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As filed with the Securities and Exchange Commission on October 30, 1997
File No. 70-8945
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
______________________________
AMENDMENT NO. 4
TO
FORM U-1
APPLICATION/DECLARATION
UNDER
THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
______________________________
Ameren Corporation
1901 Chouteau Avenue
St. Louis, Missouri 63103
(Name of company filing this statement
and address of principal executive offices)
None
(Name of top registered holding company)
William E. Jaudes
Registered Agent
Ameren Corporation
1901 Chouteau Avenue
St. Louis, Missouri 63103
(Names and addresses of agents of service)
The Commission is requested to send copies of all notices, orders and
communications in connection with this Application to:
James J. Cook William J. Harmon
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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A. Introduction
This Application/Declaration, originally filed October 31, 1996 and amended
through Amendment No.3 (the "Application"), 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").
Ameren submits this Amendment No. 4:
(1) to describe and file (a) the Order (the "ICC Order") of the
Illinois Commerce Commission ("ICC") entered September 10, 1997; the
Order (the "FERC Order") of the Federal Energy Regulatory Commission
("FERC") entered October 15, 1997 and (c) the Order (the "NRC Order")
of the Nuclear Regulatory Commission ("NRC") entered October 16, 1997,
in each case approving the Transaction;
(2) to revised the Application to indicate that the electric and gas
facilities of UE used to provide retail service in Illinois (referred
to in the original Application as the "Transferred Utility
Facilities") will not be transferred to CIPS;
(3) to provide additional information under Item 3.A.2.b.(ii) (B) of
the Application regarding satisfaction of the requirements of Section
10(c)(2) and Section 2(a)(29) of the Act and showing that the combined
gas operations of UE and CIPS after the Transaction will constitute an
integrated public utility system;
(4) to provide additional information regarding the retention by
Ameren of the non-utility investments of CIPSCO Investment Company
("CIPSCO Investment");
(5) to provide a description of the Ameren Services Company Policies
and Procedures and file such document as Exhibit B-5; and
(6) to file certain Exhibits hereto as described below.
B. The ICC Order; FERC Order and NRC Order
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 filed
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herewith. 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./1/
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;
(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
Application for Rehearing of the ICC Order and has filed an action against the
ICC in the Circuit Court, Tenth Judicial Circuit, Tazewell County, Illinois
(Case No. 97-CH-62). The filing of these pleadings does
__________________
/1/ 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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not affect the finality of the ICC Order and the ICC Order grants the parties
full authority under Illinois law to consummate the Transaction.
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.
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-4.2 is a Post
Operating License Antitrust Review Finding of No Significant Changes and a
Safety Evaluation.
C. Transferred Utility Facilities
As noted above, the ICC did not approve the proposal to transfer to CIPS
the UE retail electric and gas facilities located in Illinois./2/ 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. References to the Transferred Utility Facilities in
the Application are hereby deleted and 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.
D. Gas Operations as an Integrated Public Utility System
The Application describes the facilities and current operations of the gas
operations of each of UE and CIPS including information on the present
coordination of such operations. Since the Application was filed in October,
1996, UE and CIPS have made further study regarding how the gas operations of
the two companies can be further integrated and coordinated following the
Transaction. Accordingly, Ameren hereby amends and restates Item 3.A.2.b.(ii)(B)
of the Application as follows:
_________________
/2/ ICC Order, Finding 10(c) (Docket 95-0551, slip op at 69).
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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 as:
a system consisting of one or more gas utility companies which are so
located and related that substantial economies may be effectuated by
being operated as a single coordinated system confined in its
operation to a single area or region, in one or more States, not so
large as to impair (considering the state of the art and the area or
region affected) the advantages of localized management, efficient
operation, and the effectiveness of regulation: provided, that gas
utility companies deriving natural gas from a common source of supply
may be deemed to be included in a single area or region.
The Ameren gas utility system will meet the standard set forth in Section
2(a)(29)(B) and, therefore, will satisfy the requirements of Sections 10(c)(1)
and (2) and should be approved by the Commission.
First, both the Commission's limited precedent and current technological
realities indicate that the Ameren gas utility system will operate as a
coordinated system confined in its operation to a single area or region because
it will derive natural gas from common sources of supply, transportation and
storage. The gas utility operations of UE and CIPS will operate in a single
area or region covering portions of Missouri and Illinois. See Exhibits E-5 and
---
E-7 hereto. The Commission has not traditionally required that the pipeline
facilities of an integrated system be physically interconnected,/3/ 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./4/ The Commission
also has considered obtaining gas from a common pipeline/5/ as well as from
different
_______________
/3/ See MCN Corp., Release No. 35-26576 (Sept. 17, 1996) (physically separate
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systems served from same fields; anticipated coordinated gas purchasing
operations); In re Pennzoil Co., 43 SEC 709 (Feb. 7, 1968) (finding an
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integrated system where facilities both connected with an unaffiliated
transmission company but not each other). See also, In re American Natural
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Gas Co., 43 SEC 203 (Dec. 12, 1966) ("It is clear the integrated or
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coordinated operations of a gas system under the Act may exist in the
absence of such interconnection").
/4/ 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
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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).
/5/ In re North American Co., 31 SEC 463 (May 19, 1950) (finding Panhandle
-----------------------
Eastern
(continued...)
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pipelines when the gas originates from he same gas field in determining a common
source of supply. /6/ Since the time most of these decisions, the state of the
art in the industry has developed to allow efficient operation of systems whose
gas supplies derieve 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
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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 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
_______________
/5/ (...continued)
pipeline to be a common source of supply).
/6/ See In re Central Power Co. and Northwestern Public Service Co., 8
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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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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 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 areas: the Mid-Continent and Gulf
Coast regions.
Integrated UE and CIPS gas operations would present opportunities to use
more consolidated gas supply procurement to increase competition among
suppliers, transporters and storage providers to capture approximately $37
million in delivered gas cost reductions. One hundred percent of these
reductions will flow directly through to customers under the purchased gas
adjustment (PGA) clauses in UE's and CIPS' tariffs if all of the system
purchased gas costs continue to receive PGA treatment as at present. Integrated
gas operations could also offer opportunities for more efficient utilization of
UE and CIPS peak shaving operations and more efficient reserve margins. With
the cooperation of the common pipeline interconnections, the ability to engage
in swap transactions will also exist.
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
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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).
------------------
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 in Part C 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).
E. Retention of Non-Utility Investments
As noted in the Application and in particular Exhibit K-4, Ameren has
described in detail its existing non-utility investments/7/ and demonstrated
that such investments, except as noted below, may be retained after consummation
of the Transaction in accordance with the Act and Commission precedent. Ameren
files herewith 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.
________________
/7/ 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 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).
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Ameren has determined that the investments currently held by CIPSCO
Securities in five investment funds should be liquidated or otherwise disposed
of in an orderly fashion./8/ 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 that
such limited liability companies will not constitute affiliates of Ameren under
the Act.
F. Ameren Service Policies and Procedures
As noted in Item 3.C. of the original U-1 filing herein, Ameren Services
Company ("Ameren Services") will provide services to Ameren's utility and
non-utility subsidiaries pursuant to a General Services Agreement previously
filed as Exhibit B-4. 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/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 request 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
________________
/8/ 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 3 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, have already
been given with 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 disposition will be
applied to the business of Ameren which may include investments as described in
footnote 7 above or may be used by Ameren to pay dividends on its common stock.
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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 than 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.
G. Additional or Amended Exhibits.
As noted above the Procedures, the ICC Order, the FERC Order, the NRC Order
and revised information detailing non-utility investments are filed herewith. A
new Exhibit K-2.1 is also filed which sets forth a comparison of the "lost
economies" referred to in prior Commission decisions relating to whether an
additional utility system could be retained under Clause A of Section 11(b)(1)
of the Act. Exhibit K-2.1 includes information from recent decisions and shows
that the loss of economies that would result from a disposition of the gas
system of Ameren would exceed similar losses demonstrated in the other cases.
Certain other exhibits previously described in the U-1 are also filed herewith
as noted below.
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Item 6. Exhibits and Financial Statements
A. Exhibits
The following Exhibits are filed with this Amendment No. 4:
Amended
Exhibit B-4 Form of General Services Agreement
Exhibit B-5 Ameren Services Company Policies and Procedures
Exhibit C-3 Form S-3 re Dividend Reinvestment Plan
Exhibit C-4 Form S-8 re Long-Term Incentive Plan
Exhibit C-5 Description of existing savings plans
Exhibit D-1.3 Order of the FERC dated October 15, 1997
Exhibit D-3.2 ICC order dated September 10, 1997
Exhibit D-4.2 Order of the NRC dated October 16, 1997
Exhibit K-2.1 Updated Table of Estimated Lost Economies
Amended
Exhibit K-4 Description of Non-Utility Investments
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SIGNATURE
Pursuant to the requirements of the Public Utility Holding Company Act of
1935, the undersigned company has duly caused this Amendment No. 4 to
Application/Declaration to be signed on its behalf by the undersigned thereunto
duly authorized.
Date: October 30, 1997
AMEREN CORPORATION
/s/ William E. Jaudes
----------------------
By: William E. Jaudes
Secretary
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Exhibit Index
to Amendment No. 4
A. Exhibits
<TABLE>
<CAPTION>
Exhibit No. Description Form of
----------- ----------- Transmission
------------
<S> <C> <C>
Amended Form of General Services Electronic
Exhibit B-4 Agreement
Exhibit B-5 Ameren Services Company Electronic
Policies and Procedures
Exhibit C-3 Form S-3 re Dividend Electronic
Reinvestment Plan
Exhibit C-4 Form S-8 re Long-Term Electronic
Incentive Plan
Exhibit C-5 Description of existing Electronic
savings plans
Exhibit D-1.3 Order of the FERC dated Electronic
October 15, 1997
Exhibit D-3.2 ICC order dated September 10, Electronic
1997
Exhibit D-4.2 Order of the NRC dated Electronic
October 16, 1997
Exhibit K-2.1 Updated Table of Estimated Electronic
Lost Economies
Amended Electronic
Exhibit K-4 Description of Non-Utility
Investments
</TABLE>
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EXHIBIT B-4
GENERAL SERVICES AGREEMENT
BETWEEN
AMEREN SERVICES COMPANY
AND
AMEREN CORPORATION, UNION ELECTRIC COMPANY,
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY, AND
CIPSCO INVESTMENT COMPANY
THIS AGREEMENT, made and entered into this _____ day of _________ 1996, by
and between the following Parties: AMEREN SERVICES COMPANY (hereinafter
sometimes referred to as "Service Company") , a Missouri corporation; and AMEREN
CORPORATION ("Ameren Corporation"), a Missouri Corporation; UNION ELECTRIC
COMPANY ("UE"), a Missouri corporation; CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
("CIPS"), an Illinois corporation, and CIPSCO INVESTMENT COMPANY, ("CIC"), an
Illinois corporation, (hereinafter sometimes referred to collectively as "Client
Companies");
WITNESSETH:
WHEREAS, Client Companies, including Ameren Corporation, which has filed
for registration under the terms of the Public Utility Holding Company Act of
1935 (the "Act") and its other subsidiaries, desire to enter into this agreement
providing for the performance by Service Company for the Client Companies of
certain services more particularly set forth herein; and
WHEREAS, Service Company is organized, staffed and equipped and has filed
with the Securities and Exchange Commission ("the SEC") to be a subsidiary
service company under Section 13 of the Public Utilities Holding Company Act of
1935 (the "Act") to render to Ameren
<PAGE>
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.
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
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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 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.
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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.
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'
4
<PAGE>
written notice to the other Parties prior to the beginning of any calendar year,
each Party fully reserving the right to so terminate the Agreement.
This Agreement may also be terminated to the extent that performance may
conflict with any rule, regulation or order of the Securities and Exchange
Commission adopted before or after the making of this Agreement.
Section 10. Assignment
- -----------------------
This Agreement and the rights hereunder may not be assigned without the
mutual written consent of all Parties hereto.
5
<PAGE>
IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be
executed and attested by their authorized officers as of the day and year first
above written.
AMEREN SERVICES COMPANY
By______________________________
Title___________________________
ATTEST:
By____________________________
Title_________________________
AMEREN CORPORATION
By______________________________
Title___________________________
ATTEST:
By____________________________
Title_________________________
UNION ELECTRIC COMPANY
By______________________________
Title___________________________
ATTEST:
By____________________________
Title_________________________
6
<PAGE>
CENTRAL ILLINOIS PUBLIC SERVICE CO.
By______________________________
Title___________________________
ATTEST:
By____________________________
Title_________________________
CIPSCO INVESTMENT COMPANY
By______________________________
Title___________________________
ATTEST:
By____________________________
Title_________________________
7
<PAGE>
AMEREN SERVICES
DESCRIPTION OF EXPECTED SERVICES BY FUNCTION/DEPARTMENT
FUNCTION/DEPARTMENT DESCRIPTION
- --------------------------------------------------------------------------------
Building Service Provide facility management services for owned and
leased facilities, excluding power plants. Services
include operation and maintenance of structures,
capital improvements, interior space planning, security
and janitorial.
Controller's Perform all accounting services necessary to properly
maintain and report on the books and records of Ameren
and its subsidiaries. Provide investor relations
services.
Corporate Develop strategies for advertising and marketing
Communications efforts, develop employee communication programs,
coordinate community relations efforts and develop
policies and procedures for media relations.
Corporate Planning Provide rate engineering, interchange marketing,
resource planning and business analysis services.
Customer Services/ Answer customer inquiries pertaining to electric/gas
Division Support service usage and perform credit activities. Provide
technical support relating to planning, engineering,
constructing and operating the distribution and
transmission systems. Provide technical support and
maintenance of protective relay schemes, station meter
work, system testing and data acquisition systems.
Economic Development Provide community and business development services, as
well as natural gas development services. Analyze
community and business development opportunities.
Energy Supply Coordinate the use of the generating, transmission and
interconnection facilities to provide economical and
reliable energy.
Engineering and Provide professional services related to engineering
Construction studies, design, procurement, planning, building and
management of projects. Study technology that may
reduce costs of producing, delivering and using
electricity.
- --------------------------------------------------------------------------------
Schedule 1
Page 1
of 3
<PAGE>
FUNCTION/DEPARTMENT DESCRIPTION
- --------------------------------------------------------------------------------
Environmental Services Perform analysis and advocacy of regulatory and
& Safety legislative issues & Safety 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.
Executive Provide executive management duties for all Company
activities at the department, function and officer
levels.
Fossil Fuel Procurement Provide resources necessary to procure fuel for the
fossil power plants and minimize production costs.
Gas Supply Provide gas supply and pipeline capacity procurement
and management services. Develop policies, procedures
and standards which govern the design, construction and
operation of the gas systems.
General Counsel Provide legal advice and services in regards to
legislative activities, regulatory agencies and
security matters. Make regulatory filings, maintain
minutes of the boards of directors, conduct stockholder
meetings and procure property and casualty insurance
bonds.
Human Resources Administer and negotiate employee benefits including
pensions, major medical, long-term disability, life
insurance, defined contribution plans, executive
benefit and flexible spending plans. Provide employment
services, including required regulatory reporting and
maintenance of personnel records. Provide employee
training and communications services.
Industrial Relations Negotiate, represent and administer provisions of labor
agreements applicable to unions representing union
employees.
Information Services Provide for the development and operation of computer
software, telecommunications and other equipment used
to conduct business and engineering activities.
Maintain all billing records and process customer meter
readings.
Internal Audit Audit company operations, perform operational and
productivity reviews, review justifications for capital
projects and perform quality assurance reviews.
-------------------------------------------------------
Schedule 1
Page 2
of 3
<PAGE>
FUNCTION/DEPARTMENT DESCRIPTION
-------------------------------------------------------
Marketing Provide marketing services including account
management, program development, market research and
customer energy services.
Merger Coordination Monitor programs to achieve savings, merger costs and
position reductions as they relate to the
implementation plans.
Motor Transportation Provide engineering, support, and mechanical servicing
of vehicles, procurement of vehicles and safety and
training programs.
Purchasing Provide procurement of goods and services other than
fuel. Provide materials inventory management services.
Real Estate Acquire necessary land rights and permits including
coordination of site selection. Maintain existing land
rights while permitting licenses and leases to minimize
investment or costs of holding property.
Stores Receive, inspect, store, issue and deliver materials
and supplies throughout all service areas. Process
transformers, tools, scrap material and hazardous
waste.
Tax Research and consult on tax issues in connection with
federal, state and local tax compliance and planning
matters, including the preparation and filing of
returns.
Treasurer's Provide treasury operation, mailing, financial planning,
investments, and executive payroll and pension disbursement services.
Schedule 1
Page 3
of 3
<PAGE>
AMEREN SERVICES
EXPECTED ALLOCATED DIRECT COST FACTORS
ALLOCATION NUMBER DESCRIPTION
----------------- -----------
001A Composite*
002A Number of customers
002B Number of gas transportation 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
005A O&M labor
006A Total revenues
006B Electric revenues
006C Gas revenues
007A 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
*Composite consists of the following three factors (equal weight to each
factor):
Sales (kwh and dekatherm)
Number of customers
Number of employees
Schedule 2
<PAGE>
Exhibit B-5
AMEREN SERVICES COMPANY
POLICIES AND PROCEDURES
October 8, 1997
<PAGE>
TABLE OF CONTENTS
<TABLE>
<S> <C>
INTRODUCTION.................................................1
GENERAL ACCOUNTING PROCEDURES................................1
AMEREN SERVICES POLICIES AND PROCEDURES......................2
SERVICE REQUEST AND APPROVAL PROCEDURES......................2
SERVICE REQUEST FORM.......................................3
SERVICE REQUEST GUIDELINES.................................5
MONITORING AND CONTROL.....................................5
SERVICE REQUEST ALLOCATION FACTORS UPDATE AND REVISIONS....6
TIME REPORTING.............................................6
BILLING AND REVIEW.........................................7
DISPUTE RESOLUTION PROCEDURE.................................8
INTERNAL AUDIT CONTROL.......................................8
EVALUATION AND MEASUREMENT...................................8
</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 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 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
<PAGE>
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.
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.
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
2
<PAGE>
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 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
3
<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.
4
<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.
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 appropriate allocation factor will
be included in the electronic billing process for each service request work
order.
5
<PAGE>
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.
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.
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:
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.
6
<PAGE>
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, 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.
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.
7
<PAGE>
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.
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 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.
8
<PAGE>
Exhibit I
Page 1of 9
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
<PAGE>
Exhibit I
Page 2 of 9
Description - Develop strategies for advertising and marketing efforts, develop
employee communication programs, coordinate community relations efforts and
develop policies and procedures for media relations.
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.
<PAGE>
EXHIBIT I
Page 3 of 9
Expected Allocation Factors - 1) kwh sales
h) Engineering and Construction
Description - Provide professional services related to engineering studies,
design, procurement, planning, building and management of projects. Study
technologies 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
<PAGE>
Exhibit I
Page 4 of 9
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.
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
<PAGE>
Exhibit I
Page 5 of 9
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
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
<PAGE>
Exhibit I
Page 6 of 9
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
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
<PAGE>
Exhibit I
Page 7 of 9
*Composite consists of the following three factors (equal weight to each
factor):
Sales (kwh and dekatherm)
Number of customers
Number of employees
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.
<PAGE>
Exhibit I
Page 8 of 9
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.
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
<PAGE>
Exhibit I
Page 9 of 9
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 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.
Non-Regulated - Based on a percentage of 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 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 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 costs to AMC, the
remaining costs will be allocated based upon one of the factors above.
<PAGE>
Exhibit C-3
SUBSTANTIALLY FINAL FORM
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON ____________, 1997
Registration Statement No. 33-___________
================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM S-3
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
_____________________________________
AMEREN CORPORATION
(Exact name of registrant as specified in its charter)
STATE OF MISSOURI 43-1723446
(State or other jurisdiction (IRS Employer
of incorporation or organization) Identification No.)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(314) 621-3222
(Address, including zip code, and telephone number, including area code,
of registrant's principal executive offices)
________________________________________
DONALD E. BRANDT, Senior Vice President, Finance
JAMES C. THOMPSON, Secretary
1901 Chouteau Avenue, St. Louis, Missouri 63103
(314) 621-3222
(Names, address, including zip code, and telephone number, including area code,
of agents for service)
CALCULATION OF REGISTRATION FEE
<TABLE>
<CAPTION>
==================================================================================================================
TITLE OF EACH CLASS OF AMOUNT TO BE PROPOSED MAXIMUM PROPOSED MAXIMUM AMOUNT OF
SECURITIES TO BE REGISTERED OFFERING PRICE PER AGGREGATE OFFERING REGISTRATION FEE /(2)/
REGISTERED UNIT /(1)/ PRICE
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
COMMON STOCK,
$.01 PAR VALUE 5,000,000 SHARES $ $ $
==================================================================================================================
</TABLE>
/(1)/ Calculated in accordance with Rule 457(c) on the basis of the average of
the high and low sales prices of the Registrant's Common Stock as
reported on the New York Stock Exchange Composite Tape on _____________,
1997.
/(2)/ 800,000 shares of the Common Stock were previously registered (Form S-4
Registration Statement, Reg. No. 33-64165) and are carried forward
hereby. The amount of filing fee associated with the Common Stock that
was previously paid with such earlier registration statement is $10,949.
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: From
time to time after this Registration Statement becomes effective.
If the only securities being registered on this Form are being offered
pursuant to dividend or interest reinvestment plans, please check the following
box:[_]
If any of the securities being registered on this Form are to be
offered on a delayed or continuous basis pursuant to Rule 415 under the
Securities Act of 1933, other than securities offered only in connection with
dividend or interest reinvestment plans, please check the following box:[_]
If this Form is filed to register additional securities for an
offering pursuant to Rule 462(b) under the Securities Act, please check the
following box and list the Securities Act registration statement number of the
earlier effective registration statement for the same offering. [_]____________
If this Form is a post-effective amendment filed pursuant to Rule
462(c) under the Securities Act, check the following box and list the Securities
Act registration statement number of the earlier effective registration
statement for the same offering. [_]____________
If delivery of the prospectus is expected to be made pursuant to Rule
434, please check the following box.[_]
================================================================================
<PAGE>
PROSPECTUS
AMEREN CORPORATION
DRPLUS
DIVIDEND REINVESTMENT AND STOCK PURCHASE PLAN
DRPlus (the "Plan") of Ameren Corporation (the "Company") is designed to
provide Participants with a convenient way to purchase shares of the Company's
common stock, $.01 par value ("Common Stock"), and to reinvest all or a portion
of the cash dividends paid on the Company's Common Stock and the Preferred Stock
of the Company's subsidiaries (the "Eligible Securities"), including Union
Electric Company ("Union Electric") and Central Illinois Public Service Company
("CIPS"), in additional shares of Common Stock.
Participants in the Plan may:
. Make an initial investment in Common Stock with a cash investment of
at least $50.
. Reinvest all or a portion of cash dividends paid on Eligible
Securities in additional shares of Common Stock.
. Increase their investment in Common Stock by making optional cash
investments of at least $25 at any time.
. Receive, upon request, certificates for whole shares of Common Stock
credited to their Plan accounts.
. Deposit certificates representing Common Stock into their Plan
accounts for safekeeping.
. Sell shares of Common Stock credited to their Plan accounts.
Shares of Common Stock purchased under the Plan will, at the option of the
Company, be newly issued shares or treasury shares purchased directly from the
Company, or shares purchased in the open market or in privately negotiated
transactions. Any open market or privately negotiated purchases will be
effected through an Independent Agent (as hereinafter defined) selected by the
Company. The Common Stock is listed on the New York Stock Exchange under the
ticker symbol AEE. The Company is initially registering 5,000,000 shares with
the Securities and Exchange Commission in connection with the Plan.
The purchase price of newly issued or treasury shares of Common Stock
purchased under the Plan for an Investment Date (as hereinafter described) will
be the average of the high and low sales prices of the Common Stock on the
Investment Date reported as New York Stock Exchange Composite Transactions as
published in the Midwest Edition of The Wall Street Journal or other similar
financial publication. The price of shares of Common Stock purchased in the
open market or in privately negotiated transactions will be the weighted average
price per share of the aggregate number of shares purchased with respect to the
relevant Investment Date. The Company will pay the costs of administration of
the Plan; however, Participants will bear the costs of any brokerage commissions
and any applicable transfer taxes and service charges related to shares
purchased or sold under the Plan.
For each meeting of shareholders, Participants will receive proxy cards
which will enable them to vote both shares registered in their names and shares
credited to their Plan accounts.
To the extent required by applicable law in certain jurisdictions, shares
of Common Stock offered under the Plan to certain persons are offered only
through a registered broker/dealer in such jurisdictions.
This Prospectus contains a summary of the material provisions of the Plan
and should be retained for future reference.
EFFECTIVE _____________, THE PLAN REPLACES, BY AMENDMENT AND RESTATEMENT,
THE DIVIDEND REINVESTMENT AND STOCK PURCHASE PLAN (THE "UNION ELECTRIC PLAN")
OFFERED BY UNION ELECTRIC AND THE AUTOMATIC DIVIDEND REINVESTMENT AND STOCK
PURCHASE PLAN (THE "CIPSCO PLAN") OFFERED BY CIPSCO INCORPORATED ("CIPSCO").
ALL ACCOUNTS AND ALL ELECTIONS, NOTICES, INSTRUCTIONS AND AUTHORIZATIONS UNDER
THE UNION ELECTRIC PLAN AND THE CIPSCO PLAN WILL AUTOMATICALLY CONTINUE UNDER
THE PLAN, AND PARTICIPANTS IN THE UNION ELECTRIC PLAN AND THE CIPSCO PLAN WILL
CONTINUE AS PARTICIPANTS IN THE PLAN. NO ACTION BY CURRENT PARTICIPANTS IN THE
UNION ELECTRIC PLAN AND THE CIPSCO PLAN IS REQUIRED TO CONTINUE PARTICIPATION IN
THE PLAN. IF, AFTER REVIEWING THIS PROSPECTUS, A PARTICIPANT IN THE UNION
ELECTRIC PLAN OR THE CIPSCO PLAN DOES NOT WISH TO CONTINUE PARTICIPATION IN THE
PLAN, SUCH PARTICIPANT MUST DELIVER A WRITTEN REQUEST TO THE INVESTOR SERVICES
DEPARTMENT OF AMEREN SERVICES COMPANY, AS DESCRIBED HEREIN.
- --------------------------------------------------------------------------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS
A CRIMINAL OFFENSE.
- --------------------------------------------------------------------------------
The date of this Prospectus is _________________.
<PAGE>
AVAILABLE INFORMATION
The Company is subject to the informational requirements of the Securities
Exchange Act of 1934, as amended (the "Exchange Act"), and in accordance
therewith files reports, proxy statements and other information with the
Securities and Exchange Commission (the "Commission"). Reports, proxy
statements and other information filed by the Company may be inspected and
copied at the public reference facilities maintained by the Commission at Room
1024, 450 Fifth Street, N.W., Washington, D.C. 20549, and at the Commission's
Regional Offices at 500 West Madison Street, Suite 1400, Chicago, Illinois 60661
and at 7 World Trade Center, Suite 1300, New York, New York 10048. Copies of
such material may be obtained from the public reference section of the
Commission, 450 Fifth Street, N.W., Washington, D.C. 20549, at prescribed rates.
Such reports, proxy statements and other information concerning the Company may
also be inspected at the offices of the New York Stock Exchange, 20 Broad
Street, New York, New York 10005 on which exchange the Common Stock of the
Company is listed. The Commission maintains a Web site that contains reports,
proxy statements and other information regarding registrants, such as the
Company, that file electronically with the Commission. The address of such site
is: (http://www.sec.gov). In addition, such reports, proxy statements and other
information concerning the Company can be inspected at the principal office of
the Company, 1901 Chouteau Ave, St. Louis, Missouri 63103, telephone (314)-621-
3222.
This Prospectus does not contain all of the information set forth in the
Registration Statement on Form S-3 (together with all amendments and exhibits
thereto, the "Registration Statement"), which the Company has filed with the
Commission under the Securities Act of 1933, as amended (the "Securities Act").
Statements contained or incorporated by reference herein concerning the
provisions of documents are necessarily summaries of such documents, and each
statement is qualified in its entirety by reference to the Registration
Statement.
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
The following documents, previously filed with the Commission by CIPSCO
(File No. 1-10628), Union Electric (File No. 1-2967) or the Company (File No.
____________) pursuant to the Securities Exchange Act of 1934, as amended, are
incorporated by reference in this Registration Statement:
1. CIPSCO'S Annual Report on Form 10-K for the year ended December 31,
1996.
2. CIPSCO's Quarterly Reports on Form 10-Q for the quarters ended March
31, 1997, June 30, 1997 and September 30, 1997.
3. CIPSCO's Current Report on Form 8-K dated __________, 1997.
4. Union Electric's Annual Report on Form 10-K for the year ended
December 31, 1996.
5. Union Electric's Quarterly Reports on Form 10-Q for the quarters ended
March 31, 1997, June 30, 1997 and September 30, 1997.
6. Union Electric's Current Report on Form 8-K dated ___________, 1997.
7. The Company's Current Report on Form 8-K dated _____________, 1997.
8. The Company's Registration Statement on Form S-4 (Reg. No. 33-64165),
filed November 13, 1995, which includes a description of the Common Stock of the
Company.
All documents subsequently filed by the Company pursuant to Sections 13(a),
13(c), 14 or 15(d) of the Exchange Act after the date of this Prospectus and
prior to the termination of the offering of the Common Stock offered hereby
shall be deemed to be incorporated by reference in this Prospectus and to be a
part hereof from the date of filing of such documents. Any statement contained
herein or in a document incorporated or deemed to be incorporated by reference
herein shall be deemed to be modified or superseded for purposes of this
Prospectus to the extent that a statement contained herein or in any other
subsequently filed document which also is or is deemed to be incorporated by
reference herein modifies or supersedes such statement. Any such statement so
modified or superseded shall not be deemed, except as so modified or superseded,
to constitute a part of this Prospectus.
2
<PAGE>
The Company will provide without charge to each person, including any
beneficial owner, to whom a copy of this Prospectus has been delivered, on the
written or oral request of such person, a copy of any and all of the documents
referred to above which have been or may be incorporated in this Prospectus by
reference, other than exhibits to such documents which are not specifically
incorporated by reference into the information that this Prospectus
incorporates. Requests for such copies should be directed to the Investor
Services Department, Ameren Services Company, Post Office Box 66887, St. Louis,
Missouri 63166-6887, telephone number 1-800-255-2237.
THE COMPANY
The Company is a holding company, the principal utility operating
subsidiaries of which are Union Electric Company ("Union Electric") and Central
Illinois Public Service Company ("CIPS"). Union Electric was incorporated in
Missouri in 1922 and is successor to a number of companies, the oldest of which
was organized in 1881. Union Electric, which is the largest electric utility in
the State of Missouri, supplies electric service in territories in Missouri and
Illinois having an estimated population of 2,600,000 with an area of
approximately 24,500 square miles, including the greater St. Louis area. Retail
gas service is supplied by Union Electric in 90 Missouri communities and in the
City of Alton, Illinois and vicinity. CIPS, organized in 1902, serves 317,000
retail electricity customers and 166,000 natural gas customers in central and
southern Illinois. Union Electric and CIPS became subsidiaries of the Company
pursuant to mergers which became effective on _____________________. The
Company is a registered public utility holding company under the Public Utility
Holding Company Act of 1935, as amended.
USE OF PROCEEDS
Because the extent of the requirements of Plan Participants cannot be
predicted and because such requirements may be satisfied by either the issuance
of new shares of Common Stock by the Company or the purchase of shares of Common
Stock by an Independent Agent in the open market, the number of shares of Common
Stock, if any, that the Company ultimately will sell under the Plan, and the
prices at which such shares will be sold, is not known. If new shares of Common
Stock are issued by the Company under the Plan, the proceeds from the sale will
be used for repayment of short-term or long-term indebtedness, for working
capital or for other general corporate purposes. If shares are purchased by an
Independent Agent for Participants in the open market, the Company will not
receive any proceeds from such sales.
DESCRIPTION OF THE PLAN
PURPOSE
1. WHAT IS THE PURPOSE OF THE PLAN?
The purpose of the Plan is to provide Participants (see Question 6) with a
convenient way to purchase shares of Common Stock, $.01 par value, ("Common
Stock") of Ameren Corporation (the "Company") and to reinvest all or a portion
of the cash dividends paid on the Company's Common Stock and on the Preferred
Stock of the Company's subsidiaries (together, the "Eligible Securities") in
additional shares of Common Stock.
EFFECTIVE _____________, THE PLAN REPLACES, BY AMENDMENT AND RESTATEMENT,
THE DIVIDEND REINVESTMENT AND STOCK PURCHASE PLAN (THE "UNION ELECTRIC PLAN")
OFFERED BY UNION ELECTRIC COMPANY AND THE AUTOMATIC DIVIDEND REINVESTMENT AND
STOCK PURCHASE PLAN (THE "CIPSCO PLAN") OFFERED BY CIPSCO INCORPORATED. ALL
ACCOUNTS AND ALL ELECTIONS, NOTICES, INSTRUCTIONS AND AUTHORIZATIONS UNDER THE
UNION ELECTRIC PLAN AND THE CIPSCO PLAN WILL AUTOMATICALLY CONTINUE UNDER THE
PLAN, AND PARTICIPANTS IN THE UNION ELECTRIC PLAN AND THE CIPSCO PLAN WILL
CONTINUE AS PARTICIPANTS IN THE PLAN. NO ACTION BY CURRENT PARTICIPANTS IN THE
UNION ELECTRIC PLAN AND THE CIPSCO PLAN IS REQUIRED TO CONTINUE PARTICIPATION IN
THE PLAN. IF, AFTER REVIEWING THIS PROSPECTUS, A PARTICIPANT IN THE UNION
ELECTRIC PLAN OR THE CIPSCO PLAN DOES NOT WISH TO CONTINUE PARTICIPATION IN THE
PLAN, SUCH PARTICIPANT MUST DELIVER A WRITTEN REQUEST TO THE INVESTOR SERVICES
DEPARTMENT OF AMEREN SERVICES COMPANY, AS DESCRIBED IN QUESTION 20.
3
<PAGE>
FEATURES
2. WHAT ARE THE MAIN FEATURES OF THE PLAN?
. Non-shareholders of legal age who are customers of the Company or its
subsidiaries (a "Customer") may enroll in the Plan by making a minimum
initial cash investment of $50 to purchase Common Stock under the terms
of the Plan.
. Non-shareholders of legal age who are employees of the Company or its
subsidiaries (an "Employee") may enroll in the Plan by authorizing a
minimum payroll deduction investment of $25 per pay period to purchase
Common Stock under the terms of the Plan.
. Participants may elect to have cash dividends on all or a portion of
their shares of Common Stock or Preferred Stock automatically
reinvested. Dividend payments not reinvested will be paid to
Participants by check or through electronic direct deposit.
. Participants may make Optional Cash Investments (including by
authorizing direct debit from their personal bank accounts) in a
minimum amount of $25 per transaction ($50 in the case of initial
Customer investments) after the initial investment and up to a maximum
of $120,000 per calendar year for the purchase of Common Stock.
. Full investment of funds is possible under the Plan because both full
and fractional shares will be credited to Participants' Plan accounts.
. Participants may deposit their Common Stock certificates, at no cost,
in their Plan accounts for safekeeping.
. Personal record keeping is simplified by the Company's issuance of
statements showing account activity. STATEMENTS OF ACCOUNT ARE A
PARTICIPANT'S CONTINUING RECORD OF TRANSACTIONS AND SHOULD BE RETAINED
FOR TAX PURPOSES.
. Participants may sell shares of Common Stock held or deposited in
their Plan accounts.
. By utilizing volume commission discounts from Independent Agents, the
Plan is able to provide investors with an economical means to purchase
and sell shares of the Company's Common Stock.
ADMINISTRATION
3. WHO ADMINISTERS THE PLAN?
Ameren Services Company ("Ameren Services"), a wholly-owned subsidiary of
the Company, will administer the Plan through its Investor Services Department
("Investor Services"). Among other things, Ameren Services will receive and
hold Participants' funds pending investment in additional shares of Common
Stock, effect transfers of Common Stock, keep a continuous record of
participation and prepare and send to each Participant statements of their Plan
account. The responsibilities of Ameren Services in connection with the
administration of the Plan are administrative in nature and, in large part, are
consistent with the responsibilities of Ameren Services in acting as registered
transfer agent for the Company.
If the Company elects to meet the requirements of Participants by
purchasing shares of Common Stock in the open market, an Independent Agent will
act on behalf of Participants in buying such shares. The Independent Agent will
also sell Plan shares on behalf of Participants.
THE COMPANY RESERVES THE RIGHT TO INTERPRET AND REGULATE THE PLAN AS DEEMED
NECESSARY OR DESIRABLE. NEITHER THE COMPANY NOR ITS INDEPENDENT AGENTS WILL BE
LIABLE FOR ANY ACT DONE IN GOOD FAITH OR FOR ANY OMISSION TO ACT IN GOOD FAITH,
INCLUDING, WITHOUT LIMITATION, ANY CLAIM OF LIABILITY ARISING OUT OF FAILURE TO
TERMINATE A PARTICIPANT'S ACCOUNT UPON THE PARTICIPANT'S DEATH PRIOR TO
4
<PAGE>
RECEIPT OF WRITTEN NOTICE OF SUCH DEATH, PROVIDED THAT THE COMPANY SHALL NOT BE
RELIEVED FROM ANY LIABILITY IMPOSED UNDER ANY FEDERAL, STATE OR OTHER APPLICABLE
SECURITIES LAW WHICH CANNOT BE WAIVED. YOU SHOULD RECOGNIZE THAT THE COMPANY
CANNOT ASSURE YOU OF A PROFIT OR PROTECT YOU AGAINST A LOSS ON SHARES PURCHASED
OR SOLD UNDER THE PLAN.
4. WHO SHOULD I CONTACT WITH QUESTIONS CONCERNING THE PLAN AND ITS
ADMINISTRATION?
You may contact the Company with questions concerning the Plan by writing
to:
Ameren Services Company
Investor Services Department
P.O. Box 66887
St. Louis, Missouri 63166-6887
or by calling Investor Services toll-free at 1-800-255-2237.
Ameren Services acts as the transfer agent for all securities issued by
Ameren Corporation and its subsidiaries.
5. MAY THE PLAN BE MODIFIED OR DISCONTINUED?
The Company reserves the right to suspend, modify or discontinue the Plan
at any time including but not limited to the right to modify the fees and
commissions charged to Participants. Any suspension, major modification or
discontinuance of the Plan will be announced by the Company to all Participants.
PARTICIPATION
6. WHO IS ELIGIBLE TO PARTICIPATE IN THE PLAN?
All holders of Eligible Securities (that is, the Common Stock of the
Company and the Preferred Stock of the Company's subsidiaries), Customers of the
Company or its subsidiaries and Employees of the Company's subsidiaries are
eligible to be Participants in the Plan.
A Plan Prospectus and enrollment information will be furnished upon request
made to Investor Services.
7. HOW DOES A HOLDER OF ELIGIBLE SECURITIES PARTICIPATE?
Participants who hold Eligible Securities may join the Plan by completing
the Enrollment Form and returning it to Investor Services. A Participant who
owns Eligible Securities that are registered in a name other than the
Participant's (for example, in the name of a broker or bank nominee) and who is
not a Customer or an Employee, may also participate in the Plan, subject to
certain limitations regarding the Eligible Securities held in such other name.
(Contact Investor Services for information concerning Participation by such
beneficial owners.)
The Enrollment Form allows a Participant to choose a reinvestment option
for participation in the Plan. By checking the appropriate box a Participant
may select:
. FULL DIVIDEND REINVESTMENT - Automatic reinvestment of cash dividends
on all Eligible Securities registered in the name of the Participant
and on all Plan shares credited to the Participant's account.
. PARTIAL DIVIDEND REINVESTMENT - Receipt of cash dividends on a portion
of the Eligible Securities registered in the name of the Participant
and/or a portion of the Plan Shares credited to the Participant's
account, and automatic reinvestment of the cash dividends on the
remainder of the Participant's shares.
5
<PAGE>
. NO DIVIDEND REINVESTMENT - Receipt of cash dividends on all Eligible
Securities registered in the name of the Participant and on all Plan
shares credited to the Participant's account.
Participants may change their reinvestment options by completing the
correspondence portion of their statement of account or an Enrollment Form and
sending it to Investor Services. Changes will become effective as soon as
practicable after they are received.
8. HOW DOES A CUSTOMER PARTICIPATE?
A Customer may apply for enrollment in the Plan by completing and returning
a Plan Application Form, together with a check in an amount not less than $50,
nor more than $120,000, made payable to "Ameren Corporation".
The Plan Application Form requires each applicant to certify residency. It
also allows the applicant to decide the amount of their initial investment (not
less than $50) which will be used to purchase shares of the Company's Common
Stock. The Plan Application Form allows the applicant to choose a reinvestment
option for participation in the Plan. (See Question 7).
9. HOW DOES AN EMPLOYEE PARTICIPATE?
An Employee may join the Plan at any time by enrolling in the same manner
as any other eligible person described under Questions 7 or 8 or by completing a
Plan Payroll Deduction Authorization Form.
DIVIDEND REINVESTMENT
10. HOW AND WHEN WILL CASH DIVIDENDS BE REINVESTED?
If a Participant has elected full or partial dividend reinvestment on the
Eligible Securities registered in their name and/or their Plan shares, the
Company will reinvest those dividends in additional shares of the Company's
Common Stock. The source of Common Stock to be purchased under the Plan may be,
at the discretion of the Company, authorized but unissued Common Stock or shares
of Common Stock purchased on the open market by an Independent Agent.
If the Company is meeting the requirements of the Plan with Common Stock
purchased in the open market, an Independent Agent will determine the exact
timing of such purchases and the number of shares to be purchased, depending on
the amount of reinvested dividends, market conditions and the requirements of
federal securities laws, and the purchased shares will be credited to a
Participant's Plan account as of the applicable Investment Date. If the Company
elects to issue authorized but unissued shares of its Common Stock, these shares
will be issued by the Company and credited to a Participant's Plan account by
the Company as of the applicable Investment Date. The determination of the
price for purchases of Plan shares is explained in Question 17.
If a Participant's Enrollment Form is received by Investor Services on or
before the record date with respect to any Common Stock or Preferred Stock cash
dividend payment date, then the dividend payable on such payment date will be
used to purchase additional shares of Common Stock as of such payment date (an
Investment Date). If the Enrollment Form is received after the record date with
respect to any such cash dividend payment date, the reinvestment of dividends
will start with the dividend payment next following such payment date.
Each cash dividend payment date on the Eligible Securities will be an
Investment Date under the Plan; accordingly, cash dividends payable on each
Common Stock dividend payment date and on each Preferred Stock dividend payment
date, which are to be reinvested, will be invested in Common Stock as of such
dividend payment date. Common Stock cash dividend payment dates will normally
be on or about the last business day of March, June, September and December; and
Preferred Stock cash dividend payment dates are currently the 30th of March,
June, September and December and the 15th of February, May, August and November.
