportation 4 $ 225
Real Estate & Facilities 4 $ 225
Corporate Planning 5 $ 305
--------- --------------
Corporate Services Division Total 28 $ 1,570
General Counsel Division:
Regulatory 4 $ 240
Claims 5 $ 268
--------- --------------
General Counsel Division Total 9 $ 508
Controller Division:
Accounting, Payroll, Accounts Payable 24 $ 1,119
Internal Audit 8 $ 475
Tax 12 $ 598
--------- --------------
Controller Division Total 44 $ 2,192
Secretary/Treasurer Division:
Investor Relations 4 $ 199
Treasury Operations 13 $ 535
Insurance & Records 8 $ 351
--------- --------------
Secretary/Treasurer Division Total 25 $ 1,085
Human Resources Division:
Employment Services 28 $ 1,395
Industrial Relations 4 $ 225
--------- --------------
Human Resources Division Total 32 $ 1,620
--------- --------------
GRAND TOTAL 455 $ 21,776
========= ==============
</TABLE>
27
<PAGE>
NEWGAS-UE EXHIBIT 7
COMPARABLE INVESTOR OWNED GAS UTILITIES
CUSTOMERS PER EMPLOYEE
<TABLE>
<CAPTION>
Customers
Companies Customers Employees Per Employee
- ------------------------ --------- --------- ------------
<S> <C> <C> <C>
NEWGAS-CIPS 167,000 541 309
NEWGAS-UE 121,000 455 266
Connecticut Natural Gas 138,000 642 215
ENERGEN 435,000 1,488 292
Southern Connecticut Gas 153,000 572 267
United Cities Gas 295,000 1,343 220
Yankee Gas Service 177,000 670 264
</TABLE>
Source: American Gas Association - Directory of Member Companies
(Selection Criteria - Total Number of Customers Similar to NEWGAS)
28
<PAGE>
NEWGAS-UE EXHIBIT 8
ESTIMATED EXECUTIVE SALARIES
----------------------------
Salary Survey Data for Companies with Revenues less than $300 million were used
to establish a reasonable range for the NEWGAS-UE executive salary levels. For
existing positions that would become part of the spun-off company, existing UE
salaries were used.
<TABLE>
<CAPTION>
NEWGAS-UE SALARY
----------------
POSITION SURVEY DATA RANGE LEVELS
-------- ----------------- ------
<S> <C> <C>
President $212,000 $200,000
Vice President Level $73,600-$106,300 $80,000-$110,000
</TABLE>
Source: 1996 Edison Electric Institute Executive Compensation Survey
29
<PAGE>
NEWGAS-UE EXHIBIT 9
UE ELECTRIC RATE BASE & RATE OF RETURN
TWELVE MONTHS ENDED 12/31/95
(In Thousands of Dollars)
<TABLE>
<CAPTION>
Existing Addition Electric
Electric For Common Company
Company Plant (1) As Adjusted
---------- ---------- -----------
<S> <C> <C> <C>
Electric Plant In Service $7,796,628 $5,738 $7,802,366
Reserve For Depreciation $2,819,806 $1,083 $2,820,889
---------- ------ ----------
Net Plant $4,976,822 $4,655 $4,981,477
Fuel and Materials & Supplies $ 184,684 $ 184,684
Prepayments $ 13,425 $ 13,425
Customer Advances $ (6,935) $ (6,935)
Accumulated Deferred Income Taxes $ (848,543) $ (848,543)
---------- ------ ----------
TOTAL RATE BASE $4,319,453 $4,655 $4,324,108
========== ====== ==========
NET OPERATING INCOME $ 436,690 $ 436,690
========== ==========
RETURN ON RATE BASE 10.11% 10.10%
========== ==========
</TABLE>
(1) This represents an allocation of all plant and property jointly used by the
electric and gas departments. Under a divestiture, all common property would go
with the electric company.
30
<PAGE>
================================================================================
SECTION IV.A. NEWGAS-CIPS OVERVIEW
================================================================================
Spinning-off CIPS' gas operations into a separate stand-alone company (NEWGAS-
CIPS) would result in the following:
. NEWGAS-CIPS would need to establish service functions duplicating those at
CIPS, including treasury, financial planning, accounting, rates, risk
management, employee benefits, marketing, customer service, regulatory,
internal audit and public affairs.
. Annual operating revenue deductions, exclusive of income taxes, for NEWGAS-
CIPS would be about 31% ($36.3 million) greater than CIPS' gas operating
revenue deductions. (SECTION IV.C, Exhibit 1).
. NEWGAS-CIPS' customers would experience a rate increase of about 31% ($40.7
million) in order to provide a 10.98% rate of return for stockholders
(SECTION IV.C, Exhibit 1).
. NEWGAS-CIPS would be at a competitive disadvantage because of high
operating expenses.
. There would be no substantial benefits for customers or stockholders.
31
<PAGE>
- --------------------------------------------------------------------------------
SECTION IV.B. NEWGAS-CIPS ANALYSIS
- --------------------------------------------------------------------------------
The CIPS gas distribution system serves approximately 167,000 customers (as of
December 31, 1995) over a 20,000 square mile area of central and southern
Illinois. There are 4,572 miles of mains and 2,321 miles of service lines in the
system. Natural gas revenues for 1995 were $129.6 million on system throughput
of 37.1 billion cubic feet of gas.
CIPS operates as a tightly integrated company with many of its employees
supporting both gas and electric operations. Of CIPS' 2,428 employees (as of
December 31, 1995), only 206 devoted 100% of their time to gas operations. Some
examples of the shared operations include customer service personnel call takers
who deal with service requests for service for both gas and electric customers
and meter readers who read both the electric and gas meters of CIPS' customers.
Additionally, the gas and electric businesses also share services in the areas
of treasury, financial planning, accounting, rates, risk management, employee
benefits, marketing, customer service, regulatory, internal audit and public
affairs. The shared gas and electric responsibilities of many of CIPS' employees
have enabled CIPS to provide quality service at a low cost.
