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As Filed with the Securities and Exchange Commission December 29, 1997
File No. 70-8945
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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AMENDMENT NO. 5
(AMENDED AND RESTATED)
FORM U-1
APPLICATION/DECLARATION
UNDER
THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
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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
William Niehoff Jones, Day, Reavis & Pogue
Union Electric Company 77 West Wacker, Suite 3500
1901 Chouteau Avenue Chicago, Illinois 60601-1692
P.O. Box 149
St. Louis, Missouri 63166
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Table of Contents
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Item 1. Description of Proposed Transaction............................ 1
A. Introduction................................................... 1
1. General Request............................................ 2
2. Overview of the Transaction................................ 2
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
3. Nonutility Interests of UE and CIPSCO.....................16
a. UE.....................................................16
b. CIPSCO.................................................16
4. Present Electric Coordination.............................16
5. Present Gas Coordination..................................18
C. Description of Transaction and Statement as to Consideration...18
1. Background................................................18
2. Benefits of the Transaction...............................23
3. Merger Agreement..........................................25
a. Consideration........................................25
b. Other Terms..........................................26
c. Management Following the Mergers.....................26
4. Related Agreements........................................26
D. Dividend Reinvestment Plan and Employee Benefits Plans.........26
1. Sources of Common Stock and Use of Proceeds...............27
2. Dividend Reinvestment Plan................................27
3. Employee Benefit Plans....................................28
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a. Long Term Incentive Plan...................................28
b. Savings Plans..............................................29
4. Solicitation of Proxies........................................29
Item 2. Fees, Commissions and Expenses.....................................29
Item 3. Applicable Statutory Provisions....................................30
A. Analysis of Transaction............................................31
1. Section (10b)..................................................33
a. Section 10(b)(1)...........................................33
i. Interlocking Relationships............................33
ii. Concentration of Control.............................34
b. Section 10(b)(2)--Fairness of Consideration................38
i. Reasonableness of Consideration.......................38
ii. Reasonableness of Fees................................39
c. Section 10(b)(3)--Capital Structure; Not Detrimental to
Public Interest............................................41
2. Section 10(c)..................................................43
a. Section 10(c)(1)...........................................44
i. Retention of Gas Operations...........................44
(A) Ameren Satisfies the Traditional "ABC" Test......45
(1) Clause (A)............................................45
(2) Clauses (B) and (C) of Section 11(b)(1) are
Satisfied.............................................49
(B) The Commission Should Not Require Ameren to Satisfy
the Traditional "ABC" Test...........................50
(1) The Act Does Not Prohibit Combination Companies.......51
(2) The Commission's Interpretation of the Act............52
(3) The Commission Should Revise Its Interpretation of
The Act...............................................53
(4) UE's and CIPS' Combination Systems Are Not Prohibited
by State Law..........................................61
ii. Other Businesses......................................62
b. Section 10(c)(2)...........................................72
i. Efficiencies and Economics............................73
ii. Integrated Public Utility System......................76
(A) Electric Utility System...............................76
(B) Gas Utility System....................................80
3. Section 10(f)--Compliance with State Law.......................83
4. Section 9(a)(1)................................................83
5. Other Applicable Provisions--Section 6, 7, 12 and 13...........84
B. Intra-system Financing.............................................85
C. Ameren Services....................................................85
D. Other Services.....................................................88
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Item 4. Regulatory Approvals.............................................. 88
A. Antitrust...................................................... 88
B. Federal Power Act.............................................. 88
C. State Public Utility Regulation................................ 89
D. Nuclear Regulatory Commission.................................. 94
Item 5. Procedure......................................................... 95
Item 6. Exhibits and Financial Statements................................. 95
A. Exhibits....................................................... 95
B. Financial Statements........................................... 97
Item 7. Information as to Environmental Effects........................... 98
Appendix I................................................................ 101
</TABLE>
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This document includes the original Form U-1 Application as filed with the
Commission on October 31, 1996 with additions and deletions based on the filings
made in Amendments 1 through 4 together with certain further changes included
herein.
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 have been obtained 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"), which has occurred. 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
<PAGE>
requests that the Commission's review of this Application/Declaration commence
and proceed as expeditiously as practicable.
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 15 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 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;
(vi) the retention by Ameren of the gas properties of UE and CIPS
and the continued operation of UE and CIPS as combination utilities;
(vii) 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;
(viii) the continuation of all outstanding intrasystem debt, equity
and guaranties; and
Ameren will file its Notification of Registration on Form U5A within 30
days, and its Registration Statement on Form U5B within 90 days, of the entry
by the Commission of its order in this matter.
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,
2
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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 had expected to transfer its
retail electric and gas distribution utility assets located in Illinois (the
"Transferred Utility Facilities") to CIPS./1/
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/1/ As noted in Item 4.C - Illinois, the Illinois Commerce Commission did not
approve the transfer of the Transferred Utility Facilities. ICC Order,
Finding 10(c) (Docket 95-0551, slip op. at 69). UE and CIPSCO have
determined that this decision by the ICC does not materially affect the
proposed merger and will proceed with the Transaction and do not expect to
contest this finding. The ownership of the UE Illinois properties is not
determinative of the extent to which such properties can be operated as
part of the single integrated electric utility system or the single
integrated gas utility system of Ameren. Accordingly any request for
authority or approval from the Commission relating to such transfer is
hereby withdrawn. Ameren reserves the right to seek any then required
approval from the Commission to a transfer of any UE utility property to
CIPS that may be considered in the future and which has received all
necessary state and federal approvals.
3
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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, 1997, UE provided retail electric service to approximately
1,079,000 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, 1997, UE had 6,025 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 (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)./2/
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/2/ 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)
(continued...)
4
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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, 1997, there
were 102,123,834 shares of UE Common Stock and 2,795,095 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, 1997, UE's operating revenues were
approximately $2.1 billion, as follows:
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/2/(...continued)
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
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<CAPTION>
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Electric $2.157 billion
Gas $99.1 million
Steam $508 thousand
</TABLE>
Total net assets of UE at June 30, 1997 were approximately $6.9 billion,
consisting of approximately $5.3 billion in electric utility property, plant
and equipment; $133 million in gas utility property, plant and equipment; and
$1.5 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, 1996 (which
incorporates certain portions of its Annual Report to Shareholders which is
incorporated herein by reference as Exhibit I-3.1), a copy of which is
incorporated by reference as Exhibit I-1.1 and its Quarterly Reports on Form 10-
Q for the quarters ended March 31, 1997 and June 30, 1997, which are
incorporated by reference as Exhibit I-5.2.
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, 1997, CIPS had
approximately 2,280 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 U-3A-2 dated February 28, 1997 a copy of which is
incorporated by reference as Exhibit I-4.1 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
6
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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, 1997, 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, 1997 were approximately $885.3 million, broken down as follows:
<TABLE>
<CAPTION>
<S> <C>
Electric $719 million
Gas $155 million
Other $ 11 million
</TABLE>
Consolidated net assets of CIPSCO at June 30, 1997 were approximately
$1.9 billion, consisting of $1.0 billion in electric utility plant, property
and equipment; $138 million in gas utility property, plant and equipment; and
$762 million in other assets.
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,
1996, which is incorporated by reference as Exhibit I-2.1; the Quarterly Reports
of CIPSCO and CIPS on Form 10-Q for the quarters ended March 31, 1997 and June
30, 1997, which are incorporated by reference as Exhibit I-6.2; and CIPS'
Statement on Form U-3A-2 for the year ended December 31, 1996, which is
incorporated by reference as Exhibit I-4.1.
7
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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.
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.)
8
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2. Description of Energy Sales, Facilities and Fuel
a. UE
i. General
For the 12 months ended June 30, 1997, 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........................... 41,800,200,499
(including amounts delivered in interchange)
Mcf of gas distributed at retail...................... 20,117,277
(including transportation of customer owned gas)
ii. Electric Generating Facilities
</TABLE>
UE's generating facilities as of June 30, 1997, all of which are 100% owned
by UE, were as follows:
9
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GENERATING CAPABILITY
Union Electric Company
<TABLE>
<CAPTION>
Net Capability-mW
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Station Name & Unit No. Unit Type Summer Winter Fuel Type
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Callaway Nuclear 1137 1164 Uranium
Fairgrounds Combustion Combustion
Turbine Turbine 55 63 Oil
Howard Bend Combustion Jet
Turbine Engine 43 47 Oil
Keokuk Hydro 125 124 Water
Kirksville Combustion Combustion
Turbine Turbine 13 15 Gas
Labadie 1 Steam 574 575 Coal
Labadie 2 Steam 574 575 Coal
Labadie 3 Steam 576 577 Coal
Labadie 4 Steam 576 577 Coal
Meramec 1 Steam 132 134 Coal/Gas
Meramec 2 Steam 132 134 Coal/Gas
Meramec 3 Steam 277 279 Coal/Gas
Meramec 4 Steam 336 344 Coal
Meramec Combustion Combustion
Turbine Turbine 55 63 Oil
Mexico Combustion Combustion
Turbine Turbine 55 63 Oil
Moberly Combustion Combustion
Turbine Turbine 55 63 Oil
Moreau Combustion Combustion
Turbine Turbine 55 63 Oil
Osage Hydro 212 205 Water
Rush Island 1 Steam 579 584 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 579 584 Coal
Sioux 1 Steam 476 483 Coal
Sioux 2 Steam 476 483 Coal
Taum Sauk Pumped Storage 350 275 Water
Venice Steam 429 440 Gas/Oil
Venice Combustion Turbine Combustion
Turbine 26 31 Oil
Viaduct Combustion Turbine Combustion
Turbine 26 31 Gas
----- -----
TOTAL 7,923 7,976
</TABLE>
As of June 30, 1997, UE had a total net generating capability of 7,923 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, 1997 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 plant. The boilers have a capability of
27,600 pounds of steam per hour under sustained load.
11
<PAGE>
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 listed below, 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 spring of 1998 and the fall of
1999.
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 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.
12
<PAGE>
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, 1997, CIPS sold the following amount of
electric energy (at retail or wholesale) and sold and transported the following
amount of gas at retail:
kWh of electric energy sold
(including amounts delivered in interchange) 13,955,089,000
Mcf of gas distributed at retail
(including transportation of customer owned gas) 26,312,200
ii. Electric Generating Facilities
CIPS's generating facilities as of June 30, 1997, all of which are 100%
owned by CIPS, were as follows:
13
<PAGE>
<TABLE>
<CAPTION>
GENERATING CAPABILITY
Central Illinois Public Service Company
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, 1997, 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+ more than 1 1.798
1994 99+ more than 1 1.750
1993 99+ more than 1 1.727
1992 99+ more than 1 1.787
1991 99+ more 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>
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, 1997 and provided less than 1/4 of 1% of UE's
revenues in 1995, 1996 and the 12 months ended June 30, 1997. At June 30, 1997,
UEDC had assets of $19,110,382.
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 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, 1997 and provided less than
2% of CIPSCO's consolidated operating revenues in each of 1995, 1996 and for
the twelve months ended June 30, 1997. At June 30, 1997, CIPSCO Investment had
assets of $120.9 million out of total consolidated assets of CIPSCO of
approximately $1.9 billion, and operating revenues (excluding intercompany
eliminations) of $11.3 million out of consolidated operating revenues of
approximately $885.3 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.
16
<PAGE>
CIPS is planning to build a new interconnection with Iowa Electric Services
("IES"), a unit of IES Industries, an investor owned utility holding company.
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.
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
17
<PAGE>
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.
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.
18
<PAGE>
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.
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.
19
<PAGE>
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 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
20
<PAGE>
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 l, 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 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
21
<PAGE>
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.
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
22
<PAGE>
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
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,
23
<PAGE>
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 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
24
<PAGE>
during the 10-year period following the Transaction./3/ 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/4/ will be
converted into the right to receive one share of Ameren Common Stock;
. each issued and outstanding share of CIPSCO Common Stock/5/ 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 canceled.
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, 1997, 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.
- ------------
/3/ The savings referred to herein are the most current estimates and reflect
further study and refinement from the estimates made at the time the
Mergers were approved by the UE and CIPSCO Boards of Directors.
/4/ Other than treasury and certain other shares which will be canceled, and
shares held by holders who dissent in compliance with Missouri law.
/5/ Other than treasury and certain other shares which will be canceled, but
including shares held by holders who dissent in compliance with Illinois
law.
25
<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 15 million shares of Ameren Common Stock under
Ameren's proposed dividend reinvestment plan and certain employee benefit plans
described below that will use Ameren Common Stock (collectively, the "Ameren
Plans").
26
<PAGE>
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 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
27
<PAGE>
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).
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).
Ameren will seek final approval with respect to the LTIP, including the
issuance of shares, in a subsequent filing to be made with the Commission.
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<PAGE>
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
Ameren anticipates it will solicit proxies from the holders of its Common
Stock to approve the adoption or amendment to the Ameren LTIP. 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 in a separate filing to be made in 1998.
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
Other legal fees and expenses....................... 3,825,000
Shareholder communication and proxy
solicitation...................................... 1,064,000
NYSE listing fee.................................... 200,000
</TABLE>
29
<PAGE>
<TABLE>
<S> <C>
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
(except for the LTIP); issuance of stock of
Ameren Services to Ameren; approval of all
outstanding intra-system debt, including
guaranties and support agreements.
9(a)(1), 10 Acquisitions of Ameren Common Stock in open-
market transactions under Ameren Plans (except
for the LTIP); 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.
</TABLE>
30
<PAGE>
<TABLE>
<CAPTION>
Transactions to which Section or
Sections of the Act Rule is or may be applicable
- ------------------- --------------------------------
<C> <S>
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(a)(3), 11(b), 21 Retention by Ameren of gas operations and retention or
acquisition of nonutility businesses of UE, UEDC, CIPS
and CIPSCO Investment.
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.
Transactions to which Section or
Rules Rule is or may be applicable
- ----- --------------------------------
42 Open market purchases of Ameren Common Stock pursuant
to Ameren Plans (except LTIP).
80-92 Reimbursements between and among Ameren, UE, CIPS and
CIPSCO Investment and other system companies under the
General Services Agreement.
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
</TABLE>
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
31
<PAGE>
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:
- 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,"/6/ 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
- --------------------
/6/ Letter of the Division of Investment Management to the Securities and
Exchange Commission, 1995 Report at xii-xiii.
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<PAGE>
applicable item below, the specific recommendations of the Division with regard
to financing transactions,/7/ utility ownership/8/ and diversification/9/ are
applicable to this Transaction.
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; such acquisition will tend towards interlocking relations or the
concentration of
(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.
- --------------------
/7/ E.g., the reduced regulatory burdens associated with routine financings.
1995 Report at 50.
/8/ 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.
/9/ 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.
33
<PAGE>
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./10/ 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 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, 1997: (1) the combined assets of UE and CIPSCO totaled
approximately $8.9 billion; (2) 12-month combined operating revenues totaled
approximately $3.1 billion; and (3) combined, owned net generating capacity
totaled 11,369 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)
- -------------------
/10/ 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.
34
<PAGE>
(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
$9 billion)./11/
As the following table demonstrates, six of the current registered electric
utility holding company systems--Southern, Entergy, CSW, Northeast, GPU and
AEP--will be larger than Ameren in terms of assets, operating revenues,
customers and/or sales of electricity:/12/
<TABLE>
<CAPTION>
Total Operating Electric Sales in
System Assets Revenues Customers kWh
Total ($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,
- --------------------------
/11/ These numbers are unadjusted for inflation. The AEP-Columbus number in
particular would be considerably higher in current dollars.
/12/ 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, 1997.
35
<PAGE>
and kWh sales of 49.056 billion. 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 completed acquisition of Public Service Company
of Colorado and Southwestern Public Service Company by New Century Energies,
Inc., resulted 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./13/
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
- --------------------------
/13/ 1995 Report at 73-74.
36
<PAGE>
operations are described in greater detail below and are projected to result in
savings of approximately $686 million over the first ten years alone.
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." CIPSCO and UE filed 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
37
<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./14/ 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.
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
- ----------------------
/14/ In connection with the Transaction, the holders of UE preferred stock and
CIPS preferred stock will not be affected.
38
<PAGE>
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).
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
39
<PAGE>
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./15/ 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 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.
- -----------------------
/15/ 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.
40
<PAGE>
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, 1997, the outstanding UE preferred
stock would have represented 2.66% of the total voting power of UE preferred
and common stock, 3.43% of the total capital of UE (including long-term and
short-term debt) and 6.27% 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, 5.88% of the total capital of CIPSCO (including long-
term and short-term debt) and 10.90% of the book equity comprising CIPSCO
common and CIPS preferred stock and retained earnings. For the twelve months
ended June 30, 1997, UE's combined fixed charges and preferred dividend
requirements were covered 4.08 times before provision for taxes and such
figure was 3.45 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
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
41
<PAGE>
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, 1997 and the pro forma consolidated capital structure
of Ameren (assuming the Transactions had occurred at June 30, 1997):
UE and CIPSCO Historical Capital Structures
(dollars in thousands)
(unaudited)
<TABLE>
<CAPTION>
CIPSCO
(consolidated)
<S> <C> <C>
Common stock equity $ 653,735 48.08%
Preferred stock of subsidiary 80,000 5.89%
Long-term debt of subsidiary 570,379 41.95%
Short-term debt (including current
maturity of long-term debt) of subsidiary 55,481 4.09%
---------- ------
Total $1,359,595 100.00%
UE
Common Stock Equity $2,321,176 51.35%
Preferred stock 155,197 3.43%
Long-term debt 1,943,186 42.99%
Short-term debt (including current
maturity of long-term debt) 100,734 2.23%
---------- ------
Total $4,520,293 100.00%
Ameren Pro Forma Consolidated Capital Structure
(dollars in thousands)
(unaudited)
Common stock equity $2,974,911 49.50%
Preferred stock of subsidiaries 235,197 3.91%
Long-term debt of subsidiaries 2,629,121 43.75%
</TABLE>
42
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C>
Short-term debt (including current
maturity of long term debt) of
subsidiaries 170,659 2.84%
---------- ------
Total $6,009,888 100.00%
</TABLE>
Ameren's pro forma consolidated common equity to total capitalization ratio of
[49.50%] is significantly higher than Northeast Utilities' approved 27.6% common
equity position and 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 provision of Section 8 or is
detrimental to the carrying out of the provisions of Section 11/16/;
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 ....