6
<PAGE>
OPTIONAL CASH INVESTMENTS
11. WHO IS ELIGIBLE TO MAKE OPTIONAL CASH INVESTMENTS?
All Plan Participants, whether or not they have authorized the reinvestment
of dividends, are eligible to make Optional Cash Investments.
12. HOW ARE OPTIONAL CASH INVESTMENTS MADE?
A Plan Participant may make an initial cash investment when enrolling by
enclosing a check with the Enrollment Form. Checks should be made payable to
"Ameren Corporation," and returned in the envelope provided with the Enrollment
Form. Thereafter, Optional Cash Investments may be made by using the cash
investment form attached to the statement of account, by Automatic Cash
Investment (see Question 13) or by Employee payroll deduction (see Question 9).
Please contact Investor Services for additional cash investment forms.
13. WHAT IS THE AUTOMATIC CASH INVESTMENT OPTION OF THE PLAN AND HOW DOES IT
WORK?
The Automatic Cash Investment option offers Participants in the Plan a
direct debit service. Optional Cash Investments are electronically withdrawn
from your personal checking or savings account on a regular monthly basis and
used to purchase Common Stock. The direct debit from your personal bank
account will be shown on the monthly statement from your financial institution.
In addition, you will receive a statement from Investor Services detailing the
cash received and shares purchased.
The Automatic Cash Investment option may be authorized for regular monthly
amounts from $25 to $10,000. Funds authorized for investment through the
Automatic Cash Investment option will be debited approximately three days prior
to each Optional Cash Investment Date. (See Question 15)
For an Automatic Cash Investment application, contact Investor Services.
14. WHAT ARE THE LIMITATIONS ON MAKING OPTIONAL CASH INVESTMENTS?
Optional Cash Investments cannot be less than $25 per investment ($50 in
the case of initial Customer investments). The maximum invested in Plan Shares
by any Participant cannot exceed $120,000 for any calendar year.
15. WHEN WILL OPTIONAL CASH INVESTMENTS BE INVESTED?
The option to make cash investments is available to you at any time. The
dates on which Optional Cash Investments are used to purchase Common Stock are
determined solely at the discretion of the Company, although purchases on behalf
of Plan Participants will be made at least once a month. Purchases may be made
over a period of several days in the case of market purchases. All such
purchases will be aggregated and credited to Participants' accounts on the
Optional Cash Investment Date occurring on or after receipt of the Optional Cash
Investment. There will be an Optional Cash Investment Date on or about the last
day of each month. Participants will receive a notice at the beginning of each
year specifying the Optional Cash Investment Dates for such year.
Cash received after an Optional Cash Investment Date will be held by the
Company until, and will be invested as of, the next Optional Cash Investment
Date. No interest will be paid by the Company on any cash investments received
and held by the Company pending investment.
PURCHASES
16. HOW MANY SHARES OF COMMON STOCK WILL BE PURCHASED?
No one can predict the number of shares that will be purchased for you
during a particular purchase period, and you cannot direct the Company to
purchase a specific number of shares. The number of shares purchased for you
under the Plan depends on the amount of funds you have available for
7
<PAGE>
investment and the price of the shares. The funds you have available for
investment depends on what you have authorized in regard to dividend
reinvestment, plus any cash investments made. In every case, your available
funds will be fully invested in both whole and fractional shares of Common Stock
(computed to four decimal places).
17. WHAT IS THE PRICE OF SHARES PURCHASED FOR THE PLAN?
If shares for the Plan are being purchased on the open market or in
privately negotiated transactions, the price of such shares will be the weighted
average price at which the Independent Agent acquired the shares allocated to
Participants' accounts on the applicable Investment Date plus applicable
brokerage commissions and other fees. If the Company is issuing new shares of
Common Stock, the price of such shares will be the average of the high and low
sales prices of the Company's Common Stock on the applicable Investment Date
reported as New York Stock Exchange Composite Transactions as published in the
Midwest Edition of The Wall Street Journal or other similar financial
publication.
18. WHO PURCHASES THE SHARES FOR THE PLAN?
The Company, at its discretion, may elect to satisfy the requirements of
the Plan with either unissued shares of Common Stock or shares of Common Stock
purchased on the open market. (See Question 10) If the Company elects to
purchase shares of Common Stock on the open market, the Independent Agent will
make all such purchases necessary to meet the requirements of the Plan. Other
than establishing the length of the investment period incorporated into the
Plan, the Company does not exercise any direct or indirect control over the
timing or price of purchases made by the Independent Agent on the open market.
If open market purchases are not made, the shares issued under the Plan will be
issued directly from the authorized and unissued shares of Common Stock of the
Company.
19. ARE ANY FEES OR EXPENSES INCURRED BY PARTICIPANTS?
All costs of administering the Plan will be paid by the Company, but
Participants will be required to pay brokerage commissions and other fees for
shares purchased in the open market and shares sold through the Plan. Brokerage
commissions will be at a negotiated rate established under the terms of the
Company's agreements with Independent Agents. (See Question 5)
SALES AND TERMINATION FROM THE PLAN
20. MAY PARTICIPANTS SELL OR WITHDRAW ALL OR A PORTION OF THEIR SHARES FROM THE
PLAN?
Yes. Any Participant may withdraw from the Plan, request that a
certificate be issued for Plan shares or request that Plan shares be sold and
the cash proceeds forwarded to the Participant. Participation in the Plan is
entirely voluntary. Participants may sell or withdraw all or a portion of their
shares by filling out the correspondence portion of their account statement or
by contacting Investor Services.
A stock certificate for any whole number of shares will be issued from your
Plan account as soon as practicable after requested. If you would like stock
certificates issued in a registration other than the name on your account,
contact Investor Services.
Investor Services will aggregate Plan sale requests and place a market
order with the Independent Agent to sell such shares at least four times a
month. The Participant will receive the proceeds of the sale less any brokerage
commission and any other fees as soon as practicable after the settlement date
for the applicable sale.
If a Participant's request for a sale or withdrawal is received by Investor
Services on or soon after a dividend payment date, such request will be
processed as soon as practicable after reinvested dividends have been allocated.
8
<PAGE>
If a Participant sells or withdraws all of the full shares in the
Participant's Plan account, Investor Services will automatically sell any
fractional share remaining in the account and forward the proceeds of the sale
to the Participant.
REPORTS TO PARTICIPANTS
21. HOW WILL PARTICIPANTS BE ADVISED OF THEIR PURCHASE OF SHARES OF COMMON
STOCK AND OTHER ACTIVITY IN THEIR PLAN ACCOUNTS?
Participants will receive a quarterly statement as soon as practicable
following the end of each calendar quarter. The last quarterly statement of
each calendar year will reflect year-to-date Plan activity. In addition, a
statement will be provided in any month an account has Plan activity. THESE
STATEMENTS ARE PARTICIPANTS' CONTINUING RECORD OF THE COST OF THEIR SHARES AND
SHOULD BE RETAINED FOR TAX PURPOSES.
Participants will receive copies of the same communications sent to other
registered shareholders of Common Stock, including the Company's annual report,
notice of annual meeting and proxy statement, and certain tax information.
CERTIFICATES
22. WILL STOCK CERTIFICATES AUTOMATICALLY BE ISSUED FOR SHARES OF COMMON STOCK
ACQUIRED UNDER THE PLAN?
No. The number of shares credited to your Plan account will be held by
Ameren Services, as agent, and will be shown on your statement of account. This
service protects against loss, theft or destruction of stock certificates.
A certificate for any number of whole shares up to the full number of
shares credited to your Plan account will be issued to you if you so request in
writing. (See Question 20) Such request should be mailed to Investor Services.
Shares credited to your Plan account may not be used as collateral. If you
wish to use your Plan shares as collateral, you must request that a certificate
be issued in your name. A certificate for fractional shares will not be issued
under any circumstances.
TRANSFER OF SHARES HELD IN THE PLAN
23. CAN PLAN SHARES BE TRANSFERRED?
Upon written request, Plan shares can be transferred into names other than
the account name, subject to compliance with any applicable laws and the payment
by the Participant of any applicable taxes, provided that the request is
accompanied by a duly executed Stock Power that bears the signature(s) of the
Participant(s) and the signature(s) is/are Medallion Guaranteed by a commercial
bank or member firm of the New York Stock Exchange that is a member of either
the STAMP, SEMP or MSP Medallion Guarantee programs. Unless instructed
otherwise, Ameren Services will hold the transferred shares in an account in the
transferee's name in the Plan, and enroll the transferee in 100% dividend
reinvestment.
9
<PAGE>
SAFEKEEPING SERVICE FOR COMMON STOCK CERTIFICATES
24. WHAT IS THE PLAN'S SAFEKEEPING SERVICE AND HOW DOES IT WORK?
The Plan's safekeeping service allows you to deposit your Common Stock
certificate(s) into your Plan account. The benefits of this service include the
convenience of keeping all of your shares in one place, and the protection
against the cost of replacing your certificates should they be lost, stolen or
destroyed. If you would like to take advantage of this service, please contact
Investor Services.
INCOME TAXES
25. WHAT ARE THE FEDERAL INCOME TAX CONSEQUENCES OF PARTICIPATION IN THE PLAN?
In general, Participants in the Plan have the same federal income tax
obligations with respect to their dividends as do shareholders who are not Plan
Participants. This means that dividends reinvested under the Plan are taxable
as having been received even though the Participants did not actually receive
them in cash but, instead, used them to purchase additional shares under the
Plan.
The sale of shares by a Participant under the Plan may give rise to a
capital gain or loss, provided such shares are held as a capital asset by the
Participant. Any such gain or loss will be measured by the difference between
the proceeds received by the Participant (net of commissions and fees) and the
Participant's tax basis in the shares sold.
For Participants who are subject to U.S. withholding tax, backup
withholding or foreign taxes, the Company will withhold the required taxes from
the gross dividends or proceeds from the sale of shares. The dividends or
proceeds received by the Participant, or dividends reinvested on behalf of the
Participant, will be net of the required taxes.
The foregoing is only a general statement of federal income tax
consequences. Each Participant should consult his or her own tax advisor as to
the specific application of the tax laws and regulations governing the Plan as
they relate to such Participant. THE STATEMENTS OF ACCOUNT SENT TO PARTICIPANTS
SHOULD BE RETAINED FOR TAX PURPOSES.
LEGAL OPINION
Certain legal matters in connection with the Common Stock offered hereby
have been passed upon for the Company by William E. Jaudes, Esq., Vice President
and General Counsel of the Company and Union Electric.
EXPERTS
The financial statements incorporated in this Prospectus by reference which
have been audited by Price Waterhouse LLP, independent accountants, as indicated
in their reports with respect thereto, have been so incorporated in reliance on
such reports, given on the authority of said firm as experts in accounting and
auditing. The financial statements incorporated in this prospectus by reference
which have been audited by Arthur Andersen LLP, independent accountants, as
indicated in their reports with respect thereto, have been so incorporated in
reliance on such reports, given on the authority of such firm as experts in
auditing and accounting.
10
<PAGE>
================================================================================
This Prospectus omits certain information contained in the registration
statement which the Company has filed with the Securities and Exchange
Commission under the Securities Act of 1933 and to which reference is hereby
made for further information with respect to the Company and the securities
offered hereby.
CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Available Information............... 2
Incorporation of Certain Documents
by Reference....................... 2
The Company......................... 3
Use of Proceeds..................... 3
Description of the Plan............. 3
Legal Opinion....................... 11
Experts............................. 11
</TABLE>
____________________
No dealer, salesman or other person has been authorized to give any
information or to make any representation not contained in the Prospectus in
connection with the offer made by this Prospectus and, if given or made, such
information or representation must not be relied upon as having been authorized
by the Company. This Prospectus does not constitute an offering by any person
in any State in which such offering may not lawfully be made.
AMEREN CORPORATION
DRPLUS
DIVIDEND REINVESTMENT
AND STOCK PURCHASE PLAN
___________________
PROSPECTUS
___________________
Except as otherwise indicated by the context, this Prospectus speaks as of
the date hereof and does not purport to reflect any changes which may have
occurred in the affairs of the Company thereafter. Neither the delivery of this
Prospectus nor any sale made hereunder shall, under any circumstances, create an
implication that there has been no change in the affairs of the Company since
the date hereof.
================================================================================
<PAGE>
PART II. INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 14. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.
<TABLE>
<S> <C>
Registration fee..................... $ ------
Printing and engraving............... *
Accounting Fees...................... *
Legal Fees........................... *
Miscellaneous expenses............... *
Total............................. $ ------
</TABLE>
____________
* Estimated.
ITEM 15. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
Article IV of the Registration's Bylaws, consistent with the applicable
provisions of the Missouri General and Business Corporation Law (the "MGBCL"),
provides for indemnification of directors and officers. These provisions
provide that any person shall be indemnified for expenses and liabilities
imposed upon such person in connection with any threatened, pending or completed
action, suit, or proceeding, whether civil, criminal, administrative or
investigative, other than an action by or in the right of the Registrant, by
reason of the fact that such person is or was a director, officer, employee or
agent of the Registrant, or is or was serving at the request of the Registrant
as a director, officer, employee or agent of another corporation, partnership,
joint venture, trust or other enterprise, against expenses, including attorneys'
fees, judgments, fines and amounts paid in settlement actually and reasonably
incurred by such person in connection with such action, suit or proceeding if
such person acted in good faith and in a manner such person reasonably believed
to be in or not opposed to the best interests of the Registrant, and, with
respect to any criminal action or proceeding, had no reasonable cause to believe
his conduct was unlawful.
In a proceeding brought by or in the right of the Registrant, no
indemnification shall be made with respect to any claim as to which an officer
or director has been adjudged to have been liable to the Registrant, unless the
court determines that such a person is reasonably and fairly entitled to
indemnification for expenses. However, no indemnification shall be made in
respect of any claim, issue or matter as to which such person shall have been
adjudged to be liable for negligence or misconduct in the performance of his
duty to the Registrant unless and only to the extent that the court in which the
action or suit was brought determines upon application that, despite the
adjudication of liability and in view of all the circumstances of the case, the
person is fairly and reasonably entitled to indemnity for such expenses which
the court shall deem proper.
The By-Laws, consistent with the applicable provisions of the MGBCL,
provide that indemnification shall be made by the Registrant only if a
determination has been made by a majority vote of a quorum of the disinterested
directors or by the shareholders or by independent legal counsel, that the
director or officer met the required standard of conduct. The Registrant is
authorized to purchase liability insurance on behalf of an officer or director
whether or not the Registrant would otherwise have the power to indemnify such a
person.
The By-Laws, consistent with the applicable provisions of the MGBCL,
further provide that, in addition to the indemnities described in the preceding
paragraphs, the Registrant will further indemnify its officers and directors to
the maximum extent permitted by law, provided that no indemnity may be given for
conduct that is adjudged to be knowingly fraudulent, deliberately dishonest, or
willful misconduct.
II-1
<PAGE>
ITEM 16. EXHIBITS.
Exhibit No.
----------
4.1 Article III of the Restated Certificate of Incorporation of the
Registrant (incorporated by reference to Exhibit 3(i) of the Form
S-4 Registration Statement of the Registrant, Reg. No. 33-64165).
4.2 By-laws of the Registrant (incorporated by reference to Annex G
of the Joint Proxy Statement/Prospectus included in the Form S-4
Registration Statement of the Registrant, Reg. No. 33-64165).
5 Opinion of William E. Jaudes as to the legality of the securities
being issued.
2 Computation of ratio of earnings to fixed charges.
23.1 Consent of Price Waterhouse LLP.
23.2 Consent of Arthur Andersen LLP.
23.3 Consent of William E. Jaudes (included in Exhibit 5).
24 Powers of Attorney.
27 Financial Data Schedule.
ITEM 17. UNDERTAKINGS.
(a) The undersigned Registrant hereby undertakes:
(1) To file, during any period in which offers or sales are being
made, a post-effective amendment to this registration statement:
(i) To include any prospectus required by Section 10(a)(3) of the
Securities Act of 1933.
(ii) To reflect in the prospectus any facts or events arising after
the effective date of the registration statement (or the most
recent post-effective amendment thereof) which, individually
or in the aggregate, represent a fundamental change in the
information set forth in the registration statement.
Notwithstanding the foregoing, any increase or decrease in
volume of securities offered (if the total dollar value of
securities offered would not exceed that which was registered)
and any deviation from the low or high end of the estimated
maximum offering range may be reflected in the form of
prospectus filed with the Commission pursuant to Rule 424(b)
if, in the aggregate, the changes in volume and price
represent no more than a 20% change in the maximum aggregate
offering price set forth in the "Calculation of Registration
Fee" table in the effective registration statement.
(iii) To include any material information with respect to the plan
of distribution not previously disclosed in the registration
statement or any material change to such information in the
registration statement.
(2) That, for the purpose of determining any liability under the
Securities Act of 1933, each such post-effective amendment shall be deemed to be
a new registration statement relating to the
II-2
<PAGE>
<PAGE>
securities offered therein, and the offering of such securities at that time
shall be deemed to be the initial bona fide offering thereof.
Provided, however, that paragraphs (a)(l)(i) and (a)(l)(ii) do not apply if the
registration statement is on Form S-3, Form S-8 or Form F-3, and the information
required to be included in a post-effective amendment by those paragraphs is
contained in periodic reports filed with or furnished to the Commission by the
registrant pursuant to Section 13 or Section 15(d) of the Securities Exchange
Act of 1934 that are incorporated by reference in this registration statement.
(3) To remove from registration by means of a post-effective amendment
any of the securities being registered which remain unsold at the termination of
the offering.
(b) The undersigned Registrant hereby undertakes that, for purposes of
determining any liability under the Securities Act of 1933, each filing of the
Registrant's annual report pursuant to Section 13(a) or Section 15(d) of the
Securities Exchange Act of 1934 (and, where applicable, each filing of an
employee benefit plan's annual report pursuant to Section 15(d) of the
Securities Exchange Act of 1934) that is incorporated by reference in the
registration statement shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of such securities
at that time shall be deemed to be the initial bona fide offering thereof.
(c) Insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to directors, officers and controlling
persons of the Registrant pursuant to the provisions referred to in Item 15 of
this registration statement, or otherwise, the Registrant has been advised that
in the opinion of the Securities and Exchange Commission such indemnification is
against public policy as expressed in the Act and is, therefore, unenforceable.
In the event that a claim for indemnification against such liabilities (other
than the payment by the Registrant of expenses incurred or paid by a director,
officer or controlling person of the Registrant in the successful defense of any
action, suit or proceeding) is asserted by such director, officer or controlling
person in connection with the securities being registered, the Registrant will,
unless in the opinion of its counsel the matter has been settled by controlling
precedent, submit to a court of appropriate jurisdiction the question of whether
such indemnification by it is against public policy as expressed in the Act and
will be governed by the final adjudication of such issue.
II-3
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the Registrant
certifies that it has reasonable grounds to believe that it meets all
requirements for filing on Form S-3 and has duly caused this Registration
Statement on Form S-3 of the Registrant to be signed on its behalf by the
undersigned, thereunto duly authorized, in the City of St. Louis, and State of
Missouri, on ________________________.
AMEREN CORPORATION
By_______________________________
____________________
Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed by the following persons in the
capacities and on the date above indicated.
SIGNATURE TITLE
--------- -----
Chairman, President and Chief
/s/ Executive Officer and Director
- -------------------------------------- (Principal Executive Officer)
CHARLES W. MUELLER
/s/ Vice Chairman and Director
- --------------------------------------
CLIFFORD L. GREENWALT
/s/
- -------------------------------------- Senior Vice President, Finance
DONALD E. BRANDT (Principal Financial Officer)
/s/
- -------------------------------------- Controller
WARNER L. BAXTER (Principal Accounting Officer)
/s/
- -------------------------------------- Director
_______________________
/s/
- -------------------------------------- Director
_______________________
/s/
- -------------------------------------- Director
_______________________
II-4
<PAGE>
/s/
- -------------------------------------- Director
________________________
/s/
- -------------------------------------- Director
________________________
/s/
- -------------------------------------- Director
_______________________
/s/
- -------------------------------------- Director
________________________
/s/
- -------------------------------------- Director
________________________
/s/
- -------------------------------------- Director
_______________________
/s/
- -------------------------------------- Director
_______________________
/s/
- -------------------------------------- Director
_______________________
/s/
- -------------------------------------- Director
________________________
/s/
- -------------------------------------- Director
________________________
/s/
- -------------------------------------- Director
_________________________
*By_______________________________
_____________________________
Attorney-In-Fact
II-5
<PAGE>
EXHIBIT NO.
----------
4.1 Article III of the Restated Certificate of Incorporation of the
Registrant (incorporated by reference to Exhibit 3(i) of the Form
S-4 Registration Statement of the Registrant, Reg. No. 33-64165).
4.2 By-laws of the Registrant (incorporated by reference to Annex G
of the Joint Proxy Statement/Prospectus included in the Form S-4
Registration Statement of the Registrant, Reg. No. 33-64165).
5 Opinion of William E. Jaudes as to the legality of the securities
being issued.
12 Computation of ratio of earnings to fixed charges.
23.1 Consent of Price Waterhouse LLP.
23.2 Consent of Arthur Andersen LLP.
23.3 Consent of William E. Jaudes (included in Exhibit 5).
24 Powers of Attorney.
27 Financial Data Schedule.
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<PAGE>
EXHIBIT 23.1
CONSENT OF PRICE WATERHOUSE LLP
We consent to the incorporation by reference in the Registration Statement
on Form S-3 pertaining to the DRP Plus of Ameren Corporation of (a) our reports
dated ___________, 1997 with respect to the financial statements of Union
Electric Company for the year ended December 31, 1996 included in its Annual
Report on Form 10-K for such year filed with the Securities and Exchange
Commission, (b) our report dated _________________, 1997 with respect to the
_________________________ financial statements of Ameren Corporation included in
its Current Report on Form 8-K dated ____________________, 1997, (c) our report
dated __________, 1997 with respect to the _________________ financial
statements of Union Electric Company included in its Current Report on Form 8-K
dated _______________, 1997, (d) our report dated _________________, 1997 with
respect to the ___________________ financial statements of Central Illinois
Public Service Company included in its Current Report on Form 8-K dated
____________, 1997 and (e) our reports dated _______________, 1996 with respect
to the financial statements of Union Electric Company for the year ended
December 31, 1995 included in its Annual Report on Form 10-K for such year filed
with the Securities and Exchange Commission, incorporated by reference in the
Registration Statement on Form S-4 (Reg. No. 33-64165) of Ameren Corporation
filed November 13, 1995.
/s/ PRICE WATERHOUSE LLP
PRICE WATERHOUSE LLP
St. Louis, Missouri
[Date]
II-7
<PAGE>
EXHIBIT 23.2
CONSENT OF ARTHUR ANDERSEN LLP
We consent to the incorporation by reference in the Registration Statement
on Form S-3 pertaining to the DRP Plus of Ameren Corporation of (a) our reports
dated ___________, 1997 with respect to the consolidated financial statements of
Central Illinois Public Service Company for the year ended December 31, 1996
included in its Annual Report on Form 10-K for such year filed with the
Securities and Exchange Commission and (b) our reports dated __________, 1996
with respect to the consolidated financial statements of CIPSCO Incorporated for
the year ended December 31, 1995 included in its Annual Report on Form 10-K for
such year filed with the Securities and Exchange Commission, incorporated by
reference in the Registration Statement on Form S-4 (Reg. No. 33-64165) of
Ameren Corporation filed November 13, 1995.
/s/ AUTHUR ANDERSEN LLP
AUTHUR ANDERSEN LLP
Chicago, Illinois
[Date]
II-8
<PAGE>
Exhibit C-4
SUBSTANTIALLY FINAL FORM
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON ____________, 1997
Registration Statement No. 33-___________
================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM S-8
REGISTRATION STATEMENT
UNDER THE
SECURITIES ACT OF 1933
____________________
AMEREN CORPORATION
(Exact name of registrant as specified in its charter)
STATE OF MISSOURI 43-1723446
(State or other jurisdiction (IRS Employer
of incorporation or organization) Identification No.)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(Address, including zip code, of principal executive offices)
____________________
AMEREN CORPORATION
1997 STOCK INCENTIVE PLAN
(Full title of the plan)
DONALD E. BRANDT, Senior Vice President, Finance
JAMES C. THOMPSON, Secretary
1901 Chouteau Avenue, St. Louis, Missouri 63103
(314) 621-3222
(Names, address and telephone number, including area code, of agents for
service)
CALCULATION OF REGISTRATION FEE
<TABLE>
<CAPTION>
==========================================================================================================
AMOUNT PROPOSED PROPOSED MAXIMUM AMOUNT OF
TITLE OF SECURITIES TO BE MAXIMUM AGGREGATE REGISTRATION
TO BE REGISTERED REGISTERED OFFERING PRICE OFFERING PRICE FEE
PER UNIT*
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
COMMON STOCK,
$.01 PAR VALUE, INCLUDING RELATED 4,000,000 SHARES
RIGHTS
===========================================================================================================
</TABLE>
* Calculated in accordance with Rule 457(h) on the basis of the average of the
high and low prices of the Registrant's Common Stock as reported on the New
York Stock Exchange Composite Tape on __________________.
================================================================================
<PAGE>
PART II
INFORMATION REQUIRED IN THE REGISTRATION STATEMENT
ITEM 3. INCORPORATION OF DOCUMENTS BY REFERENCE
The following documents, previously filed with the Commission by CIPSCO
Incorporated ("CIPSCO") (File No. 1-10628), Union Electric Company ("Union
Electric") (File No. 1-2967) or the Registrant (File No. ____________) pursuant
to the Securities Exchange Act of 1934, as amended, are incorporated by
reference in this Registration Statement:
1. CIPSCO'S Annual Report on Form 10-K for the year ended December 31,
1996.
2. CIPSCO's Quarterly Reports on Form 10-Q for the quarters ended March
31, 1997, June 30, 1997 and September 30, 1997.
3. CIPSCO's Current Report on Form 8-K dated __________, 1997.
4. Union Electric's Annual Report on Form 10-K for the year ended
December 31, 1996.
5. Union Electric's Quarterly Reports on Form 10-Q for the quarters ended
March 31, 1997, June 30, 1997 and September 30, 1997.
6. Union Electric's Current Report on Form 8-K dated ___________, 1997.
7. The Registrant's Current Report on Form 8-K dated _____________, 1997.
8. The Registrant's Registration Statement on Form S-4 (Reg. No. 33-
64165), filed November 13, 1995, which includes a description of the Common
Stock of the Registrant.
All documents subsequently filed by the Registrant pursuant to Sections 13(a),
13(c), 14 and 15(d) of the Securities Exchange Act of 1934, as amended, prior to
the filing of a post-effective amendment which indicates that all securities
offered have been sold or which deregisters all securities then remaining
unsold, shall be deemed to be incorporated by reference herein and to be a part
hereof from the date of the filing of such documents.
ITEM 4. DESCRIPTION OF SECURITIES
Not Applicable.
ITEM 5. INTERESTS OF NAMED EXPERTS AND COUNSEL
William E, Jaudes, Esq., Vice President and General Counsel of the
Registrant, will pass upon the legality of the shares of Common Stock of the
Registrant to be issued under the Plan. Mr. Jaudes will be eligible to receive
awards under the Plan.
ITEM 6. INDEMNIFICATION OF DIRECTORS AND OFFICERS
Article IV of the Registrant's Bylaws, consistent with the applicable
provisions of the Missouri General and Business Corporation Law (the "MGBCL"),
provides for indemnification of directors and officers. These provisions
provide that any person shall be indemnified for expenses and liabilities
imposed upon such person in connection with any threatened, pending or completed
action, suit, or proceeding, whether civil, criminal, administrative or
investigative, other than an action by or in the right of the Registrant, by
reason of the fact that such person is or was
II-1
<PAGE>
a director, officer, employee or agent of the Registrant, or is or was serving
at the request of the Registrant as a director, officer, employee or agent of
another corporation, partnership, joint venture, trust or other enterprise,
against expenses, including attorneys' fees, judgments, fines and amounts paid
in settlement actually and reasonably incurred by such person in connection with
such action, suit or proceeding if such person acted in good faith and in a
manner such person reasonably believed to be in or not opposed to the best
interests of the Registrant, and, with respect to any criminal action or
proceeding, had no reasonable cause to believe his conduct was unlawful.
In a proceeding brought by or in the right of the Registrant, no
indemnification shall be made with respect to any claim as to which an officer
or director has been adjudged to have been liable to Registrant, unless the
court determines that such a person is reasonably and fairly entitled to
indemnification for expenses. However, no indemnification shall be made in
respect of any claim, issue or matter as to which such person shall have been
adjudged to be liable for negligence or misconduct in the performance of his
duty to the Registrant unless and only to the extent that the court in which the
action or suit was brought determines upon application that, despite the
adjudication of liability and in view of all the circumstances of the case, the
person is fairly and reasonably entitled to indemnity for such expenses which
the court shall deem proper.
The By-laws, consistent with the applicable provisions of the MGBCL,
provide that indemnification shall be made by the Registrant only if a
determination has been made by a majority vote of a quorum of the disinterested
directors or by the shareholders or by independent legal counsel, that the
director or officer met the required standard of conduct. The Registrant is
authorized to purchase liability insurance on behalf of an officer or director
whether or not the Registrant would otherwise have the power to indemnify such
person.
The By-laws, consistent with the applicable provisions of the MGBCL,
further provide that, in addition to the indemnities described in the preceding
paragraphs, the Registrant will further indemnity its officers and directors to
the maximum extent permitted by law, provided that no indemnity may be given for
conduct that is adjudged to be knowingly fraudulent, deliberately dishonest, or
willful misconduct.
ITEM 7. EXEMPTIONS FROM REGISTRATION CLAIMED
Not Applicable.
ITEM 8. EXHIBITS
Exhibit No.
----------
4.1 Article III of the Restated Certificate of Incorporation of the
Registrant (incorporated by reference to Exhibit 3(i) of the Form S-
4 Registration Statement of the Registrant, Reg. No. 33-64165).
4.2 By-laws of the Registrant (incorporated by reference to Annex G of
the Joint Proxy Statement/Prospectus included in the Form S-4
Registration Statement of the Registrant, Reg. No. 33-64165).
5 Opinion of William E. Jaudes as to the legality of the securities
being issued.
23.1 Consent of Price Waterhouse LLP.
23.2 Consent of Arthur Andersen LLP.
23.3 Consent of William E. Jaudes (included in Exhibit 5).
24 Powers of Attorney.
II-2
<PAGE>
ITEM 9. UNDERTAKINGS
(a) The undersigned Registrant hereby undertakes:
(1) To file, during any period in which offers or sales are being made, a
post-effective amendment to this registration statement:
(i) To include any prospectus required by Section 10(a)(3) of the
Securities Act of 1933;
(ii) To reflect in the prospectus any facts or events arising after
the effective date of the registration statement (or the most recent post-
effective amendment thereof) which, individually or in the aggregate, represent
a fundamental change in the information set forth in the registration statement.
Notwithstanding the foregoing, any increase or decrease in volume of securities
offered (if the total dollar value of securities offered would not exceed that
which was registered) and any deviation from the low or high end of the
estimated maximum offering range may be reflected in the form of prospectus
filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the
changes in volume and price represent no more than a 20% change in the maximum
aggregate offering price set forth in the "Calculation of Registration Fee"
table in the effective registration statement;
(iii) To include any material information with respect to the plan of
distribution not previously disclosed in the registration statement or any
material change to such information in the registration statement;
Provided, however, that paragraphs (a)(l)(i) and (a)(l)(ii) do not apply in the
registration statement is on Form S-3, Form S-8 or Form F-3, and the information
required to be included in a post-effective amendment by those paragraphs is
contained in periodic reports filed with or furnished to the Commission by the
registrant pursuant to Section 13 or Section 15(d) of the Securities Exchange
Act of 1934 that are incorporated by reference in this registration statement.
(2) That, for the purpose of determining any liability under the
Securities Act of 1933, each such post-effective amendment shall be deemed to be
a new registration statement relating to the securities offered therein and the
offering of such securities at that time shall be deemed to be the initial
bona fide offering thereof.
(3) To remove from registration by means of a post-effective amendment any
of the securities being registered which remain unsold at the termination of the
offering.
(b) The undersigned Registrant hereby undertakes that, for purposes of
determining any liability under the Securities Act of 1933, each filing of the
registrant's annual report pursuant to Section 13(a) or Section 15(d) of the
Securities Exchange act of 1934 (and, where applicable, each filing of an
employee benefit plan's annual report pursuant to Section 15(d) of the
Securities Exchange Act of 1934) that is incorporated by reference in the
registration statement shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of such securities
at that time shall be deemed to be the initial bona fide offering thereof.
(c) Insofar as indemnification for liabilities arising under the Securities
Act of 1933 may be permitted to directors, officers and controlling persons of
the Registrant pursuant to the provisions referred to in Item 6 of this
Registration Statement, or otherwise, the Registrant has been advised that in
the opinion of the Securities and Exchange Commission such indemnification is
against public policy as expressed in the Act and is, therefore, unenforceable.
In the event that a claim for indemnification against such liabilities (other
than the payment by the Registrant of expenses incurred or paid by a director,
officer or controlling person of the Registrant in the successful defense of any
action, suit or proceeding) is asserted by such director, officer or controlling
person in connection with the securities being registered, the Registrant will,
unless in the opinion of its counsel the matter has been settled by controlling
precedent, submit to a court of appropriate jurisdiction the question whether
such indemnification by it is against public policy as expressed in the Act and
will be governed by the final adjudication of such issue.
II-3
<PAGE>
SIGNATURES
The Registrant. Pursuant to the requirements of the Securities Act of
1933, the Registrant certifies that it has reasonable grounds to believe that it
meets all of the requirements for filing on Form S-8 and has duly caused this
Registration Statements to be signed on its behalf by the undersigned thereunto
duly authorized, in the City of St. Louis, State of Missouri, on the ______ day
of ____________________, 199__.
AMEREN CORPORATION
By_____________________________
_____________________
Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed by the following persons in the
capacities and on the date above indicated.
SIGNATURE TITLE
--------- -----
/s/ Chairman, President and Chief
- ----------------------------------- Executive Officer and Director
CHARLES W. MUELLER (Principal Executive Officer)
/s/
- -----------------------------------
CLIFFORD L. GREENWALT Vice Chairman and Director
/s/
- -----------------------------------
DONALD E. BRANDT Senior Vice President, Finance
(Principal Financial Officer)
/s/
- -----------------------------------
WARNER L. BAXTER Controller
(Principal Accounting Officer)
/s/
- -----------------------------------
__________________ Director
/s/
- -----------------------------------
__________________ Director
/s/
- -----------------------------------
__________________ Director
/s/
- -----------------------------------
__________________ Director
II-4
<PAGE>
/s/
-----------------------------------
_________________
/s/
-----------------------------------
_________________
/s/
-----------------------------------
_________________
/s/
-----------------------------------
_________________
/s/
-----------------------------------
_________________
/s/
-----------------------------------
_________________
/s/
-----------------------------------
_________________
/s/
-----------------------------------
_________________
/s/
-----------------------------------
_________________
/s/
-----------------------------------
_________________
Director Director
Director Director
Director Director
II-5
<PAGE>
Director
Director
Director
Director
*By_________________________
__________________
Attorney-In-Fact
II-6
<PAGE>
EXHIBIT INDEX
Exhibit No.
4.1 Article III of the Restated Certificate of Incorporation of the
Registrant (incorporated by reference to Exhibit 3(i) of the Form S-4
Registration Statement of the Registrant, Reg. No. 33-64165).
4.2 By-laws of the Registrant (incorporated by reference to Annex G of the
Joint Proxy Statement/Prospectus included in the Form S-4 Registration
Statement of the Registrant, Reg. No. 33-64165).
5 Opinion of William E. Jaudes as to the legality of the securities being
issued.
23.1 Consent of Price Waterhouse LLP.
23.2 Consent of Arthur Andersen LLP.
23.3 Consent of William E. Jaudes (included in Exhibit 5).
24 Powers of Attorney.
All Exhibits are filed electronically with Form S-8.
II-7
<PAGE>
EXHIBIT 23.1
CONSENT OF PRICE WATERHOUSE LLP
We consent to the incorporation by reference in the Registration
Statement on Form S-8 pertaining to the 1997 Stock Incentive Plan of Ameren
Corporation of (a) our reports dated ___________, 1997 with respect to the
financial statements of Union Electric Company for the year ended December 31,
1996 included in its Annual Report on Form 10-K for such year filed with the
Securities and Exchange Commission, (b) our report dated _________________, 1997
with respect to the _________________________ financial statements of Ameren
Corporation included in its Current Report on Form 8-K dated
____________________, 1997, (c) our report dated __________, 1997 with respect
to the _________________ financial statements of Union Electric Company included
in its Current Report on Form 8-K dated _______________, 1997, (d) our report
dated _________________, 1997 with respect to the ___________________ financial
statements of Central Illinois Public Service Company included in its Current
Report on Form 8-K dated ____________, 1997 and (e) our reports dated
_______________, 1996 with respect to the financial statements of Union Electric
Company for the year ended December 31, 1995 included in its Annual Report on
Form 10-K for such year filed with the Securities and Exchange Commission,
incorporated by reference in the Registration Statement on Form S-4 (Reg. No.
33-64165) of Ameren Corporation filed November 13, 1995.
/s/ PRICE WATERHOUSE LLP
PRICE WATERHOUSE LLP
St. Louis, Missouri
[Date]
II-8
<PAGE>
EXHIBIT 23.2
CONSENT OF ARTHUR ANDERSEN LLP
We consent to the incorporation by reference in the Registration
Statement on Form S-3 pertaining to the 1997 Stock Incentive Plan of Ameren
Corporation of (a) our reports dated ___________, 1997 with respect to the
consolidated financial statements of Central Illinois Public Service Company for
the year ended December 31, 1996 included in its Annual Report on Form 10-K for
such year filed with the Securities and Exchange Commission and (b) our reports
dated __________, 1996 with respect to the consolidated financial statements of
CIPSCO Incorporated for the year ended December 31, 1995 included in its Annual
Report on Form 10-K for such year filed with the Securities and Exchange
Commission, incorporated by reference in the Registration Statement on Form S-4
(Reg. No. 33-64165) of Ameren Corporation filed November 13, 1995.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Chicago, Illinois
[Date]
II-9
<PAGE>
Exhibit C-4 Part 2
SUBSTANTIALLY FINAL FORM
AMEREN CORPORATION
1997 STOCK INCENTIVE PLAN
SECTION 1. PURPOSE. The purpose of the Plan is to give Ameren
Corporation, its subsidiaries and certain affiliates a competitive advantage in
attracting, retaining and motivating officers, employees and directors by
providing for the awarding of incentives linked to the profitability of the
Corporation and its businesses and to increases in shareholder value.
SECTION 2. DEFINITIONS. In addition to the terms defined elsewhere in the
Plan, the following terms shall have the meanings set forth below:
"AFFILIATE" means a corporation or other entity controlled by the
Corporation and designated by the Committee from time to time as such.
"AWARD" means any Performance Unit, Option, Stock Appreciation Right,
Restricted Stock, Dividend Equivalent or Other Stock-Based Award, or any other
right or interest relating to Shares or cash, granted to a Participant under the
Plan.
"AWARD AGREEMENT" means any written agreement, contract or other instrument
or document evidencing an Award.
"BOARD" means the Board of Directors of the Corporation.
"CODE" means the Internal Revenue Code of 1986, as amended from time to
time, including successor provisions thereto and regulations thereunder.
"COMMITTEE" means the Human Resources Committee of the Board, or such other
Board committee as may be designated by the Board to administer the Plan, or any
subcommittee of either; provided, however, that the Committee (a) shall be
composed solely of two or more non-employee directors, as defined in Rule 16(b)-
3(b)(3) under the Exchange Act, and (b) shall be constituted to permit Awards
under the Plan to qualify for exemption under Rule 16b-3 under the Exchange Act.
"CORPORATION" means Ameren Corporation, a Missouri corporation.
"EXCHANGE ACT" means the Securities Exchange Act of 1934, as amended from
time to time, including successor provisions thereto and regulations thereunder.
"FAIR MARKET VALUE" means, with respect to Shares, Awards or other
property, the fair market value of such Shares, Awards or other property
determined by such methods or procedures as shall be established from time to
time by the Committee. Unless otherwise determined by the Committee, the Fair
Market Value of Shares as of any date shall be the closing sale price on that
date of a Share as reported on the New York Stock Exchange Composite Tape.
"INCENTIVE STOCK OPTION" means an Option that is designated as such by the
Committee and meets the requirements of Section 422 of the Code.
"NON-QUALIFIED STOCK OPTION" means an Option that is not an Incentive Stock
Option.
"PARTICIPANT" means a person who, as an officer, employee or director of
the Corporation, a Subsidiary or an Affiliate, has been granted an Award under
the Plan.
"PLAN" means the Ameren Corporation 1997 Stock Incentive Plan, as set forth
herein and as hereinafter amended from time to time.
"QUALIFIED PERFORMANCE-BASED AWARD" means an Award of Performance Units or
Restricted Stock, or other Award, designated as such by the Committee at or
prior to the time of grant, based upon a determination that the Committee
intends for such Award to qualify for the Section 162(m) Exemption.
"RULE 16B-3" means Rule 16b-3, as from time to time amended and applicable
to Participants, promulgated by the Securities and Exchange Commission under
Section 16 of the Exchange Act.
"SECTION 162(M) EXEMPTION" means the exemption from the limitation on
deductibility imposed by Section 162(m) of the Code that is set forth in Section
162(m)(4)(C) of the Code.
<PAGE>
"SHARES" means the Common Stock, $.01 par value per share, of the
Corporation and such other securities of the Corporation as may be substituted
for Shares pursuant to Section 10 of the Plan.
"SUBSIDIARY" means any company (other than the Corporation) with respect to
which the Corporation owns, directly or indirectly, 50% or more of the total
combined voting power of all classes of stock. In addition, any other related
entity may be designated by the Board as a Subsidiary, provided such entity
could be considered as a subsidiary according to generally accepted accounting
principles.
"YEAR" means a calendar year.
In addition to the foregoing, the terms "Performance Unit", "Option",
"Stock Appreciation Right", "Restricted Stock", "Dividend Equivalent" and "Other
Stock-Based Award" shall mean as described in Section 6 of the Plan.
SECTION 3. ADMINISTRATION.
3.01. Authority of the Committee. The Plan shall be administered by the
Committee on behalf of the Board. The Committee shall have full power to
interpret the Plan, to establish, modify and grant waivers of Award restrictions
and to adopt such rules, regulations and guidelines for carrying out the Plan as
it deems necessary or appropriate. All determinations by the Committee shall be
final and binding upon all parties affected thereby. Any authority granted to
the Committee may also be exercised by the full Board, except to the extent that
the grant or exercise of such authority would cause any Award or transaction to
fail to qualify for exemption under Rule 16b-3.
3.02. Manner of Exercise of Committee Authority. The express grant of any
specific power to the Committee, and the taking of any action by the Committee,
shall not be construed as limiting any power or authority of the Committee. A
memorandum signed by all members of the Committee shall constitute the act of
the Committee without the necessity, in such event, to hold a meeting. The
Committee may delegate to officers or managers of the Corporation or any
Subsidiary or Affiliate the authority, subject to such terms as the Committee
shall determine, to perform administrative functions under the Plan. Only the
Committee or the full Board may select, and grant Awards to, Participants who
are subject to Section 16 of the Exchange Act.