ORGANIZATION STRUCTURE AND STAFFING IMPACT
- ------------------------------------------
The CIPS organization as of December 31, 1995, was used as a pattern for
developing the NEWGAS-CIPS organization structure. See SECTION IV.C, Exhibit 5
for the proposed organization. Divesting the gas operations would eliminate the
effective use of SHARED STAFF to the detriment of both the gas and electric
operations. To operate the gas business on a stand-alone basis, 340 additional
employees would be required, in addition to the 206 employees mentioned above.
CIPS could expect very minimal staffing reductions in the electric business as a
result of a gas divestiture. SECTION IV.C, Exhibit 6 shows the proposed
staffing, salaries, and wages summary, while Exhibit 2d shows that NEWGAS-CIPS
would incur an estimated net labor increase, including benefits, of $21,163,000.
Exhibit 7 shows that with this proposed staffing, NEWGAS-CIPS compares favorably
with other gas utilities in the number of customers per employee. The following
comments demonstrate some of the reasons for additional staffing:
CIPS' customers receive one bill for both gas and electric service and pay
with one check. When cash processing personnel process the checks,
automated equipment posts both electric and gas payments to customers'
accounts. NEWGAS-CIPS would have to hire staff to handle gas payments that
are now handled at essentially no additional cost by CIPS. Spinning off the
gas operations would not reduce the workload on CIPS' cash processing
personnel, since approximately the same number of checks would be
processed.
32
<PAGE>
CIPS' meter readers read gas and electric meters on the same routes.
NEWGAS-CIPS would have to hire meter readers to re-trace the same routes to
read the gas meters. Spinning off the gas operations would not reduce the
number of meter readers needed by CIPS since their routes would remain
essentially the same.
CIPS' Finance and Accounting personnel maintain the books and records of
the Company and arrange for insurance (except employee benefit-related
insurance). They arrange for long-term financing and borrow short-term
funds for operations. NEWGAS-CIPS would require personnel to provide the
same services. Spinning off the gas operations would not provide any
substantial savings for CIPS in the Finance and Accounting area, since all
the existing books and records of the Company would remain, insurance needs
would be similar, and staff time devoted to financing activities would not
be significantly reduced.
CIPS' Human Resources Department administers benefit and salary plans.
NEWGAS-CIPS would need to hire personnel to perform the same duties.
Spinning off the gas operations would not provide substantial savings to
CIPS, because each of CIPS' existing benefit and salary plans, and the
associated reporting requirements, would remain.
CIPS' Purchasing and General Services Departments provide materials,
supplies, transportation equipment, etc. to operating divisions. NEWGAS-
CIPS would need to hire personnel to perform the same duties for gas
operations. Spinning off the gas operations would reduce the number of
purchase orders handled by CIPS as well as the amount of material handled
and storage costs. However, the quantities involved are a small percentage
of the total, so no staffing reductions would be possible and no facilities
could be eliminated, making the actual savings for CIPS negligible.
CIPS hires outside legal counsel to provide legal, regulatory and claims
services for CIPS' operating divisions. NEWGAS-CIPS would need to hire
outside legal counsel to perform the same duties. Since many legal issues
are not divided into gas and electric considerations, the amount of work
performed by CIPS' outside counsel would not decrease significantly, and
CIPS would not achieve any measurable savings.
33
<PAGE>
INDEPENDENT ACCOUNTANT IMPACT
- -----------------------------
CIPS hires independent accountants to audit the financial statements of the
Company. NEWGAS-CIPS would need to hire independent accountants to perform the
same duties. CIPS would not achieve any significant savings, since the existing
level of work for the independent auditors would remain essentially the same.
INFORMATION TECHNOLOGY IMPACT
- -----------------------------
CIPS provides extensive information services assistance to its operating
division and support departments. NEWGAS-CIPS would need to provide the same
assistance to its departments. Hardware costs are reflective of the quantity of
information to be processed, so NEWGAS-CIPS' hardware and telecommunications
costs would be substantially less than CIPS'. Software costs are generally less
dependent on quantity and more dependent on function, so NEWGAS-CIPS' software
costs would be similar to CIPS'. See Section IV.C, Exhibit 2b, which identifies
a net increase in cost of information services of $11,506,000.
Divesting the gas operations would eliminate opportunities for sharing
information systems resources to the detriment of both the gas and electric
operations:
NEWGAS-CIPS would be subject to the same regulatory accounting requirements
as CIPS, so similar general ledger, payroll distribution, fixed asset and
other accounting systems would be needed. Software costs would be similar
to CIPS' and are estimated to be about $4 million. CIPS would require all
existing software, resulting in no software savings and CIPS would expend
considerable resources changing accounting systems to reflect the
divestiture of the gas business.
CIPS operates an integrated material management, purchasing and accounts
payable system. The system provides ordering, purchasing, tracking,
receiving, paying and inventory control functions. To maintain existing
levels of customer service, NEWGAS-CIPS would need a similar integrated
system, which would cost about $1.5 million. CIPS would require slightly
less data storage, producing negligible savings. CIPS would require all
existing software, resulting in no software savings.
CIPS outsources investor services to handle most stockholder and bondholder
service requests, make dividend and bond payments and track unclaimed
checks. NEWGAS-CIPS would also oursource those same services, which are
estimated to be about $350,000 annually. CIPS would retain the same number
of stockholders and bondholders and thus would experience no savings.
34
<PAGE>
CIPS' customer information system is extensively integrated with numerous
other systems, providing seamless flow of information and efficient
processing of customer service requests, payments and data updates. When
customers call, the system retrieves information and displays it to the
call-taker, allowing customers to spend less time on the line. The system
automatically records customers' payments made by mail, electronically, at
pay stations or banks. It provides a multitude of services such as budget
billing, installment financing payments, combined billing for electric and
gas, preferred pay dates, etc. NEWGAS-CIPS would require similar systems to
maintain the current level of service to customers. Recently installed
utility billing systems have cost other utilities $25 - $50 million.
Scaling down might be possible for a small utility, making the estimated
cost about $20 million. CIPS would require marginally less data storage,
forms, etc., but savings would be negligible since there would be about the
same number of customers. CIPS would expend considerable resources to final
bill existing combination gas/electric customers and re-establish the
electric accounts.