- ------------
/16/ 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.
43
<PAGE>
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 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.
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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."
(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
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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")./17/
In Item 3.A.2.b.ii.(B) of the Application, Ameren demonstrates that the gas
operations of UE and the gas operations of CIPS, together, constitute a "single
integrated public utility system." Because the existing separate gas systems of
UE and CIPS may be operated as a single integrated system, it may be appropriate
to analyze the loss of economies that would occur if the gas operations were to
be divested on the assumption that the gas operations of UE and CIPS are
combined as part of the divestiture into a single new and separate gas utility
company. In order to demonstrate the effects of such a divestiture of both the
UE and CIPS gas operations into a single separate entity, UE and CIPS have
prepared a Supplemental Analysis of the Economic Impact of a Divestiture of the
Gas Operations of UE and CIPS (the "Supplemental Study").
The Supplemental Study uses the same methodology as used in the original
Analysis of Economic Impact of Divestiture of the Gas Operations of UE and CIPS
dated September 19, 1996 and previously filed in this matter as Exhibit K-1 (the
"1996 Study"), except that it is assumed that one newly formed corporation would
assume all of the divested gas operations. As would be expected, the
Supplemental Study shows that total lost economies are less than shown by the
1996 Study because the "double" costs of two corporations are eliminated.
However, even assuming that only one new company were created, the lost
economies are significantly higher than in Commission precedents. See Exhibit K-
2 to the Application. Thus, the Supplemental Study supports, as does the 1996
Study, the conclusion that the test of Clause A of Section 11(b)(1) is met in
this case.
Here, the lost economies would be far greater than in Engineers if the gas
properties of UE and CIPS were to be operated as a combined new single entity 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
described more fully in the Supplemental Study (Exhibit K-1.1 hereto).
As set forth in the Supplemental Study, divestiture of the gas operations
of UE and CIPS into one stand-alone company would result in lost economies of
$34.8 million. (This compares to lost economies of $22.1 million for UE and
$36.3 million for CIPS, totaling $58.4 million, as found by
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/17/ The original U-1 Application filed October 31, 1996 (Item 3. A. 2. a. i.)
describes Ameren's position that, in light of current conditions, the Act
does not prohibit UE or CIPS from continuing to conduct their gas
operations as part of the single integrated public utility system to be
controlled by Ameren after the Transaction. In particular, part (A) of that
section demonstrates the significant level of lost economies that would
result if each of the UE gas operations and the CIPS gas operations were
separately operated--i.e., as two stand-alone companies. As pointed out
in such part, the lost economies would be significantly higher than in
other cases where the Commission held that the additional system could be
retained. As noted in the text above, in Amendment No. 1 Ameren presented
further information as to lost economies. Accordingly, the information as
originally filed is excluded in this part of the Amended and Restated U-1
and is set out in Appendix I hereto.
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the 1996 Study). These lost economies compare with 1995 pro forma combined gas
operating revenues of $217.4 million for UE and CIPS; pro forma combined gas
operating revenue deductions of $197.9 million; pro forma combined gas gross
income of $19.6; and pro forma combined gas net income of $13.8 million.
On a percentage basis, the lost economies amount to 252% of 1995 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./18/ As a percentage of 1995 pro forma
combined gas operating revenues, these lost economies described in the
Supplemental Study amount to 16%--losses 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./19/ As a percentage of 1995 pro
forma combined gas expenses or operating revenue deductions, the lost economies
described in the Supplemental Study would amount to 17.6%--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
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/18/ 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)). This percentage compares to the 425% of 1995 UE gas net
income and 424% of 1995 CIPS gas net income shown by the 1996 Study.
/19/ 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%. 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. The percentage shown by the
Supplemental Study compares to the 25% and 28% reduction, respectively, for
UE and CIPS shown by the 1996 Study.
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authorized the retention of gas operations./20/ As a percentage of 1995 pro
forma combined gas gross income, the lost economies described in the
Supplemental Study amount to 178%--far in excess of the highest loss of gross
income in any divestiture order. The applicable percentages in past cases are
summarized in Exhibit K-2 previously filed (Table of Estimated Losses of
Economies in Prior Decisions on Divestiture and Retention of Gas Operations).
In order to recover these lost economies, the single, new stand-alone
company divested from UE and CIPS would need to increase customer rates by about
23% ($50.4 million) in order to provide an 11.07% rate of return on rate base.
This rate of return was conservatively estimated using the weighted average
approximate costs for capital of UE and CIPS rather than the higher returns that
would likely be required by the financial community for a single, stand-alone
company.
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 of minus 4.78%--significantly more detrimental than the 2.01%
projected stand-alone rate of return in Unitil, where retention was authorized.
This return is significantly lower than the returns of other utilities in the
region and represents a decline from UE's and CIPS' indicated rates of return
for 1995.
The above data show that, even assuming the gas operations of CIPS and UE
were divested by forming one stand-alone company, the loss of economies would be
significant, in excess of that present in other cases where retention was
allowed and sufficient to support a finding that requirement of Clause A of
Section 11(b)(1) is met in this case. This conclusion is even more dramatically
demonstrated if it is assumed that each gas operation would be in a separate
stand-alone company as shown by the 1996 Study.
Additional support for the conclusion that retention of the gas operations
is supported by the Act is found in the Legal Memorandum on the Retention of Gas
Operations by Ameren Corporation (the "Gas Legal Memorandum") filed herewith as
Exhibit K-3.
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/20/ 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). The combined
total loss as a percentage of gas operating revenue deductions shown in the
1996 Study was 29.5%.
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(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.
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 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.
The Recent New Century Energies Decision
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On August 1, 1997, the Commission issued its decision in New Century
Energies, Inc., Release No. 35-26748 (Aug. 1, 1997) approving the acquisition by
New Century Energies of the electric and gas operations of Public Service
Company of Colorado and Southwestern Public Service Company in a transaction
which will result in New Century Energies becoming a registered holding company
under the Act. In this decision the Commission recognized that circumstances in
the utility industry have changed significantly since the decisions in the New
England Electric System cases finding that a gas utility operation could not be
retained under the A-B-C Clauses by a holding company whose principal system was
electric.
In New Century Energies, the Commission affirmed the traditional analysis
that increased costs attributable to separation of an additional system from the
principal integrated system may be considered as "lost economies" under Clause A
of Section 11(b)(1) of the Act. In an important change from prior decisions,
however, the Commission found that other benefits of separation assumed to exist
in previous cases, i.e., the benefits of increased competition resulting from
separation of gas and electric businesses, should no longer be considered
applicable. In addition to the lost economies resulting from increased costs of
operating the additional system independently, the Commission recognized in New
Century Energies that "separation of gas and electric businesses may cause the
separated entities to be weaker competitors than they would be together. This
factor adds to the quantifiable loss of economies caused by increased costs."
Release 35-26748 at 31 (slip op.) (emphasis added). Further, the Commission held
that "[i]ncreased expenses of separate operation may no longer be offset, as
they were in New England Electric System, by a gain of qualitative competitive
benefits, but rather may be compounded by a loss of such benefits, as the
Commission finds in this matter." Id. at 32.
The Commission found in New Century Energies that the lost economies, as a
percentage of total gas operating revenues, total gas expense, gross gas income
and net gas income presented in that case were within the range of similar
losses in cases where the Commission had permitted retention of the additional
gas system. As demonstrated by the Supplemental Analysis of the Economic Impact
of a Divestiture of the Gas Operations of UE and CIPS filed as Exhibit K-1.1,
the lost economies that would be incurred by a separation of the combined gas
operations of UE and CIPS into a separate entity would exceed the losses found
sufficient to allow retention in other Commission decisions. The finding of New
Century Energies that the effect on competition caused by separation of the gas
business would increase the lost economies (not decrease them as previously
assumed) is equally applicable to this case as has been pointed out in the
Application and exhibits filed thereto.
Accordingly, New Century Energies provides strong support for the conclusion
sought by Ameren in this docket, i.e., that the gas operations of CIPS and UE
may be retained as an additional integrated utility system under Clause A of
Section 11 (b)(1) of the Act.
(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
50
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interpretation of the Act, in light of recent changes both in national energy
policy and in the energy markets./21/
(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. 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:
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/21/ 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).
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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 (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./22/ 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
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/22/ 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).
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the monolithic holding companies be broken up./23/ 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./24/
(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 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).
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/23/ That goal has been long accomplished. 1995 Report at ix.
/24/ 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.
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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.
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
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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 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./25/
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.
- --------------------------
/25/ 1995 Report at 74, 75, 76. Footnotes omitted.
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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 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."/26/
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
- ------------
/26/ 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.
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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" 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
product 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./27/ Continued reliance on outdated premises which
- ------------
/27/ It appears that each of the four proposed mergers of predominantly gas
businesses with
(continued...)
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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 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./28/ 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:
- ------------
/27/ (...continued)
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.
/28/ 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.
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"[The Act] was substantially change 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 Committee. on
Commerce, Science and Transportation,) 103rd Cong. 2nd 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 provided 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. /29/
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. /30/ Federal legislation is being proposed which would required all
states to adopt a retail wheeling scheme by the year 2000./31/ Theses
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 note 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,
- ---------------------
/29/ As noted above, UE and CIPS filed their electric open-access transmission
tariffs in compliance with Order 888 on July 9, 1996
/30/ The Illinois General Assembly has appointed a special legislative committee
to develop a policy to introduce retail electric competition. 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 approved the Transaction calls for UE to proposed
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. Deregulation legislation was passed
by the Illinois General Assembly in the fall of 1997 and signed by the
Governor, December 16, 1997.
/31/ See, e.g., HR 3790 (104th Cong,; 2d Session).
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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
circumstances presented here.
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
company./32/
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./33/
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
- -------------------------
/32/ 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.
/33/ 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).
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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 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 16 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. 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. 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 combination operations
lead to harm to utility customers. UE and CIPSCO will notify the Commission when
the required approvals are received.
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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 1.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. Information about non-utility investments at June 30, 1997 is
included in Amendment Exhibit K-4.
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 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
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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.
Enviro Tech 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 Enviro Tech, which is empowered to approve
investments that fall outside of the types specifically approved by
Enviro Tech'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, 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
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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 credit 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./34/
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./35/ One officer of UE 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
- ------------------------------
/34/ 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 39 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 of consumers.
/35/ See note 34 above.
<PAGE>
investments or business.(36) At June 30, 1996, the total amount invested
through CIPSCO Investment and its subsidiaries $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 Learning 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
consideration 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.
Standard for retention: Section 11(b)(1) permits a registered holding
company to retain "such other business 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.(37) In addition,
the Commission has stated that "retainable nonutility interests
- -----------------
/36/ Certain of the marketplace securities described below as being held by
CIPSCO Securities are held directly by CIPSCO Investments.
/37/ See e.g., General Public Utilities Corp., 32 SEC 807, (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.
(continued...)
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<PAGE>
should occupy a clearly subordinate position to the integrated system
constituting the primary business of the registered holding company."/38/ 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 business 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 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 business. 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./39/
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")./40/
- ----------------
/37/(...continued)
1971); United Light and Railways Co., 35 SEC 516, 519 (Jan. 22, 1954).
-----------------------------
/38/ United Light and Railways Co., SEC at 519.
------------------------------------------
/39/ 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.
/40/ 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
(continued...)
66
<PAGE>
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./41/
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 Rule 58. Under 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. Rule 58 requires
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 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 then proposed Rule 58 safe harbor
for energy-related diversification, the Division suggested the adoption of a de
minimus "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
- ------------
/40/ (...continued)
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 56 to 62.
/41/ The required public interest findings are set out in note 57 below.
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<PAGE>
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./42/
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
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
- ------------
/42/ 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
then proposed Rule 58 and exceeded the de minimis amount.
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<PAGE>
"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 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 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 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./43/ For purposes of the Act, a QF constitutes a nonutility
- -----------------
/43/ 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
as a facility which produces
(continued...)
69
<PAGE>
investment if made by a registered holding company./44/ 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./45/ The 1986
legislation provided similar relief to registered electric holding
companies./46/ 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 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,
- -----------------
/43/(...continued)
(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.
/44/ 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.
/45/ Pub. L. No. 99-186, 99 Stat. 1180 (codified at 15 U.S.C. (S) 79k note
(1988)).
/46/ Pub. L. No. 99-553,100 Stat. 3087 (codified at 15 U.S.C. (S) 79k note
(1988)).
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<PAGE>
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 Rule 58. Thus, the production
and distribution of thermal energy is reasonably incidental to Ameren's
utility operations and may be retained.
The applicants in New Century Energies operated a number of non-utility
business and held non-utility investments. The Commission noted that such
business and investments were required to be necessary or appropriate in the
public interest or for the protection of investors or consumers and not
detrimental to the proper functioning of the integrated system under Section
11(b)(1) and 10(c)(1) of the Act. All the various non-utility interests (which
are described in Appendix A to the decision) were found to satisfy the statutory
requirements. Release 35-26748 at 38 (slip op.).
New Century Energies also found that the existing investments, as of the
date of the consummation of the merger in that case, should be disregarded for
purposes of calculating the dollar limitation upon investment in energy-related
companies under new Rule 58. Id. Ameren respectfully requests that the amount
invested, or approved by the Commission to be invested, in its approved
non-utility investments, as of the date of the Merger, also be disregarded for
purposes of Rule 58.
The Commission reached its conclusion regarding the retention of the non-
utility investments in New Century Energies in view of the fact that the merger
partners were not subject to the restrictions that Section 11(b)(1) and the
Commission's precedent thereunder places upon the non-utility investments of
registered system companies. Id. As noted in Item 1.b.1. of the Application, UE
and CIPSCO are each exempt public utility holding companies and, as such, are
not subject to the limitations of the Act applicable to registered holding
companies. The non-utility investments of UE and CIPSCO are well within the
general guidelines of what is appropriate for an exempt holding company under
the Act./47/
As noted in the Application and in particular Exhibit K-4, Ameren has
described in detail its existing non-utility investments/48/ and demonstrated
that such investments, except as noted below,
- ---------------
/47/ As noted in New Century Energies, the Commission has never determined the
limits upon diversification by exempt holding companies. Release 35-26748
at 39, n. 73 (slip op.).
/48/ The description of existing investments includes with respect to each
described investment or entity the dollar amount invested through the most
recent available date (generally June 30, 1997) plus, where applicable, the
amount currently committed for future investment in such investment or
(continued...)
71
<PAGE>
may be retained after consummation of the Transaction in accordance with the Act
and Commission precedent. Ameren also filed Amended Exhibit K-4 which contains
additional information concerning certain of the non-utility investments of
CIPSCO Investment. This exhibit provides additional detail regarding the
activities of the investments and notes applicable commission precedent as to
retainability.
Ameren has determined that the investment currently held by CIPSCO
Securities in five investment funds should be liquidated or otherwise disposed
of in an orderly fashion./49/ Ameren seeks approval of the Commission to
liquidate or dispose of such investments over a period not exceeding 3 years
from the date of the Commission's order in this Docket. Further, Ameren has
determined that the member interest which UEDC or CIPSCO Investment have in
certain limited liability companies may be a "voting security" within the
meaning of Section 2(a)(17) of the Act such that any such interest of 5% or more
would make the entity an "affiliate" as defined in Section 2(a)(11) of the Act.
See Public Service Company of Oklahoma, Release No. 35-26445 (Dec. 29, 1995);
compare In re Metropolitan Edison Co., Release No. 35-14973 (Dec 5, 1963) (9%
voting investment in economic development corporation). Unless otherwise
approved by the Commission, Ameren proposes to reduce, not later than 3 years
from the date of the Commission Order in this Docket, its voting percentage or
investment so that such limited liability companies will not constitute
affiliates of Ameren under the Act.
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 development of an integral public utility system, thereby serving
the public interest, as required by Section 10(c)(2) of the Act.
- ------------------------------
/48/(...continued)
entity. Ameren understands that future investments not so described in this
filing may only be made in accordance with applicable rules (such as Rules 40
and 58) or pursuant to application made to the Commission for specific approval.
Item 3.A.2.a(ii) is hereby amended by deleting in its entirety the last
grammatical paragraph thereof (pages 73-74 of the October 31, 1996 Application).
/49/ A description of such holdings is included in Amended Exhibit K-4.
Holdings to be liquidated include the Flaherty & Crumrine Preferred Stock
Portfolio, the Spectrum Preferred Stock Portfolio and the Gateway Index Risk
Adjusted Program. These three investments will be liquidated within the three
year period. As noted in Amended Exhibit 4, instructions to liquidate the
remaining two fund investments, Mesirow Alternative Strategies Fund and the
Genessee Eagle Fund, hsve already been given with the funds to be distributed
prior to the end of 1997. CIPSCO Securities may retain investments in debt
securities, commercial paper or other investments permitted by Rule 40. Cash
received on such description will be applied to the business of Ameren which may
include investments as described above or may be used by Ameren to pay dividends
on its common stock.
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<PAGE>
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 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./50/ 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:
<TABLE>
<CAPTION>
Amount
Category (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
- --------------------
/50/ See Note 3 herein.
73
<PAGE>
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.
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
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<PAGE>
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 Transactions, $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 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.
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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.
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, on one or more states, not so large as to
impair (considering the state of the art and the area of 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.
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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
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 to 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
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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 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 costs 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) Amerens 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 have been
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
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affiliates to permit exercise of this regulatory authority. A copy of the
Stipulation and Agreement is filed as Exhibit D-2.3.
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(B) Gas Utility System
Section 2(a)(29)(B) defines an "integrated public utility system" as
applied to gas utility companies:
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
realties 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, /51/ 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. /52/ The
Commission also has considered obtaining gas from a common pipeline /53/ as well
as from different pipelines when the gas originates from the same gas field in
determining a common source of supply. /54/ Since the time of
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/51/ See MCN Corp., Release No. 35-26576 (Sept. 17, 1996) (physically separate
systems served from same fields; anticipated coordinated gas purchasing
operations); 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").