SECTION 4. SHARES SUBJECT TO THE PLAN. Subject to adjustment as provided
in the Plan, the total number of Shares that may be issued or delivered pursuant
to Awards under the Plan shall be 4,000,000, which shall consist of (a) Shares
which have been authorized and issued and have been acquired by or on behalf of
the Corporation or the Plan and are available for Awards under the Plan or (b)
if the Board shall so authorize, authorized and unissued Shares. The Committee
may adopt procedures for the counting of Shares relating to any Award for which
the number of Shares to be distributed or with respect to which payment will be
made cannot be fixed at the date of grant to ensure appropriate counting, avoid
double counting (in the case of tandem or substitute awards), and provide for
adjustments in any case in which the number of Shares actually distributed or
with respect to which payments are actually made differs from the number of
Shares previously counted in connection with such Award. In the event that any
Shares to which an Award relates are forfeited or the Award is settled or
terminates without a distribution of Shares (whether or not cash, other Awards
or other property are distributed with respect to such Award), any Shares
counted against the number of Shares reserved and available under the Plan with
respect to such Award shall again be available for Awards under the Plan. The
maximum number of Shares with respect to which Options or Stock Appreciation
Rights may be granted to any one Participant under the Plan during any Year is
_______ Shares.
SECTION 5. ELIGIBILITY. Awards may be granted only to individuals who are
officers, employees or directors of the Corporation, a Subsidiary or an
Affiliate; provided, however, that no Award shall be granted to any member of
the Committee except by action of the full Board and subject to such other
restrictions as the Board may require.
SECTION 6. SPECIFIC TERMS OF AWARDS.
6.01. General. The Committee may grant Awards as described in this
Section. The Committee shall determine who may participate in the Plan and the
number and types of Awards to be made to each Participant and shall determine
and set forth in the Award or the related Award Agreement the terms, conditions,
performance requirements (if any) and limitations (which need not be limited to
those referred to below) applicable to each Award. Awards may be granted
singly, in combination or in tandem.
6.02. Performance Units. An Award of Performance Units shall confer upon
the Participant a right to receive cash, Shares, other Awards or other property
contingent upon the achievement of performance goals specified by the Committee.
A Performance Unit shall be denominated in Shares and may be payable in cash,
Shares, other Awards or other Property, and have such other terms as shall be
determined by the Committee.
6.03. Restricted Stock. Restricted Stock shall confer upon the
Participant the right to receive Shares subject to such restrictions on
transferability and other restrictions as the Committee may impose (including,
without limitation,
2
<PAGE>
forfeiture if such restrictions are not satisfied, limitations on the right to
vote and limitations on the right to receive dividends), which restrictions may
expire at such times and under such circumstances as the Committee shall
determine.
6.04. Options. An Option shall confer upon the Participant the right to
purchase Shares, other Awards or property, subject to the following terms and
conditions:
(a) Exercise Price. The exercise price per share purchasable under an
Option shall not be less than the Fair Market Value of a Share on the date of
grant of such Option.
(b) Time and Method of Exercise. The Committee shall determine the
time during which an Option may be exercised in whole or in part, the methods by
which the exercise price may be paid and the methods by which Shares will be
delivered to Participants. Options shall expire not later than ten years after
the date of grant.
(c) Terms Applicable to Incentive Stock Options. The terms of any
Incentive Stock Option granted under the Plan shall comply in all respects with
the provisions of Section 422 of the Code which, among other limitations,
provides that the aggregate Fair Market Value (determined at the time the Option
is granted) of Shares for which Incentive Stock Options are exercisable for the
first time by a Participant during any calendar year shall not exceed $100,000.
The number of Shares that shall be available for Incentive Stock Options granted
under the Plan is limited to 500,000. Anything in the Plan to the contrary
notwithstanding, no term of the Plan relating to Incentive Stock Options, other
than Section 9, shall be applied, interpreted, amended or altered, nor shall any
discretion or authority granted under the Plan be exercised, so as to disqualify
the Plan under Section 422 of the Code or, without the consent of the
Participant affected, to disqualify any Incentive Stock Option under such
Section 422.
(d) Limitation on Re-Pricing and Replacement. No Option shall provide
by its terms for the re-setting of its exercise price, or for its replacement,
in whole or in part, upon its exercise or expiration; provided that the
foregoing shall not limit the authority of the Committee to grant additional
Options in any such event or circumstances.
(e) Cash Out by Committee. Upon receipt of written notice of
exercise, the Committee may elect to cash out all or part of the portion of the
Shares for which an Option is being exercised by paying the optionee an amount,
in cash or Shares, equal to the excess of the Fair Market Value of Shares over
the option price times the number of Shares for which the Option is being
exercised on the effective date of such cash-out.
(f) Change in Control Cash-Out Right. Notwithstanding any other
provision of the Plan, during the 60-day period from and after a Change in
Control (the "Exercise Period"), unless the Committee shall determine otherwise
at the time of grant, a holder of an Option to purchase Shares shall have the
right, whether or not the Option is fully exercisable and in lieu of the payment
of the exercise price for the Shares being purchased under the Option and by
giving notice to the Corporation, to elect (within the Exercise Period) to
surrender all or part of the Option to the Corporation and to receive cash,
within 30 days of such notice, in an amount equal to the amount by which the
Change in Control Price per Share on the date of such election shall exceed the
exercise price per Share under the Option (the "Spread") multiplied by the
number of Shares granted under the Option as to which the right granted under
this Section 6.04(f) shall have been exercised. Notwithstanding the foregoing,
if any right granted pursuant to this Section 6.04(f) would make a Change in
Control transaction ineligible for pooling-of-interests accounting under APB No.
16 that but for the nature of such grant would otherwise be eligible for such
accounting treatment, the Committee shall have the ability to substitute for the
cash payable pursuant to such right Shares with a Fair Market Value equal to the
cash that would otherwise be payable hereunder.
6.05. Stock Appreciation Rights. A Stock Appreciation Right shall confer
upon the Participant a right to receive the excess of (a) the Fair Market Value
of one Share on the date of exercise (or, except in the case of a Stock
Appreciation Right related to an Incentive Stock Option, the Fair Market Value
of one Share at any time during a specified period before or after the date of
exercise) over (b) the grant price of the Stock Appreciation Right, which shall
be not less than the Fair Market Value of one Share on the date of grant. A
Stock Appreciation Right may be granted as a Limited Stock Appreciation Right
which may be exercised only upon the occurrence of a Change in Control. Stock
Appreciation Rights shall expire not later than ten years after the date of
grant.
6.06. Dividend Equivalents. A Dividend Equivalent shall confer upon the
Participant a right to receive cash, Shares, other Awards or other property
equal in value to dividends paid with respect to a specified number of Shares.
6.07. Other Stock-Based Awards. The Committee is authorized to grant to
Participants such other Awards that are denominated or payable in, valued in
whole or in part by reference to, or otherwise based on or related to, Shares,
as deemed by the Committee to be consistent with the purpose of the Plan.
3
<PAGE>
SECTION 7. CERTAIN PROVISIONS APPLICABLE TO AWARDS.
7.01. Qualified Performance-Based Awards. The Committee may, at or prior
to the time of grant, designate Performance Units or Restricted Stock, or any
other Award, as a Qualified Performance-Based Award, in which event it shall
take such action with respect to such Award and the terms thereof (including the
imposition of additional requirements not otherwise required by the terms of the
Plan), and the provisions of the Plan or any Award Agreement shall be construed
or deemed amended, as shall be necessary to cause such Award to qualify for the
Section 162(m) Exemption.
7.02. Term of Awards. The term of each Award shall be for such period as
shall be determined by the Committee subject to the requirements of the Plan.
7.03. Forms of Payment. Subject to the terms of the Plan and any
applicable Award Agreement, (a) payments to be made by the Corporation, a
Subsidiary or Affiliate with respect to Awards are to be made in such forms as
the Committee shall determine; and (b) the timing, method, amount and nature of
payments to be made by Participants with respect to Awards (including, if
permitted by the Committee, by means of tendering Shares or Awards) shall be
determined by the Committee.
7.04. Termination of Employment. If the employment of a Participant
terminates, all unexercised, deferred and unpaid Awards shall be cancelled
immediately, unless the Award Agreement provides otherwise or unless the
Committee shall provide otherwise in connection with such termination,
including, without limitation, in the case of termination pursuant to
retirement, resignation, death or disability of a Participant.
SECTION 8. GENERAL RESTRICTIONS APPLICABLE TO AWARDS.
8.01. Restrictions Under Rule 16b-3. It is the intent of the Corporation
that any Award granted to a person who is subject to Section 16 of the Exchange
Act qualify for exemption under Rule 16b-3. Accordingly, if any provision of
the Plan or any Award Agreement would cause such an Award to fail to qualify for
such exemption, such provision shall be construed or deemed amended to the
extent necessary to enable such Award to qualify for such exemption.
8.02. Limits on Transfer of Awards; Beneficiaries. No Award may be
assigned or transferred by a Participant otherwise than by will or the laws of
descent and distribution, or payable to or exercisable by anyone other than the
Participant to whom it was granted, and no right or interest of a Participant in
any Award may be pledged, encumbered or hypothecated to or in favor of any
party, or shall be subject to any lien, obligation or liability of a Participant
to any party; provided, however, that (a) a Participant may, in the manner
established by the Committee, designate a beneficiary or beneficiaries to
exercise the rights of the Participant, and to receive any distribution with
respect to any Award, upon the death or disability of the Participant, (b) the
Committee may provide in any Award or the related Award Agreement that an Award
(other than an Incentive Stock Option) may be assigned, transferred, exercisable
by another person or pledged, encumbered or hypothecated, subject to the
applicable requirements of the Code, and (c) transfers of Awards may be made to
the Corporation, a Subsidiary or an Affiliate to the extent permitted under the
terms of the Plan. A beneficiary, guardian, legal representative or other
person claiming any rights under the Plan from or through any Participant shall
be subject to all terms and conditions applicable to such Participant, except to
the extent the Plan and such Award Agreement otherwise provide with respect to
such person, and to any additional restrictions deemed necessary or appropriate
by the Committee.
8.03. Share Certificates. All certificates for Shares delivered under the
Plan pursuant to an Award or the exercise thereof shall be subject to such stop-
transfer orders and other restrictions as the Committee may deem advisable under
applicable federal or state laws, rules and regulations and the rules of any
national securities exchange on which Shares are listed. The Committee may
cause a legend or legends to be placed on any such certificates to make
appropriate reference to such restrictions or any other restrictions that may be
applicable to Shares. In addition, during any period in which Awards or Shares
are subject to restrictions, or during any period during which delivery or
receipt of an Award or Shares has been deferred by the Committee or a
Participant, the Committee may require the Participant to enter into an
agreement providing that certificates representing Shares issued or issuable
pursuant to an Award shall remain in the physical custody of the Corporation or
such other person as the Committee may designate.
If certificates representing Restricted Stock are registered in the name of
the Participant, such certificates shall bear an appropriate legend referring to
the terms, conditions and restrictions applicable to such Restricted Stock, the
Corporation shall retain physical possession of the certificates and the
Participant shall deliver a stock power to the Corporation, endorsed in blank,
relating to the Restricted Stock.
SECTION 9. CHANGE IN CONTROL.
4
<PAGE>
(a) Impact of Event. Notwithstanding any other provision of the Plan
to the contrary, in the event of a Change in Control: (i) any Options and Stock
Appreciation Rights outstanding as of the date such Change in Control is
determined to have occurred, and which are not then exercisable and vested,
shall become fully exercisable and vested to the full extent of the original
grant; (ii) the restrictions and deferral limitations applicable to any
Restricted Stock shall lapse, and such Restricted Stock shall become free of all
restrictions and become fully vested and transferable to the full extent of the
original grant; and (iii) all Performance Units shall be considered to be earned
and payable in full, and any deferral or other restriction shall lapse and such
Performance Units shall be settled in cash as promptly as is practicable.
(b) Definition of Change in Control. For purposes of the Plan, a
"Change in Control" shall mean the happening of any of the following events:
(i) an acquisition by any individual, entity or group (within
the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act) (a "Person") of
beneficial ownership (within the meaning of Rule 13d-3 promulgated under the
Exchange Act) of 20% or more of either (1) the then outstanding shares of common
stock of the Corporation (the "Outstanding Corporation Common Stock") or (2) the
combined voting power of the then outstanding voting securities of the
Corporation entitled to vote generally in the election of directors (the
"Outstanding Corporation Voting Securities"); excluding, however, the following:
(1) any acquisition directly from the Corporation, other than an acquisition by
virtue of the exercise of a conversion privilege unless the security being so
converted was itself acquired directly from the Corporation, (2) any acquisition
by the Corporation, (3) any acquisition by any employee benefit plan (or related
trust) sponsored or maintained by the Corporation or any corporation controlled
by the Corporation or (4) any acquisition by any corporation pursuant to a
transaction which complies with clauses (1), (2) and (3) of subsection (iii) of
this Section 9(b); or
(ii) a change in the composition of the Board such that the
individuals who, as of the effective date of the Plan, constitute the Board
(such Board shall be hereinafter referred to as the "Incumbent Board") cease for
any reason to constitute at least a majority of the Board; provided, however,
for purposes of this Section 9(b), that any individual who becomes a member of
the Board subsequent to the effective date of the Plan, whose election, or
nomination for election by the Corporation's shareholders, was approved by a
vote of at least a majority of those individuals who are members of the Board
and who are also members of the Incumbent Board (or deemed to be such pursuant
to this proviso) shall be considered as though such individual were a member of
the Incumbent Board; but, provided further, that any such individual whose
initial assumption of office occurs as a result of either an actual or
threatened election contest (as such terms are used in Rule 14a-11 of Regulation
14A promulgated under the Exchange Act) or other actual or threatened
solicitation of proxies or consents by or on behalf of a Person other than the
Board shall not be so considered as a member of the Incumbent Board; or
(iii) the approval by the shareholders of the Corporation of a
reorganization, merger or consolidation or sale or other disposition of all or
substantially all of the assets of the Corporation ("Corporate Transaction") or,
if consummation of such Corporate Transaction is subject, at the time of such
approval by shareholders, to the consent of any government or governmental
agency, obtaining of such consent (either explicitly or implicitly by
consummation); excluding however, such a Corporate Transaction pursuant to which
(1) all or substantially all of the individuals and entities who are the
beneficial owners, respectively, of the Outstanding Corporation Common Stock and
Outstanding Corporation Voting Securities immediately prior to such Corporate
Transaction will beneficially own, directly or indirectly, more than 60% of,
respectively, the outstanding shares of common stock, and the combined voting
power of the then outstanding voting securities entitled to vote generally in
the election of directors, as the case may be, of the corporation resulting from
such Corporate Transaction (including, without limitation, a corporation which
as a result of such transaction owns the Corporation or all or substantially all
of the Corporation's assets either directly or through one or more subsidiaries)
in substantially the same proportions as their ownership, immediately prior to
such Corporate Transaction, of the Outstanding Corporation Common Stock and
Outstanding Corporation Voting Securities, as the case may be, (2) no Person
(other than the Corporation, any employee benefit plan (or related trust) of the
Corporation or such corporation resulting from such Corporate Transaction) will
beneficially own, directly or indirectly, 20% or more of, respectively, the
outstanding shares of common stock of the corporation resulting from such
Corporate Transaction or the combined voting power of the outstanding voting
securities of such corporation entitled to vote generally in the election of
directors except to the extent that such ownership existed prior to the
Corporate Transaction, and (3) individuals who were members of the Incumbent
Board will constitute at least a majority of the members of the board of
directors of the corporation resulting from such Corporate Transaction; or
(iv) the approval by the stockholders of the Corporation of a
complete liquidation or dissolution of the Corporation.
5
<PAGE>
(c) Change in Control Price. For purposes of the Plan, "Change in
Control Price" means the higher of (i) the highest reported sales price, regular
way, of a Share in any transaction reported on the New York Stock Exchange
Composite Tape or other national exchange on which such Shares are listed or on
NASDAQ during the 60-day period prior to and including the date of a Change in
Control or (ii) if the Change in Control is the result of a tender or exchange
offer or a Corporate Transaction, the highest price per Share paid in such
tender or exchange offer or Corporate Transaction; provided, however, that in
the case of Incentive Stock Options and Stock Appreciation Rights relating to
Incentive Stock Options, the Change in Control Price shall be in all cases the
Fair Market Value of the Shares on the date such Incentive Stock Option or Stock
Appreciation Right is exercised. To the extent that the consideration paid in
any such transaction described above consists all or in part of securities or
other noncash consideration, the value of such securities or other noncash
consideration shall be determined in the sole discretion of the Board.
SECTION 10. ADJUSTMENT PROVISIONS. In the event that the Committee shall
determine that any dividend or other distribution (whether in the form of cash,
Shares or other property), recapitalization, stock split, reverse stock split,
reorganization, merger, consolidation, spin-off, combination, repurchase or
share exchange, or other similar corporate transaction or event, affects the
Shares such that an adjustment is determined by the Committee to be appropriate
in order to prevent dilution or enlargement of the rights of Participants under
the Plan, then the Committee shall, in such manner as it may deem equitable,
make any adjustments it deems appropriate (including, without limitation,
adjustments to the share limitations contained in Section 4 and to the terms of
then-outstanding Awards). In addition, the Committee is authorized to make such
adjustments as it deems appropriate in the terms and conditions of, and the
criteria included in, Awards in recognition of unusual or nonrecurring events
(including, without limitation, events described in the preceding sentence)
affecting the Corporation or any Subsidiary or Affiliate or the financial
statements of the Corporation or any Subsidiary or Affiliate, or in response to
changes in applicable laws, regulations or accounting principles.
SECTION 11. CHANGES TO THE PLAN AND AWARDS.
11.01. Changes to the Plan. The Board may amend, alter, suspend,
discontinue or terminate the Plan without the consent of shareholders or
Participants, except as is required by any federal or state law or regulation or
the rules of any stock exchange on which the Shares may be listed, or if the
Board in its discretion determines that obtaining such shareholder approval is
for any reason advisable; provided, however, that, without the consent of an
affected Participant, no amendment, alteration, suspension, discontinuation or
termination of the Plan may impair the rights of such Participant under any
Award theretofore granted to such Participant.
11.02. Changes to Awards. The Committee may waive any conditions or
rights under, or amend, alter, accelerate, suspend, discontinue or terminate,
any Award theretofore granted and any Award Agreement relating thereto;
provided, however, that, without the consent of an affected Participant, no such
amendment, alteration, suspension, discontinuation or termination of any Award
may impair the rights of such Participant under such Award.
SECTION 12. GENERAL PROVISIONS.
12.01. No Rights to Awards. No Participant, officer, employee or director
shall have any claim to be granted any Award under the Plan, and there is no
obligation for uniformity of treatment of Participants or any other persons.
12.02. No Shareholder Rights. No Award shall confer on any Participant
any of the rights of a shareholder of the Corporation unless and until Shares
are duly issued or transferred to the Participant in accordance with the terms
of the Award.
12.03. Dividends. The recipient of any Award may, if so determined by the
Committee, be entitled to receive on a current or deferred basis, dividends or
Dividend Equivalents, with respect to the number of Shares covered by the Award.
12.04. Tax Withholding. The Corporation or any Subsidiary or Affiliate is
authorized to withhold from any award granted, any payment relating to an Award
under the Plan (including from a distribution of Shares) or any payroll or other
payment to a Participant, amounts of withholding and other taxes due with
respect thereto, its exercise or any payment thereunder, and to take such other
action as the Committee may deem necessary or advisable to enable the
Corporation and Participants to satisfy obligations for the payment of
withholding taxes and other tax liabilities relating to any Award. This
authority shall include authority to withhold or receive Shares or other
property and to make cash payments in respect thereof in satisfaction of a
Participant's tax obligations.
12.05. No Right to Employment. Nothing contained in the Plan or any Award
Agreement shall confer, and no grant of an Award shall be construed as
conferring, upon any employee any right to continue in the employ of the
Corporation or any Subsidiary
6
<PAGE>
or Affiliate or to interfere in any way with the right of the Corporation or any
Subsidiary or Affiliate to terminate the employee's employment at any time or
increase or decrease the employee's compensation from the rate in existence at
the time of granting of an Award.
12.06. Unfunded Status of Awards. The Plan is intended to constitute an
"unfunded" plan for incentive and deferred compensation. Nothing contained in
the Plan, any Award Agreement or any Award shall give any such Participant any
rights that are greater than those of an unsecured general creditor of the
Corporation.
12.07. Other Compensatory Arrangements. The Corporation or any Subsidiary
or Affiliate shall be permitted to adopt other or additional compensation
arrangements (which may include arrangements which relate to Awards), and such
arrangements may be either generally applicable or applicable only in specific
cases.
12.08. Fractional Shares. No fractional Shares shall be issued or
delivered pursuant to the Plan or any Award. The Committee shall determine
whether cash, other Awards or other property shall be issued or paid in lieu of
fractional Shares or whether such fractional Shares or any rights thereto shall
be forfeited or otherwise eliminated.
12.09. Governing Law. The validity, construction and effect of the Plan,
any rules and regulations relating to the Plan, any action taken pursuant to the
Plan and any Award Agreement shall be governed by the laws of the State of
Missouri, without giving effect to principles of conflicts of laws, and
applicable federal law.
12.10. Tax Offset Bonuses. At the time an Award is made under the Plan or
at any time thereafter, the Committee may grant to the Participant receiving
such Award the right to receive a cash payment in an amount specified by the
Committee, to be paid at such time or times (if ever) as the Award results in
compensation income to the Participant, for the purpose of assisting the
Participant to pay the resulting taxes, all as determined by the Committee and
on such other terms and conditions as the Committee shall determine.
SECTION 13. LAWS AND REGULATIONS. The Plan, the granting and exercising
of Awards thereunder and the other obligations of the Corporation under the Plan
shall be subject to all applicable federal and state laws, rules and regulations
and to such approvals by any regulatory or governmental agency as may be
required. The Corporation, in its discretion, may postpone the granting and
exercising of Awards, the issuance or delivery of Shares under any Award or any
other action permitted under the Plan to permit the Corporation, with reasonable
diligence, to complete any stock exchange listing or registration or
qualification of such Shares or other required action under any federal or state
law, rule or regulation and may require any participant to make such
representations and furnish such information as it may consider appropriate in
connection with the issuance of delivery of Shares in compliance with applicable
laws, rules and regulations. The Corporation shall not be obligated by virtue
of any provision of the Plan to recognize the exercise of any Award or to
otherwise sell or issue Shares in violation of any such laws, rules, or
regulations; and any postponement of the exercise or settlement of any Award
under this provision shall not extend the term of such Award, and neither the
Corporation nor its directors or officers shall have any obligation or liability
to any Participant with respect to any Award (or stock issuable thereunder) that
shall lapse because of such postponement.
SECTION 14. EFFECTIVE DATE. The Plan shall become effective on
_____________, 1997; provided that the effectiveness of the Plan shall be
subject to the approval of the Plan by the affirmative vote of the holders of a
majority of the Shares present or represented and entitled to vote at the next
following meeting of the Corporation's shareholders. The Committee shall have
the authority to grant Awards prior to such approval; provided that the
effectiveness of such Awards shall be subject to such shareholder approval of
the Plan. The Plan shall terminate ten years after its effective date, subject
to earlier termination by the Board pursuant to Section 11, after which no
Awards may be made under the Plan, but any such termination shall not affect
Awards then outstanding or the authority of the Committee to continue to
administer the Plan.
7
<PAGE>
EXHIBIT C-5
DESCRIPTION OF EXISTING SAVINGS PLANS
1. UNION ELECTRIC SAVINGS INVESTMENT PLAN
--------------------------------------
Union Electric Company ("UE") has adopted an employee savings investment
plan ("SIP") which permits eligible participants under Section 401(K) of the
Internal Revenue Code to defer current federal income taxes on contributions to
the SIP and earnings thereon. The Plan is available to both management and union
(contract) employees. All eligible employees who are at least 21 years old and
have completed 1 year of service can participate.
Participants contribute via payroll deductions up to 15% of their base pay
and can invest in the following investment funds: Aggressive Equity,
Conservative Equity, Balanced Fund, International Fund, Stable Interest Income
Fund, and Union Electric Common Stock Fund. UE, to the extent sufficient
earnings are available, may practically match contributions made to the SIP by
participants. For management employees, UE contributes 50% of the participant's
contribution up to 6% of that participant's total contribution in the plan. UE's
contribution is divided equally between the investment fund(s) chosen by the
participant and the Union Electric common stock fund. The match, if any, and the
allocation of matching contributions for contract employees are established by
the collective bargaining agreement between the participant's bargaining unit
and UE.
Previously, UE made contributions to the Employee Stock Ownership Plan
("ESOP") to claim additional tax credits on its federal income tax returns. The
contributions were used to purchase shares of UE common stock. At the time the
contributions were made, ESOP Accounts were established for employees. When the
tax laws changed, UE ceased making ESOP contributions. In 1993, the ESOP
Accounts were merged into the SIP. Provided that stock is held for a minimum of
84 months, participants may withdraw part or all of the stock held in the ESOP.
2. UNION ELECTRIC LONG-TERM INCENTIVE PLAN ("LIP")
-----------------------------------------------
In 1995 UE's Board of Directors and shareholders approved the terms of the
Long-Term Incentive Plan ("LIP") which is designed to give UE a competitive
advantage in attracting, retaining and motivating officers and certain key
employees. The LIP provides for the issuance of incentive awards linked to UE's
profitability. Pursuant to the LIP, UE encourages eligible officers and
employees to acquire or increase their ownership of Union Electric's common
stock. The Human Resources Committee of UE's Board of Directors determines which
employees are eligible to participate in the LIP. Such employees may be eligible
for performance awards payable in cash or shares of common stock, restricted
stock, stock options and stock appreciation awards. Absent early termination the
LIP will terminate ten years after its effective date. Pursuant to the Merger
Agreement, Ameren will adopt a stock compensation plan ("Ameren LIP") to replace
the UE LIP.
<PAGE>
3. CIPSCO LONG-TERM SAVINGS PLANS
------------------------------
CIPS sponsors three investment savings plans (Employee Long-Term Savings
Plan, Employee Long-Term Saving Plan - I.B.E.W. Local No. 702, Employee Long-
Term Saving Plan - I.U.O.E. Local No. 148) which permit management employees and
employees who are members of bargaining units to defer federal income taxes on
contributions to the plans and earnings thereon. The plans are qualified plans
under Section 401 of the Internal Revenue Code. Participants can participate in
only one plan.
Employees who have one year of service and have attained the age of 21 can
participate in one of the available Plans. A participant in any plan who meets
the eligibility requirements of another plan (i.e. becomes a management
employee), automatically becomes a participant of such plan and the
participant's accounts is transferred. Participants can contribute up to 15% of
his or her compensation into a Plan and invest in the following investment
funds: CIPSCO Common Stock, Bond Index Fund, Standard & Poor's 500 Equity Index
Fund, Money Market Fund, Growth Equity Fund, Merrill Lynch Retirement
Preservation Trust, Merrill Lynch Capital Fund, Merrill Lynch Global Allocation
Fund and the Aim Value Fund. At the consummation of the mergers constituting the
Transaction, the CIPSCO Common Stock will be converted to Ameren Common Stock
pursuant to the Merger Agreement.
Under the terms of the Local 702 Plan, CIPS matches a percentage of the
participant's contribution. CIPS's matching contribution is 15% of the
participant's contribution up to 5% of that participant's total contribution.
No withdrawals can be made under the plans during employment except for
certain loans and hardship withdrawals and otherwise as provided in the plans.
2
<PAGE>
EXHIBIT D-1.3
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Before Commissioners: James J. Hoecker, Chairman;
Vicky A. Bailey, and William L. Massey.
Union Electric Company ) Docket Nos. EC96-7-000, 001,
and Central Illinois ) ER96-677-000, 001, ER96-679-
Public Service Company ) 000, 001 and EL98-1-000
Opinion No. 417
OPINION AND ORDER AFFIRMING IN PART AND
REVERSING IN PART INITIAL DECISION, DISMISSING REHEARINGS,
ACCEPTING SETTLEMENT, AND INITIATING INVESTIGATION
(Issued October 15, 1997)
In this opinion the Commission approves the proposed merger
on the condition that the Applicants comply with the ratepayer
commitments made during this proceeding, as further discussed
below.
I. Introduction
------------
A. Hearing Order
-------------
These proceedings involve Union Electric Company's (Union
Electric) and Central Illinois Public Service Company's (Central
Illinois) (collectively, Applicants) request that the Commission
approve their: (1) joint merger application under section 203 of
the Federal Power Act (FPA), 16 U.S.C. (S) 824b (1994), in Docket
No. EC96-7-000; (2) System Support Agreement and Joint Dispatch
Agreement in Docket No. ER96-679-000; and (3) open access
transmission tariff in Docket No. ER96-677-000. 1/ On October
-
16, 1996, the Commission issued an order in the above proceedings
that set the proposed merger for hearing because the Commission
found that significant issues had been raised regarding the
effect of the merger on: (1) costs and rates; (2) impairment of
effective regulation; and (3) the competitive situation,
particularly the effect of transmission constraints in the
relevant markets. See Union Electric Company, et al., 77 FERC
---------------------------------
____________________
1/ Under the terms of the proposed merger, the Applicants would
become wholly-owned subsidiaries of a newly-formed company
named Ameren Corporation (Ameren). Ameren would be a
registered public utility holding company under the Public
Utility Holding Company Act of 1935 (PUHCA), 15 U.S.C.
(S)(S) 79a, et seq. (1994).
------
<PAGE>
Docket No. EC96-7-000, et al. - 2 -
-----
(P) 61,026 (1996). In addition, the Commission set for hearing the
Joint Dispatch Agreement and the System Support Agreement and the
rates contained in the Applicants' proposed open access
transmission tariffs, and directed the Applicants to re-file
within 30 days of the date of the order revised non-price terms
and conditions for their post-merger tariff that complied with
the requirements of Order No. 888. 2/
-
Regarding the effect on costs and rates, the Commission set
for hearing the Applicants' proposed open season 3/ to determine
-
whether it provided adequate protection for wholesale ratepayers
(those that receive bundled generation and transmission service
as well as those that receive unbundled generation or
transmission service) and what ratepayer protection mechanisms
might be suitable for the proposed merger. The Commission also
set for hearing the Applicants' proposed shared savings plan and
cost recovery mechanism.
Regarding the merger's impact on the competitive situation,
the Commission found that although the concentration measures in
all of the relevant markets were below the thresholds that would
trigger a concern about the merger, two transmission constraints
_________________
2/ See Promoting Wholesale Competition Through Open Access Non-
- discriminatory Transmission Services by Public Utilities;
Recovery of Stranded Costs by Public Utilities and
Transmitting Utilities, Order No. 888, 61 Fed. Reg. 21,540
(May 10, 1996), FERC Stats. & Regs. (P) 31,036 (1996), order
-----
on reh'g, Order No. 888-A, 62 Fed. Reg. 12,274 (March 14,
--------
1997), FERC Stats. & Regs. (P) 31,048 (1997), reh'g pending.
-------------
3/ Under their open season proposal, Union Electric's and
- Central Illinois' existing wholesale requirements customers
could terminate their contracts by providing 90 days' notice
commencing on the day the Applicants file a rate increase
that would affect that customer. In addition, for Central
Illinois' wholesale customers served under formula rates,
Central Illinois would allow those customers to terminate
their contracts if: (1) Central Illinois filed a rate
increase affecting them, or (2) the level of Central
Illinois' administrative and general (A&G) expenses
reflected in the formula rates were higher during any 12-
month period following the merger than during the 12-month
period preceding the date of the merger's consummation.
(The Applicants claim that the merger-related costs are most
likely to be reflected in A&G expenses in these formula
rates.) Exhibit 1 at 24-26; 77 FERC at 61,107.
<PAGE>
Docket No. EC96-7-000, et al. - 3 -
-----
were not adequately addressed by the Applicants. 4/ The
-
Commission found that these transmission constraints might limit
wholesale bulk power transactions into or across Union Electric's
system. Thus, the Commission set for hearing the effect of these
two constraints on the competitive situation. The Commission
also noted that it was engaged in a general review of its merger
policy, which had not yet been completed. 77 FERC at 61,109-10.
The Commission stated that when it acted, the parties and the
presiding administrative law judge (presiding judge) should take
that action into account. 77 FERC at 61,106-07.
Regarding the merger's impact on effective regulation, the
Commission stated that it would not set this issue for hearing if
the Applicants agreed to abide by the Commission's policies
regarding intra-corporate transactions within the newly-formed
holding company structure. 77 FERC at 61,101, 61,109. By letter
dated October 29, 1996, the Applicants agreed to abide by the
Commission's policies with respect to intra-corporate
transactions. See Exhibit 108. Therefore, the merger's impact
on effective regulation is no longer at issue in this proceeding.
B. Issues Settled
--------------
On February 6, 1997, the Applicants withdrew their request
for approval of the System Support Agreement, and on February 21,
1997, as amended February 26, 1997, the Applicants filed a
settlement offer to resolve certain issues. On July 21, 1997,
the Commission approved the partial settlement 5/ which resolved
-
for all of the parties in this proceeding: (1) all open access
tariff rate issues (i.e., all outstanding issues in Docket No.
----
ER96-677-000), and (2) whether the terms and conditions of the
Joint Dispatch Agreement are just and reasonable and not unduly
discriminatory or preferential. 6/ By letter dated March 7,
___________________
4/ The Applicants stated that Union Electric had experienced
- thermal limits on: (1) the two 345/138 kV transformers at
the Cahokia substation; and (2) the two 138 kV lines between
the Cahokia and Central substations. 77 FERC at 61,109-10.
5/ Under the terms of the settlement, within 30 days of the
- closing of the merger the Applicants must file a complete
tariff reflecting the settlement with an accurate Table of
Contents, including the substitute settlement tariff sheets,
and a revised page of the Joint Dispatch Agreement. With
regard to the Joint Dispatch Agreement, the settlement
states that Order No. 888 public utility holding company
compliance issues will not be addressed in this proceeding,
but at the time of the Applicants' compliance filing. In
addition, the Applicants agreed to modify section 7.03 of
the Joint Dispatch Agreement to include imputed transmission
revenues from Third Party Sales.
<PAGE>
Docket No. EC96-7-000, et al. - 4 -
-- --
discriminatory or preferential. 6/ By letter dated March 7,
-
1997, the Applicants notified the presiding judge that they were
withdrawing their proposed shared savings plan and plan for the
recovery of merger-related costs.
On July 21, 1997, the Applicants, the City of Kirkwood
(Kirkwood), and the Missouri Joint Municipal Electric Utility
Commission (Missouri Municipal) jointly filed a settlement
agreement with the Commission that they stated resolved the
disputes between them. 7/ On August 11, 1997, Trial Staff filed
-
comments supporting this settlement. Among other things, under
the settlement agreement, Kirkwood and Missouri Municipal
withdrew their objections to the merger effective upon Commission
acceptance of the settlement agreement and further requested that
the merger be approved. We will approve this settlement
agreement between the Applicants and Kirkwood and Missouri
Municipal. We find that this settlement agreement is fair and
reasonable and in the public interest.
Consequently, as a result of settlement agreements the only
intervenors that presently oppose the merger are: Soyland Power
Cooperative, Inc. (Soyland), UtiliCorp United, Inc. (UtiliCorp),
and Central Illinois Light Company (CILCO).
C. The Initial Decision
--------------------
On April 30, 1997, the presiding judge issued an Initial
Decision that conditionally approved the proposed merger. Union
-----
Electric Company, et al., 79 FERC (P) 63,007 (1997).
----------------
The presiding judge found that Soyland did not meet its
burden of going forward, and ruled that Soyland had submitted
insufficient evidence to substantiate its anticompetitive claims.
However, the presiding judge nevertheless imposed the following
three merger conditions on the Applicants: (1) Union Electric
must grant an open season to UtiliCorp by allowing it to
terminate its existing contract subject to a determination of any
stranded cost obligation; (2) Central Illinois must modify its
existing transmission service agreement with Soyland to pass
through merger-related savings; and (3) Central Illinois must
______________________
6/ However, the settlement did not resolve the issue of whether
- the Joint Dispatch Agreement would adversely affect the
terms and conditions or the level of charges to Central
Illinois' formula rate customers under existing agreements.
7/ The City of Springfield (Springfield) is not a party to this
- settlement but does not oppose the settlement, and will
withdraw its intervention without prejudice to pursuing in
other proceedings the issues raised in its intervention.
<PAGE>
Docket No. EC96-7-000, et al. - 5 -
-----
modify its Power Service Agreement with Soyland to reflect that
savings related to the Joint Dispatch Agreement will flow through
to Soyland.
On May 20, 1997, the Applicants, Soyland, UtiliCorp, CILCO,
and the Commission Trial Staff filed Briefs On Exceptions to the
Initial Decision. On May 30, 1997, Soyland, UtiliCorp, CILCO,
and Trial Staff filed Briefs Opposing Exceptions. On June 2,
1997, one day late (due to the failure to deliver the original
brief along with the copies), the Applicants filed a Reply Brief
to the Exceptions asking that we accept it as their late-filed
Brief Opposing Exceptions. The Applicants stated that the brief
was timely served. No party opposed the Applicants' request.
Therefore, we will accept the Applicants' brief for good cause
shown.
II. Effect of the Proposed Merger on Competition 8/
-------------------------------------------- -
A. Transmission Constraints
------------------------
The Commission's hearing order noted that the proposed
merger did not raise post-merger concentration in any relevant
market enough to warrant additional investigation. However, the
Commission required additional information on two transmission
constraints on Union Electric's system, located between the Union
Electric and Central Illinois systems, and set for hearing the
effect of the constraints on: (1) the appropriate relevant
geographic markets; (2) the Applicants' proposed plans to remedy
the constraints; and (3) the Applicants' proposed post-merger
market power.
1. Presiding Judge's Ruling
------------------------
The presiding judge found that the transmission constraints
identified in the Commission's hearing order, and their effect on
competition, were no longer at issue. In response to the three
questions posed in the Commission's order, the presiding judge
found that the constraints had a minimal impact in the past, and
noted that the constraints had been binding only for 40 hours
during the last three years (stipulated by all the active
parties). The presiding judge also determined that these
constraints would be alleviated by Union Electric's plans to
build upgrades that are expected to increase the transmission
____________________
8/ We will analyze the competition issues under two categories:
- (1) market power concerns caused by transmission
constraints; and (2) other market power concerns.
<PAGE>
Docket No. EC96-7-000, et al. - 6 -
-- --
capability into and through the merged system when they are
completed in 1997 and 1998. 9/
-
2. Commission Decision
-------------------
We note that no party excepted to the presiding judge's
ruling on this issue. Therefore, based on the record before us,
we conclude that the transmission constraints identified will not
materially affect the scope of the relevant geographic markets.
B. Other Market Power Concerns
---------------------------
1. Arguments Before the Presiding Judge
------------------------------------
Soyland argues that the merger would harm competition in the
generation and transmission markets, and would have an adverse
effect on wholesale customers and retail competition. 10/ In
--
this regard Soyland argues that potential purchasers of energy
from Soyland would be disadvantaged in competing with the merged
entity and others because Soyland is tied to an existing long-
term contract (the TSA) containing transmission rates that are
higher than those in the proposed Ameren tariff. As a
consequence, Soyland claims that new and existing electric
generators interconnected with Union Electric would be
disadvantaged when attempting to sell power to Soyland since they
would have to pay pancaked transmission rates, and that new
independent power producers that locate in the region would have
an incentive to take service under the Ameren tariff rather than
locate in Soyland's region and obtain service under the TSA.
Soyland argues that its members might also locate Soyland-owned
generation at sites other than the lowest-cost source because of
the transmission rate disparity; and as a result of the rate
disparity between the Ameren tariff and Soyland's higher TSA
rate, new or expanding industrial or commercial customers might
prefer service under the Ameren tariff. Moreover, if its 21
members were to withdraw from Soyland, Soyland claims that it
would incur significant transactional and administrative costs.
11/
--
___________________
9/ See 79 FERC at 65,035, Exhibit 102 at 6, and Exhibit 138 at
- 3-4, for a detailed description of how these upgrades will
remedy the two transmission constraints.
10/ Soyland has two jurisdictional formula rate contracts with
-- Central Illinois: a power supply agreement (PSA) and a
transmission services agreement (TSA).
11/ Soyland Initial Brief at 21-49; Soyland Reply Brief at 20-21.
--
<PAGE>
Docket No. EC96-7-000, et al. - 7 -
----
In addition, Soyland argues that the economic inefficiency
problems that are reflected in these concerns constitute an
"other factor" that characterizes the market that, under the
Merger Policy Statement, 12/ should be evaluated to assess
--
whether the merger has potential anticompetitive effects. 13/
--
Soyland also claims that a properly performed delivered price
test would show that, post-merger, the Applicants will be able to
maintain high delivered prices to Soyland. 14/
--
The Applicants and Trial Staff contend that Soyland's
arguments are flawed because it performed no market power study,
it confused harm to a competitor with harm to competition, and
its arguments are not based on record evidence.
2. Presiding Judge's Ruling
------------------------
The presiding judge concluded that a merger's ability to
enhance market power in generation is not merely tied to
transmission constraints, but must be "viewed through the prism
of the myriad of market conditions resulting from the merger and
a determination of whether generation market power will be
obtained from such resulting conditions that the threshold
articulated in Order No. 592 is exceeded." 79 FERC at 65,037.
The presiding judge held that the Applicants had the ultimate
burden of proof in demonstrating that their proposed merger is in
the public interest. The presiding judge also stated that
because Soyland raised the market power issue, it had the burden
of going forward with evidence that the merged entity's market
power in generation exceeded the thresholds articulated in the
Merger Policy Statement. The presiding judge stated that Soyland
had not met its burden since it did not submit substantiating
evidence and did not undermine the credibility of the Applicants'
_____________________
12/ Inquiry Concerning the Commission's Merger Policy Under the
-- Federal Power Act: Policy Statement, Order No. 592, 61 Fed.
Reg. 68,595 (December 30, 1996), FERC Stats. & Regs.
(P) 31,044 (1996), order on reconsideration, Order No. 592-A,
------------------------
79 FERC (P) 61,321 (1997) (Merger Policy Statement).
-----------------------
13/ Soyland Initial Brief at 45-49 & n.86, citing the Merger
-- Policy Statement at 30,118, where step 2 of the Department
of Justice Guidelines provides that the merger analysis
should "evaluate whether the extent of concentration and
other factors that characterize the market raise concerns
-------------
about potential adverse competitive effects . . . ."
(Emphasis added.)
14/ Soyland Initial Brief at 34.
--
<PAGE>
Docket No. EC96-7-000, et al. - 8 -
-----
and Trial Staff's witnesses. 15/ Therefore, the presiding judge
--
ruled that no further competitive analysis was necessary.
However, as discussed below, the presiding judge also held that,
although Soyland failed to carry its burden, he could not
conclude that there was no merger-related impact on the
generation market requiring mitigation. Id.