CIPS maintains a work order tracking system (WOTS) which is used to
quantify and control major projects. This system supports the budget
process and compares actual costs to estimated costs as the projects are
completed. NEWGAS-CIPS would need a similar system, costing about
$1,000,000, to maintain current levels of customer service. CIPS would no
longer track gas projects on its WOTS system, but data storage and
processing savings would be insignificant.
CIPS outsources valuation of the retirement plan for accounting purposes,
but maintains records of retirees, accumulates information for active
employees for pension calculations and interfaces with payroll systems to
maintain accurate information. NEWGAS-CIPS would need a similar system,
costing about $250,000, to maintain current levels of benefits to
employees. The assumed reduction of the 206 employees who perform only gas
related work would have a minimal effect on CIPS' data storage
requirements, providing insignificant savings.
CIPS maintains a sophisticated payroll, scheduling, time entry and absence
tracking system. The system provides scheduling for time worked, vacation
and other allowed time. It tracks absences and automatically updates
records and restores sick leave balances. It provides distributed entry of
time worked and the associated accounting. The system provides for the
reporting of information to government, regulatory and other agencies.
NEWGAS-CIPS would need a similar system to schedule, pay and report
earnings for employees. Since the CIPS system includes complex processes
required only for power plant operations, NEWGAS-CIPS could use simpler
software, estimated at about $2,500,000. Processing 206 fewer employees
would provide insignificant savings for CIPS.
35
<PAGE>
CIPS personnel maintain the systems described above. To maintain similar
systems, NEWGAS-CIPS would expend about $1,663,000 annually. It is
estimated NEWGAS-CIPS software maintenance would be about 77 percent of
CIPS' cost, since some systems would not exist in a gas-only company. Since
all the existing systems would remain, CIPS would achieve no maintenance
savings by spinning off the gas operations.
CIPS maintains communications networks, telephone services, radio systems,
etc. NEWGAS-CIPS would need personnel and equipment to perform these
services, costing about $3,484,000 annually to maintain similar systems.
Due to fewer employees and locations than CIPS, NEWGAS-CIPS would spend an
amount estimated at 36 percent of CIPS' costs. CIPS would achieve minimal
savings because the number of locations and employees using its systems
would remain essentially unchanged.
CIPS maintains a data center to serve all of the above systems. To operate
similar systems, NEWGAS-CIPS would need a similar data center, costing
about $2,772,000 annually, excluding personnel costs. There would be no
equipment or manpower savings for CIPS since all existing systems would
remain.
INSURANCE COSTS
- ---------------
CIPS obtains property, liability, directors and officers, workers compensation
and other insurance. NEWGAS-CIPS would require similar insurance policies, at
similar costs. See Section IV.C, Exhibit 2c, which shows an estimated increase
in insurance cost of $302,000 for NEWGAS-CIPS. Since all coverages would remain
in effect, CIPS would experience no significant savings for insurance.
OFFICE AND CREW FACILITIES COSTS
- --------------------------------
CIPS maintains combined electric and gas office and crew facilities at numerous
locations throughout the service area. NEWGAS-CIPS would need facilities for
office and crew personnel at each of the existing combined electric and gas
locations. See Section IV.C, Exhibit 2e, which shows an estimated net increase
of $1,741,506 in additional office and crew facilities costs. Since CIPS would
still operate the electric system, the existing office and crew facilities would
still be needed at each location, resulting in no significant savings for CIPS.
36
<PAGE>
TRANSPORTATION AND MOTORIZED EQUIPMENT COSTS
- --------------------------------------------
CIPS maintains transportation and motorized equipment used by both gas and
electric crew and support personnel. NEWGAS-CIPS would need to obtain similar
equipment for gas operations. NEWGAS-CIPS' additional transportation cost would
be about $295,000 as identified in SECTION IV.C, Exhibit 2g. Since vehicle needs
correlate closely with personnel needs, it is estimated that the reduction in
equipment to be achieved by CIPS would equal the additional equipment required
by NEWGAS-CIPS, except for vehicles used by meter readers to read both electric
and gas meters. CIPS would still need about the same number of meter reader
vehicles currently used in the combination gas and electric districts, but the
costs currently allocated to the gas business would be absorbed by the electric
customers, resulting in increased annual meter reading vehicle costs to CIPS of
about $41,200.
TRANSITION COSTS
- ----------------
The divestiture of the gas operations of CIPS and the creation of a stand-alone
gas company would be a complex legal and financial transaction that would
involve substantial transition costs. These costs would include legal and
financial advising fees, and the services of independent accountants, actuaries
and other consultants. Real estate services would be needed to procure
facilities. Several hundred personnel would have to be hired and trained.
Benefit plans would need to be established. The estimated transition costs of
$11,031,000 for NEWGAS-CIPS were developed by calculating the average of such
costs incurred in several other publicly reported business spin-offs. See
SECTION IV.C, Exhibit 2f.
COST OF CAPITAL
- ---------------
The effective cost of capital for the stand-alone gas business was estimated
based upon capitalization ratios of CIPS' capital structure as of December 31,
1995, and estimated current costs of debt and equity, which average about
10.98%. See SECTION IV.C, Exhibit 4 for detailed information.
CONCLUSION
- ----------
The Study concludes that a separate gas distribution company would require 546
full-time employees, an increase of approximately 165% over the number of
employees currently devoted to gas operations full-time. Based upon the
assumptions set forth in SECTION II and the staffing requirements of the
organizational structure, increased annual costs (excluding Federal and State
income taxes) for NEWGAS-CIPS are projected to be $36,317,000.
37
<PAGE>
The exhibits (SECTION IV.C) that follow show the economic effects of operating
CIPS' gas division as a separate entity.