/52/ 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).
/53/ In re North American Co., 31 SEC 463 (May 19, 1950) (finding Panhandle
Eastern pipeline to be a common source of supply).
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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,
combining the gas operations of UE and CIPS will allow the companies to
functionally perform as a coordinated system through:
(i) 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;
(ii) centralized headquarters staff management combined with local,
autonomous operational control consistent with modern business practices;
(iii) elimination of certain duplicate functions and standardization and
coordination of appropriate parts of the overall gas operations.
This functional coordination will also result in greater, not lesser, efficiency
as described below.
Most of CIPS' gas systems are currently integrated by way of physical
interconnects and contractual arrangements. This part of CIPS' overall system
comprises in 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.
Ameren expects to be able to integrate through contractual arrangements the UE's
gas systems which are served from the same pipelines that serve the combined
part of CIPS' system with CIPS' integrated system for joint dispatch. Upon
consummation of the Transaction, the companies will seek to negotiate capacity
contracts on the pipelines that serve the integrated systems which will allow
deliveries to any point on the combined gas systems. The companies may also 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
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/54/ 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").
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of where on the combined systems the gas is needed. Further, key gas flows and
pressures of both UE and CIPS will be monitored and controlled by a single gas
dispatch center to be located in Springfield, Illinois. The center will also be
responsible for forecasting total system demand for both companies and
scheduling gas deliveries to meet the projected demand. Anticipated savings or
synergies from this functional coordinated operation of the combined gas systems
are detailed below.
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-common storage providers (Eastex, Western
Gas Resources Storage Inc., MRTC and TRKL) and (iv) each procure natural gas
supplies from producers in common supply area; 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.
Management of the headquarters staff will be centralized and coordinated
for both companies. Such overall matters as billing, finance, budgeting, human
relations and other such functions relating to gas operations will be
coordinated similarly to electric operations. Consistent with modern business
practice, matters relating to local operations will be determined by operations
personnel in the field. Local operations are to be directed from current company
headquarters in Springfield and St. Louis.
Beyond such gas supply related matters and management coordination, other
elements of the UE and CIPS gas operations will be combined into a single
coordinated system. Wherever possible, the companies plan to adopt a common set
of engineering practices, operating procedures and materials specifications.
Materials purchasing and inventory practices will be standardized and
coordinated. As a result, significant savings and economies in material
procurement costs are expected as well as a reduction in the cost of maintaining
separate standards and procedures. Plans are being developed to combine all
training facilities for gas employees of both companies, consolidating training
staff and curriculum. Further, it is anticipated that gas meter testing and
repair operations will be combined to gain the economies associated with
operating a single, larger facility rather than the individual facilities
currently operated by UE and CIPS. Other areas for centralized coordination will
be explored as management gains experience with overall coordinated operations.
The Commission has recognized that these types of practices resulting in
economies and efficiencies can support findings of integration under the Act.
New Century Energies, Inc., Release No. 35-26748 (Aug. 1, 1997). See TUC Holding
Co., Release No. 35-26749 (Aug. 1, 1997).
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Finally, the combined gas 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. As noted above, the previously anticipated transfer of
the UE Illinois properties to CIPS will not occur. Ownership by UE of the
Illinois properties will not affect the anticipated coordination of operations
outlined above.
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.
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
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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 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 15
million shares of Ameren Common Stock pursuant to such existing and amended or
replacement Ameren Plans (other than the LTIP).
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).
The requirements of Section 13 are discussed under Item 3.C. below.
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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 Investments, to the extent available,
to finance their own activities or to finance the activities of entities in
which they have an 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
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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 have developed the system and procedures necessary to implement
the General Services Agreement./55/ 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
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/55/ UE and CIPS have developed the systems and procedures necessary to
implement the General Services Agreement. The Ameren Services Company
Policies and Procedures, dated October 8, 1997 (the "Procedures") are filed
herewith as Exhibit B-5. The General Services Agreement will be
administered in accordance with the Act and the Commission's regulations
thereunder. Ameren Services has established a work order system, which
utilizes work orders (referred to as "Service Requests"), for the purpose
of accumulating and charging costs to Ameren or the appropriate operating
company and/or affiliates as more fully set forth in the Procedures. The
use of Service Requests will allow Ameren Services to supply accounting
records and information to Ameren or the operating companies and affiliates
in enough detail to allow them to record and report their costs in
accordance with the FERC Uniform System of Accounts and/or Commission rules
and regulations.
Under the Procedures, the Service Request system will consist of work
orders established to capture the various types of costs incurred by Ameren
Services. The service requests will specify, in general terms, the services
that department will perform for Ameren Services, the operating companies
and affiliates. Costs incurred by the various Ameren Services departments
will then be charged to these various Service Requests which ultimately
will become the basis for the billing of costs to Ameren Services, the
operating companies and affiliates.
Ameren Services costs will be classified into either direct or indirect
categories. Direct costs are defined to be those that can be identified as
being applicable to services performed for a single Ameren affiliated
company or group of Ameren affiliated companies. Costs applicable to Ameren
or a single Ameren affiliated company will be directly charged to that
company. Costs applicable to two or more Ameren affiliated companies will
be distributed among and charged to such companies. Direct cost allocation
factors will be assigned by function based on the nature and variety of the
service being performed and are listed in Exhibit I to the Procedures.
Ameren Services has established allocation factors that most effectively
relate to the types of service being rendered to Ameren, the operating
companies and/or affiliates.
Indirect costs include those costs of a general overhead nature such as
general services, housekeeping costs and other support costs which cannot
be separately identified to a single Ameren affiliated company or group of
Ameren affiliated companies. Indirect costs will be charged and allocated
as described in the Procedures.
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Service Companies and Subsidiary Service 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 on 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 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.
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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 submitted Notification
and Report Forms and all required information to the DOJ and FTC. The 30-day
waiting period under the HSR Act has expired without adverse action or receipt
of any comments, 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
(May 18, 1997), 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
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
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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 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 set 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 requirement 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. FERC ordered the presiding
administrative law judge to issue an initial decision no later that 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 on 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.
The FERC Order, filed herewith as Exhibit D-1.3, approves the proposed
merger and accepts UE's and CIPS' proposed ratepayer protection mechanisms. FERC
found that the ratepayer protections offered by UE and CIPS are adequate to
prevent ratepayer harm. The merger was approved without additional conditions.
The FERC Order reviews in detail market power issues in both generation markets
and transmission markets. The FERC found that competition in all such markets
would not be harmed by the merger. A petition for rehearing has been filed by
Central Illinois Light Company seeking modifications to a power service
contract it has with CIPS. The filing of this pleading does not affect the
finality of the FERC Order and the FERC Order grants the parties full authority
under applicable law to consummate the Transaction.
C. State Public Utility Regulation
Missouri. 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-23. A copy of the petition portion
of the Missouri filing is submitted with this Application/duplicative as Exhibit
D-21. The exhibits and testimony supporting the Missouri petition are largely
duplicative
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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-23.
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 submitted testimony demonstrating, as it
has at FERC, that the Transaction does not raise market power concerns.
The Exhibits filed herewith include Exhibit D-2.2, the Report and Order of
the Missouri Public Service Commission (MPSC) dated February 21, 1997 (the
"Final Missouri Order"), approving the merger between Union Electric Company
(UE) and Certain Illinois Public Service Company (CIPSCO) and the pleading filed
by UE accepting conditions contained therein. In the Final Missouri Order, the
MPSC adopted and approved the terms of the Stipulation entered into by the
parties. (See Exhibit D-2.3) The MPSC also imposed two other conditions beyond
those reflected in the Stipulation. First, Ameren must agree to file or join in
the filing of regional independent system operator ("ISO") proposal at the FERC
no later than December 31, 1997, or, if not, by March 31, 1998, Ameren must
develop and file with the MPSC a plan for establishing an independent entity
charged with the operation, pricing and planning of its transmission system.
Second, UE must file with the MPSC by January 1, 1998, a report assessing the
potential ability of the merged companies to exercise market power in the price
of deregulated retail generation. UE has consented to these two conditions. The
Final Missouri Order became effective March 4, 1997.
Reply to Comments of the Missouri Public Service Commission.
Ameren has no objection to the late-filed comments being received and
considered by the Commission. However, Ameren does not believe that any reason
exists to grant the requested relief as the issues raised were the subject of
negotiation and were fully addressed in agreements accepted by the MPSC when it
approved the merger on February 21, 1997.
In negotiations during the pre-approval process, the MPSC Staff expressed
the desire to retain the ability of the MPSC to continue regulatory oversight of
UE and Ameren. The MPSC Staff proposed that contracts contain similar language
to that which has been suggested in its comments. For a variety of reasons,
including that placing the language in contracts would have been an
administration hardship and may have unnecessarily created uncertainties
regarding the enforceability of contracts, the proposal ultimately was dropped
and other means were adopted to provide the assurances the MPSC Staff sought.
Thus, the Stipulation (previously filed as Exhibit D-2.3 hereto) signed by UE
and approved by the MPSC contains numerous provisions specifically designed to
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preserve the MPSC's ability to examine books and records of the merged companies
and to engage in ratemaking determinations. For example, the Stipulation states,
in part as follows:
8. State Jurisdictional Issues
a. Access to Books, Records, and Personnel. UE and its prospective
holding company, Ameren, agree to make available to the [MPSC], at
reasonable times and places, all books and records and employees and
officers of Ameren, UE and any affiliate or subsidiary of Ameren as
provided under applicable law and [MPSC] rules; provided, that Ameren,
UE and any affiliate or subsidiary of Ameren shall have the right to
object to such production of records or personnel on any basis under
applicable law and [MPSC] rules excluding any objection that such
records and personnel are not subject to [MPSC] jurisdiction by
operation of the Public Utility Holding Company Act of 1935. . . .
****
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 [MPSC] 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 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.
(Stipulation, Exhibit D-2.3, pp. 22-24) (emphasis supplied).
In addition, the Stipulation contains a contingent jurisdictional
stipulation providing for pre-approval of contracts by the MPSC in the event
that anyone raises objection to MPSC action on the basis of SEC preemption.
(Stipulation, Attachment D)(U-1 Exhibit D-2.3). Thus, Ameren and UE have clearly
demonstrated that they did not act to deprive the MPSC of jurisdiction in
structuring the transaction so that Ameren would become a registered holding
company. Furthermore, there are agreements in place which are more than adequate
to govern relationships between the parties. Including the conditions proposed
by the MPSC would not add to that protection already in place, but has the
potential to create administrative hardship and uncertainty for Applicants post-
merger.
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For these reasons Applicants respectfully request that the Commission
decline to include in its Order conditions suggested by the MPSC unit's
comments.
Illinois UE, CIPSCO and CIPS 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./56/ 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./57/ Section 7-204 of the Illinois PUA also
provides that 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."
- ------------
/56/ 220 ILCS 5/7-204 and 7-204A.
/57/ 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;
(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.
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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;/58/ (2) prohibit a utility from lending money to, and guaranteeing the
obligations of, the holding company or its nonutility subsidiaries;/59/ (3)
exercise controls against the cross-subsidization of nonutility businesses by
utility subsidiaries;/60/ and (4) regulate and prohibit certain transactions
between utility and nonutility subsidiaries./61/ 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./62/
The Commission has reviewed the powers of the ICC relating to holding
companies in CIPSCO Inc., 47 SEC Docket 174 (Sept. 18, 1990).
On September 10, 1997, the ICC issued the ICC Order approving under the
Illinois Public Utilities Act certain of the transactions related to the
Mergers. See Exhibit D-3.2. The ICC found, inter alia, that the proposed merger
and reorganization satisfied the requirements of Section 7-204 of the Illinois
Public Utility Act and should be approved./63/
The approval of the ICC is subject to the following conditions found to be
necessary to protect the public interest:
(1) The proposed merger cost recovery and sharing savings plan shall
not be approved;
(2) CIPS and UE must file a rate case or alternative regulatory plan
within six months after the closing of the merger; CIPS and UE must
provide the information listed in Part 285 when they file their rate
cases or alternative regulatory plans; the ratemaking treatment of
merger-related costs and savings to be adopted in the rate case or
alternative regulatory plan proceeding should reflect an appropriate
sharing of net merger savings between Ameren and the ratepayers of
CIPS and UE;
- ----------
/58/ 220 ILCS 5/7-103.
/59/ 220 ILCS 5/7-102(f) and (h).
/60/ 220 ILCS 5/7-204(b).
/61/ 220 ILCS 5/7-101, 7-102, 7-204 and 7-204A(b).
/62/ 220 ILCS 5/9-230.
/63/ See Item 4.C of the Application for a discussion of the jurisdiction of
the ICC. Footnote 51 of the Application filed October 31, 1996 sets forth the
requirements of Section 7-204.
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(3) The proposed transfer of UE's existing Illinois electric and gas
service area and certain related facilities to CIPS shall not be
approved;
(4) UE and CIPS must abide by the jurisdictional conditions set forth
in the Appendix to the ICC Order; and
(5) ICC Staff must be provided access to all the books and records of
CIPS, UE and their affiliates, subject to CIPS, UE or Ameren's
reservation of the right to object to the production of documents on
any basis under applicable law and Commission rules.
ICC Order, Finding 10 (Docket 95-0551, slip op. at 69-70).
The ICC Order approved the revised General Services Agreement, in the form
filed in that matter, as reasonable and in the public interest. ICC Order,
Finding 13 (Docket 95-0551, slip op. at 70). The Joint Dispatch Agreement, which
governs costs and revenues related to the central dispatch of the combined CIPS
and UE generating sources was also approved. ICC Order, Finding 15 (Docket 95-
0551, slip op. at 70). Further, the ICC found, based on extensive evidence in
the record, that the proposed merger and reorganization are unlikely to have a
significant adverse impact on the competitiveness of existing and future
Illinois retail markets and that it was unnecessary to impose conditions on the
merger to address any market power concerns. ICC Order, Finding 18 (Docket 95-
0551, slip op. at 70).
QST Energy Trading Inc. ("QST") an affiliate of CILCORP Inc. has filed an
appeal of the ICC Order with the Illinois Appellate Court. The filing of this
pleading does not affect the finality of the ICC Order and the ICC Order grants
the parties full authority under Illinois law to consummate and Transaction. A
previously filed action against the ICC in the Circuit Court, Tenth Judicial
Circuit, Tazewell County, Illinois (Case No. 97-CH-62) by QST has been dismissed
with prejudice.
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 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.
The NRC Order, filed herewith as Exhibit D-4.2, concludes that the merger
will not affect of the qualifications of UE as holder of the license for the
Callaway Plant, and that the transfer of control of the license, to the extent
effected by the consummation of the merger agreement between UE and CIPSCO, is
otherwise consistent with the applicable provisions of law, regulations and
orders issued by the NRC. The NRC Order is conditioned upon UE making certain
future filings with the NRC and the consummation of the Transaction prior to
September 30, 1998. Also filed with the NRC Order in Exhibit D-4 is a Post
Operating License Antitrust Review Finding of No Significant Changes and a
Safety Evaluation.
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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
Amended
B-4 Form of General Services Agreement
Second
Amended
B-4 General Services Agreement (filed herewith)
B-5 Description of Ameren Services' accounting and cost allocation
methods and procedures
Amended
B-5 Description of Ameren Services' accounting and cost allocation
methods and procedures (filed herewith)
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 Registration Statement on Form S-3 (DRIP)
C-4 Ameren LTIP Form S-8
C-5 Description of existing savings plans
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 October 15, 1997
D-2.1 Application of UE and Ameren before the MPSC
D-2.2 Final MPSC Report and Order dated February 21, 1997
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 September 10, 1997
D-4.1 Application of UE before the NRC
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<TABLE>
<CAPTION>
<C> <S>
D-4.2 Order of the NRC dated October 16, 1997
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
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)
F-2.2 Final "Past Tense" Opinion of Counsel (Jones, Day, Reavis & Pogue) (To be
filed by Amendment)
G-1 Financial Data Schedule
G-1.1 Financial Data Schedule (March 1997)
G-1.2 Financial Data Schedule (June 1997)
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-1.1 Annual Report of UE on Form 10-K for the year ended December 31, 1996
I-2 Annual Report of CIPSCO and CIPS on Form 10-K for the year ended
December 31, 1995
I-2.1 Annual Report of CIPSCO and CIPS on Form 10-K for the year ended
December 31, 1996
I-3 UE 1995 Annual Report to Shareholders
I-3.1 Portions of UE 1996 Annual Report to Shareholders (Exhibit 13 to UE 1996
Form 10-K)
I-4 Statement of CIPS on Form U-3A-2 dated February 28, 1996
I-4.1 Statement of CIPS on Form U-3A-2 dated February 28, 1997
I-5 UE Quarterly Reports on Form 10-Q for the quarters ended March 31, 1996
and June 30, 1996
I-5.1 UE Quarterly Report on Form 10-Q for the quarter ended March 31, 1997
I-5.2 UE Quarterly Report on Form 10-Q for the quarter ended June 30, 1997
I-6 CIPSCO and CIPS Quarterly Reports on Form 10-Q for the quarters ended
March 31, 1996 and June 30, 1996
I-6.1 CIPSCO and CIPS Quarterly Report on Form 10-Q for the quarter ended
March 31, 1997
I-6.2 CIPSCO and CIPS Quarterly Report on Form 10-Q for the quarter ended
June 30, 1997
J-1 Proposed Form of Notice
K-1 Gas Study
K-1.1 Supplemental Analysis of the Economic Impact of a Divestiture of the Gas
Operations of UE and CIPS (the "Supplemental Study")
</TABLE>
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K-2 Table of Estimated Losses of Economies in Prior Decisions on
Divestiture and Retention of Gas Operations
K-2.1 Updated Table of Estimated Lost Economies
K-3 Legal Memorandum Regarding Standards for Retention of Gas
Properties
K-4 Descriptions of Non-Utility Investments
Amended
K-4 Description of Non-Utility Investments
Second
Amended
K-4 Description of Non-Utility Investments (filed herewith)
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-1.1 Ameren Unaudited Pro Forma Combined Condensed Consolidated
Balance Sheets as of March 31, 1997 (see Quarterly Report of UE
on Form 10-Q for the quarter ended March 31, 1997 (Exhibit I-5.1
hereto), at p.11)
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-2.1 Ameren Unaudited Pro Forma Combined Condensed Consolidated
Statements of Income for the years ended December 31, 1996, 1995
and 1994 (see Annual Report of UE on Form 10-K for the year ended
December 31, 1996 (Exhibit I-1.1 hereto, at pp. 17-19)
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-3.1 CIPSCO Consolidated Balance Sheets as of March 31, 1997 (see
Quarterly Report of CIPSCO on Form 10-Q for the quarter ended
March 31, 1997 (Exhibit I-6.1 hereto), at p.5)
FS-3.2 CIPSCO Consolidated Balance Sheets as of June 30, 1997 (see
Quarterly Report of CIPSCO on Form 10-Q for the quarter ended
June 30, 1997 (Exhibit I-6.2 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)
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FS-4.1 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, 1996 (Exhibit I-2.1 hereto), at p. 40)
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-5.1 CIPS Balance Sheets as of March 31, 1997 (see Quarterly Report
of CIPS on Form 10-Q for the quarter ended March 31, 1997
(Exhibit I-6.1 hereto), at p. 8)
FS-5.2 CIPS Balance Sheets as of June 30, 1997 (see Quarterly Report
of CIPS on Form 10-Q for the quarter ended June 30, 1997
(Exhibit I-6.2 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-6.1 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, 1996 (Exhibit I-2.1 hereto), at p. 66)
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-7.1 UE Consolidated Balance Sheet as of March 31, 1997 (see
Quarterly Report of UE on Form 10-Q for the quarter ended March
31, 1997 (Exhibit I-5.1 hereto), at p. 2)
FS-7.2 UE Consolidated Balance Sheet as of June 30, 1997 (see
Quarterly Report of UE on form 10-Q for the quarter ended June
30, 1997 (Exhibit I-5.2 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)
FS-8.1 UE Statement of Income for its last three fiscal years (see UE
Annual Report to Shareholders for the year ended December 31,
1996 (Exhibit I-3.1 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
98
<PAGE>
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.