--
3. Arguments On and Opposing Exceptions
------------------------------------
Soyland excepts to the presiding judge's findings that: (1)
Soyland had the burden of going forward to show that the
Applicants would be able to exercise market power in generation,
transmission, wholesale, and retail markets as a result of the
merger, and (2) Soyland failed to meet its burden of proof
regarding thresholds under the Merger Policy Statement. Soyland
argues that the Merger Policy Statement places on merger
applicants the burden of producing an Appendix A delivered price
study analyzing the effect of the merger in each relevant market.
Soyland reargues that the Merger Policy Statement cannot be
interpreted as stating that those opposed to a merger can only
prevail if they show increased generation concentration when
concentration in the Soyland destination market has been shown to
be 100 percent before the merger. 16/ Soyland asserts that the
--
Commission could not have adopted a merger policy that would
clearly favor merger applicants over transmission dependent
utility (TDU) customers and competitors.
Soyland also argues 17/ that it does not have the burden of
--
proving that the Applicants possess transmission market power,
and in any event it met that burden by showing the Applicants'
ability to maintain a transmission rate that is almost three
times higher than Ameren's open access rate. Soyland asserts
that this relative price disparity is caused by a combination of
factors that include: (1) Central Illinois' proposed merger with
a lower cost provider; (2) the Energy Policy Act of 1992 and the
Commission's initiatives (such as Order Nos. 888 and 888-A) to
introduce partial competition into the bulk power market; (3) the
______________________
15/ The presiding judge made similar determinations with regard
-- to the merger's effect not only on generation market power
but also on transmission market power, wholesale customers,
and retail competition.
16/ Soyland Brief on Exceptions at 45.
--
17/ Soyland relies on El Paso Electric Company, et al., 68 FERC
-- -----
(P) 61,181 at 61,914 (1994) (El Paso) where the Commission
-------
stated that before the Commission would consider approving a
merger, the applicants must agree to offer comparable
transmission service to others.
<PAGE>
Docket No. EC96-7-000, et al. - 9 -
-- --
Commission's policy of non-abrogation of existing contracts; and
(4) Central Illinois' refusal to make Ameren's open access rate
available to Soyland (even though the open access rate is
available to the Applicants' new customers and Central Illinois
itself). 18/
--
Furthermore, Soyland claims that the presiding judge erred
by failing to require either Trial Staff or the Applicants to
perform separate delivered price analyses for markets comprised
of: (1) Soyland alone, (2) all of Central Illinois' formula rate
customers, (3) all of Central Illinois' wholesale customers, and
(4) all of Central Illinois' wholesale and retail customers.
Regarding the preliminary competitive analysis that was performed
by Trial Staff, Soyland disagrees with the inputs used and thus
with the results of that analysis. For example, Soyland argues
that the correct transmission price in a delivered price analysis
is Soyland's actual cost to transmit power rather than the Ameren
open access rate used by Trial Staff. 19/
--
Lastly, Soyland excepts to the presiding judge's failure to
specify how Soyland will be insulated from pancaked transmission
rates resulting from the merger (i.e., separate transmission
---
rates across Union Electric's and Central Illinois' transmission
systems). Soyland argues that although the Applicants offered to
cap the charges to Soyland (for post-merger transmission access
to the Union Electric portion of Ameren system) at Union
Electric's current stand-alone open access rate, Soyland would
not benefit from any potential rate reductions of Union
Electric's stand-alone rate in the future because Union Electric
does not intend to retain its stand-alone rate after the merger.
20/
--
The Applicants and Trial Staff except to the presiding
judge's reliance on Soyland's "other factor" argument and
__________________
18/ Soyland Brief on Exceptions at 9-10, 52-56. Soyland also
-- claims that the Applicants' generation market power arises
from their transmission market power, and that the merger
would facilitate the exercise of the Applicants' pre-
existing transmission market power in generation markets.
Soyland claims that Central Illinois unlawfully ties
generation to transmission. As evidence, Soyland notes that
at settlement negotiations Central Illinois attempted to
compel Soyland to purchase its high-cost generation as a
condition of taking service under the Ameren open access
tariff. Soyland Brief on Exceptions at 46-48.
19/ Soyland Brief on Exceptions at 36-37.
--
20/ Soyland Brief on Exceptions at 50-51.
--
<PAGE>
Docket No. EC96-7-000, et al. - 10 -
-- --
departure from the legal standards set forth in the Merger Policy
Statement. They argue that the presiding judge erred in creating
his own legal standard of review in this proceeding. The
Applicants also dispute Soyland's claim that Central Illinois is
tying its generation with transmission to force Soyland to
purchase generation from the Applicants. The Applicants argue
that they will have no opportunity to sell generation to Soyland
when Soyland's PSA expires because Soyland has already contracted
to purchase its power requirements from Illinova Corporation
(Illinova) (an affiliate of Illinois Power Company) for ten years
after the PSA expires in 1999. The Applicants also argue that
Soyland, under the guise of concerns about increased market
concentration, actually is concerned that its existing
transmission rates are too high. Both the Applicants and Trial
Staff claim that Soyland's concerns are irrelevant here. 21/
--
4. Commission Decision
-------------------
Generation Market Power
-----------------------
Notwithstanding Soyland's arguments, we find that
competition will not be harmed as a result of this merger, and
the competition studies submitted in this proceeding support this
finding. We note that the Applicants' witness Frame filed
testimony containing an analysis for numerous relevant markets
comparing pre- and post-merger market concentration based on
total generation capacity, uncommitted generation capacity, and
non-firm energy sales (Exhibit 63 at 76-89; Exhibits 64-79).
Witness Frame stated that these analyses showed that the United
States Department of Justice Merger Guidelines (Merger
Guidelines) thresholds were not exceeded in any relevant market.
A Trial Staff witness also testified that he had performed what
he described as a preliminary Appendix A analysis that showed
that the Merger Guidelines thresholds were not exceeded in any
relevant market (Tr. 1962, 1971). 22/ We note that Soyland did
--
not sponsor any studies which challenged the testimony of these
witnesses. In addition, in our hearing order, we stated that we
had performed our own analysis of the competitive effects of the
proposed merger, and that the concentration measures in all of
the relevant geographic markets were below the thresholds in the
Merger Guidelines that would raise concern. 77 FERC at 61,109.
We note that no party sought rehearing on this finding.
___________________
21/ Applicants Brief Opposing Exceptions at 7-10, 24-25; Trial
-- Staff Brief Opposing Exceptions at 14-42.
22/ Trial Staff's study, not received into evidence, was of
-- generation concentration in TDU markets in both the Central
Illinois and Union Electric territories.
<PAGE>
Docket No. EC96-7-000, et al. - 11 -
-- --
Neither the Merger Guidelines nor the Merger Policy
Statement support Soyland's position that this merger be
rejected or conditioned because of a highly concentrated market
pre-merger. The merger itself does not significantly add to that
level of concentration. Under the Merger Guidelines, a merger
in a highly concentrated market potentially raises a competitive
concern when the change in the HHI index exceeds 50. A change in
the HHI is an important factor to consider when deciding whether
a merger raises market power concerns, 23/ yet in this case no
--
party has shown that there would be any change in the HHI that
would exceed 50 in any relevant market (including the Soyland
destination market) and neither did our own analysis.
At a prehearing conference Soyland and Southwestern Public
Service Company (Southwestern) (Southwestern subsequently
withdrew from the proceeding) argued that the then recently
issued Merger Policy Statement, specifically, the competitive
analysis screen should be applied to this proceeding.
Consequently, the presiding judge certified to the Commission a
question of procedure regarding whether the Applicants should be
required to supplement the record to incorporate the competitive
analysis screen contained in Appendix A of the Merger Policy
Statement. The Commission stated that the presiding judge and
the parties were at that juncture in the best position to
evaluate the evidence in the proceeding. Therefore, the
Commission stated that the presiding judge should determine
whether the record adequately addressed the concerns that
underlie the new competitive analysis screen and, if the record
did not address these concerns the presiding judge should direct
the Applicants to supplement the record. 24/
--
The presiding judge stated that he read the Commission's
response to the certification to mean that he was to "look at the
evidence on the record" to determine whether or not an analysis
screen should be ordered. The presiding judge found that since
Soyland could not support the need for the screen based on the
evidence already in the record, and since Soyland acknowledged
that there was no basis to disbelieve the testimony of Trial
Staff that the change in the HHI's would not exceed the
thresholds contained in the Merger Guidelines, an analysis screen
would not further clarify the record, but would only reiterate
preliminary findings of Trial Staff's witness on the issue of
market concentration. Therefore, the presiding judge ruled that
a competitive analysis screen would not be required.
__________________
23/ See, e.g., San Diego Gas & Electric Company, et al., 79 FERC
-- ---- --- -----
(P) 61,372 at 62,566 & n.60 (1997).
24/ Union Electric Company, et al., 78 FERC (P) 61,162 at 61,695-
-- -----
96 (1997).
<PAGE>
Docket No. EC96-7-000, et al. - 12 -
-- --
We will reject Soyland's claim that the Applicants had the
burden of producing a delivered price analysis, and that the
presiding judge erred by not requiring that either Trial Staff or
the Applicants submit an Appendix A analysis. The only issue on
competition set for hearing in this proceeding was the proposed
merger's effect on two transmission constraints on Union
Electric's system, and all the parties agree that this concern is
no longer an issue in this case. In our hearing order we stated
that the presiding judge should take into account the final
outcome of our merger analysis, i.e., the Merger Policy
----
Statement. That is exactly what the presiding judge did.
Moreover, in our order addressing the presiding judge's certified
question of procedure, we found that the presiding judge would be
in the best position to determine whether the record adequately
addresses the concerns that underlie the competitive analysis
screen. The presiding judge followed our direction and
supplemented the record by conducting cross-examination on this
issue, and determined that there was ample record evidence to
resolve the competition issues. On this basis the presiding
judge correctly found that an Appendix A analysis was unnecessary
to resolve the competition issues set for hearing. 25/
--
____________________
25/ At the conclusion of the hearing, the presiding judge ruled
-- that as a result of the additional evidence presented at
hearing from the Applicants and Trial Staff witnesses, the
record was adequate to address competition issues, and that
he would thus not require the competitive analysis screen
prescribed by the Merger Policy Statement. A Trial Staff
witness testified during cross-examination that in all the
relevant markets the concentration levels were below the
thresholds that are of concern in the Merger Guidelines.
Tr. 1962. That witness also testified that his analysis was
fully complete regarding the concerns Soyland raised
pertaining to its transmission contracts. Tr. 1971.
The Applicants' witness Frame stated during cross-
examination that he analyzed the impact of the merger using
a framework substantially the same as that contained in the
Merger Guidelines. Tr. 1612. Mr. Frame concluded in his
prepared testimony that the merger would not create or
increase market power in the Soyland market. Exhibit 63 at
5. The presiding judge also concluded that Soyland could
not identify additional evidence that would be obtained
under an Appendix A analysis that would change the results
of the competition analyses performed by the Applicants and
Trial Staff.
<PAGE>
Docket No. EC96-7-000, et al. - 13 -
-- --
Transmission Market Power
-------------------------
We also find that the merger does not raise any transmission
market power concerns because the transmission facilities owned
by the Applicants may be accessed post-merger under the Ameren
open access tariff. 26/ Therefore, customers will have non-
--
discriminatory access to the merged transmission system, and the
Applicants will not be able to exercise transmission market
power. 27/ With respect to Soyland's concern regarding pancaked
--
transmission rates, we find that Soyland can address this issue
when it seeks to expand its service beyond Central Illinois'
transmission system. 28/
--
Moreover, we find that Soyland has not demonstrated how this
merger would enhance or facilitate the Applicants' exercise of
market power. Under Commission precedent Soyland is required to
show a nexus between the proposed merger and the alleged
competitive harm in order for a remedy to be appropriate. 29/
--
Soyland's only argument in this regard is that its TSA rates are
too high relative to Ameren's open access rates. However, we
note that both Union Electric and Central Illinois previously had
____________________
26/ As noted previously, the only competitive issue set for
-- hearing in the Commission hearing order was the effect on
competition of two transmission constraints. However, as
discussed above, in response to the Commission's directive
to assess whether the record adequately addressed the
concerns that underlie the competitive analysis screen, the
presiding judge subsequently allowed the parties the
opportunity to raise transmission market power concerns.
See 79 FERC at 65,030.
27/ See, e.g., Atlantic City Electric Company, et al., 80 FERC
-- --- --- -- --
(P) 61,126 at 61,403 (1997); PG&E Corporation et al., 80 FERC
-- --
(P) 61,041 at 61,131 (1997).
28/ The Commission addressed a similar issue in Southern Company
-- Services, Inc., 72 FERC (P) 61,324 at 62,404 (1995) and
Entergy Services, Inc., 63 FERC (P) 61,025 at 61,146 (1993)
where we concluded that the interplay of existing agreements
providing limited service and the new open access
transmission tariff providing expanded service should not
result in customers being charged multiple rates for a
single transmission service and that such concerns should be
addressed in a separate proceeding concerning the contract
at issue.
29/ See Duke Power Company, et al., 79 FERC (P) 61,236 at 62,041
-- (1997) (Duke); Cincinnati Gas & Electric Company, et al., 64
---- -- --
FERC (P) 61,237 at 62,726 (1993).
<PAGE>
Docket No. EC96-7-000, et al. - 14 -
-- --
filed stand-alone open access tariffs, and the rates in those
tariffs were already higher than Soyland's TSA rate. Therefore,
the relative price disparity Soyland complains of is not merger-
related. We find that Soyland is actually complaining about its
existing agreements with Central Illinois, and it wants us to
abrogate these contracts as a condition to the merger. We note
that if transmission customers are concerned that their existing
agreements are not just and reasonable, they should raise such
concerns in a section 206 complaint proceeding.
We agree with the Applicants and Trial Staff that Soyland's
arguments confuse "harm to an individual competitor" with "harm
to competition." Our responsibility under section 203 of the FPA
is to determine whether the merger will harm the competitive
process, not individual competitors. In this regard, we note
that in Northeast Utilities Service Company v. FERC, et al., 993
---------------------------------------------------
F.2d 937, 951 (1st Cir. 1993) the First Circuit stated:
In evaluating [public utility mergers], the Commission
is required to find that the entire transaction, taken
as a whole, is consistent with the public interest. 16
U.S.C. (S) 824b(a). Each element of the transaction need
not benefit every utility or individual which might be
affected; rather, the whole transaction must be
consistent with the interest of the "public." There is
no reason to think that the interest of [any]
individual . . . is synonymous with the "public"
interest.
Lastly, we find no merit to Soyland's claims that Central
Illinois will use its transmission system to force Soyland to
purchase generation from Ameren. We note that Soyland has
already contracted to purchase its power requirements from
Illinova on a 10-year requirements basis when the PSA expires in
1999. 30/
--
III. Effect of the Merger on Rates
-----------------------------
A. Arguments Before the Judge
--------------------------
After the initial filing, the Applicants committed to
additional ratepayer protections. First, the Applicants offered
an additional hold harmless protection to UtiliCorp 31/ to cap
--
______________________
30/ Exhibit 406 at 14; Exhibit 169 at 9.
--
31/ UtiliCorp and Union Electric are parties to an Interchange
-- Agreement (providing for a variety of different
transactions) and a System Participation Power Agreement
(SPPA). Under the SPPA, Union Electric is obligated to
(continued...)
<PAGE>
Docket No. EC96-7-000, et al. - 15 -
-- --
UtiliCorp's annual energy charges under the SPPA at the levels
that were reflected in the Union Electric estimates given to
UtiliCorp at the time of contract negotiation. 32/ Second, the
--
Applicants offered Central Illinois' formula rate customers
(including Soyland) enhancements to their earlier ratepayer
protection in two respects: (1) the 12-month base period would
be changed from the 12-month period preceding the merger
consummation date, to the 12-month period ending July 1995 (the
month the merger was announced); 33/ and (2) the open season
--
opportunity that was to be triggered by an increase in A&G
expenses would instead be replaced by a rate cap for all
transmission and power supply components in the formula (except
for energy costs) during the first five years after the merger.
34/
--
The Applicants and Trial Staff contend that: (1) UtiliCorp,
CILCO, and Soyland are adequately insulated from merger-related
harm and that no additional ratepayer protection is required
beyond that which has been offered by the Applicants, and (2)
these intervenors are seeking to use this merger to obtain early
termination of their existing contracts with the Applicants.
___________________
31/ (...continued)
--
provide 115 MW of non-firm capacity and associated energy to
UtiliCorp through 2001. The demand charges under the SPPA
are fixed. UtiliCorp is under no obligation to purchase any
energy under the SPPA, but if it does, the energy charge is
set at Union Electric's incremental cost plus ten percent.
32/ Applicants Brief On Exceptions at 21; Exhibit 395 at 48.
--
33/ That change was made to address intervenor concerns that the
--
formula billings during the 12-month period preceding the
merger consummation date could be higher than normal due to
the inclusion of costs associated with merger transition
activities.
34/ Applicants' Brief On Exceptions at 21; Exhibit 106 at 7;
--
Exhibit 164 at 6-7. That rate cap mechanism would operate
as follows. During the computation of each monthly bill,
Central Illinois will evaluate the 12-month period
consisting of the current billing month and the 11 previous
billing months to determine if the average rate during that
12-month period exceeds the applicable rate cap for the
formula's non-energy costs. If the rate cap is exceeded, a
refund will be made for the amount of the excess. (These
formula rate customers will remain free to leave Central
Illinois' system under the previously-offered open season
protection if Central Illinois files for a rate increase
with the Commission.)
<PAGE>
Docket No. EC96-7-000, et al. - 16 -
-- --
UtiliCorp, CILCO, 35/ and Soyland each claim that they will
--
incur merger-related ratepayer harm, and seek either additional
ratepayer protections 36/ or an unconditional open season (under
--
which all wholesale power purchase and transmission customers
would immediately be entitled to terminate their existing
contracts with the Applicants and arrange for alternate
suppliers). Specifically, these intervenors raised the following
similar concerns: (1) the Applicants failed to meet their burden
of persuasion under the Merger Policy Statement to show that
wholesale customers will be adequately protected from the adverse
effects of the merger; (2) few, if any, cost savings or rate
reductions are expected to be passed on to these three
intervenors as a result of the merger; 37/ (3) their energy
--
charges for purchases from the Applicants are likely to increase
as a result of the merger; and (4) their ability to buy energy on
the open market will not adequately protect them from this
merger-related harm. 38/
--
____________________
35/ CILCO and Central Illinois are parties to an Interconnection
-- Agreement, under Schedule A of which the two utilities agree
to provide each other with limited term power from
temporarily surplus generating capacity. The two utilities
have also entered into two limited term purchase agreements.
The first agreement expires in 2002 and requires Central
Illinois to supply CILCO with a minimum of 100 MW; the
second agreement expires in 2009 and requires Central
Illinois to supply CILCO with a minimum of 50 MW. Demand
charges under both of these limited term purchase agreements
are fixed, while energy charges are set at Central Illinois'
out-of-pocket costs plus 10 percent.
36/ If the Commission would not grant it an immediate open
-- season, UtiliCorp argued that, at a minimum, the merger
should be approved with a "hold harmless" condition that
would track energy cost changes to ensure that the energy
prices it pays for purchases from Union Electric will not
increase as a result of the merger. (Although UtiliCorp's
demand charge will remain fixed after the merger, it will
pay Ameren's, instead of Union Electric's, incremental cost
plus ten percent for energy as a result of the Joint
Dispatch Agreement.)
37/ UtiliCorp and Soyland claimed that the Applicants' proposed
-- rate caps provide inadequate ratepayer protection to them
because the rate caps only insulate against certain types of
cost increases, and they do not cause any merger savings to
be passed on.
38/ UtiliCorp Initial Brief at 8-27; CILCO Initial Brief at 21-
-- 33; Soyland Initial Brief at 49-67.
<PAGE>
Docket No. EC96-7-000, et al. - 17 -
-- --
With regard to (3) above, CILCO argues that the merger will
unilaterally change the terms of the CILCO Agreements because its
payments under these agreements will become based on Ameren's
incremental energy costs rather than Central Illinois'
incremental energy costs. Specifically, CILCO argues that the
Applicants, by jointly dispatching the generating units of the
combined system, will place CILCO's position in the pricing queue
for energy after customers of both Central Illinois and Union
Electric, even though CILCO negotiated its payments for energy on
the basis of its position in a pricing queue that would follow
only Central Illinois' customers. 39/ CILCO contends that this,
--
in turn, would adversely impact the energy rates it pays under
the CILCO Agreements. 40/
--
Soyland and UtiliCorp raise several additional concerns with
regard to the merger's effect on rates. First, both intervenors
argue that the Applicants' open season proposal offers inadequate
ratepayer protection for certain wholesale customers.
Specifically, Soyland argues that the Applicants' open season
proposal does not provide it with a reasonable opportunity to
terminate its contracts with Central Illinois because it can only
use the open season if Central Illinois files for a rate increase
with the Commission, which Soyland claims is unlikely.
Second, both intervenors allege rate discrimination as a
result of the merger. Soyland contends that the Applicants'
actions are unduly discriminatory and violate the Commission's
rules on comparability because the Applicants and its new
customers take service under the Ameren tariff but the Applicants
will not allow Soyland to do so. Soyland contends that the
relative price disparity between its TSA rate and the Ameren open
access rate constitutes a ratepayer harm within the meaning of
the Merger Policy Statement. Accordingly, Soyland argues that
the merger must be conditioned on the removal of this undue
discrimination. 41/ UtiliCorp argues that, unlike the rate
--
reductions offered to Union Electric's retail and wholesale
requirements customers in a proceeding before the Missouri Public
_____________________
39/ According to the contracts, the out-of-pocket energy costs
-- under the two limited term purchase agreements were to be
based on Central Illinois' incurred costs after it has met
four other loads in the following priority queue: (1)
native load; (2) firm wholesale power contracts; (3) system
participation contracts; and (4) previously committed firm
coordination power sales contracts. See 79 FERC at 65,034;
Applicants Initial Brief at 73-75; Exhibit 419A.
40/ CILCO Initial Brief at 16-17, 27.
--
41/ Soyland Initial Brief at 49-67; Soyland Reply Brief at 34-
-- 47.
<PAGE>
Docket No. EC96-7-000, et al. - 18 -
-- --
Service Commission, 42/ Union Electric did not offer a rate
--
reduction to UtiliCorp in this proceeding. Both intervenors
claim that this alleged rate discrimination will harm their
ability to compete.
Finally, both UtiliCorp and Soyland argue that the Applicants and
Trial Staff incorrectly relied on Enron Corporation, et al. 78 FERC
------------------------
(P) 61,179 (1997). 43/ Specifically, Soyland argues that, unlike the
--
power supply agreements involved in Enron, its TSA is a cost-based,
-----
unbundled, formula rate transmission contract which, if allowed to
continue, will: (1) enable Central Illinois to over-recover its
revenue requirements for wholesale transmission service, and (2)
create a significant disparity between Soyland and all other
competitors for delivered bulk power prices.
B. Presiding Judge's Ruling
------------------------
The presiding judge rejected the Applicants' and Trial Staff's
arguments that the Merger Policy Statement did not contemplate
ratepayer protection for non-requirements or non-captive customers.
The presiding judge ruled that there are no broad categories of
customers that are excluded from such protection, and the Commission
has not adopted a "one-size-fits-all" approach to ratepayer
protection. 79 FERC at 65,080.
The presiding judge agreed with the intervenors that the
Merger Policy Statement overruled prior Commission precedent 44/
--
requiring intervenors to show a nexus between a proposed merger
and the alleged harm in order to obtain relief. The presiding
judge found that the Merger Policy Statement requires that merger
applicants have the burden of proving ratepayer protection,
including "demonstrating that their merger is in the public
interest . . . ." 79 FERC at 65,081. However, the presiding
judge found that intervenors bear the burden of going forward
with sufficient evidence to raise substantial doubt if they
believe that the Applicants' proposed ratepayer protection
________________
42/ Union Electric's wholesale requirements customers have a
--
"most favored nations" clause in their contracts, which ties
their rates to those of Union Electric's retail customers.
43/ In Enron Corporation, et al., 78 FERC (P) 61,179 at 61,737
-- ------
(1997), the Commission rejected intervenors' arguments
because they addressed conditions that existed prior to the
merger, and the intervenors did not explain how their
concerns were affected by the merger.
44/ See Cincinnati Gas & Electric Company, et al., 69 FERC
-- --- ------
(P) 61,005 at 61,042 (1994); Entergy Services Inc., et al., 62
-----
FERC (P) 61,073 at 61,376 (1993).
<PAGE>
Docket No. EC96-7-000, et al. - 19 -
-- --
mechanisms or remedies are inadequate. According to the
presiding judge, if intervenors raise substantial doubts as to
the adequacy of the proposed ratepayer protection or mitigation
measures, then the Applicants have the ultimate burden of
persuasion that their ratepayer protections are adequate.
1. UtiliCorp's Concerns
--------------------
The presiding judge found that the Applicants did not have
to demonstrate that UtiliCorp will not at varying points in time
experience higher energy charges as a result of the merger.
However, the presiding judge held that the Applicants had the
burden of showing that UtiliCorp will not experience a net,
overall increase in its SPPA energy charge as a result of the
merger. The presiding judge concluded that the Applicants failed
to meet this burden and that UtiliCorp would experience merger-
related harm. In this regard, the presiding judge relied on the
following: (1) Union Electric currently serves UtiliCorp, and
Union Electric has the lower average marginal cost of the two
merging entities; (2) on average, Ameren's incremental energy
charges would be higher than Union Electric's incremental energy
charges, thus Midwest Power Systems, et al., 71 FERC (P) 61,386
-----------------------------
(1995) (Midwest) 45/ does not apply to UtiliCorp; 46/ and (3)
------- -- --
UtiliCorp would be competitively harmed because while it would
continue to pay the same demand charge to Ameren, Applicants
would be flowing through merger savings to other retail and
wholesale customers (some of which are competitors of UtiliCorp).
With regard to (1) above, the presiding judge found that
since Ameren's incremental energy charges would be, on average,
higher than Union Electric's, it "is a statistical imperative
----------------------
that for any random set of instances selected for comparison, the
merged entity's incremental charge will generally exceed what
[Union Electric] would have charged" absent the merger. 79 FERC
at 65,082 (emphasis added.) 47/ Although the presiding judge
--
_____________
45/ In Midwest, the Commission rejected the request of a
-- -------
municipal customer to condition the merger because the city
did not show that costs would increase as result of the
merger. The Commission noted that the city acknowledged
that post-merger the energy charge would most likely
decrease, and its contract allowed it to purchase energy
elsewhere. 71 FERC at 62,509.
46/ The presiding judge stated that UtiliCorp demonstrated, and
--
the Applicants conceded, that at certain peak hours under
the Ameren energy charge, UtiliCorp would pay higher
incremental energy rates than it would without the merger.
47/ In support of this finding, the presiding judge cited a
--
(continued...)
<PAGE>
Docket No. EC96-7-000, et al. - 20 -
-- --
rejected UtiliCorp's proposed cost tracking hold harmless
provision as administratively infeasible, the presiding judge
nevertheless determined that UtiliCorp deserved ratepayer
protection from such merger-related harm. Accordingly, he
conditioned approval of the merger on the Applicants providing an
immediate open season to UtiliCorp under which it could terminate
its existing contract with Union Electric. However, the
presiding judge's grant of an open season to UtiliCorp was made
subject to a stranded cost obligation (of an undetermined amount)
if UtiliCorp left the Union Electric system.
In granting UtiliCorp an open season, the presiding judge:
(1) held that the Applicants had provided no study or
corroborating evidence to support their general conjecture that
rate decreases would result from the merger to UtiliCorp's
benefit; (2) rejected the Applicants' rate cap proposal because
it relied on out-of-date information; (3) noted that the
Applicants failed to demonstrate why the presiding judge's
"statistical imperative" was not applicable to this merger; and
(4) rejected the arguments of the Applicants and Trial Staff that
UtiliCorp, in signing its SPPA contract with Union Electric in
1987, assumed the risk of future increases in its energy charge
from any source. The presiding judge also rejected the
Applicants' and Trial Staff's arguments that the particular
circumstances of the Commission's decision in Enron are analogous
-----
to this proceeding. Instead, the presiding judge found Enron
-----
factually distinguishable from the instant case.
2. CILCO's Concerns
----------------
The presiding judge concluded that CILCO would not
experience merger-related rate increases because: (1) CILCO
provided no evidence demonstrating such harm; (2) CILCO failed to
demonstrate substantial doubt as to the adequacy of the
Applicants' ratepayer protection mechanism; (3) Ameren's
incremental energy charges, on average, would be lower than those
of Central Illinois (which currently serves CILCO), thus the
Commission's decision in Midwest is applicable to CILCO and the
-------
"statistical imperative" would benefit CILCO; and (4) unlike
Soyland, CILCO did not present any arguments alleging
anticompetitive harm from the merger. Accordingly, the presiding
judge denied CILCO's request for ratepayer protection. Citing a
lack of evidence, the presiding judge also dismissed CILCO's
concern that it would receive less reliable service on Ameren's
system than it had on Central Illinois' system as a result of
being placed in a different position in the energy queue. 79
FERC at 65,083-084.
______________
47/ (...continued)
--
textbook on the use of statistical evidence in litigation.
<PAGE>
Docket No. EC96-7-000, et al. - 21 -
-- --
3. Soyland's Concerns
------------------
The presiding judge found that Soyland, as a customer of
Central Illinois, was in a similar position to CILCO regarding
incremental energy rates because the "statistical imperative"
works against any contention of rate harm to Soyland. The
presiding judge also noted that Soyland, like CILCO, did not
provide any evidence to support its claim that it would not be
adequately protected regarding system reliability post-merger.
48/ However, the presiding judge concluded that Soyland
--
nevertheless deserved ratepayer protection in the form of a rate
reduction in its TSA with Central Illinois to reflect non-Joint
Dispatch Agreement merger savings because: (1) unlike CILCO,
Soyland is a partial requirements TDU customer of Central
Illinois; (2) Soyland should not be locked into the rates and
terms of its TSA and PSA since changes being ordered by the
Commission in Order Nos. 888, 888-A, and 592 are far more
significant than the risks that Soyland might reasonably have
envisioned when it signed these agreements; (3) Soyland would
suffer anticompetitive effects from the merger, and the rate
disparity experienced by Soyland is a "hybrid or inter-effect
issue that must be analyzed both as a competition and rate issue"
(79 FERC at 65,085); and (4) certain other anticompetitive
effects -- i.e., economically inefficient consumption decisions
---
cited by Soyland are caused by the rate disparity, 49/ which is a
--
result of the Applicants not sharing the non-Joint Dispatch
Agreement merger savings with Soyland.
The presiding judge conditioned approval of the merger on
the Applicants filing revised tariffs amending the PSA, and
proposing a formula for reducing the rates under the TSA to
reflect "Soyland's appropriate share of non-[Joint Dispatch
Agreement] merger savings amortized over the life of the TSA."
79 FERC at 65,087. The presiding judge also stated that if the
Applicants failed to make suitable amendments to the PSA and the
TSA: (1) Soyland should be given an open season to terminate the
PSA and the TSA; (2) the Applicants should be allowed to recover
stranded costs if Soyland terminates either agreement under the
_______________
48/ Soyland raised concerns that the merger would decrease the
--
level of transmission capacity available to it from Central
Illinois. See, e.g., Soyland Initial Brief at 40-41.
--- ----
49/ The presiding judge found that the merger exacerbates the
--
rate disparity that existed prior to the merger and "is a
direct result of [Union Electric] having lower marginal
costs and synergies that will arise from the merger." 79
FERC at 65,084-87. With regard to these "synergies," the
presiding judge explained that since these synergy savings
were not being passed on to Soyland, the rate disparity
---
would be exacerbated.
<PAGE>
Docket No. EC96-7-000, et al. - 22 -
-- --
open season; (3) the Applicants and Soyland should attempt to
reach settlement on the valuation of stranded costs; and (4)
failing such a settlement resolution, the stranded cost issue
should be set for hearing. 50/
--
C. Arguments On and Opposing Exceptions
------------------------------------
UtiliCorp argues on exceptions that the presiding judge
erred by imposing a stranded cost obligation as part of its open
season. UtiliCorp claims that the presiding judge's ruling is:
(1) contrary to Order No. 592 because a stranded cost exit fee
would moot the benefits of an open season as a remedy to merger-
related harm, and (2) contrary to Order Nos. 888 and 888-A since
there is no direct nexus between the availability and use of
Commission-required transmission access and stranded costs that
is required under Order No. 888-A. UtiliCorp also argues that
the Applicants and Trial Staff incorrectly state that the
Commission cannot take competitive impacts into account when
examining the merger's effect on rates. UtiliCorp reiterates
that Enron is inapplicable because the energy price issues
present here were not considered in that case since Enron did not
involve a joint dispatch of resources. 51/
--
CILCO also argues that the presiding judge erred in finding
that CILCO had the burden of proving substantial doubt regarding
the adequacy of the Applicants' proposed ratepayer protection
mechanism. CILCO argues that the presiding judge erred in
failing to grant it an open season and that this ruling is
inconsistent with the finding that adding Union Electric's native
load customers to the pricing queue ahead of CILCO dilutes
CILCO's rights. CILCO also argues that the presiding judge
erroneously relied on a statistical imperative, rather than
record evidence, to conclude that CILCO would benefit from the
merger. Finally, CILCO asserts that certain of Central Illinois'
sales to CILCO are improperly made under letter agreements that
have not been filed with the Commission and that the Commission
should thus assess penalties against Central Illinois or nullify
these letter agreements. 52/
--
Soyland argues that the presiding judge erred by failing to
grant it an unconditional open season. Soyland argues that the
harm it will experience from the merger is not adequately
__________________
50/ The Applicants have not filed amendments to the PSA or TSA,
--
nor has a settlement been filed on the stranded cost issue.
51/ UtiliCorp Brief Opposing Exceptions at 8-24.
--
52/ Trial Staff recommended that the Commission require Central
--
Illinois to file these two letter agreements. See Trial
---
Staff Brief Opposing Exceptions at 48.
<PAGE>
Docket No. EC96-7-000, et al. - 23 -
-- --
redressed by the presiding judge's decision that the Applicants
only propose a formula for reducing rates under the TSA to
reflect Soyland's share of the non-Joint Dispatch Agreement
merger savings. In support Soyland claims that: (1) additional
merger-related use of Central Illinois' transmission lines by the
Applicants will decrease the available transmission capacity for
Soyland on the Central Illinois system; (2) the Ameren open
access tariff and the Soyland TSA will operate together such that
the Applicants will greatly over-recover their FERC-approved
transmission revenue requirement; (3) the Applicants concede that
their proposed open season for formula rate customers such as
Soyland is not an open season but a rate cap; (4) the rate cap
does not protect Soyland from the disparity between the TSA rate
and the Ameren open season transmission rate paid by the
Applicants and their new customers; (5) the TSA is unduly
discriminatory as to Soyland because as opposed to the Ameren
open access tariff, the TSA requires a surcharge for variations
in customer load from year to year and a minimum daily rate even
if service is taken for only a few hours; and (6) the Applicants'
rate cap proposal fails to insulate Soyland from rate exposure
resulting from administrative fee escalations in the TSA and the
PSA. 53/
--
The Applicants and Trial Staff argue that the presiding
judge erred by: (1) imposing merger conditions relating to
UtiliCorp and Soyland because the ratepayer protections offered
by the Applicants insulate these customers from possible adverse
rate effects resulting from the merger; (2) basing additional
ratepayer protection for Soyland on competitive harm; (3)
addressing the concerns of the three intervenors regarding the
rates and terms of their existing contracts with the Applicants;
(4) not applying Enron, i.e., that the alleged harm must be
----- ----
related to the merger before mitigation measures are appropriate;
(5) creating his own legal standard of review since no evidence
was ever received regarding the existence, correctness, or
applicability of the statistical imperative used to justify
additional ratepayer protection to UtiliCorp; (6) applying an
inaccurate legal standard in finding that Soyland's rate
disparity argument is a hybrid or inter-effect issue involving
competition and ratepayer protection; (7) not finding that the
terms of the SPPA and CILCO agreements fully protect UtiliCorp
and CILCO from any adverse effect on rates; (8) finding that the
merger will result in higher energy rates from the Applicants;
and (9) concluding that Soyland would not have its fair share of
merger savings under the TSA since Soyland's TSA formula rate
will automatically operate to pass on any cost reductions that
accrue from the merger for those cost components that are
included in the TSA formula.
_________________
53/ Soyland Brief on Exceptions at 56-71.
--
<PAGE>
Docket No. EC96-7-000, et al. - 24 -
-- --
The Applicants respond to UtiliCorp's allegation of
competitive harm. They argue that UtiliCorp is currently paying
below a fully allocated, embedded cost-of-service rate for
capacity, as shown by UtiliCorp's negotiated demand charge which
is discounted steeply in relation to both Union Electric's
Missouri retail and wholesale requirements rates. The Applicants
also argue that UtiliCorp's energy charge of incremental cost
plus ten percent is also substantially less than the rates paid
by Union Electric's wholesale and retail requirements customers;
and even after the merger savings have been flowed through, the
rates of Union Electric's existing requirements customers will be
higher than the discounted rates paid by UtiliCorp. 54/
--
D. Commission Decision
-------------------
Under section 203 of the FPA, applicants must show that
their merger taken as a whole "will be consistent with the public
interest." 55/ We find that the Applicants have demonstrated
--
that ratepayers will be adequately protected from merger-related
harm.
With regard to Soyland, the presiding judge found that the
Applicants have proposed to revise their PSA contract with
Soyland to ensure that Soyland is held harmless from cost
increases, and that Soyland will receive merger savings related
to the Joint Dispatch Agreement. However, the presiding judge
ruled that these efforts were inadequate because the merger
savings to Soyland were insufficient. The presiding judge
concluded that:
. . . Soyland has demonstrated that unless it receives
its fair share of merger-related savings through
reductions in its PSA and TSA, it will suffer
anticompetitive and rate harm arising from the merger
. . . .
79 FERC at 65,086.
We conclude that the presiding judge erred in finding that
the Applicants' proposals with regard to Soyland are inadequate.
We find no evidence on this record that the merger could result
in an increase in Soyland's rates under the TSA or the PSA -- the
Applicants' rate cap proposal assures nothing less. In fact,
___________________
54/ Applicants Brief on Exceptions at 18.
--
55/ Entergy Services Inc. and Gulf States Utilities Company,
--
Opinion No. 385, 65 FERC (P) 61,332 at 62,473 (1993), order on
--------
reh'g, Opinion No. 385-A, 67 FERC (P) 61,192 (1994), appeal
----- ------
pending.
-------
<PAGE>
Docket No. EC96-7-000, et al. - 25 -
-- --
Soyland concedes that the ratepayer protections offered by the
Applicants will protect it from rate increases. 56/ Moreover, we
--
find substantial evidence that the merger may reduce Soyland's
costs under these agreements because a portion of the savings
from joint dispatch will automatically flow to Soyland through
its formula rate contracts. Soyland will automatically and
immediately receive through its formula rates the benefits of any
merger-related cost savings that pertain to the cost components
in those formulas. 57/
--
With regard to UtiliCorp and CILCO, we agree with the
Applicants and Trial Staff that the terms of the SPPA and the
CILCO Agreements, respectively, insulate these customers from any
merger-related harm. The demand charges under these agreements
are fixed at contractually established levels and will not vary
as a result of this merger (Exhibit 419A; Tr. 991) -- which
UtiliCorp concedes (Tr. 1215).
We also find that there has been no showing that energy
charges under the SPPA Agreement would increase as a result of
this merger. Moreover, there is no obligation to purchase energy
from Union Electric under these agreements -- which UtiliCorp
also concedes (Tr. 1215-16). Thus, these customers could
purchase from numerous other suppliers on the open market. In
effect, these customers already have the ability to schedule
transactions to minimize their energy costs under these
agreements. The Applicants' proposed rate cap on energy charges
provides an additional assurance that UtiliCorp's energy costs
will not increase as a result of this merger.
We also note that with respect to the energy rates charged
to CILCO, CILCO did not contract for energy at a fixed price;
rather, it contractually agreed that energy would be priced at
marginal cost plus 10 percent. Moreover, CILCO is not obligated
to purchase energy from Central Illinois; it can purchase energy
on the open market -- the same protection it would have if it
were given an open season.
________________
56/ Under cross-examination, Soyland witness Harbour agreed that
--
with the commitments and ratepayer protections offered by
the Applicants, he had no concerns that Soyland's rates
under either the PSA or the TSA would increase as a result
of this merger. Tr. 1486-87.
57/ We also find, as discussed above, that the rate disparity of
--
which Soyland complains between the transmission rates under
the TSA and the Ameren open access tariff is unrelated to
this merger since nearly the same disparity exists between
the TSA rates and the rates of Central Illinois' stand-alone
open access tariff.
<PAGE>
Docket No. EC96-7-000, et al. - 26 -
-- --
In addition, we find that the harm alleged by UtiliCorp,
CILCO, and Soyland is the result of these customers' existing
contracts with Applicants, and is thus unrelated to this merger.
The Commission has stated that we will remedy only specific harms
resulting from a proposed merger, but we have also required the
affected entity to first establish a nexus between the proposed
merger and the alleged harm. 58/ Based on the evidence in this
--
case, we find that the intervenors have failed to demonstrate the
required nexus between their alleged harm and the proposed
merger, and have, in fact, conceded that there was no such nexus.
We also find that the presiding judge erred in developing
his own standard of review of the competition and rate impact
issues in this proceeding. Specifically, the presiding judge
treated Soyland's and UtiliCorp's concerns as "a hybrid or inter-
effect issue that must be analyzed both as a competition and rate
issue." 79 FERC at 65,085. Subsequently, the presiding judge
found that
. . . when reviewing a merger that has rate increases
for certain customers and rate decreases for others as
well as merger savings, the merger's effect on rates
and competition must be viewed through a prism that is
not mutually exclusive. Instead, in circumstances such
as here, the consideration of the merger's effect on
rates must include evaluation of the merger's savings
. . . .
79 FERC at 65,085.
We find that the presiding judge's approach, in effect,
required the type of cost/benefit analysis we rejected in the
Merger Policy Statement in favor of ratepayer protection
mechanisms. Merger Policy Statement, FERC Stats. & Regs. at
-----------------------
30,111.
IV. Section 206 Investigation
-------------------------
However, we find that there is merit to CILCO's and Trial
Staff's claims concerning the two limited term purchase
agreements between CILCO and Central Illinois (Exhibit 419A). 59/
--
Although we find no basis for nullifying these agreements (as
requested by CILCO), we find that a review of these agreements is
warranted here since they contain terms and conditions of
service that have not been reviewed by the Commission and which
_________________
58/ See Duke, 79 FERC at 62,041. See also Enron, 78 FERC at
-- -------- -------- -----
61,137.
59/ The presiding judge neglected to rule on this issue in his
-- Initial Decision.
<PAGE>
Docket No. EC96-7-000, et al. - 27 -
-- --
may go beyond a simple reservation of service under the umbrella
Interconnection Agreement between these parties. 60/
--
Accordingly, we will direct the Applicants to file these
agreements with the Commission within twenty (20) days of the
date of issuance of this opinion.