38
<PAGE>
================================================================================
SECTION IV.C. NEWGAS-CIPS SCHEDULE OF EXHIBITS
================================================================================
<TABLE>
<CAPTION>
EXHIBIT NO. EXHIBIT TITLE
- ----------------------- ---------------------------------------------------
<S> <C>
1 Income Statement, Proforma Adjustments & Revenue
Requirement
2 Estimated Additional Operating Expenses
2a Estimated External Audit Fees Based on Survey Data
2b Estimated Information Services Costs
2c Estimated Increased Cost of Insurance Coverage
2d Estimated Net Labor Increase, Including Benefits
2e Estimated Operating Lease Facilities and Furniture
Costs
2f Estimated Transition Costs
2g Estimated Net Increase in Transportation &
Motorized Equipment Expense
3 Rate Base
4 Cost of Capital
5 Corporate Structure
6 Salaries and Wages Summary
7 Comparable Investor Owned Gas Companies
(Customers Per Employee Ratios)
8 Estimated Executive Salaries
9 CIPS' Electric Rate Base & Rate of Return
</TABLE>
39
<PAGE>
NEWGAS-CIPS EXHIBIT 1
NEWGAS-CIPS INCOME STATEMENT
PROFORMA ADJUSTMENTS & REVENUE REQUIREMENT
(In thousands of dollars)
<TABLE>
<CAPTION>
Existing
CIPS Gas
Company Revenue
Year Ending Proforma Proformed Requirement
12/31/95 Adjustments (1) NEWGAS-CIPS Increase (2)
----------- --------------- ----------- ------------
<S> <C> <C> <C> <C>
OPERATING REVENUE: $129,611 $ - $129,611 $170,293
Operating Revenue Deductions:
- -----------------------------
Purchased Gas $ 71,463 $ 71,463 $ 71,463
Gas Withdrawn From Storage $ 2,591 $ 2,591 $ 2,591
O & M $ 26,557 $35,043 $ 61,600 $ 61,600
Depreciation $ 6,804 $ 6,804 $ 6,804
Taxes Other Than Income $ 9,962 $ 1,274 $ 11,236 $ 11,236
-------- ------- -------- --------
TOTAL OPERATING REVENUE DEDUCTIONS $117,377 $36,317 $153,694 $153.704
-------- ------- -------- --------
GROSS GAS INCOME $ 12,234 $(24,083) $ 16,599
-------- -------- --------
FEDERAL & STATE INCOME TAX (3) $ 3,661 $ (7,225) $ 4,980
-------- -------- --------
NET GAS INCOME $ 8,573 $(16,858) $ 11,619
======== ======== ========
RATE BASE (4) $112,592 $105,819 $105,819
======== ======== ========
INDICATED RATE OF RETURN 7.61% -15.93% 10.98%(5)
======== ======== ========
</TABLE>
(1) See Exhibit 2 for a detailed summary of proforma adjustments.
(2) An increase of $40,682,000 or 31.39% in revenue is required to achieve a
rate of return of 10.98%. For the purposes of this Study, gross receipts taxes
were not considered since both the resulting revenue and taxes (revenue
deduction) would nullify any impact from this calculation.
(3) For twelve months ended 12/31/95, CIPS' effective Federal & State Income
Taxes were 30.0% of gross gas income. This effective tax rate was used to
calculate taxes for the Proformed NEWGAS-CIPS and Revenue Requirement Increase
columns.
(4) See Exhibit 3.
(5) The effective rate of return is assumed to be the weighted cost of capital
per Exhibit 4.
40
<PAGE>
NEWGAS-CIPS EXHIBIT 2
NEWGAS-CIPS
ESTIMATED ADDITIONAL OPERATING EXPENSES
PROFORMA ADJUSTMENTS
(In thousands of dollars)
<TABLE>
<CAPTION>
Exhibit
Reference
Number Amount
========== ==========
<S> <C> <C>
External Auditing Costs 2a $ 206
Information Services Outsourced 2b $11,506
Insurance Premiums 2c $ 302
Labor & Benefits 2d $21,163
Leased Facilities/Furniture 2e $ 1,742
Transition Cost (Amortized) 2f $ 1,103
Transportation & Work equipment 2g $ 295
-------
Total Additional Expenses $36,317
Less: FICA and Unemployment Insurance 2d $ 1,274
-------
TOTAL ADDITIONAL O & M EXPENSES $35,043
=======
</TABLE>
<PAGE>
NEWGAS-CIPS EXHIBIT 2a
NEWGAS-CIPS
EXTERNAL AUDITOR COSTS
ESTIMATED EXTERNAL AUDIT FEES BASED ON SURVEY DATA
PROFORMA ADJUSTMENT
<TABLE>
<CAPTION>
<S> <C>
Listing of Data for Surveys comparing External Audit Fees Amount
--------------------------------------------------------- ---------
Average fee for Utility companies with less than 300,000 Customers in 1994 $ 191,000
Average fee for Peer Group comparison with less than 300,000 Customers in 1994 $ 188,000
---------
Average of External Audit Fee Surveys $ 189,500
Average Audit Fee for Pension Plans with less than 5,000 employees $ 38,693
---------
Total Estimated Annual Audit Fees for NEWGAS-CIPS $ 288,193
Less: External Audit Fees Allocated to Gas operations in 1995 $ 22,000
---------
Net Estimated Annual Audit Fees Increase for NEWGAS-CIPS $ 206,193
=========
Sources: Illinois Power Audit Fee Peer Group Comparison - 1994
American Gas Association/Edison Electric Institute External Audit Fees - October 1995
</TABLE>
42
<PAGE>
NEWGAS-CIPS EXHIBIT 2b
NEWGAS-CIPS
INFORMATION SERVICES
ESTIMATED INFORMATION SERVICES COSTS
PROFORMA ADJUSTMENT
(In thousands of dollars)
<TABLE>
<CAPTION>
Software Application Costs Amount
-------------------------- ------
<S> <C>
General Ledger/Capital Projects/Asset Management/Accounts Payable $ 4,000
Payroll Distribution $ 500
Customer Information System (CIS) $20,000
Work Order Tracking System (WOTS) $ 1,000
Gas Systems $ 6,250
Materials Management System $ 1,500