99
<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: December 29, 1997
AMEREN CORPORATION
/s/ William E. Jaudes
-----------------------------
By: William E. Jaudes
Secretary
<PAGE>
APPENDIX I
See Note 17 to this Amended and Restated Form U-1 regarding revisions made
to the original U-1 by Amendment No. 1. The following language is from the
original filing:
(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 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
101
<PAGE>
order./1/ 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./2/ As a percentage of 1995 gas expenses or operating
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./3/
- ---------------------------
/1/ 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)).
/2/ 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%. 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.
/3/ 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
(continued...)
102
<PAGE>
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 CIP'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.
- --------------------
3(...continued)
New England Electric System, 41 SEC 888, 905 App. (1954) (attributing
expense ratio of 8.01% to North American).
Exhibit Index
to Amendment No. 5
<TABLE>
<CAPTION>
A. Exhibits
Form of
Exhibit No. Description Transmission
----------- ----------- ------------
<S> <C> <C>
Second
Amended Electronic
B-4 General Services Agreement
Amended Description of Ameren Services' accounting and cost Electronic
B-5 allocation methods and procedures
Second
Amended
K-4
</TABLE>
103
<PAGE>
Second Amended
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 _________ 1998, 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. A revised Schedule I will be provided on an annual basis.
-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 60 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>
Schedule 1
Page 1 of 9
December 18, 1997
DESCRIPTION OF EXPECTED SERVICES
TO BE PROVIDED BY AMEREN SERVICES AND
EXPECTED DIRECT COST ALLOCATION FACTORS
Description of Expected Services to be Provided
A description of the expected services to be provided by Ameren Services is
detailed below. Identifiable costs for all of the functional organizations
listed below will be directly charged to Ameren Corporation and its
subsidiaries, whenever possible.
For costs that cannot be directly assigned or distributed, the expected direct
cost allocation factors are reflected below for each Ameren Services department.
a) Building Service
Description - Provide facility management services for owned and leased
facilities, excluding power plants. To the extent that leasing arrangements
are established between Ameren Services and/or Ameren Corporation and its
subsidiaries, lease costs will include rent for space occupied and
applicable services, such as operation and maintenance of structures,
capital improvements, interior space planning, security and janitorial. As
appropriate, lease costs will be allocated based on square feet occupied
and the allocation factors listed below.
Expected Allocation Factors - 1) number of employees; 2) operations and
maintenance labor; 3) total capitalization; and 4) total assets.
b) Controller's
Description - Perform all accounting services necessary to properly
maintain and report on the books and records of Ameren and its
subsidiaries. Provide investor relations services.
Expected Allocation Factors- 1) composite*; 2) total capitalization; and 3)
total assets
c) Corporate Communications
Description - Develop strategies for advertising and marketing efforts,
develop employee communication programs, coordinate community relations
efforts and develop policies and procedures for media relations.
<PAGE>
Schedule 1
Page 2 of 9
December 18, 1997
Expected Allocation Factors - 1) composite*; 2) total capitalization; and
3) total assets
d) Corporate Planning
Description - Provide rate engineering, interchange marketing, resource
planning and business analysis services.
Expected Allocation Factors - 1) composite*; 2) kwh sales; 3) peak load
[electric]; 4) total capitalization; and 5) total assets
e) Customer Services/Division Support
Description - Answer customer inquiries pertaining to 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.
Expected Allocation Factors - 1) number of customers; 2) number of
employees; and 3) operations and maintenance labor
f) Economic Development
Description - Provide community and business development services, as well
as natural gas development services. Analyze community and business
development opportunities.
Expected Allocation Factors - 1) number of customers; 2) sales [kwh and
dekatherm]; 3) total capitalization; and 4) total assets
g) Energy Supply
Coordinate the use of the generating, transmission and interconnection
facilities to provide economical and reliable energy.
Expected Allocation Factors - 1) kwh sales
<PAGE>
Schedule 1
Page 3 of 9
December 18, 1997
h) Engineering and Construction
Description - Provide professional services related to engineering studies,
design, procurement, planning, building and management of projects. Study
technology that may reduce costs of producing, delivering and using
electricity.
Expected Allocation Factors - 1) peak load [electric]; 2) generating
capacity; and 3) construction expenditures
i) Environmental Services & Safety
Description - Perform analysis and advocacy of regulatory 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.
Expected Allocation Factors - 1) number of employees; 2) generating
capacity; 3) operations and maintenance labor; and 4) construction
expenditures
j) Executive
Description - Provide executive management duties for all applicable
activities at the department, function and officer levels
Expected Allocation Factors - 1) total capitalization; 2) total assets; and
3) sales [kwh and dekatherm]
k) Fossil Fuel Procurement
Description - Provide resources necessary to procure fuel for the fossil
power plants and minimize production costs.
Expected Allocation Factors - 1) kwh sales
l) Gas Supply
Description - 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.
<PAGE>
Schedule 1
Page 4 of 9
December 18, 1997
Expected Allocation Factors - 1) dekatherm sales; 2) gas throughput
[includes transportation]; and 3) peak load [gas]
m) General Counsel
Description - Provide general legal advice related to all applicable
activities and legal services in regards to legislative activities,
regulatory agencies and security matters. Make regulatory filings, maintain
minutes of the board of directors, conduct stockholder meetings and procure
property and casualty insurance bonds.
Expected Allocation Factors - 1) composite*; 2) total capitalization; and
3) total assets
n) Human Resources
Description - 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.
Expected Allocation Factors - 1) number of employees; 2) total
capitalization; 3) total assets; and 4) operation and maintenance labor
o) Industrial Relations
Description - Negotiate, represent and administer provisions of labor
agreements applicable to unions representing union employees.
Expected Allocation Factors - 1) number of employees; and 2) operation and
maintenance labor
p) Information Services
Description - 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.
Expected Allocation Factors - 1) composite*; 2) number of customers; 3)
number of employees; 4) CPU cycles; and 5) operation and maintenance labor
<PAGE>
Schedule 1
Page 5 of 9
December 18, 1997
q) Internal Audit
Description - Audit company operations, perform operational and
productivity reviews, review justifications for capital projects and
perform quality assurance reviews.
Expected Allocation Factors -1) composite*; 2) number of customers; 3)
number of employees; and 4) operation and maintenance labor
r) Marketing
Description - Provide marketing services including account management,
program development, market research and customer energy services.
Expected Allocation Factors - 1) sales [kwh and dekatherm]; and 2) total
assets
s) Merger Coordination
Description - Monitor programs to achieve savings, merger costs and
position reductions as they relate to the implementation plans.
Expected Allocation Factors - 1) composite*; 2) total capitalization; and
3) total assets
t) Motor Transportation
Description - Provide engineering, support, and mechanical servicing of
vehicles, procurement of vehicles and safety and training programs.
Expected Allocation Factors - 1) number of vehicles
u) Purchasing
Description - Provide procurement of goods and services other than fuel.
Provide materials inventory management services.
Expected Allocation Factors - 1) composite*; 2) total assets; and 3)
construction expenditures
<PAGE>
Schedule 1
Page 6 of 9
December 18, 1997
v) Real Estate
Description - 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.
Expected Allocation Factors - 1) composite*; 2) number of customers; and 3)
total assets
w) Stores
Description - Provide clerical, stenographic, administrative and Electronic
Data systems support. Provide engineering support and manage and direct
stores operations.
Expected Allocations Factors - 1) composite*
x) Tax
Description - 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.
Expected Allocation Factors - 1) composite*; 2) current tax expense; 3)
total capitalization; and 4) total assets
y) Treasurer's
Description - Provide treasury operation, mailing, financial planning,
investments, and executive payroll and pension disbursement services.
Expected Allocation Factors - 1) composite*; 2) number of customers; 3)
number of employees; 4) total capitalization; and 5) total assets
*Composite consists of the following three factors (equal weight to each
factor):
Sales (kwh and dekatherm)
Number of customers
Number of employees
<PAGE>
Schedule 1
Page 7 of 9
December 18, 1997
ALLOCATION FACTORS
The following allocation factors will be utilized as outlined above.
Number of Customers - Based on the number of customers (electric and/or gas) at
the end of the most recent calendar year. The numerator of which is for an
Operating Company and the denominator of which is for all Operating Companies.
This ratio will be determined annually, and/or at such time as may be required
due to a significant change in circumstances.
Sales - Based on the sales volume (kwh and/or dekatherms) for the most recent
calendar year. The numerator of which is for an Operating Company and the
denominator of which is for all Operating Companies. This ratio will be
determined annually, and/or at such time as may be required due to a significant
change in circumstances.
Number of Employees - Based on the number of employees (contract and/or
non-contract, or electric operating and/or gas operating) at the end of the most
recent calendar year. The numerator of which is for an Operating Company or an
affected affiliate company. The denominator of which is for all Operating
Companies and affected affiliate companies. This ratio will be determined
annually, and/or at such time as may be required due to a significant change in
circumstances.
Composite - Based on an equal weighting Sales (kwh & dekatherm), Number of
Customers (total), and Number of Employees (total) allocation factors. The
numerator of which is the simple average of the above three factors for an
Operating Company and the denominator of which is for all Operating Companies.
This ratio will be determined annually and/or at such time as may be required
due to a significant change in circumstances.
Operations & Maintenance Labor - Based on the Operations & Maintenance Labor
(electric and/or gas) for the most recent calendar year. The numerator of which
is for an Operating Company or an affected affiliate and the denominator of
which is for all Operating Companies and affected affiliate companies. This
ratio will be determined annually, and/or at such time as may be required due to
a significant change in circumstances.
Revenues - Based on revenues (electric and/or gas) for the most recent calendar
year. The numerator of which is for an Operating Company or an affected
affiliate company. The denominator of which is for all Operating Companies and/
or affected affiliate companies. This ratio will be determined annually, or at
such time as may be required due to a significant change in circumstances.
<PAGE>
Schedule 1
Page 8 of 9
December 18, 1997
Total Capitalization - Based on total capitalization (total common stockholder's
equity, preferred stock, and long term debt) at the end of the most recent
calendar year. The numerator of which is for an Operating Company or an affected
affiliate company. The denominator of which is for all Operating Companies and
affected affiliate companies. This ratio will be determined annually and/or at
such time as may be required due to a significant change in circumstances.
Total Assets - Based on total assets at the end of the most recent calendar
year. The numerator of which is for an Operating Company or an affected
affiliate company. The denominator of which is for all Operating Companies and
affected affiliate companies. This ratio will be determined annually, and/or at
such time as may be required due to a significant change in circumstances.
Construction Expenditures - Based on construction expenditures for the most
recent calendar year. The numerator of which is for an Operating Company or an
affected affiliate company. The denominator of which is for all Operating
Companies and affected affiliate companies. This ratio will be determined
annually, and/or at such time as may be required due to a significant change in
circumstances.
Peak Load (electric) - Based on the highest monthly maximum megawatt load
(60-minute integration) for the most recent calendar year. The numerator of
which is for an Operating Company and the denominator of which is for all
Operating Companies. This ratio will be determined annually, and/or at such time
as may be required due to a significant change in circumstances.
Peak Load (gas) - Based on the highest daily send out in therms (excluding
transportation) for the most recent calendar year. The numerator of which is for
an Operating Company and the denominator of which is for all Operating
Companies. This ratio will be determined annually, and/or at such time as may be
required due to a significant change in circumstances.
Generating Capacity (nameplate) - Based on installed capacity nameplate ratings
at the end of the most recent calendar year. The numerator of which is for an
Operating Company and the denominator of which is for all Operating Companies.
This ratio will be determined annually, and/or at such time as may be required
due to a significant change in circumstances.
Gas Throughput - Based on gas throughput in dekatherms (sales and
transportation) for the most recent calendar year. The numerator of which is for
an Operating Company. The denominator of which is for all Operating Companies.
This ratio will be
<PAGE>
Schedule 1
Page 9 of 9
December 18, 1997
determined annually, and/or at such time as may be required due to a significant
change in circumstances.
CPU Cycles - Based on cpu cycles (by application) for the most recent calendar
year. The numerator of which is for an Operating Company or an affected
affiliate company. The denominator of which is for all Operating Companies and
affected affiliate companies. This ratio will be determined annually, and/or at
such time as may be required due to a significant change in circumstances.
Current Tax Expense - Based on taxes charged (income and other) for the most
recent calendar year. The numerator of which is for an Operating Company or an
affected affiliate company. The denominator of which is for all Operating
Companies and affected affiliate companies. This ratio will be determined
annually, and/or at such time as may be required due to a significant change in
circumstances.
Number of Vehicles - Based on number of vehicles at the end of the most recent
calendar year. The numerator of which is for an Operating Company and the
denominator of which is for all Operating Companies. This ratio will be
determined annually, and/or at such time as may be required due to a significant
change in circumstances.
In addition to the allocation factors listed above, appropriate direct
allocations will be made for costs benefiting a single affiliate. Indirect
allocations will also be made to all affiliates, including non-regulated
companies and Ameren Corporation.
It may be necessary to allocate a percentage of total costs allocated to
non-regulated companies or Ameren Corporation (see below). This will be done as
a sub-factor of existing allocation factors. For example, allocating a
percentage of customer service costs to non-regulated companies and allocating
remaining costs based on number of customers. Also, allocating a percentage of
video presentation costs to Ameren Corporation and allocating remaining costs
based on capitalization.
Non-Regulated - Based on a percentage of total costs allocated to non-regulated
companies when existing allocation methods do not adequately reflect the level
of services or benefits received. After allocating this percentage of total
costs to non-regulatory company, the remaining costs will be allocated to
Ameren Corporation and/or its subsidiaries, as appropriate, based upon one of
the factors above.
Corporate - Based on a percentage of total costs allocated to Ameren Corporation
(AMC) when existing allocation methods do not adequately reflect the level of
services or benefits received. After allocating this percentage of total costs
to AMC, the remaining costs will be allocated based upon one of the factors
above.
<PAGE>
Schedule 2
Page 1 of 1
December 18, 1997
AMEREN SERVICES
EXPECTED ALLOCATED DIRECT COST FACTORS
<TABLE>
<CAPTION>
ALLOCATION NUMBER DESCRIPTION
----------------- -----------
<S> <C>
001A Composite*
002A Number of customers
002B Number of gas transportation customers
002C Number of electric customers
002D Number of gas customers
002E % to unregulated company/number of customers
003A Sales (kwh and dekatherm)
003B Kwh sales
003C Dekatherm sales
004A Number of employees
004B Number of contract employees
004C Number of non-contract employees
004D Number if AMS & UEC employees
005A O&M labor
006A Total revenues
006B Electric revenues
006C Gas revenues
007A Total capitalization
007B % to Ameren Corporation/total capitalization
008A Total assets
009A Construction expenditures
010A Peak load (electric)
010B Peak load (gas)
011A Generating capacity
012A Gas throughput (includes transportation)
013A CPU cycles - mainframe
013B CPU cycles - UNIX
015A Current tax expense
016A Number of vehicles
</TABLE>
*Composite consists of the following three factors (equal weight to each
factor):
Sales (kwh and dekatherm)
Number of customers
Number of employees
<PAGE>
Amended Exhibit B-5
AMEREN SERVICES COMPANY
POLICIES AND PROCEDURES
December 18, 1997
<PAGE>
TABLE OF CONTENTS
<TABLE>
<S> <C>
INTRODUCTION.................................................1
GENERAL ACCOUNTING PROCEDURES................................2
AMEREN SERVICES POLICIES AND PROCEDURES......................4
SERVICE REQUEST AND APPROVAL PROCEDURES......................4
SERVICE REQUEST FORM.......................................6
SERVICE REQUEST GUIDELINES.................................8
MONITORING AND CONTROL.....................................9
SERVICE REQUEST ALLOCATION FACTORS UPDATE AND REVISIONS...10
TIME REPORTING............................................11
BILLING AND REVIEW........................................12
DISPUTE RESOLUTION PROCEDURE................................14
INTERNAL AUDIT CONTROL......................................15
EVALUATION AND MEASUREMENT..................................15
</TABLE>
<PAGE>
INTRODUCTION
------------
Ameren Services Company (AMS) will provide Ameren Corporation (AMC),
as well as Union Electric Company (UEC) and Central Illinois Public Service
Company (CIP) (collectively referred to as the "Operating Companies") and other
affiliates of the Ameren Corporation system with a variety of administrative,
management, engineering, construction and support services. Exhibit I describes
the expected services to be provided by AMS. AMS will be subject to the rules
and regulations of the Securities and Exchange Commission (SEC) pursuant to the
Public Utility Holding Company Act of 1935, as amended (PUHCA) and in
particular, Section 13 thereof. AMS has requested to adopt the Federal Energy
Regulatory Commission (FERC) Uniform System of Accounts as opposed to the SEC
Uniform System of Accounts for Mutual Service Companies and Subsidiary Service
Companies. Adoption of the FERC Uniform System of Accounts will still allow
Ameren Services to fulfill the annual reporting requirements of the SEC.