In cases where, as here, the Commission institutes a section
206 investigation on its own motion, section 206(b) requires that
the Commission establish a refund effective date that is no
earlier than 60 days after publication of notice of the
Commission's investigation in the Federal Register, and no later
than five months subsequent to the expiration of the 60-day
period. In order to give maximum protection to consumers, and
consistent with our precedent, we will establish the refund date
at the earliest date allowed. 61/ That date will be 60 days from
--
the date on which notice of our initiation of the investigation
in Docket No. EL98-1-000 is published in the Federal Register.
Section 206(b) also requires that, if no final decision is
rendered in the Commission's investigation by the refund
effective date or by the conclusion of the 18-day period
commencing upon the initiation of a proceeding pursuant to
section 206, whichever is earliest, the Commission shall state
its best estimate as to when it reasonably expects to make such a
decision. To implement that requirement, we will direct the
presiding judge to provide a report to the Commission 15 days in
advance of the refund effective date in Docket No. EL98-1-000 in
the event the presiding judge has not by that date: (1)
certified to the Commission a settlement which, if accepted,
would dispose of the proceeding; or (2) issued an initial
decision. The presiding judge's report, if required, shall
advise the Commission of the status of the investigation and
provide an estimate of the expected date of certification of a
settlement or issuance of an initial decision.
V. Rehearing Requests
------------------
Timely requests for rehearing of the hearing order were
filed by the Applicants, Illinois Municipal Electric Agency
(Illinois Municipal), and jointly by Missouri Municipal,
Springfield, and Kirkwood (jointly, the Municipals).
The Applicants request that the Commission direct the
presiding judge to conduct this proceeding in two phases. The
Municipals filed an answer in response to the Applicants' request
____________
60/ See CILCO Brief On Exceptions at 35-38; Trial Staff Brief
-- ---
Opposing Exceptions at 48.
61/ See, e.g., Canal Electric Co., 46 FERC (P) 61,153, reh'g
-- --- ---- -----
denied, 47 FERC (P) 61,275 (1989).
------
<PAGE>
Docket No. EC96-7-000, et al. - 28 -
-- --
arguing that the Applicants have not provided justification for
bifurcating the proceeding. UtiliCorp also filed an answer
objecting to the Applicants' phasing proposal. The Municipals
request that the Commission clarify that specific issues that
relate directly to them (e.g., common bus agreements and
----
competition concerns) will be addressed at hearing. Illinois
Municipal requests that the Commission clarify that it set for
hearing whether the Applicants must offer Illinois Municipal
comparable system-wide transmission service and single, system-
wide rates as a condition of the merger. As discussed above,
since the issues raised by these parties have either been settled
or rendered moot by the issuance of this opinion, we will dismiss
the requests for rehearing.
Conclusion
----------
Based on the record in this proceeding, we will approve the
Applicants' proposed merger and accept the Applicants' ratepayer
protection mechanisms. We find that the ratepayer protections
offered by the Applicants are adequate to prevent ratepayer harm
and the intervenors have not met their burden of showing that
this merger will likely harm competition. Accordingly, we will
reject the merger conditions imposed by the presiding judge. 62/
--
However, the Applicants are directed to comply with the ratepayer
commitments they have made in this proceeding.
The Commission orders:
---------------------
(A) The requests for rehearing are hereby dismissed.
(B) The Initial Decision issued in this proceeding is
hereby affirmed in part and reversed in part, as discussed in the
body of this opinion.
(C) The Applicants' proposed merger is hereby approved, and
we direct the Applicants to comply with the ratepayer protection
commitments that they have made in this proceeding, as discussed
in the body of this opinion.
(D) The Commission retains the authority under section
203(b) of the FPA to issue supplemental orders, as appropriate.
(E) The foregoing authorization is made without prejudice
to the authority of the Commission or any other regulatory body
with respect to rates, service, accounts, valuation, estimates,
determinations of cost, or any other matter whatsoever now
pending or which may come before this Commission.
__________________
62/ We note that the Missouri Commission, as a condition of its
--
merger approval, ordered Union Electric to negotiate for
participation in the "Midwest ISO."
<PAGE>
Docket No. EC96-7-000, et al. - 29 -
(F) Nothing in this order shall be construed to imply
acquiescence in any estimate or determination of cost or any
valuation of property claimed or asserted.
(G) The Applicants shall promptly notify the Commission
when the proposed merger is consummated.
(H) The settlement agreement filed on July 21, 1997, among
the Applicants, Kirkwood, and the Missouri Municipal is hereby
approved.
(I) The Applicants shall modify section 11.2(a) of the PSA
to reflect the agreed-upon modification of Soyland's formula for
monthly energy charges, as noted in the Initial Decision at 79
FERC at 65,089.
(J) Within twenty (20) days of the date of the issuance of
this opinion, the Applicants are directed to file the two limited
term purchase agreements between CILCO and Central Illinois, as
discussed in the body of this opinion.
(K) Pursuant to the authority contained in and subject to
the jurisdiction conferred upon the Federal Energy Regulatory
Commission by section 402(a) of the Department of Energy
Organization Act and by the Federal Power Act, particularly
section 206 thereof, and pursuant to the Commission's Rules of
Practice and Procedure and the regulations under the Federal
Power Act (18 C.F.R., Chapter I), a public hearing shall be held
in Docket No. EL98-1-000 concerning the justness and
reasonableness of the CILCO/Central Illinois agreements, as
discussed in the body of this opinion.
(L) The Secretary shall promptly publish a notice of the
Commission's initiation of the proceeding in Docket No. EL98-1-
000 in the Federal Register.
(M) The refund effective date in Docket No. EL98-1-000,
established pursuant to section 206(b) of the Federal Power Act,
will be 60 days following publication in the Federal Register of
the notice discussed in Ordering Paragraph (L).
(N) The presiding administrative law judge shall advise the
Commission, no later than 15 days prior to the refund date
established in Docket No. EL98-1-000, in the event that the
presiding judge has not by that date certified to the Commission
a settlement which, if accepted, would dispose of the proceeding
or issued an initial decision, as to the status of the proceeding
and his best estimate of when the proceeding will be disposed of
by the presiding judge.
(O) A presiding administrative law judge, to be designated
by the Chief Administrative Law Judge, shall convene a conference
<PAGE>
Docket No. EC96-7-000, et al. - 30 -
in Docket No. EL98-1-000, to be held within approximately thirty
(30) days from the date of this order, in a hearing room of the
Federal Energy Regulatory Commission, 888 First Street, N.E.,
Washington, DC 20426. Such conference shall be held for the
purpose of establishing a procedural schedule. The presiding
judge is authorized to establish procedural dates and to rule on
all motions (except motions to dismiss) as provided for in the
Commission's Rules of Practice and Procedure.
(P) The Applicants are hereby informed of the rate schedule
designations shown on the Attachment to this opinion.
By the Commission.
( S E A L )
/s/ Lois D. Cashell
Lois D. Cashell,
Secretary.
<PAGE>
Docket No. EC96-7-000, et al. - 31 -
Union Electric Company
Docket Nos. ER96-679-000 and EC96-7-000
Rate Schedule Designations
--------------------------
Description/
Designation Effective Date
----------- --------------
(1) Supplement No. 1 to Supplement to Exhibit A
Supplement No. 4 to of the Substitute Power
Service Agreement No. Agreement with City of
36 under FERC Electric Centalia, Missouri/
Tariff, Original Volume May 31, 1997
No. 5
(2) Supplement No. 1 to Supplement to Exhibit A
Supplement No. 4 to of the Substitute Power
Service Agreement No. Agreement with Citizens
37 under FERC Electric Electric Corporation/
Tariff, Original Volume May 31, 1997
No. 5
(3) Supplement No. 1 to Supplement to Exhibit A
Supplement No. 4 to of the Substitute Power
Service Agreement No. Agreement with City of
39 under FERC Electric Farmington, Missouri/
Tariff, Original Volume May 31, 1997
No. 5
(4) Supplement No. 1 to Supplement to Exhibit A
Supplement No. 7 to of the Substitute Power
Service Agreement No. Agreement with
40 under FERC Electric Fredericktown, Missouri/
Tariff, Original Volume May 31, 1997
No. 5
(5) Supplement No. 1 to Supplement to Exhibit A
Supplement No. 4 to of the Substitute Power
Service Agreement No. Agreement with City of
41 under FERC Electric Rolla, Missouri/
Tariff, Original Volume May 31, 1997
No. 5
(6) Supplement No. 2 to Supplement to Exhibit A
Supplement No. 5 to of the Substitute Power
Service Agreement No. Agreement with City of
43 under FERC Electric Linneus, Missouri/
Tariff, Original Volume May 31, 1997
No. 5
<PAGE>
Docket No. EC96-7-000, et al. - 32 -
Union Electric Company
Docket Nos. ER96-679-000 and EC96-7-000
Rate Schedule Designations
--------------------------
Description/
Designation Effective Date
----------- --------------
(7) Supplement No. 1 to Supplement to Exhibit A
Supplement No. 4 to of the Substitute Power
Service Agreement No. Agreement with City of
44 under FERC Electric Perry, Missouri/
Tariff, Original Volume May 31, 1997
No. 5
(8) Supplement No. 1 to Supplement to Exhibit A
Supplement No. 4 to of the Substitute Power
Service Agreement No. Agreement with City of
45 under FERC Electric St. James, Missouri/
Tariff, Original Volume May 31, 1997
No. 5
(9) Supplement No. 1 to Supplement to Exhibit A
Supplement No. 3 to of the Substitute Power
Service Agreement No. Agreement with City of
46 under FERC Electric California, Missouri/
Tariff, Original Volume May 31, 1997
No. 5
(10) Supplement No. 1 to Supplement to Exhibit A
Supplement No. 4 to of the Substitute Power
Service Agreement No. Agreement with City of
49 under FERC Electric Owensville, Missouri/
Tariff, Original Volume May 31, 1997
No. 5
(11) Supplement No. 1 to Supplement to Exhibit A
Supplement No. 3 to of the Substitute Power
Service Agreement No. Agreement with City of
50 under FERC Electric Marceline, Missouri/
Tariff, Original Volume June 1, 1997
No. 5
(12) Supplement No. 1 to Supplement to Exhibit A
Supplement No. 5 to of the Substitute Power
Service Agreement No. Agreement with City of
51 under FERC Electric Kirkwood, Missouri/
Tariff, Original Volume May 31, 1997
No. 5
<PAGE>
Docket No. EC96-7-000, et al. - 33 -
Union Electric Company
Docket Nos. ER96-679-000 and EC96-7-000
Rate Schedule Designations
--------------------------
Description/
Designation Effective Date
----------- --------------
(13) Supplement No. 1 to Supplement to Exhibit A
Supplement No. 2 to of the Substitute Power
Service Agreement No. Agreement with City of
52 under FERC Electric Hannibal, Missouri/
Tariff, Original Volume May 31, 1997
No. 5
<PAGE>
EXHIBIT D-3.2
STATE OF ILLINOIS
ILLINOIS COMMERCE COMMISSION
Central Illinois Public Service :
Company :
CIPSCO Incorporated :
Union Electric Company : 95-0551
:
Joint Application for approval of :
merger and reorganization. :
ORDER
-----
DATED: September 10, 1997
<PAGE>
TABLE OF CONTENTS
-----------------
<TABLE>
<CAPTION>
<S> <C>
I. PROCEDURAL HISTORY............................................ 1
II. DESCRIPTION OF THE REORGANIZATION............................. 4
III. REASONS FOR THE PROPOSED MERGER AND OVERVIEW OF APPLICANTS'
POSITION REGARDING MARKET POWER ISSUES........................ 9
IV. RELIEF REQUESTED.............................................. 11
V. APPLICABLE LAW................................................ 12
VI. OVERVIEW OF THE POSITIONS OF STAFF, IIEC, CUB AND QST......... 15
A. Staff's Position ........................................ 15
B. IIEC's Position ......................................... 15
C. CUB's Position .......................................... 16
D. QST's Position .......................................... 17
VII. CONTESTED ISSUES............................................... 17
A. Applicants' Merger Savings Plan and Related Issues ..... 17
1. Applicants' Position ................................ 17
2. Positions of Staff, IIEC and CUB .................... 20
a. Approval of a Sharing Plan in this Proceeding .. 20
b. The Merger Premium ............................. 22
c. Applicants' Estimates of Savings ............... 24
d. Tracking of Actual Savings ..................... 26
e. Timing of Rate Case Filing ..................... 28
f. Part 285 Requirements .......................... 29
3. Commission's Conclusion ............................. 30
B. Transfer of UE's Illinois Distribution Assets and Service
Territory to CIPS........................................ 32
</TABLE>
1
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
1. Applicants' Position ........................................ 32
2. Positions of Staff and IIEC ................................. 33
a. Jurisdictional Concerns ................................ 33
b. Prudence of the SSA Alternative......................... 36
c. Allocation of Costs Under the SSA Alternative........... 39
d. Savings Under the Transfer ............................. 39
e. Consolidation of Metro East Rates with Rates Applicable
to the Rest of CIPS' Service Area .......................40
3. Commission's Conclusion ......................................40
C. Ability of CIPS and UE to provide adequate, reliable,
efficient, safe and least-cost public utility service............ 42
D. The Public Convenience Standard under Section 7-102 ............. 43
E. Market Power Issues.............................................. 44
1. Overview of the Merger Guidelines adopted by the FERC ........44
2. Applicants' Position......................................... 45
a. Product Market.......................................... 45
b. Geographic Market....................................... 47
c. HHI Results............................................. 48
d. Analysis of Other Factors Affecting Market Power........ 48
3. Staff's Position..............................................52
a. Product Market.......................................... 52
b. Geographic Market....................................... 53
c. HHI Results............................................. 53
d. Analysis of Other Factors Affecting Market Power........ 54
4. CUB's Position................................................55
</TABLE>
2
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
a. CUB's Analysis.......................................... 55
b. Responses of Applicants and Staff....................... 57
5. Commission's Conclusion...................................... 58
VIII. NO UNJUSTIFIED SUBSIDIZATION OF NON-UTILITY ACTIVITIES......... 59
IX. ALLOCATION OF COSTS AND FACILITIES BETWEEN UTILITY AND NON-
UTILITY OPERATIONS............................................. 60
A. The Commission's Jurisdiction.............................. 61
B. The Revised GSA............................................ 63
C. Other Matters.............................................. 64
X. ABILITY TO RAISE CAPITAL ON REASONABLE TERMS AND TO MAINTAIN A
REASONABLE CAPITAL STRUCTURE................................... 66
XI. CIPS AND UE WILL REMAIN SUBJECT TO ALL APPLICABLE LAWS,
REGULATIONS, RULES, DECISIONS AND POLICIES GOVERNING THE
REGULATION OF ILLINOIS PUBLIC UTILITIES........................ 67
XII. THE JOINT DISPATCH AGREEMENT................................... 67
XIII. FINDINGS AND ORDERING PARAGRAPHS............................... 68
</TABLE>
3
<PAGE>
STATE OF ILLINOIS
ILLINOIS COMMERCE COMMISSION
Central Illinois Public Service :
Company :
CIPSCO Incorporated :
Union Electric Company : 95-0551
:
Joint Application for approval of :
merger and reorganization. :
ORDER
-----
By the Commission:
I. PROCEDURAL HISTORY
On November 6, 1995, Central Illinois Public Service Company ("CIPS"),
CIPSCO Incorporated ("CIPSCO") and Union Electric Company ("UE" or "Union
Electric") (collectively, the "Applicants") filed a joint application (the
"Application") with the Illinois Commerce Commission ("Commission") pursuant to
Sections 7-204 and 7-204A, and to the extent necessary, Section 7-102, of the
Public Utilities Act ("Act") (220 ILCS 5/7-204, 7-204A and 7-102) seeking
approval of their merger and reorganization and seeking further relief pursuant
to Sections 6-103, 7-101, 7-102, 7-203, 8-406, 8-508, 8-508.1 and 9-201 of the
Act. The Application seeks an order of the Commission authorizing CIPSCO to
merge with Ameren Corporation ("Ameren"), and UE to merge with Ameren's
subsidiary, Arch Merger, Inc. ("Arch Merger"), with Ameren becoming the holding
company parent of UE and CIPS. The Application further seeks an order
authorizing the transfer of UE's Illinois electric and gas distribution assets
(other than electric generation and transmission assets) to CIPS (the
"Transfer"). The Application also seeks the Commission's approval to engage in
various transactions necessary to complete the merger and reorganization as
described therein.
The Citizens Utility Board ("CUB"), the Illinois Industrial Energy
Consumers ("IIEC")/1/,
- -------------------
/1/IIEC consists of Big River Zinc Corporation; Cerro Copper Products, a member
of the Marmon Group; Chemetco Inc.; Laclede Steel Company; Monsanto Company;
Shell Oil Company; Jefferson Smurfit Corporation; Harcross Pigments; and Ethyl
Corporation, which take electric service from UE, and Archer-Daniels-Midland
Company; Central Soya Company, Inc.; Marathon Oil Company; and Quantum Chemicals
Company, which take electric service from CIPS. (continued...)
<PAGE>
Illinois Power Company ("IP"), and the International Brotherhood of Electrical
Workers ("IBEW") Locals 2, 702, 1455 and 309 filed petitions to intervene in
this proceeding that were granted by the Hearing Examiner.
Pursuant to proper legal notice, a pre-hearing conference were held in
this matter before a duly authorized Hearing Examiner of the Commission at its
offices in Springfield, Illinois on December 6, 1995. Thereafter, additional
hearings were held on January 18, February 9, April 29 and 30, May 1 and 3, June
7 and 17 and August 22 and 29, 1996. Appearances were entered at the evidentiary
hearings by counsel on behalf of Applicants, CUB, IIEC, the Commission Staff
("Staff") and IP. The following twelve witnesses presented evidence on behalf
of Applicants in support of the Application: Clifford L. Greenwalt, President
and Chief Executive Officer of CIPSCO and CIPS; William A. Koertner, Vice
President - Finance and Corporate Secretary of CIPSCO and CIPS; Douglas W.
Kimmelman, Vice President at Goldman Sachs & Co.; Gary L. Rainwater, Vice
President of Corporate Planning of UE; Jerre E. Birdsong, Treasurer of UE;
Gilbert W. Moorman, Vice President - Power Supply of CIPS; Craig D. Nelson,
Treasurer and Assistant Secretary of CIPS and Treasurer, Assistant Secretary and
Assistant Controller of CIPSCO; Gregory L. Nelson, Manager of the Tax Department
of UE; Steven D. Pettit, Gas Supply Supervisor of CIPS; Robert J. Mill, Manager
of the Regulatory Department of CIPS; Thomas J. Flaherty, National Partner for
Utilities Consulting of Deloitte & Touche, LLP; John C. Guibert, Vice President
of SYNERGY Consulting Services Corp; and James A. Reid, Senior Vice President of
CSC Planmetrics. Richard A. Rosen, Executive Vice-President of the Tellus
Institute and Director of the Institute's Energy Group, testified on behalf of
CUB. Maurice Brubaker, a principal in the firm of Brubaker & Associates, Inc.,
testified on behalf of IIEC. The following nine witnesses testified on behalf
of Staff: Eric P. Schlaf, a Senior Economist in the Commission's Office of
Policy and Planning; Alan S. Pregozen, Chief Financial Analyst in the Finance
Department of the Commission's Public Utility Division ("PUD"); Tony Haynes, a
Senior Analyst in the Integrated Resource Planning ("IRP") Program of the
Commission's Energy Programs Division; Carl R. Peterson, an Economic Analyst in
PUD's Rate Design Department; Thomas Q. Smith, an Audit Supervisor in the
Auditing Section of PUD's Accounting Department; Karen Goldberger, an Accountant
in the Auditing Section of PUD's Accounting Department; Brian Collins, an
Economic Analyst in PUD's Planning and Operations Department; John J. Stutsman,
the Director of the IRP Program in the Commission's Energy Programs Division;
and Robert E. Bishop, Assistant Manager of PUD. At the conclusion of the
hearing on August 29, 1996, the record was marked "Heard and Taken."
Applicants, Staff, IIEC and CUB filed initial briefs and reply briefs.
Applicants filed a draft order.
- ------------------
(...continued)
Company, which take electric service from CIPS.
2
<PAGE>
The Hearing Examiner's proposed order was served on the parties.
Briefs on exceptions were filed by Applicants, Staff, IIEC and CUB. Replies to
exceptions were filed by Applicants, Staff and IIEC. These filings have been
considered by the Commission in reaching its decision in this proceeding.
On January 27, 1997, the Commission, on its own motion, reopened the
record in this proceeding to receive testimony concerning market power issues.
In reopening the docket, the Commission asked the parties to address the impact
of the proposed merger and any associated agreements on the competitiveness of
existing and likely future Illinois retail markets. The Commission expressed its
concern that the Federal Energy Regulatory Commission ("FERC") and Missouri
Public Service Commission proceedings regarding the merger will not sufficiently
address the impact of the merger on retail markets in Illinois. The Commission
stated that, if a party determines that market power under the proposed merger
will impinge upon competition in the existing or likely future Illinois retail
market, the party should suggest conditions that could be imposed on the merger
to address that market power concern. In order to limit the scope of questioning
in the reopened docket, the Commission instructed the parties to use the five
steps of merger analysis set out in Appendix A of the FERC's December 18, 1996
Merger Policy Statement./2/
On February 18, 1997, Applicants filed a motion asking the Commission
to reconsider its order reopening the record and to grant consent, authority and
approval for the merger. CUB and IIEC filed responses to this motion. Applicants
filed a reply. On March 3, 1997, the Commission entered an order denying
Applicants' motion to reconsider.
On March 3, 1997, the Commission entered an order expanding the scope
of the reopened record to address the terms and conditions of the Applicants'
proposed General Services Agreement ("GSA") and potential loss of jurisdiction
to the Securities and Exchange Commission ("SEC"). Instructions to the parties
regarding the GSA issues to be addressed on reopening were set forth in a March
4, 1997 memorandum from Commissioner Kretschmer to the Hearing Examiner that was
forwarded to the parties.
Pursuant to proper legal notice, hearings were held in the reopened
phase on February 10, February 18, February 27, March 3, March 5, March 10,
March 27, May 12 and May 29, 1997, at which scheduling and other procedural
matters were discussed. At a hearing on June 2, 1997, evidence was received
regarding the issues on reopening. The following five witnesses submitted
evidence on behalf of Applicants: William A. Koertner, Vice President - Finance
and Corporate Secretary of CIPSCO and CIPS; Maureen A. Borkowski, UE's Manager
of Energy Services in the Corporate Planning function; David A. Whiteley,
Manager of Electrical Engineering for UE; Rodney W. Frame, a Vice President of
National Economic Research Associates, Inc.; and Warner L. Baxter, Controller of
UE. William G. Shepherd, a Professor of Economics at the University of
- -------------------
/2/ FERC Docket No. PM96-6-000, Inquiry Concerning the Commission's Merger
Policy under the Federal Power Act: Policy Statement, Appendix A,
3
<PAGE>
Massachusetts, presented evidence on behalf of CUB. Three witnesses presented
evidence on behalf of Staff: Thomas Q. Smith, an Audit Supervisor in the
Accounting Department of the Commission's Public Utilities Division; Steven A.
Mitnick, a Director of Hagler Bailly Consulting, Inc.; and Robert J. Michaels, a
Professor of Economics at California State University, Fullerton, and Senior
Advisor to Hagler Bailly Consulting, Inc. The parties waived cross-examination
of the witnesses. At the conclusion of the hearing on June 2, 1997, the record
was marked "Heard and Taken."
On June 26, 1997, QST Energy Trading Inc. ("QST") filed a petition to
intervene and to reopen the record. On July 7, 1997, the Commission granted the
petition to intervene, but denied the request to reopen the record.
On June 26, 1997, CUB filed a motion to reopen the record for the
purpose of admitting into evidence the responses of Applicants to two CUB data
requests. The motion was not opposed by any party. The Hearing Examiner granted
the motion and admitted the data request responses into evidence as CUB's Late-
Filed Exhibits 1 and 2. After admitting these exhibits, the Hearing Examiner
marked the record "Heard and Taken."
Applicants, Staff and CUB filed initial briefs and reply briefs on
reopening. Applicants filed a draft order on reopening.
A second Hearing Examiner's proposed order reflecting the proceedings
on reopening was served on the parties. Briefs on exceptions thereto were filed
by Applicants, Staff, IIEC, CUB and QST. Replies to exceptions were filed by
Applicants, Staff, CUB and QST. These filings have been considered by the
Commission in reaching its decision in this proceeding to the extent that they
address issues considered in the reopened record.
II. DESCRIPTION OF THE REORGANIZATION
CIPS is an Illinois corporation that operates as a public utility in
Illinois pursuant to the Act. CIPS provides electric service to 317,000
customers and gas service to 166,000 customers in a 20,000 square mile region of
central and southern Illinois. CIPSCO, an Illinois corporation and a holding
company, owns all of the common stock of CIPS and CIPSCO Investment Company
("CIC"), through which CIPSCO conducts non-utility businesses. UE is a Missouri
corporation that operates as a public utility in Missouri and Illinois. UE
provides electric service to approximately 1,060,000 customers in Missouri and
64,000 customers in Illinois. Its Illinois electric service area includes the
cities of East St. Louis and Alton. UE provides gas service to approximately
100,000 customers in Missouri and 18,000 customers in Illinois. Under the
Agreement and Plan of Merger between Union Electric and CIPSCO (the "Merger
Agreement") (App. Ex. WAK-2), once all shareholder and regulatory approvals have
been obtained, CIPSCO will merge with and into Ameren, a Missouri corporation,
and UE will merge with Ameren's subsidiary, Arch Merger, a Missouri corporation,
with UE as the surviving company. As a result, Ameren, which will
4
<PAGE>
register under the Public Utility Holding Company Act of 1935, 15 U.S.C. (S) 79
et seq. ("PUHCA"), will become the holding company parent of UE, CIPS and CIC.
Ameren will transfer UE's Illinois assets (excluding electric generation and
transmission assets) to CIPS, and CIPS will succeed to UE's Illinois public
utility business.
Each share of issued and outstanding CIPSCO common stock will be
converted into 1.03 shares of Ameren common stock, and each issued and
outstanding share of UE common stock will be converted into Ameren common stock
using a one-for-one conversion ratio. Ameren is expected to have a total of
about 137,000,000 shares of common stock outstanding. The shareholders of CIPSCO
and UE would own securities representing approximately 25.6% and 74.4%,
respectively, of the outstanding voting power of Ameren. The outstanding UE and
CIPS preferred stock will not be affected. Ameren's Board of Directors will
consist of fifteen persons drawn from the Boards of Directors of UE and CIPSCO,
ten designated by UE and five designated by CIPSCO.
The shareholders of CIPSCO and UE met in separate meetings on December
20, 1995 to vote on the merger proposal. The merger was approved by the
affirmative vote of 97% of the CIPSCO shares voting and 96% of the UE shares
voting.
Ameren intends to use the "pooling of interests" method of accounting
to reflect the merger on its books. The assets, liabilities and capitalization
of UE and CIPSCO will be combined in the consolidated financial statements of
Ameren at the recorded amounts stated in their respective balance sheets
immediately preceding the merger. For the fiscal year in which the merger
occurs, the income of Ameren will include the income of UE and CIPSCO for the
entire year. The reported income of the separate companies for prior periods
will be combined and restated as income of Ameren.
The headquarters of Ameren will be in St. Louis, Missouri. The
headquarters of the two utility subsidiaries will remain in their current
locations: UE's in St. Louis, and CIPS' in Springfield, Illinois.
Subsequent to the merger, Applicants intend to integrate various
corporate functions via a service company providing services to the Ameren
companies. Applicants have entered into a services agreement (the "General
Services Agreement"), which Applicants intend to file with the Securities and
Exchange Commission ("SEC"). Under PUHCA, the SEC has jurisdiction over
affiliated interest transactions of public utility affiliates of a registered
holding company. [PUHCA, (S) 13.] Applicants indicate that the Commission will
also continue to have jurisdiction over affiliated interest transactions under
Section 7-101 of the Act and the jurisdictional conditions agreed to by
Applicants that are set forth in the Appendix to this Order. These
jurisdictional conditions were set forth in Appendix B to Applicants' reply
brief.
Subsequent to the merger, CIPS and UE will operate their combined
electric generation and transmission facilities as a single control area. A
control area is an electric system that conforms to consistently applied
regional and national reliability standards,
5
<PAGE>
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, Union Electric and CIPS operate as separate control areas.
After the merger is effected, a system dispatch center will dispatch
CIPS and Union Electric generating units without regard to which operating
company actually owns the unit, but rather, on the basis of which of the units,
or competitive options, offers the lowest incremental cost (subject to
operational constraints) for the next increment of load. Each company will
continue to be credited with its own lowest-cost generation to serve its own
load requirements. Both systems will be modeled after-the-fact to determine how
variable generation costs are to be allocated between the companies. Each
company will have lower energy supply variable costs as a result of electric
joint dispatch. CIPS and Union Electric have entered into a Joint Dispatch
Agreement (App. Ex. GWM-6 (Rev.)) to govern the allocation of costs and revenues
associated with the central dispatch of their electric generation.
Union Electric and CIPS also intend to arrange all gas purchases,
transportation and storage on a centralized basis. Applicants are currently
evaluating joint dispatch of their gas systems. Applicants intend to realize the
economies possible from gas joint dispatch under existing purchase,
transportation and storage contracts, and to increase the potential for such
economies in future arrangements. Applicants have agreed to Staff's proposal
that consideration of the joint dispatch of CIPS' and Union Electric's gas
systems be addressed in a future proceeding before the Commission.
Pursuant to the Merger Agreement, Ameren would transfer Union
Electric's electric and gas service territory in Illinois, known as the "Metro
East" area, and the electric and gas distribution facilities used to provide
service to Metro East, from Union Electric to CIPS. The Metro East electric
service area comprises about 330 square miles, with about 64,000 customers in 33
communities; the Metro East gas service territory is considerably smaller, with
gas service provided in and around Alton, Illinois to about 18,000 customers.
CIPS would acquire the electric and gas distribution systems, including electric
lines and substations, as well as all associated general plant in service in
Illinois (the "Distribution Assets"). CIPS would not take ownership of any Union
Electric electric generation or transmission facilities operating in Illinois or
elsewhere.
As an integral element of this transfer, CIPS and Union Electric would
enter into a System Support Agreement (the "SSA"), the purpose of which is to
maintain, during a transition period, the allocation to the Metro East service
area of the Union Electric generation and transmission plant currently serving
that area. The SSA, as originally filed with this Commission and the FERC, had a
term of 30 years and provided that, as Union Electric's existing generation
units are retired, the contracted level of capacity and energy support to CIPS
from the Union Electric generation would proportionately decrease. In response
to objections to the SSA from the Staff and IIEC regarding the 30 year term,
Applicants offered an alternative SSA (the "SSA Alternative"). Specifically,
Applicants
6
<PAGE>
offered to amend the SSA to provide two contract periods totalling ten years: a
five-year fixed period, followed by a five-year phase-out period. UE witness
Rainwater testified that, in addition to addressing the concerns of other
parties, this proposal would also provide Union Electric with a reasonable
transition period to mitigate the possibility of the contract phase-out causing
an adverse impact on either Ameren's shareholders or Union Electric's Missouri
customers.
Applicants indicate that this transitional agreement would avoid the
effectuation of changes in the cost of service for either existing CIPS
customers or Metro East customers by virtue of the change in corporate
structure, and would avoid the creation of stranded costs for Union Electric.
Under the SSA Alternative, Union Electric would provide CIPS with specified
levels of capacity and energy, based on historical load patterns in Metro East.
CIPS will be responsible for meeting power requirements in excess of those
provided by the SSA Alternative for all future load growth in the transferred
area, and for replacement of power services phased out during the second five
years of the SSA Alternative.
The Applicants explained that the SSA Alternative is, essentially, a
cost allocation mechanism for the continued recovery of currently allocated
Union Electric power supply and transmission costs from the transferred Illinois
electric customers. Union Electric's generation and transmission system was
planned and constructed as an integrated system which would serve all of its
customers, including those customers being transferred to CIPS. Consequently,
cost allocations have historically been made between jurisdictions to reflect
Union Electric's generation and transmission costs in serving each jurisdiction,
resulting in revenue levels that provide for cost recovery. Applicants indicate
that the SSA Alternative preserves the recovery of costs for the portion of
Union Electric's generation and transmission system that will continue to serve
Illinois customers after the merger is effective. Applicants emphasize that if
an appropriate mechanism for continued cost allocation were not implemented,
cost shifting could occur between state jurisdictions and, consequently, rates
could be impacted as a result of the transfer. Accordingly, Applicants conclude
that the transfer of the Illinois customers would not be possible without the
SSA Alternative.
As will be discussed more fully in Section VII.B.2.a of this order,
Applicants are willing to enter into the SSA Alternative subject to the
condition that the Commission's retail rate jurisdiction over the allocation of
Union Electric plant and expenses to Metro East be preserved.
Applicants also intend to transfer to CIPS the accumulated deferred
income taxes ("ADIT") associated with the transferred property. Applicants have
requested the issuance of a private letter ruling ("PLR") by the Internal
Revenue Service ("IRS") related to the ADIT associated with the distribution
assets to be transferred by UE to CIPS. Applicants intend that the distribution
assets not be transferred until a favorable PLR is issued by the IRS.
7
<PAGE>
Another aspect of the proposed transfer involves the disposition of
certain nuclear decommissioning funds. Union Electric's rates in Illinois, as
well as its wholesale rates and its rates in Missouri, recognize nuclear
decommissioning expenses related to its Callaway generating plant. The amounts
reflected in cost of service are deposited quarterly in an external qualified
trust. Union Electric also maintains a non-qualified trust, subject to this
Commission's jurisdiction under Section 8-508.1 of the Act. The amount collected
by Union Electric annually from Illinois ratepayers is $355,000. As of June 30,
1995, a total of $5.7 million was held in the Illinois subaccount of the
external qualified trust. No funds are held in the non-qualified trust.
If the merger and property transfer are consummated, Union Electric
will no longer have an Illinois retail electric jurisdiction. Since the IRS
requires that contributions into a qualified trust must be included in the
contributing utility's cost of service for the contributing jurisdiction, Union
Electric will no longer be able to place the annual contribution from Illinois
customers into the qualified trust. The SSA Alternative provides, inter alia,
for the payment by CIPS to Union Electric of nuclear decommissioning costs,
which would be contributed quarterly to the qualified trust in the FERC
subaccount, because the SSA Alternative is FERC-jurisdictional. This cost, which
is currently reflected in the rates paid by Metro East customers, would continue
to be passed on to them as part of the cost of power purchases that CIPS makes
from UE under the SSA Alternative. Therefore, Applicants seek the Commission's
approval to transfer the Illinois subaccount funds to the FERC subaccount.
UE and CIPS intend that there be no immediate change in the status quo
for any customer group as a result of the transfer of UE's Illinois customers to
CIPS. They assert that the structural changes resulting from the merger are not
intended to benefit some customers at the expense of others, and should not
effect rate increases. Accordingly, prior to the closing of the merger, CIPS
intends to seek approval of tariffs for Metro East electric customers that will
produce customer bills identical to bills under the Union Electric existing
tariffs now in effect for the transferred Union Electric territory. Base rates
will be identical to Union Electric's current base rates. CIPS witness Mill
explained that CIPS will make any necessary adjustments to the FAC to avoid
passing through the FAC any costs that are presently included in Union
Electric's base rates.
CIPS will propose a separate service schedule of tariffs for gas
customers being transferred from Union Electric to CIPS. The gas tariffs,
including the PGA, will be identical to Union Electric's existing tariffs and
will produce customer bills equal to the bills that would have been issued under
the current Union Electric gas tariffs. The PGA calculation after the transfer
of customers will be performed with the same cost information used currently by
Union Electric for the Illinois customers.
CIPS has committed to file a rate case applicable to its present
service territory no later than 12 months after closing of the merger. Mr. Mill
indicated that in all likelihood, the rate case will be an alternative
regulation proceeding under Section 9-244 of the Act. (App. Ex. RJM-7, p. 2) The
rate filing will include a proposal for reflecting in rates the
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effect of the merger, including cost savings, the costs to achieve those
savings, transaction costs and the merger premium. Specifically, Applicants have
proposed that, over the first ten years following the merger, initially
estimated merger-related savings, net of the costs to achieve, transaction costs
and merger premium, be shared equally between the shareholders and ratepayers.
All merger-related savings during the first ten years that exceed the initially
identified amount and all such savings after that ten-year period would accrue
to the sole benefit of the ratepayers. The proposal is discussed in detail in
Section VII.A of this order. Applicants request that the Commission find that
this proposed treatment of the merger-related costs and cost savings is
reasonable, and should be reflected in the rate case to be filed by CIPS.
Alternatively, Applicants request that the Commission find, at the very least,
that (i) the merger premium and transaction and transition costs are just and
reasonable; (ii) it is reasonable and appropriate for Applicants to recover the
merger premium and transaction and transition costs; and (iii) it is reasonable
and appropriate for Applicants to share in the net merger savings (App. initial
brief, p. 28).
III. REASONS FOR THE PROPOSED MERGER AND OVERVIEW OF APPLICANTS' POSITION
REGARDING MARKET POWER ISSUES
Applicants' witness Greenwalt's description of the reasons for the
merger is summarized in the next three paragraphs.
The managements of both UE and CIPSCO believe that the merger offers
significant strategic, operational and financial benefits. The merger provides
benefits and opportunities to shareholders of both companies as well as to the
employees and customers in the communities in which both companies do business.
The merger will create significant cost savings that will help offset rising
costs and maintain competitive prices, thereby benefiting customers and
improving the ability of both utility affiliates to meet the challenges of the
increasingly competitive environment in the utility industry. 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
merger will provide benefits for customers in the form of lower rates than would
otherwise be the case over the long term and for shareholders in the form of
greater financial strength, increased financial flexibility, and improved
competitive position.
The strategically combined companies will have enhanced opportunities for
marketing in the wholesale and interchange markets. The two companies will have
electric interconnections with 28 other electric utility systems. These
interconnections will provide opportunities for sales transactions with the
directly interconnected systems and, through them, with even more systems. 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 geographic diversity should reduce risk due to exposure to local
changes in economic or competitive conditions.
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Together, UE and CIPS will be able to draw on a larger and more
diverse mid- and senior-level management pool to lead Ameren in an increasingly
competitive environment. Moreover, the combined companies should be better able
to attract and retain highly qualified employees. The employees of Ameren and
its affiliated companies should also benefit from new opportunities in the
expanded organization.
Applicants' witness Craig D. Nelson outlined the Applicants' final
estimate of savings expected to result from the merger during the first ten
years after the merger The estimated savings are as follows (App. Ex. CDN-16):
<TABLE>
<CAPTION>
Savings Category Savings (millions)
---------------- ------------------
<S> <C>
Labor $267
Corporate and administrative programs 235
Purchasing economies (non-fuel) 84
Electric production 101
Gas production 37
Additional operational savings 35
----
Total Savings $759
</TABLE>
Taking into account transaction costs of $22 million and transition
costs of $51 million, Applicants expect the merger to produce $686 million in
net savings over the ten-year period. [App. Ex. CDN-16.] The savings figures
presented by Mr. Nelson, which were the result of a nine-month Implementation
Plan effort by Applicants, are greater than the original net savings estimate of
$549 million presented in the direct testimony of Applicants' witnesses Flaherty
and Rainwater.
With respect to the market power issues, Applicants note that
utilities in Illinois currently have protected retail service territories. Since
this Commission regulates the price, type and quality of service rendered to
retail customers, as well as the area within which retail service is rendered
for each utility under its jurisdiction, Applicants conclude that the merger
cannot now have a significant adverse impact on retail competition.
Concerns relating to market power in retail markets could arise, in
Applicants' view, only from the restructuring of the retail market to permit
competition for load across service areas. Applicants indicate that any such
concerns would be generic in nature and would relate to all utilities,
regardless of whether they have previously undergone a merger or not.
Although it is difficult to predict today what shape the coming retail
market will take, precisely when that market will arrive, or just what specific
problems will arise when that market gets underway, Applicants assert that their
evidence shows that this merger is likely to have no adverse market power
implications in a deregulated retail market. Applicants indicate that when their
proposed merger is subjected to the FERC "screening
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analysis" ordered by the Commission, it is clear that the merger poses no market
power concerns requiring mitigation.
IV. RELIEF REQUESTED
Applicants request that the Commission enter an order granting the
following relief: (1) pursuant to Sections 7-204 and 7-204A of the Act, and to
the extent required, 7-102, authorizing UE, CIPS and CIPSCO to reorganize as set
forth in the Application; (2) pursuant to Section 7-102, authorizing Ameren to
transfer to CIPS UE's Illinois assets (other than electric generation and
transmission assets) and authorizing CIPS to succeed to UE's Illinois public
utility business; (3) pursuant to Sections 7-101, 7-102 and 7-204A, authorizing
CIPS to engage in transactions with affiliated interests as set forth in the
application; (4) finding that the cost allocation principles reflected in the
General Services Agreement are reasonable; (5) finding that CIPS' entry into the
SSA Alternative is prudent and reasonable and consenting thereto; (6) finding
that CIPS' entry into the Joint Dispatch Agreement is prudent and reasonable and
consenting thereto; (7) pursuant to Section 6-103, approving the post-merger
capitalization of CIPS, as set forth in the application; (8) pursuant to Section
8-508, authorizing UE to discontinue providing retail electric and gas service
in the State of Illinois as of the effective date of the Transfer; (9) pursuant
to Section 8-406, generally transferring to CIPS as of the effective date of the
Transfer all certificates of public convenience and necessity issued by the
Commission pursuant to Section 8-406, or any similar provision of predecessor
statutes, to UE; (10) pursuant to Section 7-203, transferring to CIPS all
Illinois franchises, licenses, permits or rights held by UE at the effective
date of the Transfer; (11) finding that, upon UE's discontinuance of retail
electric and gas service in Illinois, UE shall cease to be a public utility as
defined in Section 3-105 of the Act; (12) pursuant to Section 9-201, waiving the
45-day notice requirement for the filing of the initial CIPS tariffs for the
Metro East service territory and authorizing CIPS to file such tariffs not less
than five days prior to the effective date of the merger, the tariffs to be the
effective as of the effective date of the Transfer; (13) finding that
Applicants' proposal for recovery of merger-related costs and sharing of merger
benefits is appropriate; (14) terminating the conditions for transactions among
CIPS and its affiliates imposed in Docket No. 86-0256, effective upon
consummation of the merger; (15) to the extent required by Section 8-508.1,
approving the transfer of funds in the Illinois subaccount of UE's nuclear
decommissioning qualified external trust to the FERC subaccount of that same
trust; and (16) authorizing to the extent necessary Applicants' performance of
such other and further actions or transactions which are not contrary to the Act
or the rules of the Commission, or inconsistent with the Application, as may be
necessary and appropriate to carry out the actions and transactions proposed by
the Application.
V. APPLICABLE LAW
The action of the Commission in this proceeding with respect to the merger
of CIPSCO into Ameren and Union Electric with Arch Merger is governed by Section
7-204 relating to the approval of reorganizations. Under Section 7-204, the
term "reorganization"
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is defined as "any transaction which, regardless of the means by which it is
accomplished, results in a change in the ownership of a majority of the voting
capital stock of an Illinois public utility; or the ownership or control of any
entity which owns or controls a majority of the voting capital stock of a public
utility." This section further provides that the "Commission shall not approve
any proposed reorganization if the Commission finds, after notice and hearing,
that the reorganization will adversely affect the utility's ability to perform
its duties under this Act."