Pension Manager $ 250
Payroll/Human Resources $ 1,500
Time Reporting $ 1,000
Miscellaneous $ 2,830
-------
Total Software Application Costs (1) $38,830
=======
Annual System Operating Costs
-----------------------------
Data Processing $ 2,772
Software Maintenance and Support $ 1,663
Telecommunications $ 3,484
-------
Total Annual System Operating Costs (2) $ 7,919
=======
Estimated Cost to Outsource Information Services
------------------------------------------------
(1) Annualized Software Application Costs (10 year amortization) $ 3,883
(2) Total Annual System Operating Costs $ 7,919
(3) Investment Services Costs $ 350
-------
Total Annual Cost to Outsource Information Services $12,152
-------
Less: Information Services Expenses Allocated to Gas Operations in
1995 $ 646
-------
Net Increase in Cost for Information Services $11,506
=======
</TABLE>
43
<PAGE>
NEWGAS-CIPS EXHIBIT 2c
NEW GAS-CIPS
ESTIMATED INCREASED COST OF INSURANCE COVERAGE
PROFORMA ADJUSTMENT
<TABLE>
<CAPTION>
Limits Estimated Net Increase to
Coverage (Millions) Deductible Premium Cost NEWGAS-CIPS
- ----------------------------- ---------- ---------- ------------ ---------------
<S> <C> <C> <C> <C>
Property $ 5 $ 250,000 $ 30,000
General Liability $ 60 $ 250,000 $ 236,000
Auto Liability (self-insured) $ - $ - $ -
Directors & Officers Liability $ 10 $ 250,000 $ 75,000
Workers Compensation Statutory $ 350,000 $ 25,000
Fiduciary Liability $ 5 $ 5,000 $ 10,000
Crime (Fidelity) $ 5 $ 5,000 $ 10,000
------------
Total NEWGAS-CIPS Premium $ 386,000
Less: 1995 Insurance Cost Allocated to CIPS Gas Operation $ 84,000
------------
Net Increase in Insurance Costs for NEWGAS-CIPS $ 302,000
===============
</TABLE>
Source: Premiums based on estimated cost quotations obtained by the Risk
Management Section of CIPS' Accounting Department.
44
<PAGE>
NEWGAS-CIPS EXHIBIT 2d
NEWGAS-CIPS
ESTIMATED NET LABOR INCREASE, INCLUDING BENEFITS
PROFORMA ADJUSTMENT
(In thousand of dollars)
Total Estimated Salaries and Wages (Exhibit 6) $27,589
Less: Amount for Construction & Removals (10%) (1) $ 2,759
---------
Total Estimated NEWGAS-CIPS Salaries & Wages Charged to O & M $24,830
Less: 1995 CIPS Gas Salaries & Wages Charged to O & M $ 9,926
---------
Increase in NEWGAS-CIPS Salaries & Wages Charged to O & M $14,904
Benefits(2):
Employee Life, Hospitalization, savings plans, etc. $3,678
Pension Plan $ 757
FICA & Unemployment Insurance (Exhibit 2) $1,274
Other $ 550
--------
Total Benefits $ 6,259
---------
NEWGAS-CIPS Net Labor Increase, Including Benefits $21,163
=========
(1) Amount of labor allocated to construction and removal is based on the actual
amount spent by CIPS in 1995.
(2) Benefit costs were estimated base upon the cost (as a percentage of payroll)
currently budgeted by CIPS:
Life, hospitalization, savings plans, post employment
benefit, etc. 24.68%
Pension Plan 5.08%
FICA & Unemployment Insurance 8.55%
Other 3.69%
--------
Total 42.00%
========
45
<PAGE>
NEWGAS-CIPS EXHIBIT 2e
NEWGAS-CIPS
ESTIMATED OPERATING LEASE FACILITIES AND FURNITURE COSTS
PROFORMA ADJUSTMENT
<TABLE>
<CAPTION>
-----------------------------------------------------------
Office Space Calculation
-----------------------------------------------------------
Management Office Space ------ ------------
& Staff Needs in Cost Per Total Works Total Leased
Employee Square Feet Square Foot Office Space Hqtrs. Facilities
Count (1) (2) Cost (3) Cost
----------------------------------------------------------- ------ ------------
<S> <C> <C> <C> <C> <C> <C>
General Office:
Springfield, IL 267 82,236 $11.00 $904,596 - $ 904,596
Eastern Division (IL):
Effingham 3 - $ - $ - $17,000
Hoopeston 3 - $ - $ - $17,000
Mattoon 18 5,544 $10.00 $ 55,440 $55,400
Paris 3 - $ - $ - $17,000
Robinson 3 - $ - $ - $17,000
Taylorville 3 - $ - $ - $17,000
-------
Total $ 195,840
Southern Division (IL):
Benton 3 - $ - $ - $17,000
Carbondale 3 - $ - $ - $17,000
Marion 16 4,928 $ 9.00 $ 44,342 $55,400
-------
Total $ 133,752
Western Division (IL):
Beardstown 18 5,544 $ 7.00 $ 38,808 $55,400
Canton 3 - $ - $ - $17,000
Jerseyville 3 - $ - $ - $17,000
Macomb 3 - $ - $ - $17,000
Petersburg 3 - $ - $ - $17,000
Quincy 3 - $ - $ - $55,400
-------
Total $ 217,608
Estimated Office Operating Furniture Lease Expense for All Areas: $ 343,000
----------
NEWGAS-CIPS FACILITIES - GRAND TOTAL $1,794,796
Less: Current allocated costs for gas facilities $ 53,290
----------
NET NEWGAS-CIPS FACILITIES - GRAND TOTAL $1,741,506
==========
</TABLE>
(1) This cost was based on an average 308 square feet per employee.
(2) Cost per square foot per annum averaged $7 in Beardstown, $9 in Marion, $10
in Mattoon, and $11 in Springfield. Excluding Springfield these averages were
derived taking purchased cost of buildings amortized over 7 years for annual
lease expense.
(3) This includes space for construction & service supervision, staff,
materials & supplies, and vehicles & equipment. Annual lease costs were based on
actual appraised values of utility facilities capable of accommodating
applicable staff, materials & equipment.