AMS will provide such services in accordance with a General Services
Agreement which will be entered into with AMC, the Operating Companies and
affiliates. The service agreement will be administered in accordance with PUHCA
and the SEC's regulations thereunder. AMS has established a work order system,
which utilizes work orders (referred to as "Service Requests"), for the purpose
of accumulating and charging costs to AMC or the appropriate Operating Company
and/or affiliates. The use of Service Requests will allow AMS to supply
accounting records and information to AMC or the Operating Companies and
affiliates in enough detail to allow
<PAGE>
them to record and report their costs in accordance with the FERC Uniform System
of Accounts and/or SEC rules and regulations.
Though this document describes AMS' accounting policies and
procedures, the provisions of the General Services Agreement serve as the
official source of the accounting policies and practices to be followed by AMS.
GENERAL ACCOUNTING PROCEDURES
- -----------------------------
Accounting procedures and systems have been developed which will
capture the costs of AMS for subsequent billing to AMC, the Operating Companies
and/or affiliates. These costs will be accumulated via a "Service Request"
system. The Service Request system will consist of work orders established to
capture the various types of costs incurred by AMS. The service requests will
specify, in general terms, the services that department will perform for AMC,
the Operating Companies and affiliates. Costs incurred by the various AMS
departments will then be charged to these various service requests which
ultimately will become the basis for the billing of costs to AMC, the Operating
Companies and affiliates.
AMS costs will be classified into either direct or indirect
categories. Direct costs are defined to be those than can be identified as being
applicable to services performed for a single Ameren affiliated company or group
of Ameren affiliated companies. Costs
2
<PAGE>
applicable to AMC or a single Ameren affiliated company will be directly charged
to that company. Costs applicable to two or more Ameren affiliated companies
will be distributed among and charged to such companies. Direct cost allocation
factors will be assigned by function based on the nature and variety of the
service being performed and are listed in Exhibit I. AMS has established
allocation factors that most effectively relate to the types of service being
rendered to AMC, the Operating Companies and/or affiliates.
Indirect costs shall include those costs of a general overhead nature
such as general services, housekeeping costs and other support costs which
cannot be separately identified to a single Ameren affiliated company or group
of Ameren affiliated companies. Indirect costs can be functional or corporate.
Functional indirect costs, such as office supplies and secretarial labor, will
be accumulated by the departments within a function and allocated to AMC, the
Operating Companies and affiliates based on the ratio of total direct and
allocated direct costs charged to that company by each function. For example,
the Controller's Function is comprised of the General Accounting Department,
Plant and Regulatory Department, Financial Communications Department and Budget
Department. All of the Controller's Functions' indirect costs from these five
departments would be accumulated and allocated to AMC, the Operating Companies
and affiliates based on the ratio of total direct and allocated direct costs
charged to that company by the Controller's Function.
3
<PAGE>
Corporate indirect costs, such as AMS property taxes and insurance
costs, will be allocated based on total charges to AMC, the Operating Companies
and affiliates.
Overhead costs associated with labor, such as pensions and benefits,
payroll taxes and injuries damages expenses will be charged to AMC, the
Operating Companies and affiliates based on the AMS labor costs that were
charged to the pertinent service request.
The costs of materials, labor, outside services and other expenses
directly attributable to construction work shall be excluded from the accounting
system of AMS and charged directly to the construction project work order.
AMEREN SERVICES POLICIES AND PROCEDURES
- ---------------------------------------
SERVICE REQUEST AND APPROVAL PROCEDURES
Initially, each department in AMS will determine the appropriate
number and type of service requests required by AMC, the Operating Companies and
affiliates. In the future, it will be the responsibility of AMC, the Operating
Companies and affiliates to establish the service requests.
4
<PAGE>
These services will be reviewed and agreed upon with AMC, the
Operating Companies and affiliates annually. Direct service requests will be
prepared for ongoing or special services which benefit one or more of the Ameren
affiliated entities. If the service request benefits more than one of the
Ameren affiliated entities, direct costs will be distributed among the companies
based on an appropriate allocation factor. Examples of ongoing services are the
monthly closing of financial systems and the generation of routine monthly
reports. Examples of special services are developing a new information system
or preparing rate case testimony and schedules. The SEC requires that, whenever
feasible, AMS costs should be directly charged to AMC, the Operating Companies
or affiliates.
Indirect functional and indirect corporate service requests will be
prepared as appropriate for costs benefiting more than one of the Ameren
operating companies and/or affiliated entities which cannot be allocated
directly. These services will also be reviewed and agreed upon with AMC, the
Operating Companies and affiliates annually.
SERVICE REQUEST FORM
All activities performed by AMS for AMC, the Operating Companies and
affiliates must have a completed and approved Service Request form. Approvals
are required by either AMC, the Ameren-related operating company or affiliate
requesting the work, the AMS service provider and the AMS General Accounting
Department. That is, only
5
<PAGE>
those companies requesting the work are required to approve a Service Request
form. In addition, all Service Request forms must be approved by the pertinent
AMS function providing the service and the AMS General Accounting Department.
The following information is required to complete the Service Request
form. Refer to Exhibit II for an example of a completed Service Request form.
Service Request Type Determined by the party originating
Service Request:
- Charges zeroed annually (continuing
services)
- Related to a Work Order at an
Affiliated Company
- Project-type (non-recurring)
Title Description of services provided or
activities performed (to uniquely
identify Service Request)
Name of Originator Person responsible for Service Request
Originator's Telephone Telephone number of Originator
Budget Budget responsible for Service Request
6
<PAGE>
Service Request Category Cost allocation method:
- Direct, 100% to one company
- Allocated Direct-benefits more than one
company
- Functional Indirect-allocated based on
Direct and Allocated Direct Service
Request charges within function
- Corporate Indirect-allocated based on
allocation of all Service Request charges
excluding Corporate Indirect
Allocation Factor Basis for cost allocation, required for
Direct and Allocated Direct Service
requests. Factor should logically relate
to the benefit derived from the service
provided.
Payroll Percents Allows accounting distribution of labor
charges.
Begin Project Date Optional; valid for project-type Service
Requests and Service Requests related to a
work order at an affiliated company only.
Scheduled Completion Date Optional; valid for project-type Service
Requests and Service Requests related to a
work order at an affiliated company only.
Department Project ID Optional; abbreviated description or
identifier for departmental use.
Service Request Description Description of services to be provided.
Listing of major activities performed to
provide services.
Reason category was selected and why
allocation factor (if required) is
appropriate.
Charge Accounts Accounting information for Ameren Services
accounts that will capture charges for
this Service Request.
Target Accounts Accounts to be charged to corporations
benefiting from the service request.
7
<PAGE>
SERVICE REQUEST GUIDELINES
A new Service Request form may be appropriate when a new service or
project is identified. However, the cost of the new service or project may be
able to be captured in an existing Service Request. Any one of the following
criteria should be considered in determining the need for a new Service Request:
1. No allocation method exists that is appropriate for the new service or
project.
2. No existing service request distributes costs to AMC, the desired
Operating Companies or affiliates for the new service or project.
3. No existing service request distributes costs to the desired FERC
accounts on the affiliates' books for the new service or project.
4. The total estimated annual cost of the new service or project is
greater than $25,000.
5. There is a regulatory requirement to allocate costs in a specific
manner for a new service or project.
8
<PAGE>
MONITORING AND CONTROL
The AMS General Accounting Department is responsible for reviewing,
monitoring and maintaining the Service Request system. The AMS General
Accounting Department also authorizes new Service Requests and ensures that
allocation factors are proper, accurate and kept current including ensuring that
the process is in accordance with SEC regulations. The AMS General Accounting
Department is also responsible for coordinating the monthly billing process as
described in the Billing and Review policies and procedures section.
Additionally, the accounting system will provide detailed billing information
for AMC, the Operating Companies and affiliates' management review to ensure
proper billings. Monthly and year-to-date information will be available.
AMC, AMS, the Operating Companies and affiliates' management will be
required to operate within an approved budget for their area of responsibility.
Monthly summaries and detailed cost reports will compare actual results to
budgeted amounts.
All costs will be properly documented with supporting employee time
reports, expense accounts, invoices or other source documents. Each source
document will be coded with a service request work order number that is
assignable to AMC, an Operating Company or affiliate, use one of the allocated
direct cost factors in Exhibit I to allocate the costs, or charge an indirect
functional or corporate service request. The
9
<PAGE>
appropriate allocation factor will be included in the electronic billing process
for each service request work order.
The AMS General Accounting Department will review and maintain copies
of all workpapers supporting any cost allocations. The AMS General Accounting
Department will also be responsible for utilizing the cost allocation factors
and accumulating costs among AMC, the Operating Companies and affiliates for
billing and accounting purposes.
SERVICE REQUEST ALLOCATION FACTORS UPDATE AND REVISIONS
The AMS General Accounting Department will have the primary
responsibility for ensuring that the Service Request allocation factors are
proper, accurate and kept current. All allocation factors utilized must be
approved by the SEC. Any modification of allocation factors which requires
filing under 60-day letter procedures based on existing commission guidelines
will be filed on a timely basis. The current guidelines require approval if the
change will cause the lesser of $50,000 or 5% change in the allocation of costs
between companies. This guideline is subject to change.
To the greatest extent possible, the allocation factors will be based
on cost drivers specifically applicable to the service being provided. The AMS
General Accounting Department, the customer and the service provider will decide
on the proper direct cost allocation factors. The AMS General Accounting
Department will decide on the appropriate method of allocating indirect service
requests.
10
<PAGE>
As necessary, but at least annually, the allocation factors currently
utilized to allocate costs will be reviewed by AMS with AMC, the Operating
Companies and affiliates to determine if they are still appropriate. Any
changes in allocation methods utilized to allocate costs will be reviewed with
AMC and the Operating Companies and affiliates for their concurrence prior to
implementation of the new method. Changes and/or new allocation methods may be
recommended at any time subject to any necessary SEC and other appropriate
regulatory approvals. All changes will be documented in writing and approved by
appropriate AMS, AMC, the Operating Company and affiliate management.
The AMS General Accounting Department will be responsible for
evaluating new allocation methodologies and determining if SEC approval is
required. The General Accounting Department will coordinate SEC approval
efforts, if necessary, with the Legal Department.
TIME REPORTING
Labor is expected to be one of the most significant costs for Ameren
Services. Employees will be required to enter a service request code on the
appropriate labor source document to be used in identifying AMS costs and the
appropriate cost assignment factor. The following guidelines are provided to
ensure accurate and efficient time keeping:
11
<PAGE>
1. Time should be entered daily into the appropriate time reporting
system. If this is not practical, the employee should submit manually
prepared time records, substantiating later electronic time entry.
2. In no event should time entry be delayed past the end of the normal
pay period. If the pay period ends after the calendar end of month,
all time must be entered through the last day of the month within the
following two working days.
3. Employees should keep track of time in one hour increments.
4. The employee's supervisor is encouraged to approve all time reports
daily. In addition, final time reports must be approved either bi-
monthly or every two weeks.
BILLING AND REVIEW
AMC, the Operating Companies and affiliates will receive a monthly
bill detailing the work performed by AMS. Pertinent officers at AMC, the
Operating Companies and/or affiliates will approve the billings. Billings will
be discussed by AMS accounting personnel with AMC, the Operating Companies and
affiliates prior to their approval. Provisions will be made for billing
corrections and adjustments when necessary. AMC,
12
<PAGE>
the Operating Companies and affiliates will remit payments to AMS within 60 days
of the billing date:
Each bill will contain the following information (see Exhibit III):
* Company
* Functions whose costs are being billed
* Service Request Number
* Description of service provided
* Allocation Factor
* Direct, Allocated Direct, Indirect Functional and
Indirect Corporate charges
* Total amount of charges
* Service Request Contact person and phone
Detailed information such as source documents, labor hours and
accounts charged are also available on Service Request detailed charge reports.
This information will also be made available on hard copy reports, microfiche
general ledgers or via personal computer report screens.
AMS management will review monthly reports to ensure all payroll hours
and billings are properly recorded. Monthly and year-to-date reports are also
available for review and control purposes.
13
<PAGE>
After the Service Requests are processed and transactions are posted
to AMS, initial billings are generated. General Accounting Department personnel
will review the billings for errors at this time. General Accounting will also
verify that Service Requests have the correct allocation factors. Any material
discrepancies identified will be corrected prior to the generation of the final
monthly financial statements. After the final monthly financial statements are
generated, the General Accounting Department will reconcile billings to the AMS
general ledger. If an error is found after the final statements are generated,
a correction will be made the following month.
Upon receipt of the billing, management for AMC, the Operating
Companies and affiliates, with assistance of the AMS General Accounting
Department, will review and reconcile the billing. Any discrepancies found at
this time will be discussed with the General Accounting Department personnel and
corrections will be made to the subsequent month's bill.
DISPUTE RESOLUTION PROCEDURE
- ----------------------------
If there is a dispute between the AMC, Operating Companies and/or
affiliates and an AMS service provider regarding a billing, representatives of
all parties along with the AMS General Accounting representative, will meet to
resolve the issues. Managers of the representatives may also be consulted. In
the event a resolution cannot be reached, the issue will be referred to senior
management for final resolution.
14
<PAGE>
INTERNAL AUDIT CONTROL
- ----------------------
The AMS Internal Audit Department will conduct audits of the Service
Request system every two years. Computer systems, billings and source
documentation will be examined to ensure the services provided are authorized,
documented and accurately recorded in AMS's, AMC's, the Operating Companies' and
affiliates' books and records. The Internal Audit Department will also examine
Service Request allocation factors to ensure such methods comply with those
approved by the SEC. In addition, Service Request policies, operating
procedures and controls will be evaluated annually. The Internal Audit
Department reports to the CFO of AMC and has independent access to the Audit
Committee of the Board of Directors of AMC at any time.
EVALUATION AND MEASUREMENT
- --------------------------
In order to encourage AMS to operate efficiently and cost effectively,
and provide high quality service, AMS will establish bench marking activities to
the extent deemed appropriate by senior management of AMC, as well as initiate a
customer review process. The customer review process will be based on a
customer-oriented service philosophy and measure success based on customer
satisfaction. It will allow for customer input into the volume and value of the
products and services provided by AMS. These reviews will be part of the annual
budget development process and the completion of the Service Request Agreements
between AMS and its customers. In
15
<PAGE>
addition to the review process with customers, AMS will establish a bench
marking plan to the extent deemed appropriate by senior management of AMC within
24 months to continue to improve the effectiveness of services offered to AMC,
the operating companies and affiliates and to ensure that the services offered
are cost competitive.
16
<PAGE>
Exhibit I
Page 1 of 9
December 18, 1997
DESCRIPTION OF EXPECTED SERVICES
TO BE PROVIDED BY AMEREN SERVICES AND
EXPECTED DIRECT COST ALLOCATION FACTORS
Description of Expected Services To Be Provided
A description of the expected services to be provided by Ameren Services is
detailed below. Identifiable costs for all of the functional organizations
listed below will be directly charged to Ameren Corporation and its
subsidiaries, whenever possible.
For costs that cannot be directly assigned or distributed, the expected direct
cost allocation factors are reflected below for each Ameren Services department.
a) Building Service
Description - Provide facility management services for owned and leased
facilities, excluding power plants. To the extent that leasing arrangements
are established between Ameren Services and/or Ameren Corporation and its
subsidiaries, lease costs will include rent for space occupied and
applicable services, such as operation and maintenance of structures,
capital improvements, interior space planning, security and janitorial. As
appropriate, lease costs will be allocated based on square feet occupied
and the allocation factors listed below.
Expected Allocation Factors - 1) number of employees; 2) operations and
maintenance labor; 3) total capitalization; and 4) total assets
b) Controller's
Description - Perform all accounting services necessary to properly
maintain and report on the books and records of Ameren and its
subsidiaries. Provide investor relations services.
Expected Allocation Factors - 1) composite*; 2) total capitalization; and
3) total assets
c) Corporate Communications
Description - Develop strategies for advertising and marketing efforts, develop
employee communication programs, coordinate community relations efforts and
develop policies and procedures for media relations.
<PAGE>
Exhibit I
Page 2 of 9
December 18, 1997
Expected Allocation Factors - 1) composite*; 2) total capitalization; and 3)
total assets
d) Corporate Planning
Description - Provide rate engineering, interchange marketing, resource planning
and business analysis services.
Expected Allocation Factors - 1) composite*; 2) kwh sales; 3) peak load
[electric]; 4) total capitalization; and 5) total assets
e) Customer Services/Division Support
Description - Answer customer inquiries pertaining to 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.
Expected Allocation Factors - 1) number of customers; 2) number of employees;
and 3) operations and maintenance labor
f) Economic Development
Description - Provide community and business development services, as well as
natural gas development services. Analyze community and business development
opportunities.
Expected Allocation Factors - 1) number of customers; 2) sales [kwh and
dekatherm]; 3) total capitalization; and 4) total assets
g) Energy Supply
Coordinate the use of the generating, transmission and interconnection
facilities to provide economical and reliable energy.