In reviewing the proposed reorganization, the Commission is required by
Section 7-204 to 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 non-utility activities by the utility or its
customers;
(c) costs and facilities are fairly and reasonably allocated between
utility and non-utility activities in such a manner that the Commission
may identify those costs and facilities which are properly included by
the utility for ratemaking purposes;
(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; and
(e) the utility will remain subject to all applicable laws, regulations,
rules, decisions and policies governing the regulation of Illinois
public utilities.
Section 7-204 provides that "in approving any proposed reorganization
pursuant to this Section, the Commission may impose such terms, conditions or
requirements as, in its judgment, are necessary to protect the interests of the
public utility and its customers."
Staff and CUB and IIEC contend that the merger also requires Commission
approval under Section 7-102 of the Act. (Staff initial brief, pp. 8-9, CUB
initial brief, p. 2, IIEC initial brief, p. 28) Section 7-102(d) of the Act
requires Commission approval before a public utility by any means, direct or
indirect, can merge or consolidate its franchises, licenses, permits, plants,
equipment, business or other property with that of any other public utility. The
standard for approval of a merger under Section 7-102 is a finding by the
Commission that the application "should reasonably be granted, and that the
public will be convenienced thereby." Section 7-102 provides that the Commission
may attach such conditions to its approval as it deems proper.
Applicants contend that the merger transaction does not require Commission
approval under Section 7-102. Applicants emphasize that CIPS and UE are not
merging;
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rather, CIPS and UE are reorganizing under a common holding company. They
further note that the Merger Agreement is between CIPSCO and UE. (Initial brief,
p. 19)
The Commission concludes that approval of the merger is required under
Section 7-102(d).. Section 7-102(d) applies to the direct or indirect merger or
consolidation of one public utility's franchises, licenses, plants, equipment,
business or other property with that of another public utility. While CIPS and
UE may not be directly merging per se, Applicants seek approval for CIPSCO to
merge with Ameren and UE to merge with Ameren's subsidiary, Arch Merger, with
Ameren becoming the holding company parent of CIPS and UE. These transactions
indicate an indirect merger of CIPS and UE. In addition, the operation of the
Joint Dispatch Agreement and the General Services Agreement, coupled with the
formation of Ameren Services Company for the purpose of providing services to
Ameren and its subsidiaries, demonstrates a direct or indirect consolidation of
plant and equipment of UE and CIPS. The Joint Dispatch Agreement between CIPS
and UE indicates that its purpose is to provide the contractual basis for
coordinated operation of their combined generating resources and transmission
facilities to achieve economies consistent with the provision of reliable
electric service and an equitable sharing of the benefits and costs of such
coordinated operation between them. (Applicants' Ex. GWM-6 (Rev.), p. 6)
The proposed transfer of UE's Illinois assets to CIPS also requires the
Commission's approval under a number of sections of the Act. Section 7-102
requires the Commission's approval for a number of transactions by and between
public utilities. In particular, Section 7-102 provides that, without Commission
approval:
(b) No public utility may purchase, lease, or in any other manner acquire
control, direct or indirect, over the franchises, licenses, permits,
plants, equipment, business or other property of any other public
utility;
(c) No public utility may assign, transfer, lease, mortgage, sell (by
option or otherwise), or otherwise dispose of or encumber the whole or
any part of its franchises, licenses, permits, plant, equipment,
business, or other property . . . .
Under Section 7-102, the Commission must find that the transfer is reasonable
"and that the public will be convenienced thereby."
Other Sections of the Act are implicated by the proposed transfer, as well.
Applicants' proposed SSA Alternative requires Commission approval under Section
7-101(3) of the Act, which governs transactions with affiliated interests. The
Commission may condition its approval under Section 7-101(3) "in such manner as
it may deem necessary to safeguard the public interest." Section 8-406 of the
Act governs certificates of public convenience and necessity. Section 8-508
prohibits a public utility from abandoning or discontinuing any service without
the approval of the Commission. Section 7-203 of the Act requires the
Commission's approval of the assignment or transfer of any
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<PAGE>
"franchise, license, permit or right to own, operate, manage or control any
public utility." Also, Section 8-508.1 may require approval of the transfer of
the funds in UE's Illinois subaccount to the FERC subaccount. Accordingly, to
effect the Metro East transfer, Applicants require authorization for UE to
discontinue the Metro East operations, and for the transfer of UE's property,
business, certificates and franchises to CIPS.
Also, Section 9-102 requires every public utility to file with the
Commission schedules showing all rates, charges, classifications, rules and
regulations relating to any product, commodity or service provided by the public
utility. As indicated above, as of the effective date of the Transfer, CIPS
propose to adopt essentially the same rates, charges, classifications, rules and
regulations relating to electric and gas service as UE had in effect prior to
the effective date of the Transfer for service provided by CIPS to the customers
in the former UE Illinois service territory. Due to the exigencies of
implementing the merger upon receiving all requisite shareholder and regulatory
approvals, CIPS anticipates filing its tariffs with the Commission on less than
the 45 days notice before effectiveness normally required by Section 9-201.
Accordingly, CIPS requests permission under Section 9-201 to file the Metro East
tariffs less than 45 days before their effective dates.
Other sections of the Act are impacted by Applicants' need to obtain
approval of various actions, transactions and waivers required to consummate the
merger and reorganization. Section 6-103 provides that any reorganization of a
public utility requires approval of the amount of post-reorganization
capitalization by the Commission. Under Section 6-103, the amount of
capitalization shall not exceed the fair value of the property involved.
Applicants' proposed General Services Agreement requires Commission
approval under Section 7-101(3) of the Act, which governs transactions with
affiliated interests. CIPS and UE will jointly dispatch their electric
generating resources pursuant to a Joint Dispatch Agreement. CIPS also requires
the Commission's approval to enter into the Joint Dispatch Agreement pursuant to
Section 7-101(3).
Finally, Section 7-204A requires that the Applicants submit certain
information documenting the nature of the proposed reorganization.
VI. OVERVIEW OF THE POSITIONS OF STAFF, IIEC, CUB AND QST
A. Staff's Position
Staff does not oppose the approval of the basic merger transaction whereby
CIPS and UE become wholly owned subsidiaries of Ameren. (Tr. 381) Staff,
however, objects to Applicants' proposal for direct recovery of the merger
premium, Applicants' request for pre-approval of their proposal that
shareholders and ratepayers share the net forecasted merger-related savings over
a ten year period, and Applicants' proposal to transfer UE's Illinois customers
to CIPS.
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<PAGE>
Staff does not oppose approval of the merger so long as the following six
conditions are imposed: (1) the Applicants' request for direct recovery of the
$232 million merger premium is denied; (2) any decision regarding the ratemaking
treatment of the merger transaction/transition (non-merger premium) costs is
deferred to a future rate proceeding; (3) the Applicants' request for pre-
approval of their proposed sharing plan for the forecasted net merger-related
cost savings is denied; (4) CIPS and UE are required to file an alternative
regulatory plan or a traditional rate case within six months after the date the
merger is closed; (5) CIPS and UE are required to include as part of their
filing the information contained in 83 Ill. Adm. Code 285; and (6) the
Applicants' request to transfer UE's Illinois customers and related facilities
to CIPS is denied. (Staff Ex. 20.00, pp. 2-3)
With respect to market power, Staff performed a screening analysis in
accordance with the Merger Guidelines followed by the FERC. Staff concludes that
the merger will not in any way impede a transition to full retail competition in
Illinois. Staff points out that the merger may increase the benefits of
competition because it will widen the market from which retail users in Illinois
can choose suppliers.
Staff recommends that no market power remedial conditions be imposed upon
the merger. Staff states that mandatory divestiture would not noticeably
increase competitiveness, and that divestiture would be a costly and risky
process with little possible payoff, given CIPS' small part in the regional
power market. Staff also notes that denying recovery of stranded investment
would be of little effect since CIPS has a system with few stranded assets.
B. IIEC's Position
IIEC's recommendations concerning the proposed merger address two principal
areas: (1) the proposed transfer of UE's Illinois customers to CIPS and (2)
Applicants' proposed merger savings plan and related issues. IIEC recommends
that the Commission not allow the transfer of UE customers to CIPS, and that the
Commission find that recovery of merger costs may be permitted in future
proceedings only if Applicants can demonstrate the existence of those costs and
establish that savings resulting from the merger are greater than the merger
costs sought to be recovered. (Initial brief, pp. 1-2)
IIEC indicates that the Commission should not in this proceeding make any
finding concerning the prudence of Applicants' merger premium or transaction
costs and should not prejudge the recovery of the merger premium or transaction
costs. IIEC recommends that the Commission require that Applicants file a rate
case, including an alternative regulatory plan, within six months of the final
order in this docket, if the merger is approved. IIEC concludes that the
Commission should require that Applicants demonstrate in that rate case through
some affirmative means or mechanism that merger-related savings have actually
occurred. (Initial brief, p. 29)
IIEC took no position with respect to market power issues.
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C. CUB's Position
CUB opposes Applicants' proposed treatment of merger-related costs and
savings. CUB asserts that Applicant's treatment places all of the financial
risks on ratepayers. CUB indicates that the merger should be rejected unless the
Commission modifies the treatment of merger-related costs and benefits in the
manner proposed by it.
CUB indicates that the Commission should determine in this proceeding how
merger-related savings should be split between Applicants' shareholders and
ratepayers. CUB concludes that Applicants' shareholders should receive
approximately 20% of the merger-related actual savings, net of merger
transaction costs. (Initial brief, pp. 19-20, reply brief, p. 2) CUB recommends
that Applicants be required to implement a mechanism to track actual merger-
related savings. CUB indicates that its proposed treatment of merger-related
savings and costs should be implemented in a future rate case that Applicants
should be ordered by the Commission to file within six months after the merger
is consummated.
With respect to market power, CUB concludes that the proposed merger would
significantly hinder the development of a competitive retail market in Illinois.
CUB emphasizes that the proposed merger is a merger between two utilities that
are likely to be important competitors with each other during and after the
expected shift to retail competition. CUB indicates that the merger will
eliminate this future competition. CUB further contends that the merger will
strengthen the ability of UE and CIPS to repel future competition from other
firms. In light of these market power concerns, CUB witness Shepherd recommended
that the Commission "not approve the merger until it is clear that there is a
fully competitive retail electricity market for all customers." (CUB Ex. WGS-1,
p. 18) If the Commission does not deny the request for approval of the merger,
CUB recommends that the Commission require immediate divestiture of the
generation of CIPS and UE as a condition of approval. (Initial brief on
reopening, p. 19)
D. QST's Position
QST opposes approval of the merger unless the Commission investigates the
alleged anti-competitive behavior of Applicants described in QST's petition to
intervene and reopen the record. The Commission has denied QST's request to
reopen the record. Therefore, there is no evidentiary basis in support of QST's
allegations.
VII. CONTESTED ISSUES
A. Applicants' Merger Savings Plan and Related Issues
1. Applicants' Position
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<PAGE>
In this proceeding, Applicants have requested the Commission's approval of
a regulatory plan for treatment of the costs associated with, and the savings
produced by, the merger. There are four elements to Applicants' cost recovery
and shared savings plan.
The first two elements are the transaction and transition costs associated
with the merger. The transaction costs total $22 million, and include costs for
legal fees, regulatory costs, investment-banking and financial advisory fees,
accounting fees, printing, postage, proxy solicitation, filing fees and
consulting fees associated with the negotiation of the Merger Agreement and the
obtaining of necessary regulatory approvals. (App. Ex. WAK-1, p. 9) The
transition, or implementation, costs of $51 million are the costs necessary to
effectuate the merger and achieve the merger-related cost savings./3/
Applicants' witness Koertner testified that transition costs include such costs
as employee separation packages, employee relocation, system integration,
telecommunication networking, internal and external communication, employee
retraining and facility consolidation. (App. Ex. WAK-1, p. 9)
The third element of Applicants' proposal is a merger premium. Applicants'
witness Kimmelman testified that the merger premium represents the value over
the stock market valuation prior to announcement of the merger to be received by
CIPSCO stockholders. Mr. Kimmelman testified that the negotiated conversion
ratios for Union Electric and CIPSCO stock produce a premium of 23% to the stock
market valuation of CIPSCO. Applicants indicate that the dollar amount of this
premium is $232 million.
The final element of Applicants' plan is the sharing of the estimated net
savings in the first ten years after the merger. Applicants' witness Rainwater
described the plan in his direct testimony. The plan reflected the merger
premium of $232 million, transaction costs of $22 million, initially estimated
transition costs of $19 million and initially estimated cost savings from the
merger of $590 million during the first ten years after the merger. Mr.
Rainwater testified that the plan allows Ameren's stockholders and ratepayers to
share equally in the net merger savings. He explained that the plan allows
Ameren's stockholders to recover their direct merger investment of $273 million,
consisting of the merger premium, transaction costs and transition costs, over a
ten-year period. The plan amortizes that investment in proportion to expected
savings in each of the ten years to ensure that there are net savings in each
year. The net savings would then be split equally between shareholders and
ratepayers.
Mr. Rainwater explained how the plan would operate on a year-by-year basis.
For example, for the fourth year following the completion of the merger,
Applicants initially estimated that the merger would reduce UE's and CIPS'
combined costs by $52.8 million. That amount is 8.96% of the initial estimated
total savings of $590 million over the ten-year
- ------------------
/3/The original estimate of transition costs presented by Applicant in this
proceeding was $19.1 million. (App. Ex. TJF-1, p.6) The final estimate of $51
million presented by Applicants was developed in Applicants' Final Merger
Implementation Plan. The implementation plan process involved 20 teams and more
than 400 people. The planning effort began in August, 1995 and extended into
April, 1996.
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period. The plan would charge 8.96%, or $24.5 million, of the merger investment
of $273 million as a pro-forma cost of service in that year. Subtracting the
$24.5 million from the $52.5 million results in approximately $28 million of net
savings which would be split equally between stockholders and ratepayers.
Fourteen million would be charged as a pro-forma adjustment to UE's and CIPS'
cost of service and $14 million would be available to benefit customers. (App.
Ex. GLR-1, p. 15)
As explained by Mr. Rainwater, Applicants initially proposed to share 50%
of the originally estimated net savings with ratepayers, or approximately $158
million. (App. Ex. GLR-6) Applicants' Final Merger Implementation Plan
identified an additional $169 million of savings and an additional $32 million
of transition costs, resulting in an additional $137 million of net savings.
(App. Ex. CDN-16) Applicants' witness Craig D. Nelson testified that all of
these additionally identified net savings will be available to the ratepayers of
UE and CIPS. Accordingly, Applicants indicate that under their proposed
regulatory plan, the net savings available to ratepayers during the first ten
years following the merger will be $296 million, out of a total of $454 million
of total net savings, or approximately 65%, as shown on App. Ex. CDN-17.
Applicants witness Rainwater testified that merger savings would be shared
between CIPS and UE in proportion to the size of their respective electric and
natural gas businesses. He indicated that approximately 70% of electric savings
will flow to UE and 30% will flow to CIPS, while 30% of gas savings will flow to
UE and 70% will flow to CIPS. (App. Ex. GLR-1, p. 11)
Applicants contend that their proposed plan for sharing of net merger
savings is fair and reasonable. They assert that it is appropriate to allow them
to recover the transition and transaction costs since these costs are out-of-
pocket expenditures that are necessary to bring about the merger and the
associated savings.
Applicants indicate that recovery of the merger premium is reasonable and
appropriate. Applicants witness Kimmelman testified that without the merger
premium, the CIPSCO shareholders would not be induced to enter into the merger
and the merger-related cost savings would not be achieved. (App. Ex. WAK-1, p.
4) Applicants emphasize that they would not propose the merger if the merger
could not achieve sufficient cost savings to offset the merger premium.
Therefore, Applicants conclude that ratepayers have an interest in seeing that a
fair merger premium is negotiated.
Applicants witness Birdsong testified that each utility merger which has
been announced or completed in the last two years that involved two parties of
the same size differential as UE and CIPS had a merger premium. He indicated
that a merger can be attempted without a merger premium only if the parties have
the same approximate size. He noted that under the merger, CIPSCO shareholders
will no longer control 100% of their company and will become minority
shareholders of Ameren. He concluded that they must be given some financial
incentive for doing so. (App. Ex. JEB-3, p. 3)
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Mr. Birdsong indicated that the merger premium resulted from arms length
negotiations between UE and CIPSCO. He stated that UE had the incentive to make
the merger premium as low as possible, while CIPSCO had the incentive to make
the premium as large as possible. He noted that UE received advise from Goldman
Sachs and CIPSCO received advise from Morgan Stanley, who are two of the most
knowledgeable and respected Wall Street firms working in the utility industry.
Applicants indicated that the merger premium of 23% received by CIPSCO
shareholders is at the low end of premiums paid in comparable utility
transactions. Mr. Kimmelman testified that the merger premiums ranged from 21%
to 65% for mergers since 1989 in the electric utility sector between two
companies of significantly different size. (App. Ex. DWK-1, pp. 4-5)
Mr. Kimmelman testified that a failure to provide for recovery of merger
costs and the merger premium and a sharing of the merger savings between
shareholders and ratepayers would result in dilution of the value of the shares
of Ameren's stockholders. He indicated that there could then be an increase in
the cost of capital for the combining entities, as well as difficulty in
attracting capital for future investment projects. He stated that such future
investment projects would make cost savings possible. (App. Ex. DWK-1, p. 6)
Applicants assert that it would be unfair to deny shareholders a share of
the net savings produced by the merger. They conclude that the 65%/35% split of
net savings between ratepayers and shareholders in their plan is more than fair
to ratepayers and should be approved. They indicate that the merger will
continue to produce savings benefiting ratepayers beyond the tenth year.
Applicants propose that the Commission approve its proposed plan in this
docket for implementation in a future rate proceeding. As noted earlier in this
order, Applicants' witness Mill indicated that CIPS has committed to file a rate
case, in all likelihood an alternative regulatory proceeding under Section 9-244
of the Act, within one year of the closing of the merger. (App. Ex. RJM-7, p.2)
Applicants contend that it is reasonable to provide shareholders with assurance
of fair treatment of merger costs and savings prior to consummation of the
merger.
While Applicants recommend approval of their plan, they are not insisting
that any particular form of sharing plan be approved. They indicate that they
are willing to consider any plan that affords them the opportunity to recover an
amount equal to their investment in the merger and a reasonable portion of the
savings. Applicants conclude that the Commission should, at the very least,
endorse in this proceeding the following principles of their sharing plan: (1)
the merger premium and transaction and transition costs are prudent and
reasonable; (2) it is reasonable and appropriate for Applicants to recover the
merger premium and transaction and transition costs; and (3) it is reasonable
and appropriate for Applicants to share in the net merger savings.
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2. Positions of Staff, IIEC and CUB
a. Approval of a Sharing Plan in this Proceeding
Staff contends that it is premature to approve any plan for the sharing of
merger benefits in this proceeding. Staff indicates that the ratemaking
treatment of merger savings should not be determined in isolation outside the
context of a general rate proceeding. Staff emphasizes that this proceeding is
not a rate case, but rather has the purpose of determining whether the merger
should be approved. Staff notes that elements of ratemaking such as rate base
items and operating expenses were not included in Applicants' filing in this
proceeding. Staff concludes that the ratemaking treatment of any merger-related
savings should be determined in the rate case or alternative regulatory plan
proceeding that is filed by CIPS. (Initial brief, pp. 18-19)
IIEC agrees with Staff's position. IIEC concludes that the Commission
cannot preapprove the recovery of any cost or expense outside the context of a
rate case, without the benefit of a test year, citing Business and Professional
People for the Public Interest v. Illinois Commerce Commission, 146 Ill. 2d 175,
585 N.E. 2d 1032 (1991) and A. Finkl and Sons Company v. Illinois Commerce
Commission, 250 Ill. App. 3d 317, 620 N.E. 2d 1141 (1st Dist. 1993). (Initial
brief, p. 15)
IIEC provides an additional reason for supporting Staff's position. IIEC
notes that CIPS has indicated that it will file an alternative regulatory plan
pursuant to Section 9-244 of the Act within one year after the close of the
merger. IIEC points out that Section 9-244 only allows the Commission to
authorize an alternative regulatory plan through June 30, 2000. IIEC indicates
that Applicants have failed to explain how ratepayers will recover merger
savings after the year 2000 in the event there is no legislation that would
allow the continuation of an alternative regulatory plan beyond that year.
(Initial brief, p. 15)
In response to Staff and IIEC, Applicants indicate that their savings plan
can be adopted in this proceeding since they are not requesting approval of
specific rates. (Reply brief, p. 13)
CUB contends that the Commission should approve a plan in this docket for
the sharing of merger benefits between shareholders and ratepayers. CUB states
that in order to decide whether the merger is likely to benefit ratepayers, the
manner in which savings are to be shared must first be determined.
CUB indicates that Applicants' plan inappropriately places all of the
financial risk on ratepayers. CUB states that Applicants' plan guarantees that
the shareholders will recover all of the merger costs and receive one-half of
the projected savings, whether the savings are actually realized or not. CUB
indicates that Applicants' plan does not guarantee any savings to ratepayers.
CUB recommends that a tracking mechanism be approved to determine actual savings
from the merger. The parties' positions on a tracking mechanism are summarized
hereafter in Section VII.A.2.d beginning on page 26.
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CUB indicates that if the tracking mechanism establishes the existence of
substantial actual net savings from the merger, Applicants' shareholders should
then be entitled to a portion of the net savings. CUB states that an allocation
of net savings described in the testimony of its witness Rosen should be
adopted. (Initial brief, p. 19) Mr. Rosen testified as follows (CUB Ex. 1, p.
25):
One useful guideline to use here would be to use the fraction of the
utility's revenue requirements that represents the return on equity. If a
merger causes the revenue requirements to fall by a certain percent
(through merger savings net of merger transaction costs), then it might be
reasonable to increase the amount of money going to the return on equity by
the same fraction. For CIPS, this fraction is about twenty percent (20%),
which means that $5 of merger savings, net of merger transaction costs,
actually used to reduce rates could be rewarded with $1 of extra profits to
shareholders.
CUB concludes that shareholders should receive approximately 20% of actual net
savings.
In response, Applicants take issue with CUB's contention that Applicants
are seeking a guarantee of recovery of merger-related costs and a share of
merger savings through rates. To the contrary, Applicants state that they seek a
fair and reasonable opportunity to recover their prudent and reasonable costs
and to share in the savings produced by the merger. (Reply brief, p. 12)
b. The Merger Premium
Staff indicates that Applicants are requesting that the merger premium
negotiated between UE and CIPS be recovered directly from ratepayers. Staff
opposes direct recovery of the merger premium for several reasons. First, the
direct recovery of the merger premium is part of Applicants' proposal under
which ratepayers bear the risk that estimated merger savings may not be
achieved. Staff indicates that ratepayers would realize savings from the merger
under Applicants' plan only if the cost of service after the merger, which would
include the merger premium, transaction and transition costs and a percentage of
estimated net merger savings, is lower than the cost of service in the absence
of the merger. Staff concludes that investors should bear risk associated with
merger savings.
Second, the level of actual merger-related cost savings is not affected by
the merger premium. Third, ratepayers did not participate in the negotiations
between CIPS and UE which resulted in the merger premium. Fourth, direct
recovery of the merger premium eliminates the incentive to minimize the
negotiated premium.
Fifth, direct recovery of the merger premium is not necessary to enable
CIPSCO shareholders to receive the $232 million premium that they negotiated
with UE. An
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analysis performed by Goldman Sachs on behalf of UE indicated that the merger
would increase earnings per share with a retention of a portion of merger
savings and no direct merger premium recovery. (Staff Ex. 13, p. 6)
Sixth, the merger premium is not a cost of the Applicants' utility
operations, but rather results from a transaction between stockholders. Staff
witness Smith noted that the Commission's Uniform System of Accounts does not
contain a provision for the recording of a merger premium.
In response, Applicants indicate that if they are not provided with the
opportunity to recover the merger premium in rates, the value of each share of
Ameren stock will be diluted. Applicants emphasize that without the merger
premium, there would be no merger, and, therefore, no merger-related savings and
efficiencies. Applicants also note that their plan provides for the recovery of
the merger premium over a ten-year period. Applicants indicate that spreading
the recovery over ten years results in shareholders receiving only approximately
50% of the merger premium after the time value of money and taxes are
considered. Applicants also indicate that costs which are not recorded on a
utility's books are allowed to be reflected in rates, citing the cost of equity
as an example.
In reply, Staff indicates that only UE stockholders will suffer dilution of
their investment if the merger premium is not recovered from ratepayers. Staff
witness Pregozen testified that CIPSCO common shareholders will receive the
merger premium directly from UE common shareholders when the merger is
consummated through the exchange of their stock for Ameren stock. (Staff Exs. 2,
p. 6. and 13, p. 5)
Both Staff and CUB criticize Applicants' witness Kimmelman's analysis which
concluded that the merger premium of 23% received by CIPSCO stockholders is at
the low end of premiums paid in comparable utility transactions. Mr. Kimmelman
included six electric utility mergers in his comparison group that had premiums
ranging from 21% to 65%. Staff indicates that Mr. Kimmelman should have include
other electric utility mergers in his comparison group. Staff further states
that the record does not establish that the facts surrounding the mergers in his
comparable group are similar to those applicable to the merger proposed in this
docket. Staff notes that two of the mergers in his comparable group involved
multiple bidders or unsolicited takeover proposals. Moreover, Staff notes that
the evidence does not indicate the level of savings expected from the mergers in
the comparable group.
CUB indicates that Mr. Kimmelman did not explain whether the regulatory
commissions approved the recovery of the merger premiums in the six mergers
included in his comparison group. CUB notes that the Texas Commission denied
recovery of the merger premium in one of those mergers and that the Kansas and
Utah Commissions tied recovery of the merger premiums in two of those mergers to
merger savings to be realized by ratepayers. (Initial brief, pp. 8-9)
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CUB opposes recovery of any merger premium, contending that the premium
contributes to strandable costs. CUB further asserts that the amount of the
merger premium is too high. If recovery of the premium is allowed, CUB is
concerned that ratepayers could receive no benefits from the merger if merger-
related savings are lower than Applicants' estimate. (Initial brief, p. 11-12)
CUB contends that rather than relying on the Applicants' merger premium,
the Commission should "put the purchase price to a market test." CUB witness
Rosen testified that a market test is necessary in light of the emergence of
increasing competition in the electric utility industry. CUB indicates that the
market test should be limited to the price paid for the electric generation
assets, which are the assets that will be exposed to competition. Mr. Rosen
explained the market test as follows (CUB Ex. 1, p. 19):
A market test for the electric generation assets would require subtracting
the depreciated book value of the non-generation assets of the utility from
the total purchase price to be paid for the utility. (This total price to
be paid for the utility would, of course, include the merger premium) The
remaining price would equal the implicit price to be paid for the acquired
utility's generating assets. In performing a "market test" this price
would be compared to the market value of the generating assets; and if the
costs to be paid for the generating assets were higher than the market
value, then some uneconomic (and potentially strandable) generation costs
would exist, and would have been caused by the merger. In other words, the
uneconomic costs of the merged company's generating assets would equal the
amount by which the cost to be paid for the generating assets exceeded the
market value of those assets.
In response, Applicants indicate that CUB's market test should be rejected.
Applicants do not concede that the merger premium relates only to generating
assets. Assuming that the premium applies only to the generating assets, they
state that the best test of the market value of the generating assets is the
price paid by UE, which resulted from arm's length bargaining. They indicate
that if the market value is something less than this amount, then the merger
premium must relate to something other than the generating assets. (Reply brief,
p. 24)
Applicants also emphasize that the risk that savings from the merger will
not exceed its costs is minimal to non-existent. Applicants indicate that total
savings from the merger are estimated to be $759 million over the first ten
years alone, while total costs, including the merger premium, are expected to be
$327 million.
c. Applicants' Estimates of Savings
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Staff, IIEC and CUB are critical of the Applicants' use of estimated
savings in their plan. Staff indicates that there is no guarantee that the
forecasted savings will be achieved. Staff witness Goldberger testified that
Applicants' estimate of savings utilized numerous assumptions that reflected
subjective judgments. She indicated that it is possible to develop somewhat
different but equally plausible assumptions from the same information. (Staff
Ex. 18.00, p. 5)
In response, Applicants' witness Craig D. Nelson testified that the
judgments reflected in their savings estimates were made by highly qualified
personnel, based on the best objective data available. He emphasized that the
supervisors, managers and officers actually responsible for the functioning of
UE and CIPS on a day-to-day basis, who participate in the normal budgeting
process, estimated the merger savings in their respective functional areas. He
indicated that they are the persons most qualified to develop the plans to
integrate the operations of UE and CIPS and make the judgments upon which the
assumptions used in developing the merger savings are based. Mr. Nelson
concluded that there is no reason to believe that any other party to this case
could have developed "somewhat different but equally plausible assumptions"
without devoting the same resources as UE and CIPS and without the knowledge
that UE and CIPS have of their costs and business processes. (App. Ex. CDN-32,
pp. 2-3)
IIEC witness Brubaker also expressed doubts concerning the Applicants'
estimate of merger-related savings. Mr. Brubaker indicated that in many areas,
workpapers and other documentation that he reviewed did not support the
estimated savings. For example, he indicated that there are no workpapers
detailing the specific analyses that support the estimated reduction in
employees attributable to the merger. (IIEC Ex. 1.0. p. 17-18) Other areas with
lack of support for savings estimates noted by Mr. Brubaker include professional
services, contract services, and procurement and inventory.
In response, Applicants' witness Flaherty testified that the estimates of
merger cost savings in the areas questioned by Mr. Brubaker were based on
substantial, detailed financial and operating data from UE and CIPS and sound
business assumptions. He indicated that the detailed workpapers and related
testimony of Applicants fully support the estimated savings. (App. Ex. TJF-4,
pp. 2-13)
Mr. Brubaker further indicated that the reports of the merger transition
teams provide very little detail in most instances in support of the
quantification of non-labor savings. He stated that in some cases, savings
estimates amounting to tens of millions of dollars were simply stated as a final
number without any backup workpapers. (IIEC Ex. 3, pp. 4-5)
In response, Applicants' witness Craig D. Nelson testified that there are
numerous detailed workpapers supporting the items in question. He indicated
that for the items in question, Mr. Brubaker only reviewed reports that are
summaries of information developed by transition teams. He stated that these
reports do not include the volumes of workpapers and analyses developed by the
teams. (App. Ex. CDN-32, p. 5)
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IIEC indicates that the reports of the merger transition teams reveal that
a number of hurdles must be overcome in order to realize the merger savings.
IIEC notes that these hurdles include, among others, (1) the implementation of
UE's system and management reporting philosophies throughout the merged company;
(2) training of CIPS' employees on systems, processes and management reporting
philosophies of UE; (3) converting ledger and other systems for use in a merged
environment; (4) general modifications of systems and creation of new programs;
(5) developing single system thinking, standards and policies; (6) resolving
conflicting resolutions made by other teams; (7) addressing changes in personnel
reporting relationships; (8) resolving locational issues; (9) standardization of
material specifications; and (10) bargaining unit issues related to the transfer
of and allocation of work between union and non-union job categories in the UE
structure. (IIEC Ex. 3.0 Supp., pp. 3-4) IIEC emphasizes that these objectives
are not foregone conclusions.
In response, Applicants indicate that they have already begun to implement
the merger transition to the extent practicable.
CUB challenges Applicants' estimate of $101 million of electric production
savings attributable to the merger. CUB witness Rosen testified that these
savings could be obtained without the merger through tighter power pooling,
better coordinated central dispatching through the Illinois-Missouri Power Pool,
and other means of power coordination with other electric utilities in the
region. (CUB Ex. 1, p. 62-63)
In response, Applicants' witness Moorman testified that there are
significant obstacles to joint dispatch by unaffiliated entities. First,
coordinated operations such as joint dispatch may result in an uneven
distribution of benefits and costs among participants, requiring reapportionment
to treat each equitably. Second, unaffiliated entities who are jointly
dispatching may be required by the Federal Energy Regulatory Commission ("FERC")
to permit additional entities to participate. Third, there is a possibility of
legal challenges to unaffiliated joint dispatch under the antitrust laws. (App.
Ex. GWM-7, pp. 2-3)
d. Tracking of Actual Savings
IIEC and CUB recommend that the Commission require that Applicants
implement a mechanism to track actual cost savings related to the merger. IIEC
witness Brubaker testified that the Commission should conclude that it will
permit recovery of merger costs in future proceedings only if Applicants
demonstrate the existence of those costs and establish that the actual savings
resulting from the merger exceed the merger costs for which recovery is sought.
(IIEC Ex. 1, pp. 3-4) Similarly, CUB witness Rosen testified that a tracking
mechanism would help ensure that the relationship between the amount of the
merger premium to be recovered from ratepayers and the net merger savings is
reasonable. (CUB Ex. 1, pp. 29-30) CUB asserts that a tracking mechanism will
result in a far more accurate indication of actual savings than reliance on
Applicants' estimates of savings. (Initial brief, p. 17)
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Mr. Brubaker acknowledged that a precise tracking of all actual savings
would not be possible. He concluded, however, that Applicants owe it to their
ratepayers to convincingly establish that actual savings have occurred. IIEC
notes that Applicants have estimated that there will be labor savings of $267
million during the first ten years after the merger. IIEC asserts that
Applicants witnesses Flaherty and Reid have acknowledged that reductions in the
number of employees can be tracked. (Tr. 444 and 830) IIEC further notes that
Mr. Flaherty acknowledged that the Kansas Commission adopted an index for use in
tracking operation and maintenance expense savings associated with the merger of
Kansas Power and Light Company and Kansas Gas and Electric Company. (Tr. 442-
443)
CUB also concedes that some actual merger savings are more easily
quantifiable than others. CUB concludes that Applicants should be required to
implement the best possible method for tracking savings. CUB recommends that
Applicants be required to adopt a tracking system for merger-related non-fuel
savings that is similar to that approved by the Texas Public Utility Commission
in the Entergy Corporation-Gulf States Utility Company merger. Mr. Rosen
described the tracking system in the following manner (CUB Ex. 1, pp. 57-58):
Specifically, the mechanism should compute (1) the level of non-fuel costs
that would have been incurred by UE and CIPS had there been no merger and
(2) the level of non-fuel costs that were actually incurred by the merged
company. The difference between these two cost components would have the
rebuttable presumption of being merger-related non-fuel savings. The
tracking mechanism should establish a baseline for determining whether
merger-generated non-fuel savings have been achieved, and should escalate
that baseline by predetermined escalators to create scenario (1) above.
The baseline should be based on UE's and CIPS' calendar year 1995
normalized actual non-fuel expenses, adjusted for non-recurring costs
related to isolated events. Various appropriate escalators should be
applied to the baseline to account for various changes such as inflation
and non-fuel expense savings that UE and CIPS could have achieved on a
stand-alone basis. In the Entergy-GSU merger case, the baseline was
divided into two components: (1) non-fuel generation costs and (2) all
other non-fuel costs. The two components were to be escalated separately
using different escalation factors.
In response, Applicants assert that the tracking of savings proposed by
IIEC and CUB is not possible. Applicants' witness Rainwater stated that the
term "tracking" incorrectly implies that it would be a simple matter to keep
precise records of merger savings. He emphasized that merger savings are costs
which would be incurred absent a merger, but would not be incurred following a
merger. He indicated that because these
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costs will not be realized, they will not be recorded, and cannot simply be
"tracked." (App. Ex. GLW-11, p. 7)
Mr. Rainwater testified, however, that while merger savings cannot be
tracked, they can be estimated. He indicated that Applicants' original merger
savings estimate required hundreds of man-hours of effort from UE, CIPS, and
consultant Deloitte & Touche. He indicated that the more detailed savings
estimate developed in the merger implementation planning process required
thousands of man-hours. He concluded that the same effort would likely be
required to annually re-estimate savings, but would not necessarily be any more
accurate or conclusive than the original estimate. (App. Ex. GLW-11, p. 8)
Applicants assert that their approach for ensuring achievement of savings
is better than the tracking proposed by IIEC and CUB. Applicants' witness Craig
D. Nelson testified that Applicants' Implementation Plan identifies milestones
for completion of tasks needed to achieve the overall goals. He indicated that
Ameren will closely monitor progress against these milestones. Mr. Nelson
testified that Ameren also plans to use the budgeting process to assure that
savings are actually achieved.
Applicants' witness Rainwater explained that the effort necessary to
estimate just one small part of treasury operation savings is a good example of
why "tracking" is not appropriate. Currently, both Union Electric and CIPSCO
produce annual reports to stockholders. Applicants know with certainty exactly
how much this activity cost both Union Electric and CIPSCO in 1994. Applicants
also know with certainty that only one annual report will be produced by Ameren,
rather than one by Union Electric plus one by CIPSCO. Therefore, Applicants know
with certainty that savings will exist, and can make a knowledgeable estimate of
these savings. Mr. Rainwater testified that if a tracking mechanism were
mandated, Applicants would have to continually re-estimate the cost of producing
two separate annual reports. He indicated that the tracking mechanism would be
no more conclusive than the current savings estimate since it would still
involve a comparison of actual costs to estimated costs. He concluded that the
tracking mechanism would only result in greater expense and less productivity.
(App. Ex. GLW-11, pp. 8-9)
e. Timing of Rate Case Filing
CIPS has committed to file a rate case for its present service territory,
in all likelihood an alternative regulation plan under Section 9-244 of the Act,
no later than 12 months after the closing of the merger. In Section VII.B
hereafter of this order, Applicants' request for approval of the transfer of
UE's Illinois service area and certain related facilities to CIPS is denied. As
a result of that denial, UE will remain a public utility under the Commission's
jurisdiction. UE has not made a commitment to file a rate case. (Tr. 190-191)
Staff recommends that the Commission require as a condition of the merger
that both CIPS and UE file a rate case or an alternative regulatory plan within
six months of the closing of the merger. (Staff Ex. 20.00, p. 2) Staff witness
Bishop testified that this
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condition is necessary to ensure that merger-related savings are passed on to
ratepayers in a timely fashion.
IIEC supports Staff's recommended condition. IIEC witness Brubaker
testified that the Commission should require that CIPS and UE file a rate case
to establish pre-merger rate levels on a cost of service basis. IIEC notes that
UE last filed a rate case in Illinois over a decade ago and that CIPS has not
filed a rate case in the last several years. Mr. Brubaker testified that the
base for the measurement of merger savings should be the pre-merger rates
established on a traditional revenue requirements basis, using normal Commission
ratemaking practices. He indicated that the test year should be the most recent
test year that is appropriate for a full rate case. He indicated that the base
should be adjusted to eliminate any costs or cost savings attributable to the
merger. (IIEC Ex. 1, p. 21)
In response to Staff's proposed condition, Applicants witness Mill
testified that CIPS' proposed timetable of one year for the filing of a rate
case is more reasonable than Staff's in light of the substantial effort that
will be required of Applicants to effectuate the merger. He indicated that
Applicants must put their transitions plans into effect immediately upon closing
of the merger. He stated that most of the employees will be involved in that
effort, including those responsible for developing the rate filing. He concluded
that it would be difficult for CIPS to also prepare and file a rate case within
the first six months after the merger. He noted that the Commission did not
impose such a condition in the MidAmerican Energy Company merger proceeding.
(App. Ex. RJM-7, pp. 2-3)
In their briefs on exceptions, Staff, IIEC and CUB cite the schedule in the
merger proceeding before FERC. Staff and IIEC note that the schedule calls for a
decision by the administrative law judge by April 30, 1997. CUB indicates that
final briefs on exceptions in the FERC proceeding are due on May 30, 1997. Since
all regulatory approvals required for the merger cannot possibly be obtained
until mid-1997 at the earliest, Staff, IIEC and CUB emphasize that Staff's
deadline for the filing of a rate case or alternative regulatory plan should be
adopted to ensure that ratepayers benefit from the merger in as timely a manner
as possible. IIEC and CUB state that the lag between the receipt of merger
benefits by Applicants and ratepayers should be minimized.
In response, Applicants state that a delay in the effective date of the
merger will not reduce the time frame required to assemble and file a rate case.
They further note that full implementation of the merger cannot occur until
after the closing of the merger. They state that the evidence indicates that
only some initial level of labor savings will be experienced prior to the
consummation of the merger. Applicants conclude that the six month time frame
proposed by Staff is unrealistic. (Reply to exceptions, pp. 3-4)
IIEC contends that Mr. Mill has not presented any compelling reason for
rejecting Staff's condition. IIEC indicates that Applicants have already taken
steps to implement the merger. IIEC notes that Applicants' witness Craig D.
Nelson submitted an exhibit which details key merger implementation milestones.
(App. Ex. CDN-30) IIEC asserts that this
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exhibit shows that many of the milestones have already been met. IIEC also
asserted that Applicants' witness Reid acknowledged that some labor savings
associated with the merger have already been realized. (Tr. 831)
f. Part 285 Requirements
Staff also recommends, as a condition of approval of the merger, that UE
and CIPS be required to include in their rate case or alternative regulatory
plan filing the information specified in 83 Ill. Adm. Code 285, which sets forth
the standard filing requirements for an increase in rates. Staff witness Bishop
testified that it is not Staff's intent to generically require that such
information be provided as part of all alternative regulatory plans. He
indicated that this information is necessary in the instant situation in light
of the changes that are occurring as a result of the merger (Tr. 885-886) Staff
concludes that the information required by Part 285 is needed to determine that
rates established as part of an alternative regulatory plan are just and
reasonable, and to establish a cost of service that can be used as a baseline to
measure cost savings.
Applicants contend that Staff's proposal is neither necessary nor
appropriate under the law. Applicants indicated that Part 285 requirements are
wide-ranging and burdensome, requiring the production of voluminous information
covering a broad spectrum of areas for a number of historical, and, in some
cases, future periods. Mr. Mill further noted that Part 285 only applies when
the proposed change in base rates produces an increase in annual jurisdictional
revenues of 1% or more. Applicants contend that the Commission may not single
them out and apply Part 285 to them differently from how that rule is applied to
other utilities. See Business and Professional People in the Public Interest v.
Commerce Comm'n., 136 Ill.2d 192, 225-227 (1990) (Commission may alter rules,
but only pursuant to rulemaking procedures). Applicants conclude that if the
Commission is of the opinion that the Part 285 filing requirements need updating
in light of the changing regulatory environment and the prospect of alternative
regulation filings, such revisions should be the subject of a generic proceeding
involving all interested parties in the State of Illinois and should not be
limited to Applicants in this docket.
Applicants also committed that CIPS would meet with Staff prior to the time
of its rate filing to discuss the scope of supporting information that will be
provided. Applicants indicated that they are confident that the scope of the
information could be resolved through such discussions.