46
<PAGE>
NEW GAS-CIPS EXHIBIT 2f
NEW GAS-CIPS
ESTIMATED TRANSITION COSTS
PROFORMA ADJUSTMENT
Transition costs required to established a new corporation would include the
following:
Legal fees
Financial advisory fees
Consulting services of independent accountants,
actuaries, and others.
Real estate services for acquisitions
Hiring and training costs to staff newly created
positions
Benefits plans established
Data conversion
Transition costs for NEWGAS-CIPS were estimated based upon an average of the
following published transition costs for other corporate spin-offs:
<TABLE>
<CAPTION>
ORIGINAL CORPORATION SPIN-OFF COMPANY COSTS(000)
- -------------------- ---------------- ----------
<S> <C> <C>
Baxter International Caremark $ 13,300
Adolph Coors ACX Technologies $ 7,200
Dial Corporation GFC Financial $ 13,000
Union Carbide Praxair $ 11,000
Ryder Avial $ 9,000
Price Costco Price Enterprises $ 15,250
Humana Galen $ 15,000
Honeywell Aliant $ 4,500
--------
Average Transition Costs of the Above Companies $ 11,031
--------
Annual amortization of Transition Costs for NEWGAS-CIPS (10%) $ 1,103
========
</TABLE>
Source: Transition costs reported in SEC Form 10-K filings.
47
<PAGE>
NEWGAS-CIPS EXHIBIT 2g
NEWGAS-CIPS
ESTIMATED NET INCREASED IN TRANSPORTATION EXPENSE
PROFORMA ADJUSTMENT
<TABLE>
<CAPTION> ======================= =================== ==================== ===================
General Office(GO)\Pool Eastern Division Southern Division Western Division
============================= ============ ======================= =================== ==================== ===================
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Rate Per Est. Annual Est. Annual Est. Annual Est. Annual
Description Month Number Cost Number Cost Number Cost Number Cost
=============================--============--=======================--===================--====================--===================
Pool Vehicles $470 8 $45,120
- ------------------------------------------------------------------------------------------------------------------------------------
Pool Vehicles $442 5 $26,520
- ------------------------------------------------------------------------------------------------------------------------------------
Manager $470 1 $ 5,640 1 $ 5,640 1 $ 5,640
- ------------------------------------------------------------------------------------------------------------------------------------
Superintendent $442 6 $ 31,824 6 $ 31,824 6 $ 31,824
- ------------------------------------------------------------------------------------------------------------------------------------
H/R Supervisor $442 1 $ 5,304 1 $ 5,304 1 $ 5,304
- ------------------------------------------------------------------------------------------------------------------------------------
New Business Supervisor $442 1 $ 5,304 1 $ 5,304 1 $ 5,304
- ------------------------------------------------------------------------------------------------------------------------------------
C/S & N/B Representatives $442 4 $ 21,216 4 $ 21,216 4 $ 21,216
- ------------------------------------------------------------------------------------------------------------------------------------
Engineer $442 2 $ 10,608 2 $ 10,608 2 $ 10,608
- ------------------------------------------------------------------------------------------------------------------------------------
Operating Supervisor $442 1 $ 5,304 1 $ 5,304 1 $ 5,304
- ------------------------------------------------------------------------------------------------------------------------------------
Meter Reader $505 7 $ 42,420 5 $ 30,300 8 $ 48,480
- --------------------------------------------------------=======----------------========---------------========-------------========-
- ------------------------------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------------------------------
NEWGAS-CIPS TOTAL $71,640 $127,620 $115,500 $133,680
- --------------------------------------------------------=======----------------========---------------========-------------========-
- ------------------------------------------------------------------------------------------------------------------------------------
Less: 1995 allocations on CIPS vehicles
- ------------------------------------------------------------------------------------------------------------------------------------
====================================================================================================================================
NET INCREASED TRANSPORTATION EXPENSE FOR NEWGAS-CIPS
====================================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
====================================================================
GRAND
Description TOTAL
====================================================================
<S> <C>
Pool Vehicles
- --------------------------------------------------------------------
Pool Vehicles
- --------------------------------------------------------------------
Manager
- --------------------------------------------------------------------
Superintendent
- --------------------------------------------------------------------
H/R Supervisor
- --------------------------------------------------------------------
New Business Supervisor
- --------------------------------------------------------------------
C/S & N/B Representatives
- --------------------------------------------------------------------
Engineer
- --------------------------------------------------------------------
Operating Supervisor
- --------------------------------------------------------------------
Meter Reader
- --------------------------------------------------------------------
- --------------------------------------------------------------------
- --------------------------------------------------------------------
NEWGAS-CIPS TOTAL $448,440
- --------------------------------------------------------------------
- --------------------------------------------------------------------
Less: 1995 allocations on CIPS vehicles $153,591
- -----------------------------------------------------------=========
====================================================================
NET INCREASED TRANSPORTATION EXPENSE FOR NEWGAS-CIPS $294,849
====================================================================
</TABLE>
Note: Projected costs based on management's assessment of transportation &
equipment needs and operating & maintenance experience.
48
<PAGE>
NEWGAS-CIPS EXHIBIT 3
NEWGAS-CIPS
RATE BASE
(In thousands of dollars)
<TABLE>
<CAPTION>
Existing
CIPS Gas
Company Reduction
Year Ending For Common
12/31/95 Plant(1) NEWGAS-CIPS
----------- ---------- -----------
<S> <C> <C> <C>
Gas Plant In Service $ 228,207 $ 7,024) $ 221,183
Reserve For Depreciation $ 93,453 $ (251) $ 93,202
----------- ---------- -----------
Net Plant $ 134,754 $ (6,773) 127,981
Materials & Supplies 1,048 $ 1,048
Prepayments $ (986) $ (986)
Customer Advances $ (464) $ (464)
Accumulated Deferred Income Taxes $ (21,760) $ (21,760)
----------- ---------- -----------
TOTAL RATE BASE $ 112,592 $ (6,773) $ 105,819
=========== ========== ===========
</TABLE>
(1) Mainly building and equipment jointly used by the electric and gas
departments. Under a divestiture, all common property would go with the electric
company.