Expected Allocation Factors - 1) kwh sales
<PAGE>
EXHIBIT I
Page 3 of 9
December 18, 1997
h) Engineering and Construction
Description - Provide professional services related to engineering studies,
design, procurement, planning, building and management of projects. Study
technology that may reduce costs of producing, delivering and using
electricity.
Expected Allocation Factors - 1) peak load [electric]; 2) generating capacity;
and 3) construction expenditures
i) Environmental Services & Safety
Description - Perform analysis and advocacy of regulatory 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.
Expected Allocation Factors - 1) number of employees; 2) generating capacity; 3)
operations and maintenance labor; and 4) construction expenditures
j) Executive
Description - Provide executive management duties for all applicable activities
at the department, function and officer levels
Expected Allocation Factors - 1) total capitalization; 2) total assets; and 3)
sales [kwh and dekatherm]
k) Fossil Fuel Procurement
Description - Provide resources necessary to procure fuel for the fossil power
plants and minimize production costs.
Expected Allocation Factors - 1) kwh sales
l) Gas Supply
Description - 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.
<PAGE>
Exhibit I
Page 4 of 9
December 18, 1997
Expected Allocation Factors - 1) dekatherm sales; 2) gas throughput [includes
transportation]; and 3) peak load [gas]
m) General Counsel
Description - Provide general legal advice related to all applicable activities
and legal services in regards to legislative activities, regulatory agencies and
security matters. Make regulatory filings, maintain minutes of the board of
directors, conduct stockholder meetings and procure property and casualty
insurance bonds.
Expected Allocation Factors - 1) composite*; 2) total capitalization; and 3)
total assets
n) Human Resources
Description - 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.
Expected Allocation Factors - 1) number of employees; 2) total capitalization;
3) total assets; and 4) operation and maintenance labor
o) Industrial Relations
Description - Negotiate, represent and administer provisions of labor agreements
applicable to unions representing union employees.
Expected Allocation Factors - 1) number of employees; and 2) operation and
maintenance labor
p) Information Services
Description - 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.
Expected Allocation Factors - 1) composite*; 2) number of customers; 3) number
of employees; 4) CPU cycles; and 5) operation and maintenance labor
<PAGE>
Exhibit I
Page 5 of 9
December 18, 1997
q) Internal Audit
Description - Audit company operations, perform operational and productivity
reviews, review justifications for capital projects and perform quality
assurance reviews.
Expected Allocation Factors - 1) composite*; 2) number of customers; 3) number
of employees; and 4) operation and maintenance labor
r) Marketing
Description - Provide marketing services including account management, program
development, market research and customer energy services.
Expected Allocation Factors - 1) sales [kwh and dekatherm]; and 2) total assets
s) Merger Coordination
Description - Monitor programs to achieve savings, merger costs and position
reductions as they relate to the implementation plans.
Expected Allocation Factors - 1) composite*; 2) total capitalization; and 3)
total assets
t) Motor Transportation
Description - Provide engineering, support, and mechanical servicing of
vehicles, procurement of vehicles and safety and training programs.
Expected Allocation Factors - 1) number of vehicles
u) Purchasing
Description - Provide procurement of goods and services other than fuel. Provide
materials inventory management services.
Expected Allocation Factors - 1) composite*; 2) total assets; and 3)
construction expenditures
<PAGE>
Exhibit I
Page 6 of 9
December 18, 1997
v) Real Estate
Description - 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.
Expected Allocation Factors - 1) composite*; 2) number of customers; and 3)
total assets
w) Stores
Description - Provide clerical, stenographic, administrative and Electronic Data
systems support. Provide engineering support and manage and direct stores
operations.
Expected Allocations Factors - 1) composite*
x) Tax
Description - 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.
Expected Allocation Factors - 1) composite*; 2) current tax expense; 3) total
capitalization; and 4) total assets
y) Treasurer's
Description - Provide treasury operation, mailing, financial planning,
investments, and executive payroll and pension disbursement services.
Expected Allocation Factors - 1) composite*; 2) number of customers; 3) number
of employees; 4) total capitalization; and 5) total assets
*Composite consists of the following three factors (equal weight to each
factor):
Sales (kwh and dekatherm)
Number of customers
Number of employees
<PAGE>
Exhibit I
Page 7 of 9
December 18, 1997
Allocation Factors
The following allocation factors will be utilized as outlined above.
Number of Customers - Based on the number of customers (electric and/or gas) at
the end of the most recent calendar year. The numerator of which is for an
Operating Company and the denominator of which is for all Operating Companies.
This ratio will be determined annually, and/or at such time as may be required
due to a significant change in circumstances.
Sales - Based on the sales volume (kwh and/or dekatherms) for the most recent
calendar year. The numerator of which is for an Operating Company and the
denominator of which is for all Operating Companies. This ratio will be
determined annually, and/or at such time as may be required due to a significant
change in circumstances.
Number of Employees - Based on the number of employees (contract and/or
non-contract, or electric operating and/or gas operating) at the end of the most
recent calendar year. The numerator of which is for an Operating Company or an
affected affiliate company. The denominator of which is for all Operating
Companies and affected affiliate companies. This ratio will be determined
annually, and/or at such time as may be required due to a significant change in
circumstances.
Composite - Based on an equal weighting Sales (kwh & dekatherm), Number of
Customers (total), and Number of Employees (total) allocation factors. The
numerator of which is the simple average of the above three factors for an
Operating Company and the denominator of which is for all Operating Companies.
This ratio will be determined annually and/or at such time as may be required
due to a significant change in circumstances.
Operations & Maintenance Labor - Based on the Operations & Maintenance Labor
(electric and/or gas) for the most recent calendar year. The numerator of which
is for an Operating Company or an affected affiliate and the denominator of
which is for all Operating Companies and affected affiliate companies. This
ratio will be determined annually, and/or at such time as may be required due to
a significant change in circumstances.
Revenues - Based on revenues (electric and/or gas) for the most recent calendar
year. The numerator of which is for an Operating Company or an affected
affiliate company. The denominator of which is for all Operating Companies and/
or affected affiliate companies. This ratio will be determined annually, or at
such time as may be required due to a significant change in circumstances.
<PAGE>
Exhibit I
Page 8 of 9
December 18, 1997
Total Capitalization - Based on total capitalization (total common stockholder's
equity, preferred stock, and long term debt) at the end of the most recent
calendar year. The numerator of which is for an Operating Company or an affected
affiliate company. The denominator of which is for all Operating Companies and
affected affiliate companies. This ratio will be determined annually and/or at
such time as may be required due to a significant change in circumstances.
Total Assets - Based on total assets at the end of the most recent calendar
year. The numerator of which is for an Operating Company or an affected
affiliate company. The denominator of which is for all Operating Companies and
affected affiliate companies. This ratio will be determined annually, and/or at
such time as may be required due to a significant change in circumstances.
Construction Expenditures - Based on construction expenditures for the most
recent calendar year. The numerator of which is for an Operating Company or an
affected affiliate company. The denominator of which is for all Operating
Companies and affected affiliate companies. This ratio will be determined
annually, and/or at such time as may be required due to a significant change in
circumstances.
Peak Load (electric) - Based on the highest monthly maximum megawatt load
(60-minute integration) for the most recent calendar year. The numerator of
which is for an Operating Company and the denominator of which is for all
Operating Companies. This ratio will be determined annually, and/or at such time
as may be required due to a significant change in circumstances.
Peak Load (gas) - Based on the highest daily send out in therms (excluding
transportation) for the most recent calendar year. The numerator of which is for
an Operating Company and the denominator of which is for all Operating
Companies. This ratio will be determined annually, and/or at such time as may be
required due to a significant change in circumstances.
Generating Capacity (nameplate) - Based on installed capacity nameplate ratings
at the end of the most recent calendar year. The numerator of which is for an
Operating Company and the denominator of which is for all Operating Companies.
This ratio will be determined annually, and/or at such time as may be required
due to a significant change in circumstances.
Gas Throughput - Based on gas throughput in dekatherms (sales and
transportation) for the most recent calendar year. The numerator of which is for
an Operating Company. The denominator of which is for all Operating Companies.
This ratio will be
<PAGE>
Exhibit I
Page 9 of 9
December 18, 1997
determined annually, and/or at such time as may be required due to a significant
change in circumstances.
CPU Cycles - Based on cpu cycles (by application) for the most recent calendar
year. The numerator of which is for an Operating Company or an affected
affiliate company. The denominator of which is for all Operating Companies and
affected affiliate companies. This ratio will be determined annually, and/or at
such time as may be required due to a significant change in circumstances.
Current Tax Expense - Based on taxes charged (income and other) for the most
recent calendar year. The numerator of which is for an Operating Company or an
affected affiliate company. The denominator of which is for all Operating
Companies and affected affiliate companies. This ratio will be determined
annually, and/or at such time as may be required due to a significant change in
circumstances.
Number of Vehicles - Based on number of vehicles at the end of the most recent
calendar year. The numerator of which is for an Operating Company and the
denominator of which is for all Operating Companies. This ratio will be
determined annually, and/or at such time as may be required due to a significant
change in circumstances.
In addition to the allocation factors listed above, appropriate direct
allocations will be made for costs benefiting a single affiliate. Indirect
allocations will also be made to all affiliates, including non-regulated
companies and Ameren Corporation.
It may be necessary to allocate a percentage of total costs allocated to
non-regulated companies or Ameren Corporation (see below). This will be done as
a sub-factor of existing allocation factors. For example, allocating a
percentage of customer service costs to non-regulated companies and allocating
remaining costs based on number of customers. Also, allocating a percentage of
video presentation costs to Ameren Corporation and allocating remaining costs
based on capitalization.
Non-Regulated - Based on a percentage of total costs allocated to non-regulated
companies when existing allocation methods do not adequately reflect the level
of services or benefits received. After allocating this percentage of total
costs to non-regulatory company, the remaining costs will be allocated to Ameren
Corporation and/or its subsidiaries, as appropriate, based upon one of the
factors above.
Corporate - Based on a percentage of total costs allocated to Ameren Corporation
(AMC) when existing allocation methods do not adequately reflect the level of
services or benefits received. After allocating this percentage of total costs
to AMC, the remaining costs will be allocated based upon one of the factors
above.
<PAGE>
Exhibit II
Page 1 of 5
REPORT NO: 301SR AMEREN SERVICES
REPORT DATE: 9/8/97 APPROVAL FORM SERVICE REQUEST ID: A012
DEPT PROJECT ID:
CORPORATION: AMS
DEPARTMENT: ENERGY SERV OTHER BUDGET NO: 042 DATE AUTHORIZED: __/__/__
ALLOCATION FACTOR: 003B SALES (KWH) PAYROLL PERCENT: Y
SERVICE REQUEST CATEGORY: DIRECT ALLOCATED TYPE: ZERO OUT ANNUALLY
GENERATION COORDINATION AND DISPATCH
SERVICES PROVIDED UNDER THIS SERVICE REQUEST IS
COORDINATION AND DISPATCH OF THE UE AND CIPS
GENERATING UNITS.
GENERATION COORDINATION AND DISPATCH INCLUDES THE
FOLLOWING ACTIVITIES: DEVELOP LOAD FORECAST FOR
GENERATION PLANNING, POWER PLANT SURVEYS, SHORT
TERM GENERATING UNIT MAINTENANCE SCHEDULING,
COMMITMENT OF GENERATING UNITS. DISPATCH OF
GENERATING UNITS, COORDINATION OF INTERCHANGE
PURCHASES AND SALES, MAINTAINING ADEQUATE
RESERVES, MAINTAIN AREA CONTROL ERROR, AND
ROUTINE REPORTING.
THE KWH SALES ALLOCATION FACTOR WAS SELECTED
AS THE MAJOR FACTOR OF GENERATION COORDINATION
AND DISPATCH IS THE KWH SALES OF EACH COMPANY.
DATES: PROJECT START __/__/__ SCHEDULED COMPLETION __/__/__
ORIGINATOR: TELEPHONE:
REQUESTED BY: APPROVED BY: APPROVED BY ACCOUNTING
____________________ ____________________ ____________________
APPROVED BY CIP APPROVED BY UEC
____________________ ____________________
<PAGE>
Exhibit II
Page 2 of 5
REPORT NO: 301SR AMEREN SERVICES
REPORT DATE: 9/8/97 APPROVAL FORM SERVICE REQUEST ID: A012
DEPT PROJECT ID:
************************** ACCOUNTING INFORMATION ****************************
- ------ CHARGE ACCOUNTING ------ ----- TARGET ACCOUNTING -----
COST ACCOUNT NO PAYROLL ACCOUNT NO
CAT. U DV MAJ MIN T % CORP U DV MAJ MIN T WKORDER
EXPENSE
1 11 426 005 CIP 1 41 426 005 E
UEC 1 21 426 005 E
1 11 457 110
1 11 457 111
1 11 457 113
1 11 457 114
1 11 457 121
1 11 457 141
1 11 457 210
1 11 457 211
1 11 457 213
1 11 457 214
1 11 457 221
1 11 457 241
1 11 556 100 CIP 1 41 556 E 1
UEC 1 21 556 E 1
1 11 557 001 CIP 1 41 557 001 E 1
UEC 1 21 557 001 E 1
1 11 921 001 CIP 1 41 921 001 E 1
UEC 1 21 921 001 E 1
1 11 921 002 CIP 1 41 921 002 E 1
UEC 1 21 921 002 E 1
1 11 921 050 CIP 1 41 921 050 E 1
UEC 1 21 921 050 E 1
1 11 935 002 CIP 1 41 935 002 E 1
UEC 1 21 935 002 E 1
1 11 935 003 CIP 1 41 935 003 E 1
UEC 1 21 935 003 E 1
TOTAL CHARGE PERCENT: 100
<PAGE>
Exhibit II
Page 3 of 5
Ameren Services
---------------
Service Request Information Form
--------------------------------
General Information Screen (EAPSR)
----------------------------------
Service Request Type: Z
-----
. Z - Charges are zeroed annually
-
. W - Corresponds to a Work Order at an Affiliated company
-
. P - Project-type Service Request (indefinite life)
-
Title Generation Coordination and Dispatch
------------------------------------------------------------------------
(50 Characters, maximum)
Originator Information:
Name: Tim Finnell
-------------------------------------------------------------------
Telephone: 554-3495 Budget: 042 Energy Supply
-------------------- ---------------------------------
Service Request Category: A
-----
. D - Direct - 100% to one company (requires allocation factor)
-
. A - Direct Allocated - Benefits more than one company (requires
-
allocation factor)
. F - Indirect Functional - Spread to Affiliated companies based on
-
allocation of Direct Service Requests within function.
. C - Indirect Corporate - Spread based on allocation of all other Service
-
Requests
Allocation Factor: 003B (Descriptions and Factors available on Screen UAF01)
----------
Payroll Percents (Y/N) Y
-----
. Y - Allows employee to enter only Service Request number for Time
Reporting. Accounting will be assigned as specific by Service
Request. Optionally, full accounting may be input if desired.
. N - Employee will be required to enter full account when charging this
Service Request.
Dates (Optional):
Begin Construction: / / Scheduled Completion: / /
-- -- -- -- -- --
. Valid only for Service Request types W and P
Department Project ID: (Optional, 10 characters, maximum)
----------------------
<PAGE>
EXHIBIT II
Page 4 of 5
Ameren Services
---------------
Service Request Information Form
--------------------------------
Work Order Information Screen (EAPW3)
-------------------------------------
and Extended Description Screen (UEDES)
---------------------------------------
The Service Request description must include the following:
. The services to be provided.
. Major activities performed to provide the services.
. Why the Service Request category was selected and if an Allocation
Factor is required, justification for the one used.
The service provided under this service request is the coordination and dispatch
of the UE and CIPS generating units.
Generation coordination and dispatch includes the following activities: develop
load forecast for generation planning, power plant surveys, short term
generating unit maintenance scheduling, commitment of the generating units, the
dispatch of the generating units, the coordination of interchange purchases and
sales, maintaining adequate reserves, maintain area control error, and routine
reporting.
The KWH sales allocation factor was selected because the major factor of
generation coordination and dispatch is the KWH sales of each company.
2
<PAGE>
Exhibit II
Page 5 of 5
Ameren Services
---------------
Service Request Information Form
--------------------------------
Service Request Charge Accounts Information Screen (EACSR)
----------------------------------------------------------
All valid charge accounts for this Service Request must be entered on this
screen.
<TABLE>
<CAPTION>
Cost Payroll
Category U DIV MAJ MIN Acctg. %
-------- - --- --- --- --------
<S> <C> <C> <C> <C> <C>
E 01 21 391 002
E 01 21 391 022
E 01 21 426 005
E 01 21 556 000 100%
E 01 21 557 001
E 01 21 921 001
E 01 21 921 002
E 01 21 921 050
E 01 21 935 002
E 01 21 935 003
------ -- --- --- --- -----
------ -- --- --- --- -----
------ -- --- --- --- -----
------ -- --- --- --- -----
------ -- --- --- --- -----
</TABLE>
Valid Cost Categories:
. E - Expense
. 0 - Capital
. 5 - Removal Costs
If the Payroll Percents option selected was Yes ("Y"), for every account that
will have labor distributed, you must enter the desired distribution percentage.
The total of these percents must equal 100%.