In reply, Staff agrees with Applicants that Part 285 does not apply to
alternative regulatory filings or to traditional rate cases involving an
increase in jurisdictional revenues of less than 1%. Staff, however, emphasizes
that Section 7-204 of the Act provides that the Commission may impose such
terms, conditions or requirements as, in its judgment, are necessary to protect
the interests of the public utility and its customers. Staff asserts that its
proposed condition meets this standard. (Reply brief, p. 6)
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IIEC indicates that most of Applicants' criticisms of Staff's condition
would go by the wayside if Staff had merely listed the information that is
required by Part 285 and made no specific reference to Part 285. IIEC concludes
that Applicants' assertions of misapplication of Part 285 and different
treatment than that afforded to other utilities are red herrings. (Reply brief,
p. 7)
3. Commission's Conclusion
The Commission concludes that Applicants' proposed merger cost recovery and
savings sharing plan, including their request for direct recovery of the merger
premium, should not be approved in this proceeding. The Commission agrees with
the position of Staff and IIEC that the ratemaking treatment of these merger-
related costs and savings should not be determined outside the context of a
general rate proceeding in which all elements of the utility's cost of service
are examined. The ratemaking treatment of merger costs (including the merger
premium) and savings to be adopted in a future rate case or alternative
regulatory plan proceeding should be fair to both stockholders and ratepayers.
The appropriate distribution of net merger savings between shareholders and
ratepayers will be determined in that future case.
CIPS committed to file a rate case or alternative regulatory plan within
one year after the close of the merger. UE has made no similar commitment. The
Commission agrees with Staff that both CIPS and UE should be required to file a
rate case or alternative regulatory plan to ensure that an appropriate share of
merger-related savings are passed on to ratepayers in a timely manner. The
Commission also accepts Staff's recommendation that the rate cases or
alternative plans be filed within six months of the closing of the merger. The
one-year time frame proposed by CIPS would result in an unreasonable delay in
the ratepayers' receipt of an appropriate share of merger-related savings.
The Commission notes that the Illinois Legislature is considering
legislation which addresses the deregulation of the electric industry. If
legislation becomes effective that would arguably affect the Commission's
authority to require that UE and CIPS file a rate case or alternative regulatory
plan within 12 months after the consummation of the merger, UE and CIPS should
file a petition with the Commission requesting that this requirement be modified
or eliminated, as appropriate. Upon receipt of the petition, the Commission will
take appropriate steps to reach a determination on this issue.
The Commission accepts Staff's recommendation that CIPS and UE be ordered
to provide the information required by Part 285 as part of their rate case or
alternative regulatory plan filing. Although Part 285 provides that its filing
requirements have to be met when the utility proposes an increase in base rates
of 1% or more, the Commission is in no way barred from using or requiring the
submission of the information outlined in Part 285 as a part of its review of an
alternative regulatory plan or a rate case involving a proposed rate increase of
less than 1% or a proposed rate decrease.
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95-0551
IIEC and CUB each recommend that UE and CIPS be required to track actual
savings associated with the merger. IIEC concedes that a precise tracking of all
actual savings is not possible, but indicates that labor savings can be tracked.
CUB concedes that some actual merger savings are more easily quantifiable than
others. Applicants' witness Rainwater contended that actual savings cannot be
tracked. He also emphasized that thousands of man-hours were expended in the
merger implementation process that developed Applicants' final estimate of net
merger savings and that this estimate is an accurate indication of savings. The
Commission believes that UE and CIPS should present in the required rate case or
alternative regulatory plan as much evidence of actual merger savings as
possible. By the time that the rate case or alternative regulatory plan is
filed, Applicants will have actual operating experience under the reorganization
approved in this order. The Commission cannot accept Applicants' assertion that
no amount of merger-related savings can be tracked. The Commission agrees with
IIEC that in an area such as labor savings, some tracking of actual savings is
possible. By the time that the rate case or alternative regulatory plan is
filed, UE and CIPS would know, for example, the reduction in the number of their
employees that has already occurred.
B. Transfer of UE's Illinois Distribution Assets and Service Territory
to CIPS
1. Applicants' Position
Subsequent to the merger, Ameren plans to transfer the Metro East electric
and gas operations and distribution properties to CIPS. Applicants indicate that
the purpose of the transfer of Metro East is two-fold: (1) to achieve savings of
approximately $2.1 million annually; and (2) to achieve administrative and
regulatory convenience by having just one regulated entity in each state.
Applicants also intend to transfer the accumulated deferred income taxes
("ADIT") associated with the transferred property. Staff and Applicants agree
that if the ADIT cannot be transferred with the property without violating the
normalization rules of the Internal Revenue Code, the transfer should not occur.
Accordingly, Applicants have requested the issuance of a private letter ruling
("PLR") by the Internal Revenue Service ("IRS") related to the ADIT associated
with the distribution assets to be transferred by UE to CIPS. The Applicants and
Staff agree that, irrespective of other objections to the transfer, the
distribution assets should not be transferred until a favorable PLR is issued by
the IRS.
Applicants indicate that with the transfer of the Metro East assets and
operations to CIPS, UE would cease to operate as a public utility in Illinois,
and would become a "Missouri only" company, subject only to the jurisdiction of
the Missouri Commission and FERC. CIPS would become a somewhat larger "Illinois
only" company than it is today, subject only to the jurisdiction of this
Commission and FERC.
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This organization of the operating companies along state lines would
eliminate or greatly reduce the potential for conflicting regulatory
requirements, according to Applicants' witness Rainwater. Mr. Rainwater stated
in his rebuttal testimony that such conflicts are already evidenced in such
areas as Commission-mandated resource planning. On cross-examination, however,
Mr. Rainwater testified that in UE's least cost plans filed to date in Missouri
and Illinois, no real problems have resulted as a consequence of multi-state
jurisdiction. (Tr. 171) He indicated that there is a possibility of future
interjurisdictional conflicts in areas such as retail access or competitive
bidding requirements. (Tr. 171)
The savings produced by the transfer would be substantial, according to
Applicants. Craig D. Nelson testified that the avoided Illinois invested capital
tax would be $1.9 million annually. The Illinois invested capital tax is
imposed on the invested capital of public utilities selling electricity or gas
at retail in Illinois. See 35 ILCS 615/2a.1, 620/2a. Mr. Nelson indicated that
UE's invested capital tax liability in 1995 was approximately $2,320,000. He
stated that as a result of the transfer, UE's invested capital tax liability
would be eliminated completely, while CIPS' would increase by just $440,000
annually, for a net annual savings of approximately $1.9 million. In addition,
the transfer would produce approximately $200,000 annually in other savings,
principally avoided regulatory expenses, according to Mr. Rainwater.
Accordingly, Applicants conclude that the net savings produced by the transfer
would be approximately $2.1 million annually.
CIPS and UE initially proposed to enter into a System Support Agreement
(the "SSA") in connection with the transfer of the Metro East operations and
distribution properties to CIPS. UE currently provides approximately 500 MW of
firm power and 70 MW of interruptible power to its Illinois electric customers.
(App. Ex. GLR-1, p. 8) Applicants' witness Mill explained that the SSA preserves
the recovery of costs for UE's generation and transmission system that will
continue to serve the Metro East area after the merger. The SSA has a term of
30 years. Mr. Mill indicated that under the SSA, CIPS agreed to a long-term
assignment of capacity and energy from UE's generation which is equivalent to
the generation currently committed to serving UE's Illinois customers. The SSA
provides that the contract capacity and energy may be adjusted downward if CIPS
experiences the loss of a significant customer load in the transferred area and
other load in that area has not increased sufficiently to cover that load
reduction. Mr. Mill noted that CIPS will be responsible for providing resources
for load and energy in excess of those provided by the SSA, which are based on
current load levels.
In their rebuttal testimony, Applicants agreed to amend the SSA to provide
for two contract periods totalling ten years: a five-year fixed period followed
by a five-year phase out period. Applicants request that the Commission
authorize CIPS and UE to enter into the amended SSA (the "SSA Alternative").
Mr. Mill indicated that prior to the closing of the merger, CIPS intends to
seek Commission approval of tariffs for the transferred territory that will
produce customer bills identical to bills under the UE tariffs now in effect.
(App. Ex. RJM-1, p. 10) Thus, CIPS
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would have separate rates for its existing Illinois service territory and the
Metro East area. Mr. Rainwater testified that Applicants would propose the same
rates for CIPS' existing service territory and the Metro East area only if there
would be minimal impact on customers. He indicated that consolidation of the
rates might be possible in a five to ten-year time period. (App. Ex. GLR-11,
p.6)
2. Positions of Staff and IIEC
Staff and IIEC oppose the transfer of UE's Illinois service territory and
distribution assets to CIPS. Their concerns with the transfer are summarized
hereafter.
a. Jurisdictional Concerns
IIEC witness Brubaker and Staff witness Schlaf expressed concern over the
loss of Commission authority over the rates associated with the transmission and
generation component of service to the Metro East area if the transfer as
proposed by Applicants were approved. IIEC notes that Applicants acknowledge
that the regulation of the SSA Alternative falls under the primary jurisdiction
of FERC. (App. Ex. GLR-11, p. 2)
Dr. Schlaf indicated that since the SSA Alternative is a wholesale power
contract, its terms and conditions, including the demand and energy charges
specified therein, are subject to FERC approval. He indicated that once FERC
approves such a contract, the Commission must give binding effect to the rates
therein. He indicated that the Commission could determine that a utility does
not require the contracted capacity amount in the contract or that the utility
had lower-cost alternatives available to it and disallow purchased power costs
on such bases. (Staff Ex. 1.0, p. 6-7)
Staff indicates that the Commission's loss of authority over the rates in
the SSA Alternative could negatively impact the transferred customers,
emphasizing that generation costs are the dominant component of their rates. Dr.
Schlaf testified that FERC's review of the SSA Alternative may not focus on
issues that are important to the Commission, such as whether it is in the best
interests of Illinois ratepayers.
Dr. Schlaf testified that it is likely that most, if not all, retail
electric customers will be permitted to choose their electric supplier within
the next decade. He noted that the SSA Alternative requires CIPS to take all of
the contracted amount of power. He indicated that within the next several years,
a sizable portion of the Metro East load may decide to take service from
suppliers other than UE or CIPS. Therefore, he concluded that the remaining
Metro East customers may end up paying for power that they do not need. Staff
indicates that the lack of jurisdiction by the Commission over the costs
reflected in the SSA Alternative prevents the Commission from adjusting the
allocations thereunder.
In response, Applicants indicate that Staff's fear of loss of load is based
on mere conjecture. Applicants indicate that those utilities that are most at
risk from loss of load from retail wheeling are those with relatively high
rates. Applicants note that Dr. Schlaf
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conceded that the existing Metro East rates are among the lowest in Illinois for
all customer classes and that no Illinois electric utility has a lower average
industrial rate than that in effect for the Metro East area. (Tr. 709)
Applicants conclude that CIPS' risk of loss of load from retail wheeling in the
Metro East area is relatively low.
Applicants indicate that they are willing to preserve the Commission's
jurisdiction over the SSA Alternative by agreeing to jurisdictional conditions
with the same effect as those to which UE agreed in the merger proceeding before
the Missouri Public Service Commission. (Initial brief, p. 44) Applicants
indicate that UE agreed that all wholesale electric energy or transmission
service contracts or tariffs between it and any Ameren affiliate required to be
filed with and/or approved by FERC would be conditioned upon the following terms
(Initial brief, p. 44):
Union Electric and Ameren and each of its affiliates and subsidiaries
will not seek to overturn, reverse, set aside, change or enjoin,
whether through appeal or the initiation or maintenance of any action
in any forum, a decision or order of the Commission which pertains to
recovery, disallowance, deferral or ratemaking treatment of any
expense, charge, cost or allocation incurred or accrued by Union
Electric in or as a result of a wholesale electric energy or
transmission service contract, agreement, arrangement or transaction
on the basis that such expense, charge, cost or allocation has itself
been filed with or approved by the FERC, or was incurred pursuant to a
contract, arrangement or allocation method which was filed with or
approved by the FERC. (App. Ex. RJM-8, pp. 25-26)
Applicants further committed to not challenge the Commission's authority over
agreements between public utilities and affiliated interests under Section 7-101
of the Act on the basis of federal preemption. (Initial brief, pp. 44-45)
Applicants state that the jurisdictional condition in the preceding
paragraph places the Commission in the same position as it is in today with
respect to the ratemaking treatment of UE generation and transmission allocated
to the Metro East area. Applicants indicate that the terms of the jurisdictional
condition allow the Commission to adjust the level of plant and expenses
allocated under the SSA Alternative. Therefore, Applicants conclude that the
criticisms of Staff and IIEC in this regard have been fully addressed. (Initial
brief, p. 45) The final jurisdictional conditions agreed to by Applicants in
this proceeding were attached to Applicants' reply brief as Appendix B and are
attached to this order as an Appendix.
In reply, IIEC indicates that the proposed jurisdictional condition
language in Applicants' initial brief does not change the fact that costs under
the SSA Alternative are still regulated by FERC. IIEC notes that Applicants
failed to cite any case law in support of their claim that the language would
preserve the Commission's jurisdictional authority.
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IIEC further notes that no party has had an opportunity to examine the
application of the language under a variety of possible situations or to
determine whether the language has successfully been used in other
jurisdictions. Therefore, IIEC concludes that the language does not satisfy its
jurisdictional concerns. (Reply brief, pp. 11-12)
Staff indicates that it has not had an opportunity to conduct discovery or
cross-examination on the proposed language in Applicants' initial brief.
Therefore, Staff states that it is unable to conclude whether the language
satisfies its jurisdictional concerns. Staff indicates that several factual
issues are raised by the language, such as whether similar language has
successfully been used in similar circumstances, or whether the Commission would
have an opportunity to unilaterally modify the language. (Reply brief, p. 13)
In their brief on exceptions, Applicants offer a new proposal to address
concerns regarding the loss of jurisdiction by the Commission over the SSA
Alternative. Applicants commit to revise the SSA Alternative by including their
proposed jurisdictional condition language within the body of that agreement.
They indicate that if FERC approves the SSA Alternative with this revision, FERC
will be approving the preservation of the Commission's retail ratemaking
jurisdiction. They state that if FERC does not approve the SSA Alternative with
this revision, the transfer of the Metro East service territory will not occur.
(Brief on exceptions, pp. 5-6)
In response, IIEC states that this proposal does not satisfy its concerns.
IIEC notes that the proposal has not been examined during the evidentiary
hearings. IIEC indicates that Applicants are apparently insisting that the
Commission be bound by a FERC decision concerning the Commission's jurisdiction
over retail rates. IIEC again emphasizes that costs allocated under the SSA
Alternative are subject to FERC's jurisdiction. (Reply to exceptions, p. 5)
b. Prudence of the SSA Alternative
Staff witness Stutsman indicated that Staff performed an analytical review
of both the original SSA and the SSA Alternative. In explaining the analytical
review, Mr. Stutsman indicated that Staff prepared a pre-merger (base) analysis
of the CIPS system that utilized data submitted in Docket No. 95-0337, CIPS'
1995 least-cost plan proceeding. Numerous post-merger analyses were conducted
under the assumption that the UE Illinois load was added to CIPS, and that the
SSA or SSA Alternative could be treated as new resource alternatives to meet
that increased load. The new resource alternatives assumed to be available, in
addition to the SSA and the SSA Alternative, included natural gas combustion
turbines, natural gas combined cycle units, and purchased power contracts. Staff
assumed that the capacity available under the SSA Alternative during the first
five years was the same as that available under the SSA, and that the capacity
thereafter available under the SSA Alternative declined on an equal basis each
year to zero after year ten. Staff compared the present value revenue
requirements of the resource alternatives to determine the least-cost resource.
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Mr. Stutsman testified that the analysis shows that the SSA Alternative is
a lower cost resource than the SSA when the effects of a drop off in load are
considered. He indicated that a drop off in load could occur if customers left
CIPS' system because of the availability of retail wheeling or other factors. He
stated that if the SSA were available in one year 100 MW blocks, the combination
of such blocks and natural gas combustion turbines would be less costly than the
SSA Alternative in the load reduction scenario. Staff concluded that the SSA
Alternative is preferable, from a resource planning perspective, to the SSA.
Staff found, however, that in most cases, purchased power and/or combined cycle
units were less costly than the SSA Alternative. Staff concluded that the SSA
Alternative is imprudent since it is not the lowest cost resource alternative.
In response, Applicants acknowledge that it is appropriate to evaluate
whether the transfer of UE's Metro East operations to CIPS is prudent.
Applicants assert that only two options should be compared in deciding that
issue: (1) keep Metro East with UE or (2) transfer Metro East to CIPS and phase
out existing allocations of UE plant to Metro East over 10 years in accordance
with the SSA Alternative. Applicants emphasize that the SSA Alternative is
designed to maintain the same cost allocations and rates after the transfer as
exist today. Applicants conclude that there can be no transfer without the SSA
Alternative.
Applicants note that Staff's third option is the transfer of Metro East
operations to CIPS, with CIPS then obtaining capacity and energy in the
marketplace to meet the Metro East load. Applicants assert that Staff's third
option is not a viable option and should be rejected. Applicants state that this
third option would cause UE to incur stranded costs. Applicants indicate that
the amount of the stranded costs would be the difference between the costs
allocable under the SSA Alternative and the price at which the power previously
provided to the Metro East area could be sold on the open market. Applicants
state that this loss of revenue to UE would preclude the transfer, thereby
preventing the realization of substantial savings in the amount of $2.1 million
attributable to the reduction in the invested capital tax and reduced regulatory
expense. Applicants also emphasize that the transfer would reduce the regulatory
burden on the Commission and the Ameren companies since UE would not be
regulated by the Commission.
Applicants further contend that any least-cost analysis of the SSA
Alternative, such as that presented by Mr. Stutsman, is inappropriate because
the SSA Alternative reflects the use of existing resources of UE that are used
to provide service to its jurisdictional customers. As support for this
position, Applicants state that the Commission's least-cost planning rule for
electric utilities, 83 Ill. Adm. Code 440 ("Part 440"), distinguishes between
"existing resources" and "future resource options." Applicants also note that
Part 440 requires that utilities consider alternative methods of meeting future
demand, but does not require an analysis of options for meeting existing
demands. (Tr. 658-661) Applicants further note that the Commission has stated
that "the least-cost planning process conducted pursuant to Section 8-401 of the
Act is directed toward new resources needed to meet increased demand."
Amendatory Order in Docket No. 91-0050, pp. 2-3 (June 10, 1992) (emphasis added)
Applicants indicate that the Commission rejected a proposal that
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existing load and resources be the subject of a least-cost analysis in Docket
No. 90-0038, involving Commonwealth Edison Company.
Applicants indicate that the transfer of the Metro East operations to CIPS
does not change the fact that the resources used to provide service under the
SSA Alternative are existing resources. Applicants note that the ultimate
control of the resources and load resides in the same entity, Ameren, regardless
of whether the Metro East area is in the service territory of CIPS or UE.
Applicants assert that CIPS' acquisition of the Hancock, Illinois service
territory of UE in 1992 is analogous to the Metro East transfer. Applicants
indicate that in connection with that acquisition, CIPS and UE entered into a
three-year power agreement under which CIPS utilized the UE electric generation
that had previously served the acquired territory. Applicants witness Mill
indicated that neither the Commission nor any party in that case suggested that
the power agreement be evaluated as a new resource. (App. Ex. RJM-3, p. 4)
Applicants also assert that Staff's recommended denial of the transfer
contradicts least-cost principles. They indicate that if there is no transfer,
the existing UE generation and transmission and its cost structure would remain
with the UE Metro East customers in perpetuity. In contrast, they indicate that
under the SSA Alternative, those customers would be allocated those costs for
only five years, and would then gradually be phased to rates based on the cost
of new resources by the end of ten years.
In reply to Applicants' criticisms, Staff disagrees with Applicants'
assertion that Staff's "third option" would lead to stranded costs for UE. Staff
notes that UE is planning to add 347 MW of resources to its system during the
five year period from 1997 through 2001 and 638 MW over the next five years.
Staff indicates that if CIPS used resources other than those available from UE
under the SSA Alternative to meet the Metro East load, some of the resource
additions planned by UE could possibly be deferred and UE's stranded costs could
actually be mitigated.
Staff also indicates that it did not perform a Part 440 least-cost
analysis. Consequently, Staff concludes that Applicants' discussion concerning
the scope and purpose of Part 440 is irrelevant. Staff indicates that its
analysis was performed to determine whether CIPS entry into the 30-year SSA or
10-year SSA Alternative is prudent in today's electric utility industry
environment. Staff emphasizes that it was necessary to treat the SSA as a new
resource in order to determine if a prudent lesser-cost option existed.
Staff also disagrees with Applicant's contention that the transfer of the
Hancock County service territory from UE to CIPS is analogous to the proposed
Metro East transfer. Staff indicates that today's environment in which electric
utilities operate is substantially different than that which existed in 1992,
citing the movement toward increased competition. Staff further notes that the
three-year term of the power agreement between
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CIPS and UE in 1992 is substantially shorter than the terms of the SSA and SSA
Alternative.
Staff also disagrees with Applicants' assertion that the UE generation,
transmission and cost structure would remain with its Metro East customers in
perpetuity if the transfer were denied. Staff indicates that Applicants'
position ignores the likelihood that retail wheeling will be available in the
future.
c. Allocation of Costs Under the SSA Alternative
IIEC contends that the methodology for allocating costs under the SSA
Alternative is inappropriate since it is inconsistent with the methodology
previously used by the Commission. Mr. Brubaker explained that the Commission
has utilized a comprehensive inter-jurisdictional embedded cost of service study
to determine the portion of UE's total system generation and transmission costs
that should be allocated to Illinois customers. In contrast, he indicated that
the SSA Alternative utilizes a levelized carrying charge approach to allocate
costs that is based on a "fixed charge rate methodology" that UE downloaded from
the FERC Bulletin Board. He expressed concern that UE has not calculated the
amount of costs that would be allocated under the allocation method approved by
the Commission in UE's last electric rate case in 1985. (IIEC Ex. 1.0, pp. 8-9)
Mr. Brubaker cited two differences in the allocation methodologies. He
indicated that the methodologies treat depreciation expense differently and that
the SSA Alternative utilizes the 12 coincident peak ("CP") method to allocate
costs, while the Commission approved the 4 CP method in UE's last rate case.
In response, Applicants' witness Mill emphasized that the SSA Alternative
was designed to maintain existing cost of service allocations. He indicated that
the traditional embedded cost of service approach and the levelized fixed charge
approach are both reasonable, widely accepted methodologies that produce similar
results over time. (App. Ex. RJM-4, pp. 3-4)
In reply, IIEC notes that Mr. Mill was unaware of any entity besides FERC
that utilized the levelized fixed charge methodology. (Tr. 364) Mr. Brubaker
also emphasized that Mr. Mill presented no evidence that the two methodologies
produce similar results over time. (IIEC Ex. 3.0, p.3)
d. Savings Under the Transfer
Staff and IIEC indicate that the $2.1 million in annual savings associated
with the transfer that were identified by Applicant are not significant enough
to overcome the drawbacks of the transfer. Dr. Schlaf noted that the $2.1
million is only 1.3% of the $161 million of sales by UE to its Illinois service
area in 1995. (Staff Ex. 19.0, p. 3) Mr. Brubaker testified that the invested
capital tax savings of $1.9 million per year calculated by
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Applicants are not sufficient to offset the increased risk of higher costs to
Metro East ratepayers. (IIEC Ex. 3.0 Supp., p. 6)
In response, Applicants assert that $2.1 million in annual savings is a
significant amount.
Citing its witness Smith's testimony (Staff Ex. 17.00, p. 8), Staff
questions whether annual savings of $2.1 million would be realized from the
transfer. Staff indicates that besides invested capital tax, changes in items
such as depreciation expense, property tax, income tax, payroll tax and wage
expense may impact revenue requirement following the transfer.
In response, Applicants contend that Mr. Smith never suggested that these
items would change if Metro East is transferred to CIPS. They assert that Mr.
Smith only speculated as to the effect of those items on the post-merger (not
post-transfer) apportionment factors used to determine the level of the invested
capital tax. They indicate that their witness Craig Nelson explained that Ameren
fully considered the effects of those items on the invested capital tax. They
state that the only item that has a significant impact is the change in the
payroll factor. They indicate that this impact is fully reflected in their
estimate of the reduction in invested capital tax. (Tr. 813-814) Therefore,
Applicants conclude that Staff's conjecture regarding other changes to the
revenue requirement has no foundation in the record and should be rejected.
e. Consolidation of Metro East Rates with Rates Applicable to
the Rest of CIPS' Service Area
IIEC witness Brubaker raised the concern that if the transfer is approved,
Metro East customers could see substantial electric rate increases when the
Metro East rates are consolidated with the rates for the rest of CIPS' service
area. Mr. Brubaker testified that CIPS' rates are considerably higher than UE's
Metro East rates for all major customer classes. He indicated that firm
industrial customers in the Metro East area would experience an overall increase
of 23% if they were placed on CIPS' existing rates, while interruptible
industrial customers would experience an overall increase of 52%. (IIEC Ex. 1.0,
p. 12)
In response, Applicants indicate that the Commission will have the final
say as to whether rates should be uniform for CIPS' service area. Applicants
state that they are confident that the Commission will treat Metro East
customers appropriately and would fully consider significant customer impacts
from rate consolidation. Applicants emphasize that they would not propose
uniform rates unless rate impacts were minimal. (App. Ex. GLR-11, p. 6) They
further note that they have proposed that the Commission require CIPS to
maintain separate rates for the Metro East area for at least five years. (Id.)
3. Commission's Conclusion
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The Commission concludes that the public will not be convenienced by the
proposed transfer and that the proposed transfer should not be approved. In
reaching this conclusion, the Commission recognizes that there are benefits from
the transfer. The evidence presented by Applicants indicates that the transfer
will result in annual savings of approximately $2.1 million, of which $1.9
million is attributable to the reduction in the Illinois invested capital tax,
and $200,000 is attributable principally to avoided regulatory expenses.
Applicants also indicate that the transfer eliminates the possibility of future
interjurisdictional conflicts between Illinois and Missouri, although they
failed to identify any real problems that have resulted from the jurisdiction by
the Commission and the Missouri Public Service Commission over UE's public
utility operations.
The Commission determines that these potential benefits of the transfer are
outweighed by the transfer's deficiencies associated with the SSA Alternative.
The SSA Alternative is a wholesale power contract between CIPS and UE, and would
be subject to FERC approval. FERC would have jurisdiction over the terms and
conditions of the SSA Alternative, including the demand and energy charges
specified therein. The loss of jurisdiction over the rates associated with the
transmission and generation component of service to the Metro East service area
is a major concern to the Commission. This concern is aggravated by the fact
that the SSA Alternative utilizes a levelized fixed charge approach previously
approved by FERC to allocate costs which is different than the allocation
methodology previously adopted by the Commission for the allocation of UE's
capacity costs to its Illinois service area. While Applicants presented
testimony that the FERC methodology and the methodology previously adopted by
the Commission should produce similar results over time, no evidence was
presented which compared actual results from the two methodologies.
The Commission is not convinced that the jurisdictional conditions agreed
to by Applicants, set forth in the Appendix to this Order, will preserve either
the Commission's jurisdiction over the SSA Alternative or its ability to adjust
the allocation of plant and expenses thereunder. As IIEC points out, the
language does not change the fact that costs under the SSA Alternative are
regulated by FERC. Applicants have failed to cite any case law in support of
their conclusion that the language will preserve the Commission's jurisdiction.
The inclusion of the jurisdictional conditions in the body of the SSA
Alternative, as proposed by Applicants in their brief on exceptions, does not
satisfy concerns about the loss of the Commission's jurisdiction.
The Commission believes that Staff's analysis presented by Mr. Stutsman
further supports the conclusion that the SSA Alternative should not be approved.
Staff's analysis appropriately examined whether entry into the ten-year SSA
Alternative is prudent in today's electric utility environment. That analysis
indicates that CIPS could serve the transferred Metro East electric load through
less costly resources than the SSA Alternative, such as purchased power and/or
combined cycle units.
The Commission determines that Applicants' criticism of Staff's analysis
has no merit. Applicants' discussion regarding "existing resources" in the
context of Part 440 is
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irrelevant. Staff did not perform a Part 440 least-cost analysis as part of an
electric utility energy plan proceeding. Rather, Staff appropriately examined
least-cost considerations solely in the context of determining whether the SSA
Alternative is prudent and in the public interest. Staff's analysis leads to the
conclusion that the SSA Alternative is not the least-cost resource option and
provides one reason for not approving it.
The Commission further concludes that the SSA Alternative is
distinguishable from the transfer of the Hancock County service area from UE to
CIPS in 1992. As Staff noted, the electric utility environment today, with the
movement toward increased competition, is significantly different than that
which existed in 1992. Also, the three-year term of the power agreement between
CIPS and UE that was implemented in connection with the Hancock County transfer
is substantially shorter than the term of the SSA Alternative.
For the foregoing reasons, the Commission concludes tat approval of the SSA
Alternative is not in the public interest. Since the SSA Alternative is an
integral part of Applicants' proposed transfer of the Metro East service area
from UE to CIPS, the Commission concludes that the transfer cannot reasonably be
approved.
C. Ability of CIPS and UE to provide adequate, reliable, efficient, safe
and least-cost public utility service.
Section 7-204 of the Act requires that before a proposed reorganization can
be approved, the Commission must find that "the proposed reorganization will not
diminish the utility's ability to provide adequate, reliable, efficient, safe
and least-cost public utility service." With the denial of the transfer of the
Metro East service area to CIPS, both CIPS and UE will remain public utilities
subject to the Commission's jurisdiction.
Applicants assert that their evidence establishes that the proposed
reorganization will not adversely affect electric or gas service for any portion
of the Ameren system. Applicants indicate that the merger will enhance
efficiency by reducing overall costs by approximately $759 million over the next
ten years. Applicants witnesses Moorman and Pettit testified that centralized
dispatch of the electric and gas systems of UE and CIPS will enhance efficiency
and system reliability. (App. Exs. GWM-1, pp. 9-11, and SDP-1, pp. 11-12)
Applicants witnesses Greenwalt, Koertner and Moorman testified that the merger
will reduce the risk exposure of UE and CIPS and will provide greater marketing
opportunities. (App. Exs., CLG-1, p. 12; GWM-1, pp. 10-11; and WAK-1, p. 7) The
managerial talent pool will be enhanced and customer service will benefit from
the merger, according to Mr. Greenwalt and Mr. Koertner. (App. Exs. CLG-1, p.
12, and WAK-1, p. 7) Thus, Applicants conclude that every principal aspect of
public utility service (operations, finance and customer service) will be
enhanced by the merger, without any adverse side effects. (Initial brief, p. 21)
CUB contends that the proposed reorganization will diminish the ability of
UE and CIPS to provide least-cost service. CUB's opinion is based on its
conclusion that
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Applicants' plan for the ratemaking treatment of merger costs and savings places
all of the risk that net savings may not be achieved on ratepayers. (Initial
brief, p, 4)
The Commission has previously concluded in this order that Applicants'
proposed ratemaking treatment of merger costs and savings should not be approved
in this docket. The ratemaking treatment will be determined in a future rate
case or alternative regulatory plan that CIPS and UE are required to file within
six months after the closing of the merger. As noted hereinabove, the Commission
intends to adopt ratemaking treatment of merger costs and savings in those rate
cases or alternative regulatory plan proceedings that is fair to both Ameren and
the ratepayers of CIPS and UE. Therefore, CUB's least-cost concerns are based on
a plan that has not been adopted by the Commission.
The Commission concludes that the evidence establishes that the
reorganization as approved herein will not diminish the ability of CIPS and UE
to provide adequate, reliable, efficient, safe and least-cost public utility
service.
D. The Public Convenience Standard under Section 7-102
Before the proposed merger can be approved, the Commission is required
under Section 7-102 (I) of the Act to find that the public will be convenienced
by it. In Commonwealth Edison Company v. Illinois Commerce Commission, 181 Ill.
App. 3d 1002, 131 Ill. Dec. 25, 538 N.E. 2d 213 (2d Dist. 1989), the Court
stated:
"[P]ublic convenience" must be read in the context of the specific purposes
of the Act, namely to provide the public with efficient utility service at
a reasonable cost. Our supreme court has stated that the public convenience
factor, when read in the context of the Act, includes such factors as costs
to customers, simplification of utility service, operating costs,
facilities planning and proximity of service territories. (Illinois Power
Co. v. Illinois Commerce Commission, (1986), 111 Ill. 2d 505, 96 Ill. Dec.
50, 490 N.E, 2d 1255)
The Commission recently revisited the public convenience standard in
Commonwealth Edison Company (Docket No. 95-0615, March 12, 1997) For purposes of
that docket, the Commission found that the public convenience standard would be
met if the evidence indicates that the benefits to ratepayers are reasonably
likely to exceed the costs or harms to them. This standard was subsequently
applied by the Commission in Docket No. 96-0229 (Order, March 31, 1997) The
Commission determines that this same standard should be applied in this merger
proceeding.
Applicants contend that to the extent that Section 7-102 applies to the
merger transactions, their evidence amply establishes that the public
convenience standard has been met. (Initial brief, p. 19)
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CUB, on the other hand, contends that the merger, as proposed by
Applicants, does not meet the public convenience standard. CUB's conclusion is
based on its position that Applicants' plan for the ratemaking treatment of
merger costs and savings places all of the financial risk associated with the
merger on ratepayers. CUB asserts that Applicants' plan guarantees that
Applicants will recover all of their merger costs and receive one-half of their
originally estimated merger savings, regardless of whether the savings are
actually achieved. CUB further asserts that Applicants' plan does not guarantee
any merger savings to ratepayers. (Initial brief, pp. 3-6).
The Commission concludes that the public will be convenienced by the
proposed merger. The evidence establishes that the merger's benefits to Illinois
ratepayers of CIPS and UE are reasonably likely to exceed its costs to them.
Applicants have estimated that there will be total merger savings of $759
million during the first ten years after the merger. Taking into account
transaction costs of $22 million and transition costs of $51 million, Applicants
expect the merger to produce $686 million in net savings over the ten-year
period. Applicants' witness Rainwater testified that Applicants expect that the
merger savings will flow as follows: 58.7% to UE retail electric, 3.5% to UE
wholesale electric, 3.6% to UE gas, 22.5% to CIPS retail electric, 3.9% to CIPS
wholesale electric and 7.8% to CIPS gas. (Applicants' Ex. GLR-1, p. 16).
Applicants' witness Mill testified that certain joint dispatch and purchased gas
savings will flow to Illinois ratepayers through the fuel adjustment clause
("FAC") and purchased gas adjustment ("PGA") clause. (Applicants' Ex. RJM-1, p.
13)
CUB contends that if Applicants' proposed ratemaking treatment of merger
costs and savings is approved, the public convenience standard will not be met.
CUB's concerns are based on a ratemaking treatment that has not been adopted by
the Commission. The ratemaking treatment of merger costs and savings will be
determined in a future rate case or alternative regulatory plan that CIPS and UE
are required to file within six months after the closing of the merger. The
Commission intends to adopt ratemaking treatment of merger costs and savings in
those rate cases or alternative regulatory plan proceedings that is fair to both
Ameren and the ratepayers of CIPS and UE.
E. Market Power Issues
1. Overview of the Merger Guidelines adopted by the FERC
FERC has adopted the U.S. Department of Justice and Federal Trade
Commission Merger Guidelines (the "Guidelines") as the basic framework for
evaluating the competitive effects of proposed mergers. The Guidelines are
explained in the direct testimony of Staff witness Michaels and Applicants'
witness Frame. (Staff Ex. 22.0, pp. 9-10; Applicants Ex. RWF-I, pp. 40-45)
Dr. Michaels testified that the Guidelines presume that a merger is harmful
if it could increase price by more than a "small but significant and
nontransitory amount" in some
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relevant market. That amount is "in most contexts . . . an increase of five
percent lasting for the foreseeable future." The Guidelines specify procedures
for defining the relevant product and geographic markets. Dr. Michaels indicated
that a product (or group of products) is defined as relevant if buyers cannot
easily turn to substitutes when faced with higher prices for it. Similarly, the
relevant market's geography is also determined by the alternatives open to
buyers. Dr. Michaels stated that the relevant geographic market is "the smallest
area in which a monopolist in the same products could profitably impose that
[significant and nontransitory] price increase."
After the relevant markets are defined, the Guidelines require an
examination of seller concentration in those markets. Dr. Michaels indicated
that the rationale for this examination is the expectation that markets with
numerous suppliers will be more likely to perform competitively than markets
with few suppliers. The study of concentration must also account for the
relative size of the sellers; e.g., the price in a market where one seller has
90 percent of sales and 99 others share the remaining 10 percent may differ from
the price in a market shared by 100 equally sized sellers. To capture such
differences, the Guidelines require the calculation of the relevant market's
Herfindahl-Hirschman Index ("HHI") of concentration both prior to and post
merger. An HHI is computed by squaring the market shares of each seller in the
market and then summing those squares.
The Guidelines provide that a market with a post-merger HHI under 1,000
will ordinarily require no further analysis. Markets with post-merger HHI's
between 1,000 and 1,800 are considered to be "moderately concentrated." If the
HHI in such markets increases by less than 100 points, it is "unlikely to have
adverse competitive effects." If the increase exceeds 100 points, it is deemed
to "potentially raise significant competitive concerns." Markets with HHI's in
excess of 1,800 are considered to be highly concentrated. An increase in the HHI
in such markets of 50 to 100 points "potentially raises significant competitive
concerns", while an increase in the HHI of over 100 points is "likely to create
or enhance market power or facilitate its exercise."
If the above thresholds are not exceeded, the merger applicants are not
required to provide further information. If the thresholds are exceeded, this
does not mean that the merger must fail on competitive grounds. Rather, the
applicants are required to present additional information that addresses the
potential for adverse competitive effect. The Guidelines indicate that
additional factors that could mitigate or counter-balance the potential
competitive harm should be examined, such as ease of entry in the market.
2. Applicants' Position
a. Product Market
Applicants indicate that the analysis set forth in the Guidelines is
designed for the evaluation of the effect of a merger on wholesale competition.
They note that FERC recommends the analysis of the effect of a merger on long-
term capacity, short-term capacity and non-firm energy markets over a variety of
seasonal segments. Applicants'
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witness Frame concluded that the only product market that is relevant to the
investigation of market power in this proceeding is short-term or non-firm
energy. (Applicants' Ex. RWF-1, p. 50)
Applicants indicate that concerns about the merger-induced creation of
market power in long-term capacity markets can be readily dismissed for the
following reason. Investigations of the potential for exercising market power in
long-term capacity generally have focused on whether the entity subject to the
investigation controls entry barriers that might be used to thwart the entry of
its would-be competitors. Applicants' witnesses Frame, Borkowski, and Koertner
testified that Applicants lack control over relevant entry barriers, and that
Applicants' open access transmission tariff, FERC's Orders 888 and 889 and
Applicants' commitment to the Missouri Public Service Commission ("MPSC") to
form or participate in a regional Independent System Operator ("ISO") eliminate
any concern that Ameren might be able to use its transmission system to thwart
competitive entry.
Mr. Frame concluded that concerns about the merger-induced creation of
market power in short-term capacity markets can also be readily dismissed. He
indicated that, because UE must purchase additional capacity from other
suppliers in order to meet its native load and reserve goals, UE cannot
realistically be considered a competitor in the short-term capacity markets,
even for time periods as short as a year. (Applicants' Ex. RWF-1, p. 51)
Mr. Frame stated that capacity sales for shorter than one-year time periods
generally are included in an analysis of non-firm or short-term energy markets.
Therefore, he focused on an assessment of the impact of the merger on the non-
firm or short-term energy market.
Both Staff witness Michaels and CUB witness Shepherd criticized Mr. Frame's
failure to include short-term capacity as a relevant market. Dr. Michaels
testified that, with retail wheeling, capacity will be freed up as UE's former
captive load departs. (Staff Ex. 22.0, p. 19) Similarly, Dr. Shepherd testified
that the shortage of capacity makes no sense under competitive conditions. He
indicated that UE would no longer be dedicated to serving its native load. (CUB
Ex. WGS-1, p. 5)
Dr. Shepherd also testified that Mr. Frame's decision to focus only on the
non-firm energy market ignores the fact that many customers, especially
residential customers, will require firm power. He indicated that these firm
power markets are likely to be vulnerable to the exercise of market power. (CUB
Ex. WGS-1, p. 7)
In response, Mr. Frame indicated that while he defined non-firm energy as
the relevant market, he used measures of capacity to assess concentration in
that market. He testified that those same capacity measures could be used to
assess concentration in capacity markets. (Applicants Ex. RWF-13, p. 5)
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b. Geographic Market
In performing the screening analysis set forth in the Guidelines, Mr. Frame
examined two separate geographic markets. The first of these was the "CIPS
market." Mr. Frame indicated that customers in the CIPS market are those located
within the existing CIPS control area. Generation which can supply the CIPS
market includes both that which is located within the CIPS control area as well
as that which can be imported from the outside. Mr. Frame concluded that
potential outside suppliers to the CIPS market include (i) all entities
currently interconnected with any Illinois supplier, (ii) UE and all entities
interconnected with UE, and (iii) most entities located in the Mid-Continent
Area Power Pool (MAPP), even if not interconnected with UE or an Illinois
supplier. Mr. Frame testified that he included most entities of MAPP because of
the existence of a single postage-stamp transmission rate throughout MAPP.
Because the merger combines an entity owning all or virtually all of the
generation inside the CIPS control area (i.e., CIPS) with one potential outside
supplier (i.e., UE), Mr. Frame indicated that the effects of the merger on
generation concentration are likely to be greater in the CIPS market than in any
other. (Applicants' Ex. RWF-1, pp. 48-49)
Mr. Frame also defined and analyzed an "All-Illinois market." Customers in
the All-Illinois market include all of the load in Illinois, except that served
by the distribution cooperative members of Soyland and municipal systems other
than Springfield. Mr. Frame indicated that time limitations did not permit
inclusion of these additional loads in his analysis. Suppliers include all
entities owning generation in Illinois (other than Soyland and municipal systems
other than Springfield), as well as those that can export energy to Illinois
from out-of-state. Out-of-state suppliers in this market are the same as for the
CIPS market.
CUB contends that Mr. Frame is overly optimistic regarding the suppliers
that will be selling electricity to customers in CIPS' territory. Dr. Shepherd
testified that it is better to assume that the generation serving the local
service territory is the relevant market until experience shows that markets are
actually wider. (CUB Ex. WGS-1, p. 8)
In response, Mr. Frame indicated that the broad group of suppliers included
in his analysis is consistent with the economics of potential bulk power
transactions and the Guidelines. He stated that the Guidelines do not place
arbitrary limits on who may supply energy into the market. He indicated that all
suppliers that are directly connected with UE, CIPS or another Illinois supplier
are at most only one wheeling charge away from the relevant geographic market.
He stated that the group of one wheel suppliers includes four suppliers within
MAPP. He indicated that he added other MAPP suppliers to his analysis in light
of the opportunities for directly connected MAPP entities to broker power into
Illinois retail markets, using MAPP's existing single system transmission
tariff. (Applicants Ex. RWF-13, p. 3)
c. HHI Results
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For both the All-Illinois market and the CIPS market, Mr. Frame performed
HHI analyses for 36 different cases; i.e., nine time periods times two capacity
measures times two transmission allocation measures. The results for the All-
Illinois market are summarized in Applicants' Exhibits RWF-4 through RWF-7, and
the results for the CIPS market are summarized in Applicants' Exhibits RWF-8
through RWF-11.