49
<PAGE>
NEWGAS-CIPS EXHIBIT 4
NEW GAS-CIPS
STAND ALONE COST OF CAPITAL
AS OF 12/31/95
<TABLE>
<CAPTION>
Capitalization Cost Weighted
Type of Capital Ratios Component Cost
- --------------- -------------- --------- --------
<S> <C> <C> <C>
Long Term Debt 42.41% 8.41% 3.567%
Preferred Equity 7.08% 8.41% 0.595%
Common Equity 50.51% 13.50% 6.819%
-------
WEIGHTED COST OF CAPITAL 10.98%
=======
</TABLE>
Note: Capitalization ratios are based on the total CIPS capital structure as of
12/31/95.
Debt and equity were estimated at current costs.
Current cost of debt and preferred = 30 year, 10 Year No Call first mortgage
bond
@7.91% (all-in-cost) + 50 basis points
Bond and preferred stock rate provided on April 19, 1996 by Smith Barney.
50
<PAGE>
NEWGAS-CIPS EXHIBIT 5
NEWGAS-CIPS
Organization Chart
President & CEO
Vice President - Finance
Supervisor - Risk Management
Controller
Treasurer & Assistant Secretary
Manager - Internal Audit
Vice President - H/R, Labor Relations, Admin & Corporate Secretary
Supervisor - Labor Relations
Supervisor - Benefits & Administration
Manager - Corporate Communications
Manager - Purchasing & Stores
Manager - General Services
Vice President - Marketing & Customer Service
Supervisor - Customer Expansion
Manager - Customer Service
Manager - Gas Marketing
Vice President - Operations
Manager - System Planning &
Engineering
Manager - Eastern Division
Manager - Southern Division
Manager - Western Division
Vice President - Gas Supply
Manager - Gas Supply
Manager - Corporate Planning
Manager - Rates & Regulatory
Manager - Public Affairs
51
<PAGE>
NEWGAS-CIPS EXHIBIT 6
NEWGAS-CIPS
Salaries and Wages Summary (In Thousands of Dollars)
<TABLE>
<CAPTION>
Totals
---------------------------------
Employees Salaries/Wages Employees Salaries/Wages
--------- -------------- --------- --------------
<S> <C> <C> <C> <C>
Executive Staff & Secretarial Support 12 $ 928
Marketing & Customer Service Div:
Customer Expansion 9 $ 507
Customer Service 33 $ 1,349
Gas Marketing 11 $ 549
--------- -------------
Mrkting & Cust. Serv Div Total 53 $ 2,405
Operations Division:
Gas Planning & Engineering 12 $ 640
Eastern Division 97 $ 3,899
Southern Division 74 $ 2,980
Western Division 108 $ 4,528
--------- --------------
Operations Division Total 291 $ 12,047
Planning & Regulatory Division:
Gas Supply 15 $ 826
Corporate Planning 5 $ 272
Rates and Regulatory 14 $ 755
Public Affairs 4 $ 238
--------- --------------
Planning & Reg. Division Total 38 $ 2,091
Finance Division:
Risk Management 10 $ 535
Accounting Operations 40 $ 2,344
Treasury Operations 22 $ 3,528
Internal Audit 7 $ 407
--------- --------------
Finance Division Total 79 $ 6,814
H/R, Admin., Labor Rel., & Corp. Sec:
Labor Relations 3 $ 183
Benefits and Administration 16 $ 813
Corporate Communications 7 $ 370
Purchasing & Stores 11 $ 573
General Services 36 $ 1,365
--------- --------------
H/R, Admin., Labor Rel., Corp. Total 73 $ 3,304
--------- --------------
GRAND TOTAL 546 $ 27,589
========= ==============
</TABLE>
52
<PAGE>
NEWGAS-CIPS EXHIBIT 7
COMPARABLE INVESTOR OWNED GAS UTILITIES
CUSTOMERS PER EMPLOYEE
<TABLE>
<CAPTION>
Customers
Companies Customers Employees Per Employee
- ---------------------- ------------ ----------- ------------
<S> <C> <C> <C>
NEWGAS-CIPS 167,000 541 309
NEWGAS-UE 121,000 455 266
Connecticut Natural Gas 138,000 642 215
ENERGEN 435,000 1,488 292
Southern Connecticut Gas 153,000 572 267
United Cities Gas 295,000 1,343 220
Yankee Gas Service 177,000 670 264
</TABLE>
Source: American Gas Association - Directory of Member Companies
(Selection Criteria - Total Number of Customers Similar to NEWGAS)
53
<PAGE>
NEWGAS-CIPS EXHIBIT 8
ESTIMATED EXECUTIVE SALARIES
----------------------------
Salary Survey Data for Companies with Revenues less than $300 million were used
to establish a reasonable range for the NEWGAS-CIPS executive salary levels. For
existing positions that would become part of the spun-off company, existing CIPS
salaries were used.
<TABLE>
<CAPTION>
NEWGAS-CIPS SALARY
------------------
POSITION SURVEY DATA RANGE LEVELS
-------- ----------------- ------
<S> <C> <C>
President $212,000 $200,000
Vice President Level $73,600-$106,300 $80,000-$110,000
</TABLE>
Source: 1996 Edison Electric Institute Executive Compensation Survey
54
<PAGE>
NEWGAS-CIPS EXHIBIT 9
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
ELECTRIC RATE BASE & RATE OF RETURN
TWELVE MONTHS ENDED 12/31/95
(In thousands of dollars)
<TABLE>
<CAPTION>
Existing Addition Electric
Electric For Common Company
Company Plant (1) As Adjusted
------------ ---------- -------------
<S> <C> <C> <C>
Electric Plant In Service $ 2,285,299 $ 7,024 $ 2,292,323
Reserve For Depreciation $ 1,038,809 $ 251 $ 1,039,060
------------ ------- ------------
Net Plant $ 1,246,490 $ 6,773 $ 1,253,263
Fuel and Materials & Supplies $ 39,199 $ 39,199
Prepayments $ 7,181 $ 7,181
Customer Advances $ (742) $ (742)
Accumulated Deferred Income Taxes $ (326,854) $ (326,854)
----------- ------- ------------
TOTAL RATE BASE $ 965,274 $ 6,773 $ 972,047
=========== ======= ============
NET OPERATING INCOME $ 97,557 $ 97,557
=========== ============
RETURN ON RATE BASE 10.11% 10.04%
=========== ============
</TABLE>
(1) This represents an allocation of all plant and property jointly used by the
electric and gas departments. Under a divestiture, all common property would go
with the electric company. See Exhibit 3.