3
<PAGE>
Exhibit III
1 of 1
Rept. No.: GA12345 AMEREN SERVICES Page No. 1
Run Date: 10/10/97 Monthly Billing
Run Time: 14:40:41 Service Request Allocations
September, 1997
UEC Union Electric Company
<TABLE>
<CAPTION>
Service Allocation Indirect
Request # Description(1) Factor(3) Direct(2) Allocated Direct Functional
- --------- -------------- ---------- --------- ---------------- ----------
<S> <C> <C> <C> <C>
CONTROLLER'S(4)
A1234 Maintain GL and AP financial systems Composite 9,999,999.99
A1235 Maintain Contract Payroll financial system # of contract emp. 9,999,999.99
A1236 Maintain Work Order and Asset Mgmt systems Assets 9,999,999.99
A1237 Missouri Rate Case UEC 100% 9,999,999.99
A1238 Secretarial Support & Office Supplies (5) 9,999,999.99
Total Controller's 99,999,999.99 99,999,999.99 99,999,999.99
ENGINEERING & CONSTRUCTION
A2729 Office Supplies (5)
0E029 High Ridge Sub UEC 100% 9,999,999.99
04463 Control System Upgrade-Osage Plant UEC 100% 9,999,999.99
00682 Emergency Bus Arrangement-Sioux Plant UEC 100% 9,999,999.99
Total E&C 99,999,999.99 99,999,999.99 99,999,999.99
GENERAL COUNSEL
A1291 Provide legal service and procure
insurance bonds Composite 9,999,999.99
A1292 Provide corporate insurance (6)
Total General Counsel 99,999,999.99 99,999,999.99 9,999,999.99
Total UEC 99,999,999.99 99,999,999.99 9,999,999.99
(page break)
CIP Central Illinois Public Service Company 9,999,999,999.99 9,999,999,999.99 9,999,999,999.99
etc.
Total CIP 9,999,999,999.99 9,999,999,999.99 9,999,999,999.99
(page break)
Grand Total 9,999,999,999.99 9,999,999,999.99 9,999,999,999.99
</TABLE>
<TABLE>
<CAPTION>
Service Indirect Service Request Contact
Request # Description(1) Corporate Total Name Phone
- --------- -------------- --------- ----- ---- -----
<S> <C> <C> <C> <C>
CONTROLLER'S(4)
A1234 Maintain GL and AP financial systems XXXXXXXXXXXXXXX XXXXX
A1235 Maintain Contract Payroll financial system XXXXXXXXXXXXXXX XXXXX
A1236 Maintain Work Order and Asset Mgmt systems XXXXXXXXXXXXXXX XXXXX
A1237 Missouri Rate Case XXXXXXXXXXXXXXX XXXXX
A1238 Secretarial Support & Office Supplies XXXXXXXXXXXXXXX XXXXX
Total Controller's 99,999,999.99 99,999,999.99
ENGINEERING & CONSTRUCTION
A2729 Office Supplies
0E029 High Ridge Sub XXXXXXXXXXXXXXX XXXXX
04463 Control System Upgrade-Osage Plant XXXXXXXXXXXXXXX XXXXX
00682 Emergency Bus Arrangement-Sioux Plant XXXXXXXXXXXXXXX XXXXX
Total E&C 99,999,999.99 99,999,999.99
GENERAL COUNSEL
A1291 Provide legal service and procure
insurance bonds XXXXXXXXXXXXXXX XXXXX
A1292 Provide corporate insurance 9,999,999.99 XXXXXXXXXXXXXXX XXXXX
Total General Counsel 99,999,999.99 99,999,999.99
Total UEC 99,999,999.99 99,999,999.99
(page break)
CIP Central Illinois Public Service Company 9,999,999,999.99 9,999,999,999.99
etc.
Total CIP 9,999,999,999.99 9,999,999,999.99
(page break)
Grand Total 9,999,999,999.99 9,999,999,999.99
</TABLE>
<PAGE>
SECOND AMENDED EXHIBIT K-4
DESCRIPTION OF NON-UTILITY INVESTMENTS
As a result of the Transaction, the nonutility businesses and interests of
UE and CIPSCO described in Item l.B.3 of the Application will become businesses
and interests of Ameren. The total assets of all nonutility investments of UE
and CIPSCO at June 30, 1997 ($144.5 million) constituted less than 1.6% of pro
forma consolidated assets of Ameren or about 2.4% of pro forma consolidated
capitalization.
From UE, Ameren will hold the following nonutility subsidiaries,
investments or businesses:
1. Steam heating operations of UE.
------------------------------
The steam heating business of UE will continue to be owned and operated by
UE. This operation, which is located exclusively in its service territory and
limited to Jefferson City, Missouri, serves the needs of the Missouri State
Capitol complex. 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./1/
2. 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, 1997, the total
amount invested in such nonutility investments was $19.1 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. As noted in the Application, UE has authority from the ICC
to invest up to
_____________________
/1/ 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 Rule 58. Thus,
the production and distribution of thermal energy is reasonably incidental to
Ameren's utility operations and may be retained.
<PAGE>
$100 million in UEDC "for the purpose of benefitting and improving" its business
and/or service area and for charitable purposes. (ICC Docket No. 94-0237, Sept.
24, 1994). Missouri law does not require prior approval to make non-utility
investments. These investments are categorized as follows:
a. Energy/Utility Related
----------------------
Gateway Energy Alliance -- At June 30, 1997, $429,792 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. Any
future activity or investment not described herein will only be made in
accordance with applicable rules (such as Rules 40 and 58) or pursuant to
application made to the Commission for specific approval./2/
CellNet, Inc. -- At June 30, 1997, $9.9 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./3/
EnviroTech Investment Fund LLC -- At June 30, 1997, $700,000 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./4/
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./5/
_________________________
/2/ See cases cited in Note 1. UEDC, through a joint venture limited liability
company, is negotiating with a municipal utility to construct a new
generating unit to be owned and operated by the municipal utility. See,
----
e.g., Southern Co., Release No. 22132 (July 17, 1981); American Electric
----- ------------ -----------------
Power Co., Inc., Release No. 22468 (Apr. 28, 1982) (consulting services).
---------------
See also Release No. 26667 (Adoption of Rule 58) at Part II,A,1,b.(7).
--------
See footnote 48 to Amendment No. 5 to the Form U-1.
/3/ Central and South West Corp. Release No. 35-26250 (Mar. 14, 1995) (develop
----------------------------
and provide meter reading services to non-affiliated companies).
/4/ Several other registered holding companies have received approval to invest
in EnviroTech partnerships. See, e.g., Southern Co., Release No. 35-26240
--------- ------------
(Feb. 28, 1995).
/5/ Appliance sales, installation and servicing businesses have been approved.
See, e.g., Consolidated Natural Gas, Release No. 36-26234 (Feb. 23, 1995).
---------- ------------------------
2
<PAGE>
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. This activity has been
and will be limited to the United States. Any future activity or investment
not described herein will only be made in accordance with applicable rules
(such as Rules 40 and 58) or pursuant to application made to the Commission
for specific approval./6/
Gateway Energy Systems, L.C. -- At June 30, 1997, UEDC had invested
$125,000 in a 49% interest in a limited liability company which has entered
into letters of intent for two projects, one to develop facilities for
providing steam, compressed air and treated water, the other to provide
only steam. Individual projects developed through this entity would in most
cases be performed by separate limited liability companies of which UEDC
will be an investor./7/ Any future activity or investment not described
herein will only be made in accordance with applicable rules (such as Rules
40 and 58) or pursuant to application made to the Commission for specific
approval.
b. Community and Civic Development/Venture Capital
-----------------------------------------------
Civic Ventures LLC -- At June 30, 1997, $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./8/
_________________________
/6/ See, e.g., Eastern Utilities Associates, Release No. 35-26232 (Feb.15,
--------- ----------------------------
1995).
/7/ See Notes 4 and 6.
/8/ The Commission has on numerous occasions permitted investments in various
economic development activities. In UE's case, the Commission approved an
investment in 1962 (at which time UE was a registered holding company) in a
Civic Center Redevelopment Corporation, which was sponsored by a group of
citizens of St. Louis and supported by newspapers, banks, department stores,
manufacturers, merchants, labor unions, and public utility companies in
metropolitan St. Louis. This venture was to assist in the complete redevelopment
of an area of 31 blocks of about 82 acres in the main business district of St.
Louis. Union Electric Co., Release No. 35-14608 (Mar. 22, 1962). See also,
------------------
Appalachian Power Co., Release No. 35-25266 (growth capital in new and expanding
- ---------------------
small, rural firms to improve local economy); Missouri Power & Light Co.,
--------------------------
Release No. 35-12524 (June 3, 1954) (industrial enterprises supported by
community businesses to fulfil civic responsibility).
See also, 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); 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
--------------
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
3
<PAGE>
Gateway National Bank -- At June 30, 1997, approximately $60,000 was
invested in non-voting 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./9/
Laclede's Landing Redevelopment -- At June 30, 1997, $10,000 was
invested in a less than 5% limited partnership interest in this limited
partnership, which is engaged in neighborhood commercial redevelopment
projects in St. Louis, Missouri./10/
Kiel Investments -- At June 30, 1997, $5.86 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 located two
blocks from UE's headquarters in St. Louis, Missouri. The partnership also
owns 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.
The Kiel Center provides substantial economic and civic benefits to
the St. Louis area. In addition to professional hockey, the Kiel Center
hosts professional soccer, college basketball, concerts, meetings,
conventions and other similar events. Kiel Center is a unique facility in
the region and is a major stimulator of economic activity in the downtown
area.
The partnership that constructed and now owns Kiel Center consists of
the largest corporations operating in the St. Louis area. Ownership of the
St. Louis Blues is incidental to and as a result of ownership of the Kiel
Center. Consolidating ownership of the Blues and the Kiel Center in one
group was accomplished in part to provide financial stability to the Kiel
Center and thus support the existence of space for other civic and
community purposes. The financial stability of the Kiel Center is vital to
the success of its overall economic development purposes. Furthermore, the
Blues presence in St. Louis makes a positive contribution to the image and
economic well-being of the region. Retaining local ownership of the hockey
team assures that these benefits will continue.
UEDC's Kiel investments, though relatively small, are extremely
important to the continued ability of the partnership to provide the
essential community benefits described
_____________________
(...continued)
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).
/9/ See Notes 8 and 11. As the holder of non-voting preferred stock, UEDC has
no vote in the direction or management of the affairs of Gateway National
Bank.
/10/ See Note 8.
4
<PAGE>
above. Shareholders and customers also benefit because the Kiel Center is
located in UE's service territory and is a significant electric customer.
Any impairment of UE's continued participation in Kiel investments
would have an extremely negative impact on UE's ability to fulfill its
necessary and beneficial civic obligations. Moreover, the partnerships are
structured so that it would be very difficult for UE to withdraw
therefrom./11/
St. Louis Equity Fund -- At June 30, 1997, $2.59 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. More than 30 major St. Louis corporations are
investors and also participate in various committees./12/
___________________
/11/ See the cases cited in Note 8 for decisions approving economic development
and civic responsibility investments. In addition, the Commission has allowed
investments in other businesses which clearly had no connection to the utility
business in special circumstances. In National Fuel Gas Co. Release No. 23466
--------------------
(Nov. 1, 1984), the Commission approved an investment in a venture capital firm
whose sole investment was to be a regional commercial airline company which
provided air service to the utility's headquarters city. It appears from the
decision that the utility was concerned that vital air service would be lost to
the community without the support of the venture capital investment. UE's
support of the Kiel Center, together with that of other community leaders, was
instrumental in the success of the project which is providing significant
economic development advantages to St. Louis.
Under the terms of the Kiel partnership agreement and Missouri law, the
general partner (an entity unaffiliated with Ameren) will have the full,
exclusive and complete authority and discretion in the management and control of
the business of the partnership subject to limited approval rights of the
limited partners. The supermajority approval of limited partners is required for
certain extraordinary actions such as sale of substantially all the partnership
assets, removal of the general partner for cause, admitting a new general
partner and changing the nature of the business of the partnership. These rights
are such that the limited partnership interests do not constitute a "voting
security" within the meaning of Section 2(a)(11) of the Act. See Cinergy Corp.,
------------
Release No. 35-26562 (Aug. 28, 1996).
/12/ Georgia Power Co., Release No. 35-26220 (Jan. 24, 1995) (limited
-----------------
partnership investments in low-income housing projects that qualify for low-
income housing tax credit under Section 42 of the Internal Revenue Code).
Subsequent to June 30, 1997, an additional, identical investment was made for
calender year 1997.
UEDC's investments in limited partnerships or limited liability companies
which are engaged in providing low income housing are distinguishable from the
situation in Michigan
--------
5
<PAGE>
Housing Missouri -- At June 30, 1997, $34,003 was invested in or
committed to a 14% interest in this limited liability corporation, which
owns low income housing in Missouri outside the St. Louis area. Such
investments produce low income housing federal income tax credits for
UE./13/ One officer of UE is on the board of directors and investment
policy committee of Housing Missouri.
Other Activities -- UEDC is directly involved (not through investments
in other entities)in certain other activities:
______________________
(...continued)
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 and fulfilling UE's civic responsibilities in the communities it serves.
UEDC's investments appear to be substantially identical to those approved in
Georgia Power referred to above.
- -------------
As noted, certain of these investments are in the form of limited liability
companies. Unlike in limited partnerships, investors in an LLC may participate
in the management of the LLC without the risk of losing limited liability
status. Accordingly, the operating agreements of these LLC's do not limit the
voting rights or rights to participate in the management of the entity as does a
typical limited partnership agreement. Under Missouri law, however, the
management of the LLC is vested in the "manager" if one is provided for, as is
the case in each of the LLCs described. The member interest which UEDC has in
the LLC's may be a "voting security" within the meaning of Section 2(a)(17) of
the Act such that any such interest of 5% or more would make the entity an
"affiliate" as defined in Section 2(a)(11). See Public Service Company of
-------------------------
Oklahoma, Release No. 35-26445 (Dec. 29, 1995); compare In re Metropolitan
- -------- ------- ------------------
Edison Co., Release No. 35-14973 (Dec. 5, 1963) (9% voting investment in
- ---------
economic development corporation). Unless otherwise approved by the Commission,
Ameren proposes to reduce, not later than 3 years from the date of the
Commission Order in this Docket, its voting interest or investment so that such
LLC's will not constitute affiliates of Ameren under the Act. Under the terms of
the limited partnership agreements and Missouri law, the general partner (an
entity unaffiliated with Ameren) will have the full authority and discretion in
the management and control of the business of such of these investments as are
limited partnerships, subject to limited approval rights of the limited
partners. The majority approval of limited partners is required for certain
extraordinary actions such as replacing the general partner or amending the
partnership agreement other than in certain respects where the general partner
may effect amendments without such approval. Certain actions relating to the
business of the partnership require the approval of the investment committee.
These rights are such that the limited partnership interests do not constitute a
"voting security" within the meaning of Section 2(a)(11) of the Act. See Cinergy
-------
Corp., Release No. 35-26562 (Aug. 28, 1996). See Note 25.
- ----
/13/ See Note 12.
6
<PAGE>
Turn-Key leasing: UEDC acts as a finder for bank or other lender
financing for capital improvement projects within UE's service territory. UEDC
does not perform due diligence or loan money or provide any guaranties in the
course of any transaction. This is incidental to its economic development
activities outlined above.
Distribution Services: UEDC provides maintenance and repair services
for large business customers receiving primary voltage electric service and who
own or operate electrical substation equipment./14/
Energy Audits: Energy audits are conducted and efficiency solutions
are implemented through alliances with an engineering firm an a mechanical
contractor./15/
c. Other Activities Marketing -- UE and UEDC have applied for a power
----------------
marketing license from FERC. No power marketing activities have yet been
undertaken and no significant investment has been made./16/ Any future
activity or investment not described herein will only be made in accordance
with applicable rules (such as Rules 40 and 58) or pursuant to application
made to the Commission for specific approval.
From CIPSCO, Ameren will hold the following nonutility subsidiaries and
investments:
3. CIPSCO Investment Company ("CIPSCO Investment")
CIPSCO Investment manages CIPSCO's nonutility investments and 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./17/ At June 30, 1997, the total amount
invested through CIPSCO Investment and its subsidiaries was $125.4 million as
follows:
a. CIPSCO Securities Company ("CIPSCO Securities")
CIPSCO Securities invests in marketable securities./18/ At June 30,
1997 $54.1 million was invested in hedged portfolios of preferred and
common stocks and other
_____________________
/14/ See Note 3.
/15/ See Note 6
/16/ Wholesale and retail power and energy marketing activities have been
approved for several registered holding companies. See, e.g., SEI Holdings,
---------- ------------
Release No. 35-26581 (Sept. 26, 1996).
/17/ Certain of the marketable securities described below as being held by
CIPSCO Securities and the Illinois Equity Fund Limited Partnerships described
below as being held by CIPSCO Venture Company (see Note 28) are held directly by
CIPSCO Investment.
/18/ In Amendment No. 4 to the Application, Ameren has indicated that CIPSCO
Securities will undertake to liquidate or otherwise dispose of the investments
described as items 1 through 5 in this subsection. Ameren has requested approval
to dispose of such investments over a period not exceeding 3 years from the date
of the Commission's Order in this Docket.
7
<PAGE>
marketable securities. Of this amount, approximately $26.2 million 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. Details regarding the marketable securities
investments are as follows:
1. Flaherty & Crumrine Preferred Stock Portfolio -- A portfolio of
adjustable rate, sinking fund, and perpetual preferred stock hedged
with financial futures and options. Flaherty & Crumrine acts as
investment manager pursuant to investment guidelines established by
CIPSCO Securities. CIPSCO Securities is beneficial owner of the
portfolio of securities but all buy and sell orders are made by the
investment manager. Investment guidelines include limitations on
amounts invested in any one issue and exposure to any issuer as well
as minimum ratings. Initial Investment Cost: $12,000,000 in June
1991. Market Value as of June 30, 1997: $20,360,761. Investment in
utility preferred stock: 52%, $10.7 million.
2. Spectrum Preferred Stock Portfolio -- A portfolio of high quality
fixed-dividend, utility sinking fund and perpetual preferred stocks
hedged with financial futures and options. Spectrum acts as investment
manager pursuant to investment guidelines established by CIPSCO
Securities. CIPSCO Securities is beneficial owner of the portfolio of
securities but all buy and sell orders are made by the investment
manager. Investment guidelines include limitations on amounts
invested in any one issue and exposure to any issuer as well as
minimum ratings. Initial Investment Cost: $10,000,000 in June 1991.
Market Value as of June 30, 1997: $15,685,593. Investment in utility
preferred stock: 99%, $15.5 million.
3. Gateway Index Risk Adjusted Program -- A portfolio consisting of
substantially all common stocks represented in the S&P 100 Index and
hedged with S&P 100 and S&P 500 Index options. Gateway acts as
investment manager pursuant to investment guidelines established by
CIPSCO Securities. CIPSCO Securities is beneficial owner of the
portfolio of securities but all buy and sell orders are made by the
investment manager. Investment guidelines limit investment to no more
than 2% of the outstanding amount of any class of equity security of
an issuer. Total exposure to any issuer is limited to 10% of the
portfolio. Initial Investment Cost: $5,200,000 in September 1990.
Market Value as of June 30, 1997: $9,091,774. Since this fund is
meant to match the S&P 100, those utilities included in the S&P 100
Index will be proportionally included (approximate June 30, 1997
value: $47,100).
4. Mesirow Alternative Strategies Fund, L.P. -- A multi-manager
investment partnership that seeks to achieve a superior long-term
return in equity securities with a lower degree of volatility than the
S&P 500 Index. CIPSCO Securities holds a limited partnership interest.
The partnership is beneficial owner of all securities but all buy and
sell orders are made by the investment manager. Initial Investment
Cost: $2,900,000 in March of 1995. Market Value as of June 30, 1997:
$3,916,522. This investment is in liquidation which is to be completed
prior to the end of 1997.
8
<PAGE>
5. Genesee Eagle Fund -- A multi-manager investment partnership that
seeks to achieve a superior long-term return with a lower degree of
volatility than the S&P 500 Index through equity and other
investments. CIPSCO Securities holds a limited partnership interest.
The partnership is beneficial owner of all securities but all buy and
sell orders are made by the investment manager. Initial Investment
Cost: $2,900,000 in July 1994. Market Value as of June 30, 1997:
$4,583,553. This investment is in liquidation which is to be completed
prior to the end of 1997
In addition, at June 30, 1997, CIPSCO Securities had $2.0 million of
temporary marketable investments in the Dreyfus Treasury Prime Cash
Management Fund, a money market mutual fund designed for institutional
investors with the objective of preserving capital and maintaining
liquidity. This fund invests only in securities issued or guarantied by
the U.S. Government and consequently is permitted under Section 9(c)(1) of
the Act./19/
b. CIPSCO Leasing Company.
Passive, financial investments in long-term leveraged lease transactions.
At June 30, 1997, $34.7 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./20/
c. CIPSCO Energy Company.
Passive, financial energy-related investment opportunities.
Turbine Leases. At June 30, 1997, $23.5 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./21/
________________________
/19/ Accordingly this investment need not be liquidated.
/20/ Central and South West Corp. Release No. 35-23578 (Jan. 22, 1985) (passive,
---------------------------
tax advantaged leveraged lease structure). Details regarding the four leveraged
lease transactions are presented in Attachment 1 to this Exhibit K-4. A schedule
showing the timing of the aggregate tax benefits of the four leases is set forth
on Attachment 2 to this Exhibit K-4. As the Attachment 2 shows, the portfolio
was designed to provide tax benefits in the early years.
/21/ Each of these investments is in the form of a leveraged lease like those
referred to in Note 20. Although the turbines which are subject of the leases
would constitute electric utility facilities
(continued...)
9
<PAGE>
Cogeneration. At June 30, 1997, $5.5 million was invested in 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./22/
d. CIPSCO Venture Company ("CIPSCO Venture").
Invests within the CIPS service territory. These investments are the civic
and economic development investments of CIPSCO important to the fulfillment of
CIPSCO's responsibilities as a good corporate citizen./23/ In addition,
enhancement of economic development in the CIPS service territory is beneficial
to CIPS's customers and to shareholders. In many areas of the CIPS service
territory, particularly in Southern Illinois, unemployment is at high rates and
economic activity is generally very depressed relative to other parts of the
State and United States. CIPS has for many years been active in job creating
economic development activities in these areas. CIPSCO Venture is able to expand
on the activities carried out by CIPS. Investment capital is scarce in this
area. As one of the few large, public companies located and operating in the
area, CIPSCO, through CIPSCO Venture, can be a source of capital for economic
development when few other sources are available. The participation of CIPSCO
Venture is often critical in attracting the necessary investment for a
project. CIPSCO Venture's activities have focused on cooperating with State,
county and local economic development agencies and others to provide
infrastructure to assist local businesses to start or expand in this area. The
two investments referred to in paragraphs 1 and 2 below are "industrial park"
developments designed to provide the infrastructure to facilitate businesses
locating in the area. CIPSCO Ventures looks for quality investments which are
likely to produce a good return, but investment return is not the sole or
primary purpose of CIPSCO Venture activities. Seeking an attractive return is
not inconsistent with the economic development motivation which has formed the
basis for Commission approval in similar cases./24/
Each investment of CIPSCO Venture described below is passive. Neither
CIPSCO Venture nor any of its affiliates takes any role in the management of the
underlying business which is the focus of the investment and its role in the
limited liability company that is the investment vehicle is generally equivalent
to that of a limited partner in a limited partnership.
_____________________________
(...continued)
under Section 2(a)(3), by virtue of Rule 7(d), the entities that hold title to
the turbines are not "electric utility companies." In each of these transactions
the appropriate certificate on Form U-7D has been filed. Additional details,
including the docket number of the Form U-7D filing, are included in Attachment
1 to this Exhibit K-4.
/22/ The cogeneration facility is a qualifying facility under PURPA pursuant to
FERC determination in docket QF 87-250-000. See Attachment 1 to this Exhibit K-
4 for details.
/23/ See Notes 8, 11 and 12.
/24/ Georgia Power Co., Release No. 35-25949 (Dec. 15, 1993) (venture capital
investments could be sought outside service territory to achieve superior
returns); Appalachian Power Co., Release No. 35-25266 (Mar. 6, 1991) (growth
capital in small, rural firms with the potential to offer significant returns on
investment and to improve local economy). The activities of CIPSCO Venture are
distinguishable from the situation in Michigan Consolidated, supra Note 12. In
that case, the registered holding company subsidiaries were actively engaged in
the development, financing, construction and other aspects of the business of
providing low income housing. The Commission's decision, upheld on appeal, was
that such active participation in and control of a business not functionally
related to the utility business was not permitted under the Act. This was the
case even though the activity also involved service area development which, in a
proper situation, would be permitted as shown by the cases cited above in this
Note. The Commission emphasized this distinction in Michigan Consolidated noting
that allowable economic development activities "involved only investments in,
and have not involved ownership and control of, another business by an acquiring
company." Michigan Consolidated, 44 SEC at 367. As noted herein, CIPSCO Venture
takes no role in the management of the limited liability companies in which it
has investments. Further, Ameren has committed to reduce its voting percentage
or investment in any of these entities so they would not constitute affiliates
under the Act thus ensuring that it will not control the entities. Thus, the
CIPSCO Venture activities are consistent with those approved in Georgia Power,
Appalachian Power and similar cases cited in Notes 8 and 26 and distinguishable
from Michigan Consolidated.
10
<PAGE>
CIPSCO Venture is not the controlling member of these entities./25/ At June 30,
1997, $3,250,000 was invested or committed as follows:
1. Effingham Development Building II Limited Liability Company -- A 40%
equity investment in a $6.5 million Limited Liability Company which owns a
manufacturing facility leased to an industrial customer of CIPS. CIPSCO
Venture is not the managing member of this LLC, but has certain voting
rights up to the percent of equity ownership in the LLC. (September 1994)
CIPSCO Venture was instrumental in acting as a catalyst to ensure that this
industrial customer, which is one of CIPS major customers representing a 5
MW load and about $1.3 million in annual revenues, would locate in southern
Illinois. The facility is a 267,056 square foot manufacturing facility
located in an Effingham, Illinois industrial park./26/
2. Mattoon Enterprise Park -- A 20% equity investment in a Limited
Liability Company which owns 231 acres of farmland to be used for
development of an industrial park within the boundaries of the City of
Mattoon and CIPS service territory. CIPSCO Venture is not the managing
member of this LLC, but has certain voting rights up to the percent of
equity ownership in the LLC. CIPSCO Venture's investment is $165,200.
Since June 30, 1997, CIPSCO Venture has made an additional investment of
$110,000 in
_____________________
/25/ These investments are in the form of limited liability companies ("LLC's").
Unlike in limited partnerships, investors in an LLC may participate in the
management of the LLC without the risk of loosing limited liability status.
Accordingly, the operating agreements of these LLC's do not limit the voting
rights or rights to participate in the management of the entity as does a
typical limited partnership agreement. Under Illinois law, however, the
management of the LLC is vested in the "manager" if one is provided for, as is
the case in each of the LLCs described. The member interest which CIPSCO
Venture has in the LLC's may be a "voting security" within the meaning of
Section 2(a)(17) of the Act such that any such interest of 5% or more would make
the entity an "affiliate" as defined in Section 2(a)(11). See Public Service
--------------
Company of Oklahoma, Release No. 35-26445 (Dec. 29, 1995); compare In re
- ------------------- ------- -----
Metropolitan Edison Co., Release No. 35-14973 (Dec. 5, 1963) (9% voting
- ----------------------
investment in economic development corporation). Unless otherwise approved by
the Commission, Ameren proposes to reduce, not later than 3 years from the date
of the Commission Order in this Docket, its voting interest or investment so
that such LLC's will not constitute affiliates of Ameren under the Act. See Note
12.
/26/ The Commission has approved similar real estate projects. East Ohio Gas
-------------
Co., Release No. 35-25046 (Feb. 27, 1990) (limited partnership to finance the
- --
development of real estate projects in downtown Cleveland designed to create
jobs and other benefits). See also, Georgia Power Co., Release No.
-----------------
35-25949 (Dec. 15, 1993) (venture capital investments in high technology
companies located in the utility's service territory); Appalachian Power
-----------------
Co., Release No. 35-25266 (Mar. 6, 1991) (growth capital in small, rural firms
- --
with the potential to offer significant returns on investment and to improve
local economy); Northeast Utilities, Release No. 35-24585 (Feb. 24, 1988)
(venture capital with holding company invited to participate because of its
technology-related business interest and its strong presence, through its
operating utility, in the state); In re Missouri Power & Light Co., Release No.
-------------------------------
35-12524 (Jun. 3, 1954) (investment in industrial enterprises as part of civic
responsibility).
11
<PAGE>
a 33.3% equity interest in MAAC, LLC which owns a wharehousing facility
located in the Mattoon Enterprise Park./27/
3. Illinois Equity Fund Limited Partnerships -- The funds are real estate
investment funds that finance rental housing developments in Illinois
outside the six-county Chicagoland area. They consist of limited
partnerships that develop low income housing so that they can receive tax
savings generated by the Section 42 federal low-income housing tax credits.
There are three separate funds: 1992, 1994 and 1996. The commitment to
those funds is: $2.5 million./28/
September 1997
____________________________
/27/ These investments are substantially the same as the Effingham development
referred to in Item 1 above. See cases cited in Note 26.
/28/ See Note 12.
12
<PAGE>
Attachment 1 to Amended Exhibit K-4
Additional Information on CIPSCO Leveraged Leases
and Turbine Investments
CIPSCO Leasing Company (CLC) Total current asset book value $34.7 million.
1. CIPSCO Leasing Company (KN Energy)
Transaction: A 17.5% undivided interest in a leveraged lease
financing of a natural gas liquids plant. All operations are the
responsibility of lessee. (November 1991)
Equipment Description: The plant removes natural gas liquids and
moisture from natural gas thereby improving the operational
efficiency of the natural gas pipeline. The equipment consists of
gas processing and related equipment; lean oil absorption unit,
turbo expander, fractionist unit, helium unit, and truck rack.
Lessee: KN Energy (with guarantee from original lessee, ENRON
Corp.)
Lease Term: 21 years (subject to certain lessee purchase or
renewal options)
Lease Termination Date: May 25, 2012
2. CLC Leasing Company A (Amoco)
Transaction: An equity investment in a leveraged lease financing
of various oil and gas production treating and processing
equipment with Amoco Corporation. This investment represents 25%
of a $63 million lease transaction. All operations are the
responsibility of lessee. (December 1991)
Equipment Description: New oil and gas production, treating and
processing equipment such as pumping units, pressure vessels,
tanks, compressors and related equipment. The equipment is
located in various locations within five southwestern states.
Lessee: Amoco Equipment Leasing Company
Lease Term: 18 years (subject to certain lessee purchase or
renewal options)
Lease Termination Date: June 18, 2009
3. CLC Aircraft Leasing Company (Delta)
Transaction: An equity investment in a leveraged lease financing
of one new McDonnell Douglas MD-88 aircraft for lease to Delta
Airlines. All operations are the responsibility of lessee.
(September 1991)
<PAGE>
Equipment Description: One (1) McDonnell Douglas MD-88 narrow
body aircraft, primarily used on Delta's domestic routes and on a
limited basis, outside the U.S.
Lessee: Delta Airlines, Inc.
Lease Term: 22 years (subject to certain lessee purchase and
renewal options)
Lease Termination Date: September 23, 2013
4. CLC Leasing Company B
Properties: A sale/leaseback of 15 Wal-Mart stores in six states.
The properties were completed in 1991 or early 1992. Wal-Mart
retains ownership of the underlying land and grants a site lease
for the term of the lease and any renewals thereof. All
operations are the responsibility of lessee. (December 1992)
Structure: There are individual leases on each store in the
package. The lease is a triple net lease with lessee responsible
for maintenance, insurance and most taxes.
Lease Term: 20 years (subject to certain lessee purchase and
renewal options)
Lease Termination Date: December 21, 2012
CIPSCO Energy Company (CEC) Total current asset book value $29 million.
1. Beaver Generating Station Combustion Turbine Units
Lessee: Portland General Electric Company
Transaction: 51% interest in a Partnership which owns two turbine
generators currently serving Portland General Electric. Lessee
has full responsibility for operation and maintenance of the
equipment. All units are currently connected to a 150 MW combined
cycle system with individual HRSGs, which are owned by the
lessee. These units are currently operated as base to
intermediate load units. CEC is the general partner of the
Partnership. (August 1993)
Location: Beaver Generating Station, Units 5 & 6 Beaver, Oregon.
Original Delivery Date: August 8, 1974. Lease Termination Date:
August 8, 1999 (subject to certain lessee purchase and renewal
options).
SEC U-7D: #32-334, 9/21/93
2. Blytheville Generating Station Combustion Turbine Units
Transaction: 51% interest in a Partnership which owns three
combustion turbines currently serving Arkansas Power & Light
(Entergy). The units are currently used as peaking units. Lessee
has full responsibility for operation and maintenance of the
equipment. CEC is the general partner of the Partnership.
2
<PAGE>
(August 1993) Location: Blytheville Generation Station, Units 1,
2 & 3 Blytheville, Arkansas. Original Delivery Date: August 28,
1974. Lease Termination Date: August 28, 1999.
SEC U-7D: #32-341, 9/21/93
3. Whitehorn Station Combustion Turbine Units
Transaction: 51% interest in a Partnership which owns two
combustion turbines which drive one power generator (twin pac)
currently serving Puget Sound Power & Light Company. Lessee has
full responsibility for operation and maintenance of the
equipment. The unit is gas fired and has black start capability.
It is currently used for peaking capacity. CEC is the general
partner of the Partnership. Location: Whitehorn, Washington.
Original Delivery Date: December 11, 1974. Lease Termination
Date: December 11, 1999 (subject to certain lessee purchase and
renewal options).
SEC U-7D: # not known, but filed, 9/21/93
4. Greenwood Energy Center Combustion Turbine Units
Transaction: 28.5% interest in a Partnership which owns two gas
fired combustion turbines currently serving Missouri Public
Service, a subsidiary of Utilicorp. Lessee has full
responsibility for operation and maintenance of the equipment.
The units are currently used as peaking units. CEC is the general
partner of the Partnership. Location: Jackson County, Missouri.
Original Delivery Date: June 30, 1975. Lease Termination Date:
June 30, 2000 (subject to certain lessee purchase and renewal
options).
SEC U-7D: #32-345, 6/21/94
5. Mickleton Plant Combustion Turbine Unit
Transaction: 100% interest in a Partnership which owns a single
turbine generator with dual fuel capability, currently serving
Atlantic City Electric. Unit is currently run as a peaking unit
and for voltage support. Lessee has full responsibility for
operation and maintenance of the equipment. Lease includes
additional equipment such as transmission transformer, black
start equipment and fuel tanks. CEC is the general partner of the
Partnership. (July 1995). Location: Near Paulsboro, New Jersey.
Original Delivery Date: July 2, 1974. Lease Termination Date:
July 2, 1999 (subject to certain lessee purchase and renewal
options).
SEC U-7D: #32-338, 8/3/94
6. Appomattox Cogeneration Limited Partnership (ACLP)
3
<PAGE>
Description: A 24.75% limited partnership interest in a limited
partnership which owns a Power Sales Agreement associated with a
40 MW cogeneration facility. Term: Through October 2004. Power
Purchase Agreement: ACLP sells the net electrical output from
this Qualifying Facility to Virginia Electric Power Company under
an agreement expiring in 2004. Volume is approximately 3500 MW
per year.
Qualifying Facility: QF87-250-000
4
<PAGE>
ATTACHMENT 2 TO EXHIBIT K-4
SCHEDULE OF LEVERAGES LEASES/CURRENT TAXES PAID
<TABLE>
<CAPTION>
YEAR TOTAL - ALL
----
EXISTING LEASES
---------------
<S> <C>
1991 $(3,093,908)
1992 (3,269,947)
1993 (9,566,467)
1994 (4,372,983)
1995 (3,085,861)
1996 (2,971,649)
1997 (2,746,649)
1998 (1,803,210)
1999 (96,693)
2000 583,670
2001 653,711
2002 826,856
2003 1,905,350
2004 3,117,294
2005 3,187,775
2006 4,451,226
2007 3,298,733
2008 2,594,167
2009 5,348,276
2010 3,750,660
2011 4,547,993
2012 5,502,940
2013 1,247,927
2014 2,371,486
2015 43,327
- ------------ -----------
TOTAL $12,424,029
===========
</TABLE>
5