55
<PAGE>
Exhibit K-2
SUMMARY OF LOST ECONOMY RATIOS
<TABLE>
<CAPTION>
UE and CIPS
_______________________________________________________________________
NEWGAS-UE NEWGAS-CIPS
________________________________ ____________________________________
Percent of Percent of
estimated loss estimated loss
Amount of economies to: Amount of economies to:
______ ________________ ______ ________________
<S> <C> <C> <C> <C>
Operating Revenues $87,814,000 25.19% $129,611,000 28.02%
Operating Revenue Deductions/1/ 80,478,000 27.48% 117,377,000 30.94%
Gross Income/2/ 7,336,000 301.47% 12,234,000 296.85%
Net Income/2/ 5,205,000 424.90% 8,573,000 423.62%
Estimated Loss of Economies 22,242,000 35,986,000
</TABLE>
NOTES
1 Excludes federal income taxes.
2 Before deducting federal income taxes.
<PAGE>
<TABLE>
<CAPTION>
CINergy
____________________________________________________________________________
Gas Properties of Cincinnati Gas Properties of Union Light, Gas Properties of Lawrenceburg
Gas & Electric Co. - 1993 Heat and Power Co. - 1993 Gas Co. - 1993
___________________________ ___________________________ ______________________________
Percent of Percent of Percent of
estimated estimated estimated
loss of loss of loss of
economies economies economies
Amount to: Amount to: Amount to:
_______ __________ _______ __________ _______ __________
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues $382,726,614 7.88% $74,769,120 10.93% $7,516,461 14.46%
Operating Revenue 355,064,520 8.49% 64,616,026 12.65% 6,268,225 17.34%
Deductions/1/
Gross Income/2/ 27,732,094 108.71% 10,153,094 80.49% 1,298,236 87.09%
Net Income/2/ 14,286,471 211.02% 6,335,113 129.00% 1,062,927 102.28%
Estimated Loss of Economies 30,146,860 8,172,339 1,087,136
</TABLE>
NOTES
1 Excludes federal income taxes.
2 Before deducting federal income taxes.
2
<PAGE>
<TABLE>
<CAPTION>
Gulf States Utilities Fitchburg Gas & Electric
---------------------------- -----------------------------
GSU Gas Division 1991 Fitchburg Gas Division 1990
---------------------------- -----------------------------
Percent of Percent of
estimated loss of estimated loss of
Amount economies to: Amount economies to:
----------- ----------------- ----------- -----------------
<S> <C> <C> <C> <C>
Operating Revenues $31,858,000 16.13% $17,324,993 13.94%
Operating Revenue Deductions/1/ 30,770,000 16.70% 15,755,267 15.33%
Gross Income/2/ 1,088,000 472.24% 1,569,726 153.87%
Net Income/2/ n/a n/a n/a n/a
Estimated Loss of Economies 5,138,000 2,415,391
</TABLE>
NOTES
/1/ Excludes federal income taxes.
/2/ Before deducting federal income taxes.
3
<PAGE>
<TABLE>
<CAPTION>
General Public Utilities
NEES Middle South Utilities, Inc. Corp. Philadelphia Company
------------------------- ---------------------------- ------------------------ --------------------
Gas Properties of Jersey
Gas Properties of 8 Gas Properties of Louisiana Central Power & Light
Subsidiaries Combined-1958 Power & Light Co.-1954 Co.-6/30/49 Gas Group-1946
-------------------------- ---------------------------- ------------------------ --------------------
Percent of Percent of Percent of Percent of
estimated estimated estimated estimated
loss of loss of loss of loss of
economies economies economies economies
Amount to: Amount to: Amount to: Amount to:
---------- ---------- --------- ------------ -------- ---------- -------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Operating Revenues $22,752,270 4.83% $5,264,186 5.18% $4,714,958 4.87% $16,656,560 3.00%
Operating Revenue
Deductions/1/ 18,207,191 6.03% 4,112,285 6.63% 4,235,661 5.42% 13,197,846 3.79%
Gross Income/2/ 4,718,864 23.28% 1,151,901 23.68% 479,477 47.84% 3,565,357 14.03%
Net Income/2/ 3,669,931 29.93% n/a n/a 202,582 113.24% n/a n/a
Estimated Loss of
Economies 1,098,500 272,816 229,398 500,328
</TABLE>
NOTES
/1/ Excludes federal income taxes.
/2/ Before deducting federal income taxes.
4
<PAGE>
<TABLE>
<CAPTION>
The North American Company Engineers Public Service Company
------------------------------- ------------------------------------------------------
Gas Properties of Virginia
Gas Properties of the St. Louis Gas Properties of Gulf Electric and Power
County Gas Co.-1942 States Utilities Co.-1940 Co.-1940
------------------------------- ------------------------- --------------------------
Percent of Percent of Percent of
estimated estimated estimated
loss of loss of loss of
economies economies economies
Amount to: Amount to: Amount to:
---------- ---------- -------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues $2,748,770 5.85% $638,711 6.58%* $1,057,000 3.38%
Operating Revenue 2,009,757 8.01% 444,006 9.46%* 735,294 4.86%
Deductions/1/
Gross Income/2/ 742,027 21.68% 201,594 20.85%* 317,890 11.25%
Net Income/2/ 661,110 24.34% 166,402 25.25%* 168,412 21.23%
Estimated Loss of Economies 160,900 42,024 35,750
</TABLE>
NOTES
/1/ Excludes federal income taxes.
/2/ Before deducting federal income taxes.
* Based on estimated cost increases rejected by the Commission as
"overstated" and "doubtful." In re Engineers Public Service Co., 12 SEC 41,
80-81 (Sept. 16, 1942).
5