Mr. Frame testified that in each of the 36 cases analyzed for the All-
Illinois market, the post-merger HHI falls into the "highly concentrated"
(greater than 1,800) category under the Guidelines. He indicated, however, that
for each of the cases, the merger-induced HHI increase is far below the
Guidelines screening threshold of 50. He also noted that the post-merger shares
of Ameren are relatively small, reaching a maximum of only 6.8%. Therefore, he
concluded that his analysis of the All-Illinois market shows that concerns about
the merger creating unacceptable levels of market power can be summarily
dismissed. (Applicants' Ex. RWF-1, pp. 63-64)
Mr. Frame testified that there are relatively few HHI increases in the CIPS
market that exceed the threshold levels of the Guidelines. Applicants' Exhibits
RWF-8 through RWF-11 indicate that in 10 of the 36 cases analyzed for the CIPS
market, the merger-induced increases exceeded the threshold levels. In those 10
cases, the post-merger HHI was between 1,000 and 1,800 and the increase in the
HHI exceeded 100, ranging from 108 to 211.
Mr. Frame's All-Illinois market ignores transmission constraints between
Illinois control areas and, in effect, treats all generation and load in
Illinois as if it were located at a single point. Mr. Frame recognized that this
assumption is unrealistic in an electrical sense, He indicated, however, that
the only way to avoid this problem is to apply a much more costly modeling tool
to the Illinois retail market than is required under the Guidelines. He stated
that the use of such a model would preclude the completion of the study within
the limited time frame available in this docket. (Applicants' Ex. RWF-1, p. 49)
CUB contends that Mr. Frame's assumption of no transmission constraints causes
his HHI results to understate the market power problems resulting from the
merger. (Initial brief on reopening, pp. 10-11)
d. Analysis of Other Factors Affecting Market Power
The Guidelines indicate that it would be improper to reject a merger on the
basis of HHI concentration indices alone. Rather, the Guidelines provide that if
the HHI analysis indicates that a proposed merger may significantly increase
concentration in any relevant markets, other factors should be examined that
either address the potential for adverse competitive effect or could mitigate or
counterbalance the potential competitive harm. (Guidelines, p. 58)
Applicants' analysis of other factors generally focused on whether there
are likely to be adverse competitive effects resulting from the merger and
whether entry is sufficiently easy to prevent existing market participants from
exercising market power.
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With regard to the former, Mr. Frame indicated that it is unlikely that a firm
with market shares as low as those that Ameren will have post-merger could ever
be in a position to exercise market power on a unilateral basis. (Applicants'
Ex. RWF-1, pp. 71-72) Mr. Frame testified that UE is short of capacity and,
therefore, must purchase additional capacity in the marketplace in order to meet
its peak demand plus reserve responsibilities on behalf of its native load
customers. As a result, Applicants conclude that UE lacks market power at those
times when relatively few additional resources are available to limit price
increases by those possessing market power.
Mr. Frame indicated that another factor likely to mitigate competitive
concerns is the difficulty in coordinating pricing and output decisions with
other market participants. He indicated that coordination is difficult in light
of the different terms and conditions under which electricity is sold. He stated
that these differences include the degree of reliability (firmness of supply),
the manner in which price fluctuations are shared, location, transmission path
and contract duration. (Applicants' Ex. RWF-1, p. 72)
Mr. Frame also pointed out that Applicants' single-system, open-access
transmission tariff should increase competitive possibilities. Accordingly, he
indicated that customers will be able to transact with more trading partners by
paying only a single wheeling fee whereas, without a merger, arranging two
transmission transactions and paying two wheeling charges would have been
required. Because of the manner in which transmission prices are determined
under traditional procedures, the ceiling price under the Ameren tariff always
will be less than the sum of the two stand-alone charges. As a result,
transactions may go forward in the future that, without the merger, would have
been deterred by the "pancaking" of transmission charges. If and when retail
"customer choice" comes about in Illinois, the Ameren open access tariff may
have a particularly beneficial effect on customers now served by CIPS. While
they may lose UE as an independent "one wheel" supply option as a result of the
merger, CIPS' current customers will gain numerous other "one wheel" supply
options that would not otherwise have been available to them. A similar
statement is true of the retail customers in Illinois currently served by UE.
(Applicants' Ex. RWF-1, pp. 36-37)
In this regard, as a condition for its approval of the UE-CIPS merger, the
Missouri Public Service Commission has required that UE "file or join in the
filing of a regional ISO proposal at the Federal Energy Regulatory Commission
that eliminates pancaked transmission rates . . . . " UE has accepted this
condition, and therefore, once the merger is consummated, additional one wheel
options also may become available. (Id., pp. 37-38)
Applicants also point out that CIPS' interconnections with its neighbors
are strong. Applicants' witness Whiteley testified that, except for extremely
limited amounts of local generation inside of CIPS' control area which must run
to provide voltage support (i.e., reactive power), CIPS' transmission system is
capable of importing all of the control area requirements from the outside and
CIPS' transmission system generally is free from constraints. (Applicants Ex.
DAW-1, p. 9) Mr. Frame testified that this fact, coupled with the fact that UE
and CIPS together are interconnected with so many important bulk power
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suppliers in the region, mitigates market power concerns with respect to the
merger. (Applicants' Ex. RWF-1, p. 38)
Additionally, as Applicants' witnesses Koertner and Borkowski testified,
CIPS and UE are in a very competitive market for generation. They indicated that
this market has many suppliers, and much capacity and energy to market.
(Applicants' Exs. WAK-6, p. 13; MAB-1, pp. 14-15) Applicants state that the
competitive nature of this market is likely to persist after the industry is
restructured to allow for greater retail competition.
Applicants indicate that there is overwhelming evidence in the testimony of
its witnesses Frame, Borkowski and Koertner that there are no significant entry
barriers preventing entry by new suppliers into electric generation. Mr. Frame
noted that the Guidelines specifically state that where entry is easy, a "merger
raises no antitrust concerns and ordinarily requires no further analysis." He
stated that this is true no matter what the market shares and concentration
indices are. (Applicants' Ex. RWF-1, p. 73)
Applicants also pointed out that they made their Hart-Scott-Rodino ("HSR")
filings on April 18, 1997. They indicate that the United States Department of
Justice ("DOJ") cleared the merger under HSR as of May 19, 1997, and that no
further filings by Applicants or action by the DOJ or the Federal Trade
Commission will be required. They state that this is, in effect, a finding by
the nation's two primary antitrust enforcement agencies that the merger presents
no concerns with regard to adverse effects on competition. (Initial brief on
reopening on market power issues, pp. 6-7)
Applicants also contend that issues relating to the mitigation of potential
market power in a deregulated regime are generic and do not arise from the
merger. Applicants' view is that the most important new types of potential
market power problems likely to arise from deregulation relate to (i) the
concentration of the ownership of generation inside particular geographic areas
that at times may be transmission-constrained (the "load pocket problem") and
(ii) local "must run for reliability" generation. (Initial brief on reopening on
market power issues, p. 8)
Regarding the load pocket problem, Mr. Frame testified that if transmission
lines into "load pockets" are constrained, additional supplies from the outside
may not be available to defeat price increases by those who control generation
inside the load pockets. Therefore, if one supplier owns all of the generation
inside the load pocket and the prices that it may charge are not regulated or
otherwise limited as they are today, that entity may be able to exercise market
power. Where situations are identified in which a supplier might be able to
exercise market power as a result of concentrated ownership of generation inside
of load pockets, it may be appropriate to identify mitigation measures in the
process of designing the restructured electric supply industry. (Applicants' Ex.
RWF-1, pp. 25-26)
Mr. Whitely testified that neither the CIPS nor the UE-Illinois control
area is or contains a load pocket. Applicants noted in this regard that FERC
undertook an extensive
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review of whether Applicants' transmission lines were constrained. Applicants
state that the FERC Initial Decision indicates that the uncontroverted evidence
showed that there are no significant transmission constraints on Applicants'
systems. Applicants conclude that there is, therefore, no need for mitigation
measures with regard to a load pocket problem in the context of considering the
market power implications of a merger of UE and CIPS. Applicants emphasize that
the load pocket problem, by its very nature, is a local problem not likely to be
exacerbated by a merger, even between adjacent electric suppliers (such as UE
and CIPS), because if limits on imports into any particular area were to exist,
they would be there regardless of the merger. (Initial brief on reopening on
market power issues, p. 4)
Mr. Frame explained that a local must-run problem involves a situation in
which those who own or otherwise control specific generators, or small groups of
generators, that must be run for reliability purposes could, if unconstrained by
contract or regulation, extract monopoly profits in a world where the supply of
generation service of all kinds is unregulated. He indicated that the owners of
such must-run generation could bid very high prices for their output, and the
system operator would be forced to call on those generators to operate for
reliability reasons even if the energy which they provide could be replaced by
much cheaper sources absent the must-run constraints. (App. Ex. RWF-1, pp. 26-
27)
Applicants explained that, as with load pockets, the merger could not cause
or exacerbate any must-run problem. Mr. Whiteley testified that CIPS has a very
strong transmission system, which gives it the capability to import generation
to serve its total load, except for a very small amount of must-run generation
equal to 12% of load. He also indicated that the UE-Illinois service area has no
native generation and is, therefore, capable of importing all of its generation
requirements. (Applicants Ex. DAW-1, p. 9) Applicants state that the merger of
UE and CIPS will not alter the physical configuration of their systems, and,
therefore, cannot affect what level of generation must run for reliability
purposes.
Mr. Frame testified that if its is ultimately determined that particular
generators (or small groups of such generators) should be considered local must-
run and, therefore, possess market power in a regime of totally deregulated
electricity supply, it presumably would be necessary to develop mitigation
measures which address that must-run market power. He indicated, however, that
this must be done regardless of whether the merger of UE and CIPS occurs.
(Applicants Ex. RWF-1, p. 27)
Finally, Applicants explained that their participation in an ISO
arrangement is further assurance that the merger will create no market power
concerns.
Applicants conclude that no conditions should be imposed on the merger with
regard to market power.
3. Staff's Position
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a. Product Market
In applying the Guidelines, Staff witness Michaels determined that the
relevant commodity is firm full-requirements power delivered to the retail
customer. He indicated that users of electricity value the reliability provided
by full requirements power. He stated that utilities are the only retail sellers
of bundled services in the current regulated market. Therefore, Dr. Michaels
concluded that the components of full requirements power should be examined. He
indicated that the components of full requirements power are long-term and
short-term capacity (and the associated energy), short-term energy, ancillary
services and transmission access. (Staff Ex. 22.0, pp. 4, 13-20)
With regard to transmission access, Dr. Michaels indicated that FERC
currently assumes that open access transmission tariffs for comparable services
could mitigate or eliminate market power in transmission. He concluded that if
open access occurs similarly over state-jurisdictional lines, it will mitigate
or eliminate the monopoly power of the transmission owners. (Staff Ex. 22.0, p.
17)
Dr. Michaels testified that in the advent of retail wheeling, end-users,
marketers, merchants and utilities can make use of long-term capacity. He noted
that neither CIPS nor UE control any resources, including fuel supplies and
plant sites, that might act as barriers to the construction or reallocation of
capacity. (Staff Ex. 22.0, pp. 17-18)
Dr. Michaels indicated that the merger replaces CIPS and UE with a single
owner of non-firm energy that might be available to retail wheeling customers.
He noted, however, that UE seldom sells substantial quantities of non-firm
energy. He stated that non-firm energy is only sporadically available and that a
customer desiring a full-requirements power supply must own capacity or options
on capacity to function reliably without interruptions. He concluded that the
merger will not affect the non-firm energy markets to which retail customers
will have access. (Staff Ex. 22.0, p. 18)
He testified that the characteristics of future markets for ancillary
services will be influenced by the details of deregulation He concluded that any
evaluation of the merger's impact on ancillary services would be conjectural in
light of uncertainty as to future market conditions and lack of data. (Staff Ex.
22.0, p. 18)
Dr. Michaels determined that short-term capacity is the most important
market in which the merger can effect retail competition. He indicated that
achieving a firm power supply through the construction of long-term capacity is
quite expensive and may become uneconomic if fuel or power prices change
adversely. He stated that short-term capacity is a more market-sensitive
substitute for long-term capacity. He concluded that short-term capacity will be
valuable to end-users and marketers in a retail wheeling market, providing them
with flexibility and reliability. (Staff Ex. 22.0, pp. 18-19) . Therefore, Staff
focused on the short-term capacity market in its Guideline's analysis.
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b. Geographic Market
Staff witness Mitnick testified that the geographic market for the
Guideline's analysis should be limited to electric capacity owned by CIPS or by
a utility directly interconnected with CIPS (including UE). He indicated that
this market includes generation capacity owned by 14 utilities. He stated that
if no significant market problems were found to exist in this limited market,
certainly no threats to retail competition would exist if the market was
actually more extensive. (Staff Ex. 23.0, pp. 13, 20) Dr. Michaels testified
that the size of this limited market is appropriate since competition is likely
to first occur in a narrow market after retail wheeling is implemented. He
indicated that if retail wheelers find that the first market in which they
operate is not competitive, they may be discouraged from further
experimentation. He stated that Mr. Frame's finding of competition in a broad
market, if correct, will carry additional force if there is competition in a
narrower market that is an evolutionary step toward a broader one. (Staff Ex.
23.0, p. 21)
c. HHI Results
For Staff's HHI analysis, Mr. Mitnick first selected 36 hours of actual
operation in the electric generation market that are broadly representative of
all hours. The 36 hours are from the period October 31, 1995 through September
30, 1996. Three hours per month were used: one weekday daytime hour, one weekday
nighttime hour, and one weekend hour. To ensure a complete analysis, he selected
an additional 36 hours in which peak generation occurred during the same 12-
month period. (Staff Ex. 23.0, p. 14) For each of the 72 hours in his analysis,
Mr. Mitnick utilized five measures of capacity. (Id., pp. 17-18) The results of
Staff's HHI analysis are summarized in Staff Exhibits 23.6 A and B, 23.7 A and B
and 23.8 A and B. Mr. Mitnick concluded from his analysis that the merger does
not appear to be a serious threat to competition. He indicated that this result
is not surprising in light of the fact that UE's market share is approximately
10% for most of the 360 combinations and CIPS' market seldom exceeds 5%. (Staff
Ex. 23.0, pp. 20-21)
Dr. Michaels testified that for most hours in both of Mr. Mitnick's
representative and peak-hour samples, the calculated HHI's and the merger-
induced increases in the HHI's are in the range that triggers concern under both
FERC merger policy and the Guidelines. He stated that this pattern of HHI
increases and sizes persists through the five definitions of relevant market
capacity. (Staff Ex. 22.0, p. 22) Therefore, he conducted an additional analysis
of market factors in accordance with the Guidelines.
d. Analysis of Other Factors Affecting Market Power.
Staff contends that the most important factor that mitigates possible
adverse effects of increased market concentration is transmission access policy.
Dr. Michaels testified that open access with comparable service either
eliminates or mitigates a utility's monopoly power over its own transmission. He
indicated that if markets for the components of full requirements power are
competitive, open access will allow retail customers to compete in such markets
under the same ground rules as transmission
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owners. He concluded that absent any evidence to the contrary, it appears that
the same type of open access provisions that eliminate market power over
wholesale transmission will also do so for retail transmission. (Staff Ex. 22.0,
p.24)
Staff points out that under FERC open access order 888, transmission owners
must serve retail wheeling customers on the same terms under which they serve
themselves and wholesale wheeling customers. Staff indicates that Applicants'
commitment to participate in an ISO arrangement provides further assurance of
nondiscriminatory treatment of retail wheeling customers. (Initial brief on
reopening, p. 11) Dr. Michaels indicated that Ameren's single system open access
tariff may increase the competitive opportunities of retail wheeling customers
in the CIPS area and is unlikely to diminish them. (Staff Ex. 22.0, p. 25)
Dr. Michaels also examined entry conditions facing new sellers of
electricity. He noted that marketer activities in CIPS' service territory have
grown rapidly He noted that in 1996, CIPS sold power to 30 marketers, bought
power from 22, and wheeled electricity for five, while in 1994. CIPS had no
transactions with marketers. He further stated that if the results of the pilot
retail wheeling programs of Illinois Power Company and Central Illinois Light
Company are applicable to CIPS, marketer entry under retail wheeling will be
quick and substantial. He also indicated that Ameren's single system
transmission tariff and ISO will probably facilitate the entry of marketers
seeking retail customers. (Staff Ex. 22.0, p. 26-28)
Dr. Michaels also addressed vertical market power, which is the ability of
a utility that owns generation to prevent market entry of less expensive power
through its control of the transmission system. He indicated that retail
wheeling with open access provides retail customers with numerous power sources
and enables them to circumvent vertical market power in ways that were
previously unavailable. On the other hand, he noted that a merged firm's control
of a larger grid might provide it with more opportunities to exercise vertical
market power. He indicated that regulators can probable ensure that the ISO will
diminish the likelihood of vertical market power. (Staff Ex. 22.0, pp. 28-29)
Dr. Michaels indicated that load pocket problems are closely related to
vertical market power. He stated that the configuration of transmission and the
peculiarities of geography may require that some generation run independently of
market conditions, e.g. to produce reactive power or serve isolated loads. He
indicated that if the capacity is dispatched on the basis of bids, the owner of
a "must run" unit has unavoidable market power. He stated that a merger might
aggravate a load pocket problem by eliminating competition in a load pocket. He
emphasized, however, that there is no evidence of any load pockets in which
competition will be effected by the proposed merger. (Staff Ex. 22.0, pp. 29-30)
Finally, Dr. Michaels addressed the effect on competition of customer
loyalty to the incumbent electric provider. He noted that numerous utilities
have advertising campaigns that advise their customers that they will soon have
choice, but should remain with their
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current supplier. He indicated that loyalty to the existing electric supplier is
not a reason for rejecting the merger. He noted that locally unknown marketers
captured a substantial fraction of industrial users in the retail wheeling pilot
programs in Illinois. He also noted that Public Service Company of New
Hampshire's near state-wide incumbency did not prevent it from losing a
substantial portion of its residential customers during the initial phase of
retail competition in that state. (Staff Ex. 22.0, pp. 30-31)
Dr. Michaels concluded that the merger will not impede in any way the
transition to full retail competition in Illinois. In fact , he indicated that
the merger will increase the benefits of retail competition because it will
widen the market from which retail users in Illinois can choose electric
suppliers. (Staff Ex. 22.0, pp. 33-34)
Dr. Michaels also commented that mandatory divestiture of CIPS' generation
will not noticeably increase retail competition in Illinois. He indicated that
mandatory divestiture is a costly and risky process, whose benefits would be
small at best in light of the fact that CIPS is a minor force in the regional
power market, He also indicated that CIPS should not be denied recovery of
stranded investment as a condition of merger approval. He indicated that
policies regarding stranded investment are best made at the state-wide level. He
further noted that CIPS system has few assets that would be stranded. (Staff Ex.
22.0, p. 35)
Staff recommends that no conditions regarding market power be imposed on
the merger.
4. CUB's Position
a. CUB's Analysis
CUB did not perform an HHI screening analysis in accordance with the
Guidelines. CUB indicates that its witness Shepherd concluded that such an
analysis is of minimal use since he believes that local utilities are likely to
retain over a 70 percent market share and have only a few minor rivals. Dr.
Shepherd indicated that this retention of market share is comparable to the
results from deregulation in other industries. (CUB Ex. WGS-1, p.17) While CUB
did not perform an HHI analysis, it did note that the HHI analyses performed by
Staff and Applicants identified a number of scenarios in which the post-merger
HHI exceeds the thresholds in the Guidelines. For example, CUB points out that
Staff's analysis includes 15 hours in which the post-merger HHI is greater than
1,800 and the increase in the HHI exceeds 100. CUB notes that the Guidelines
indicate that such an increase is "likely to create or enhance market power."
Dr. Shepherd emphasized that the UE-CIPS combination is a horizontal merger
between two utilities that are likely to be important competitors of each other
during and after the expected shift to retail competition. He contended that the
merger, therefore, threatens the prospects for effective competition. He
asserted that effective competition requires a market with limited concentration
and preferably, 8 to 10 comparable rivals. He
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also indicated that the combined Ameren firm will have more resources to protect
its market share in the areas served by UE and CIPS, and repel future
competition from other firms. He maintained that the Commission should not
approve the merger "until it is clear that there is a fully effective
competitive retail electricity market for all customers." (CUB Ex. WGS-1, pp.
2,12-14, and 17-18).
CUB also maintains that utilities have already been acting in an anti-
competitive manner in preparing for a competitive market and are likely to
exercise mutual restraint once the competitive market arrives. Dr. Shepherd
asserted that each utility can probably gain more by staying home and fortifying
its monopoly, rather than encouraging retaliation by invading other areas. (CUB
Ex. WGS-1, p. 11) He also noted that utilities have been locking up large
industrial customers with long-term contracts that have special price discounts.
He indicated that this practice leaves only small and less attractive customers
for new entrants to attract when competition commences. (Id., pp. 14-15) Citing
its Late-Filed Exhibit 1, CUB notes that industrial customers who purchase power
from CIPS through discount contracts used 567 million kWh in 1996, which is
22.6% of total industrial usage. (Initial brief on reopening, p. 6)
In response to Applicant's testimony that here are no significant barriers
preventing entry by new suppliers into electric generation. Dr. Shepherd
indicated that entry requires more than just construction of new capacity. He
emphasized that it requires access to customers, new marketing, packaging by
aggregators, new types of suppliers and mutual invasions by existing suppliers,
all of which may be stopped by retaliation or threats by the existing dominant
firms. (CUB Ex. WGS-1, p. 6)
Dr. Shepherd acknowledged that an open access tariffs and an ISO will help
ensure access to the transmission system of CIPS. He indicated, however, that
they do not ensure that marketers will be able to penetrate CIPS' market on a
retail basis. (CUB Ex. WGS-2, p. 7)
CUB recommends that the Commission require immediate divestiture of
generation as a condition of merger approval if the Commission does not accept
CUB's position that the merger should be denied. CUB asserts that such action is
necessary to protect customers. (Initial brief on reopening, p. 19) Dr. Shepherd
testified that it would be more difficult for the Commission to order the
Applicants to divest assets after the merger is consummated, than before the
merger. He indicated that waiting until after the merger to require divestiture
would be akin to trying to unscramble an egg. (CUB Ex. WGS-1, p. 5).
b. Responses of Applicants and Staff
Applicants and Staff criticize CUB for its failure to perform a merger
analysis in accordance with the Guidelines. They indicate that Dr. Shepherd
failed to engage in any quantitative analysis. (Applicant's initial brief on
reopening on market power issues, p. 20, Staff's initial brief on reopening, pp.
13-14)
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Applicants note that Dr. Shepherd was concerned that the merger of CIPS and
UE would eliminate a competitor from the retail market. Applicants point out
that this is true for any horizontal merger in any industry. They indicate that
if the elimination of a competitor were sufficient justification to deny a
merger, the Guidelines and the structured analysis prescribed thereunder would
have no purpose. (Applicant's Initial brief on reopening on market power
issues, p. 21)
Applicants indicate that Dr. Shepherd conjured up an "ideal market" and
hypothesized CIPS' post-merger market share. This, they explained, is no
substitute for a real analysis of the merger.
Applicants and Staff also criticized Dr. Shepherd for assuming that market
power concerns in other industries are applicable to the instant merger.
(Applicants' initial brief on reopening on market power issues, pp. 25-26,
Staff's initial brief on reopening, p. 14)
Staff notes that CUB relies on its Late-Filed Exhibit 1 as evidence that
CIPS is engaging in anti-competitive behavior by signing industrial customers to
discount rate contracts. Staff asserts that without additional information (e.g.
length of contracts, presence of opt-out clauses, revenue to CIPS, effect on
captive customers if the industrial customers left CIPS system), it is not
possible to conclude whether the contracts are anti-competitive. (Reply brief
on reopening, p. 4)
Staff also notes that CUB recommends in its initial brief that divestiture
of generation assets be imposed as a condition of the merger. Staff indicates
that there is no support in the record for this condition. Staff points out
that no witness, including Dr. Shepherd, advocated approval of the merger on
this condition. (Reply brief on reopening, p. 10)
5. Commission's Conclusion
The Commission notes that some of the HHI market power concentration
indices calculated by Applicants and Staff were above the "safe harbor" limits
set forth in the Guidelines. Under the Guidelines, such results should trigger
examination of other factors that either address the potential for adverse
competitive effect or that could mitigate or counterbalance the potential
competitive harm. Such further analyses were performed in this case. In the
Commission's view, the analyses performed by Applicants and Staff of additional
factors affecting market power sufficiently ameliorate the concerns raised by
the HHI analyses. In particular, their further analyses amply demonstrate that
the merger should be approved with no market power conditions for the following
reasons: (1) Applicants lack control over relevant entry barriers; (2)
Applicants' open access transmission tariff will increase transaction
opportunities; (3) Applicants have committed to form or participate in a
regional ISO; (4) the different terms and conditions under which electricity is
sold make it difficult for multiple competitors to coordinate pricing and
output; (5) CIPS' interconnections with its neighbors are strong; (6) UE and
CIPS together are interconnected with many bulk power suppliers in the region;
and (7) CIPS and UE are in
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a very competitive market for generation. Accordingly, the Commission concludes
that no market power conditions should be imposed on the merger.
The Commission rejects CUB's recommendations to deny the merger or, in the
alternative, to require immediate divestiture of generation as a condition of
the merger. CUB's witness raised some concerns about the emergence of
competition in the early stages of retail wheeling. Drawing on observations
from other industries, Dr. Shepherd argued that the electric generation market
would likely be highly concentrated for some time after the initiation of
retail wheeling. In comparison, the witnesses tendered by Staff and Applicants
have done more thorough analyses that take into account the specific
circumstances and mitigating factors inherent in the electric generation
market. For example, Staff and Applicants have shown that there is a lack of
entry barriers into the retail electric generation market.
To a large extent, CUB relied on speculation and unsupported
generalization. For example, Dr. Shepherd asserted that electric utilities will
essentially collude to maintain high electric rates and that electric utilities
would refrain from competing against each other. Such assertions are completely
unsubstantiated in the record. They also fail to recognize the large number of
utility and non-utility generators that could compete for a given load under
retail wheeling. CUB offers no credible theory to demonstrate the likelihood
that such a large number of potential competitors would be able to so
effectively collude in the manner suggested by CUB.
CUB's position that utilities have already acted in an anti-competitive
manner through the use of discount rates for large industrial customers is also
without merit. This Commission has permitted utilities to use pricing
flexibility for various reasons. First and foremost, discounts have been used
to retain load that would otherwise be lost to co-generation and similar
opportunities facing certain customers. Where the revenues earned by the
utility exceed the cost of serving the specific customer, such discount rates
provide a benefit to the utility and the customer receiving the discount, as
well as the other customers served by the utility. The Commission cannot agree
that any discount from the more standard rates charged by a utility is in any
way proof of anti-competitive practices.
With respect to conditioning the merger on generation divestiture, the
Commission notes that no witness, including CUB's own witness, Dr. Shepherd,
recommended that the Commission so condition this merger. Furthermore, the
Commission finds insufficient justification for imposing the condition of
generation divestiture on the merger approval.
VIII. NO UNJUSTIFIED SUBSIDIZATION OF NON-UTILITY ACTIVITIES
Section 7-204 of the Act provides that before the Commission can approve
any proposed reorganization, it must find that the reorganization will not
result in the unjustified subsidization of non-utility activities by the utility
or its customers. Applicants contend that this requirement will be met by the
proposed merger and reorganization.
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The organizational structure proposed by Applicants consists of the holding
company, Ameren, as the parent company with UE, CIPS and CIC as its three
subsidiaries. Prior to consummation of the merger, Ameren Services Corporation
("Ameren Services") will be incorporated in Missouri to serve as the service
company for the Ameren system. A subsidiary of UE, Union Electric Development
Corporation ("UEDC") will continue to own and invest in certain civic-related
projects.
Mr. Mill and Mr. Craig D. Nelson testified that following the merger,
Applicants will put in place measures to assure that costs are fairly and
reasonably allocated among the affiliated companies and that there will be no
cross-subsidization of one affiliate by another. Each separate corporate
affiliate in the Ameren system will have its own books, accounts and records
maintained in accordance with generally accepted accounting principles, which
will facilitate auditing of costs pertaining to affiliates, according to Mr.
Nelson. Ameren's procedures in this regard will be subject to the SEC's review
and approval. This Commission will also have jurisdiction. Mr. Nelson stated
that CIPS will revise its procedures to the extent necessary to comply with the
SEC's rules and requirements. Mr. Nelson indicated that CIPS has substantial
experience in this area due to its relationship with CIPSCO. He noted that CIPS'
current allocation procedures were approved by the Commission in Docket No. 86-
0256, the proceeding in which the Commission approved the reorganization which
resulted in the formation of CIPSCO. Order, Docket No. 86-0256, p. 38 (Oct. 7,
1987).
The Commission concludes that the evidence establishes that the proposed
merger and reorganization will not result in the unjustified subsidization of
non-utility activities by UE and CIPS or their Illinois ratepayers.
IX. ALLOCATION OF COSTS AND FACILITIES BETWEEN UTILITY AND NON-UTILITY
OPERATIONS
Section 7-204 also requires that before the Commission can approve any
proposed reorganization, it must find that costs and facilities are fairly and
reasonably allocated between utility and non-utility activities in such a manner
that the Commission may identify those costs and facilities which are included
by the utility for ratemaking purposes. Applicants indicate that Ameren will
have procedures in place to allow the Commission to identify specific costs
associated with utility and non-utility activities, and thereby ensure that
costs are fairly and reasonably allocated among such activities.
On December 20, 1995, Ameren, UE, CIPS and CIC entered into a General
Services Agreement (the "initial GSA") under which they propose to provide
services to each other. The initial GSA was admitted into evidence as
Applicants' Exhibit RJM-3 (Rev.). Applicants requested that the Commission find
that the cost allocation principles reflected in the initial GSA were reasonable
and in the public interest.
The initial GSA provided that " . . . each Party shall furnish to any other
Party personnel to provide or assist in providing services, as appropriate in
the performance of
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the purposes of the corporations." Section 2 of the initial GSA provided that
any Party receiving services thereunder "shall reimburse the Providing Party the
Cost of Service for all time spent in the performance of such services." Cost of
Service was defined in Section 2 as "the total reasonable and necessary
compensation paid by the Providing Party to the personnel performing the
services for the time so spent, plus an equitable proportion of the reasonable
and necessary annual overhead expenses of the Providing Party."
Staff witness Smith testified that the lack of specificity in the initial
GSA prevented him from assessing its impact on the parties thereto and
ratepayers. Mr. Smith noted that the initial GSA did not identify the specific
services to be supplied or the parties that will be supplying or receiving
specific services. He further noted that the initial GSA did not contain any
formulas showing how prices would be calculated.
Mr. Smith indicated that if the merger is approved, affiliated transactions
among the parties to the initial GSA would occur immediately after the
consummation of the merger. Therefore, he recommended that the initial GSA be
approved on an interim basis. Mr. Smith further recommended that Applicants be
ordered to submit a new GSA for Commission approval within six months after the
merger is consummated. He testified that the new GSA should identify specific
services and products to be provided, the specific entities receiving the
services and products, and specific formulas for calculating the prices to be
paid. (Staff Ex. 5.00, p. 20)
Applicants' witness Mill testified that Mr. Smith's recommendations are
appropriate. He noted that Applicants have decided to form a service company,
Ameren Services Company. He indicated that Applicants would prepare an addendum
to the interim GSA under which Ameren Services Company would agree to be bound
by the terms of the interim GSA. (App. Ex. RJM-5, p. 2) Staff did not object to
such an addendum.
A. The Commission's Jurisdiction
As noted above, the Commission requested that the parties address in the
reopened record the terms and conditions of Applicants' proposed GSA and the
potential loss of jurisdiction to the Securities and Exchange Commission
("SEC"). These issues were addressed in the reopened record by Applicants and
Staff.
With respect to the Commission's concerns regarding potential loss of
jurisdiction to the SEC, Applicants explained that , to the extent the SEC has
jurisdiction over the GSA and other transactions involving Applicants under the
Public Utility Holding Company Act of 1935 ("PUHCA"), such jurisdiction is
concurrent with, and does not preempt the Commission's jurisdiction over such
transactions under the Public Utilities Act (the "Act").
Applicants indicate that the decision in Ohio Power v. Federal Energy
Regulatory Commission, 954 F. 2d 779 (D.C. Cir. 1992), cert. denied, 506 U.S.
981 (1992) should have no effect on the Commission's jurisdiction and/or
authority over the GSA and any other non-power transactions or agreements that
may occur in the future as a result of the
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consummation of the merger. The Ohio Power case involved an alleged
inconsistency between rulings by the SEC and FERC with respect to certain coal
costs incurred by Ohio Power Company. Applicants indicate that the issue was
whether the SEC'S approval of the price paid by Ohio Power Company for coal
purchased from an affiliated coal producer barred FERC from undertaking an
independent evaluation of the reasonableness of that price for the purpose of
determining the amount of costs recoverable by the utility through its wholesale
fuel adjustment clause ("FAC"). The Court held that, as between the SEC and
FERC, the SEC alone has the authority to review the price of goods purchased by
one registered holding company affiliate from another. Applicants point out that
the Court relied on Section 35.14(a)(7) of FERC's FAC regulations, which
provides in pertinent part:
Where the utility purchases fuel from a company-owned or controlled source,
the price of which is subject to the jurisdiction of a regulatory body,
such cost shall be deemed to be reasonable and includable in the adjustment
clause.
Applicants indicate that the Court had an additional basis for its decision. The
Court noted the contrast between "the SEC's specific statutory mandate [under
Section 13(b) of PUHCA] to establish a cost-based price for sales of goods
between associates" and FERC's "general charge to establish just and reasonable
wholesale electric rates" under the Federal Power Act. Applicants note that the
Court stated that "of course, it is black letter law that when a conflict arises
between specific and general provisions of the same legislation, the courts
should give voice to Congress' specific articulation of its policies and
preferences." 954 F. 2d at 784.
In concluding that the Ohio Power decision should have no effect on the
Commission's jurisdiction over the GSA and any other non-power agreements or
transactions that may occur as a result of the merger, Applicants emphasize that
Ohio Power does not address the question of whether and to what extent the SEC's
jurisdiction over transactions among subsidiaries of registered holding
companies preempts the authority of state regulatory agencies to regulate such
transactions or review the reasonableness of costs incurred pursuant to such
transactions.
Applicants state that there is no statement of congressional intent in
PUHCA to preempt state regulatory authority over public utilities in holding
company systems. Applicants indicate that PUHCA expressly provides for
concurrent state and federal regulation and reflects Congress' intent to
"restore effective state regulation." North American Co. v. SEC, 327 U.S. 686,
704 (1946); Indiana and Michigan Power Company v. State, 275 N.W. 2d 450, 454
(Mich. 1979)
Applicants further indicate that courts and state regulatory agencies have
uniformly held that states retain the power to review and disallow costs
associated with affiliated transactions, notwithstanding the SEC's authority
under PUHCA to approve the underlying contracts. Applicants cite, among other
decisions, Blackstone Valley Elec. Co. v. Public Utilities Comm'n, 486 A. 2d
617, 618-19 (R. I. 1985)
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Applicants state that, to the extent the Commission continues to have
concerns regarding potential preemption of its authority with respect to
affiliated interest transactions, such concerns should be eliminated by the
adoption of the jurisdictional conditions which the Applicants have previously
indicated they would accept. Applicants indicate that those conditions, which
have already been approved by the Missouri Public Service Commission, are
substantially the same as conditions recently accepted in similar circumstances
by several other state commissions. (Initial brief on reopening regarding
affiliate transaction issues, pp. 2 and 22-26) The jurisdictional conditions
agreed to by Applicants are set forth in the Appendix to this Order.
Staff similarly concluded that the SEC's jurisdiction over the GSA is
concurrent with that of the Commission. (Initial brief on reopening, pp. 24-30).
Staff also noted the Applicant's commitment to abide by the jurisdictional
conditions mentioned above.
The Commission concludes that, to the extent the SEC has jurisdiction over
the GSA and other transactions involving Applicants under PUHCA, such
jurisdiction is concurrent with, and does not preempt, the Commissions'
jurisdiction over such transactions under the Public Utilities Act. The
Commission accepts the Applicants' commitment to abide by the jurisdictional
conditions set forth in the Appendix to this Order.
B. The Revised GSA
In the reopened record, Applicants submitted a more detailed GSA in
response to the concerns of Staff witness Smith regarding lack of specificity in
the original GSA. The revised GSA was admitted into evidence as Applicants' Ex.
WLB-2. Applicants' witness Baxter described the terms of the revised GSA. Mr.
Baxter testified that the revised GSA sets forth the terms and conditions under
which Ameren Services Company agrees to perform services for Ameren Corporation
and its subsidiaries. Section 8 of the revised GSA states that companies within
the Ameren system are not prohibited from performing services for each other.
Mr. Baxter indicated that this situation is expected to occur infrequently. He
indicated that if such services are provided, they will be provided under the
same conditions and terms as set out for Ameren Services Company. Schedule 1 of
the revised GSA lists the expected services to be provided by each
function/department of Ameren Services Company.
Section 3 of the revised GSA provides that Ameren Services Company shall be
paid the cost of the services it provides, computed in accordance with
applicable SEC rules and regulations. Section 3 indicates that the compensation
to be paid shall include direct charges and allocated costs. Schedule 2 sets
forth the expected allocation factors that will be used to allocate direct
costs. Mr. Baxter described the method for allocating indirect costs, which he
described as those costs of a general overhead nature that cannot be separately
identified to a single or group of companies within the Ameren system. He
indicated that departmental indirect costs will be allocated to Ameren
Corporation and its subsidiaries based on the ratio of total direct and
allocated direct costs charged to each company by each Ameren Services Company
department. He stated that corporate
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indirect costs will be allocated on the basis of total billings to Ameren
Corporation and its subsidiaries. (Applicants' Ex. WLB-1, pp. 3-4)
Staff witness Smith testified that the SEC's criteria for determining cost
(17 CFR 250.91) is consistent with the Commission's policy. (Staff Ex. 21.0, pp.
8-9) Mr. Baxter indicated that he is unaware of any significant differences
between the SEC's policy on cost and that which could be utilized by the
Commission in any rate proceeding. (Applicants' Ex. WLB-1, p.15)
The only objection raised by Mr. Smith as to the provisions of the revised
GSA concerns Applicants' proposed use of revenues as a cost allocation factor.
Mr. Smith testified that revenues should not be used as an allocation factor
since they reflect prices paid, rather than cost incurred. (Staff Ex. 21.0, pp.
6-8) In response, Mr. Baxter indicated that Applicants will not use revenues as
an allocation factor. (Applicants' Ex. WLB-4, p. 6)
The Commission concludes that the revised GSA is reasonable and in the
public interest and should be approved on the condition that revenues should not
be used as a factor to allocate costs thereunder.
C. Other Matters
Mr. Smith recommended that the relevant books and records of Ameren
corporation and its affiliates, as well as the independent auditor's workpapers
as needed by Staff, be made available either in the Springfield or St. Louis
offices of Applicant. (Staff Ex. 21.0, p. 2) Applicants agreed to this
recommendation. Mr. Baxter indicated that to the extent there are relevant books
and records at other locations, Applicants would work with Staff to make them
available in Springfield, St. Louis, or elsewhere, if mutually acceptable.
(Applicants' Ex. WLB-4, p.2)
Staff initially requested that Applicants maintain separate sub-accounts
for all accounting entries resulting from transactions with affiliates.
Applicant's accounting system does not allow for the maintenance of records in
this manner. Applicants indicated that their accounting system does enable them
to identify the specific affiliated company source of each charge to each
account, and that this information would be available to Staff, potentially
within one day after the Applicants' books are closed at the end of each month.
Staff agreed to Applicants' proposal. (Staff Ex. 21.0, p. 6; Applicants Ex. WLB-
4, pp. 5-6)
Staff recommended that the Commission require, as a condition of the
approval of the GSA and the proposed reorganization, that Staff should be
provided access to all books and records of CIPS,UE and their affiliates to
enable Staff to determine whether there have been any transactions with or
impact on CIPS or UE. (Initial brief on reopening, pp. 19-20) Staff witness
Smith testified that this condition is necessary to enable Staff to verify
charges and allocations under the GSA and to protect against the subsidization
of non-utility activities by CIPS, UE or their customers. Mr. Smith explained
that Ameren Services Company could possibly perform services for a non-utility
company and fail to
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charge it for appropriate costs. He indicated that Staff could potentially
discover this failure by inspecting the records of Ameren and its affiliates.
(Staff Ex. 21.0, pp. 3-4) Staff stated that if its proposed condition is not
adopted, it cannot conclude that the requirements of Sections 7-204(b) and (c)
of the Act have been met (i.e., that the proposed reorganization will not result
in the unjustified subsidization of non-utility activities by CIPS, UE or its
customers, and that costs are fairly and reasonably allocated between utility
and non-utility activities). (Initial brief on reopening, p. 19)
Staff indicated that the Commission has previously approved the same scope
of Staff access to the books and records of affiliated interests in MidAmerican
Energy Company (Order in Docket No. 95-0353, September 5, 1996) Staff indicated
that the Commission , over MidAmerican's objection, granted Staff access to all
the books and records of MidAmerican's affiliated interests to enable Staff to
determine whether there have been transactions between its affiliates and
MidAmerican or any impact on MidAmerican. The requested access was imposed as a
condition of the approval of affiliated interest contacts pursuant to Section 7-
101(3) of the Act. Staff notes that the Commission concluded (Order, p. 19):
The recommended access is necessary to enable Staff to ascertain
whether there has been an unjustified subsidization of non-utility
activities and to determine whether costs are fairly and reasonably
allocated between utility and non-utility activities. The Commission fails
to see how the requested access is inconsistent with Section 7-101(2) of
the Act.
Applicants agreed to provide the access to books and records requested by
Staff, subject to Applicants' reservation of the right to object to the
production of documents on any basis under applicable law and Commission rules.
Staff opposes this reservation of rights, characterizing it as a "red herring.".
Staff witness Smith testified that Staff requires access to all of the books and
records of UE, CIPS and their affiliates and opposes any limitation on such
access. (Staff Ex. 21.0, pp. 4-5)
In response, Applicants pointed out that Staff's request for records may
include documents covered by the attorney-client privilege or the attorney work
product doctrine. They stated that disclosure of such information could
constitute a waiver of a privilege with respect to other parties. They indicated
that they should not be required to sacrifice their due process rights. They
indicated that if Staff has a problem with a particular objection to a request
for documents, Staff can bring the objection before the Commission for a
resolution. (Applicants' initial brief on reopening regarding affiliate
transaction issues, pp. 36-37)
Applicants also contended that the MidAmerican case cited by Staff involved
a different situation. Applicants indicated that the issue there was whether
Staff was entitled to review the books and records of affiliates that did not
have transactions with the utility. Applicants stated that they do not contest
access to such materials. Rather, they asserted
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that they have raised the narrower point of reserving the right to object under
applicable law and Commission rules. (Reply brief on reopening, p 12)
The Commission concludes that Staff's requested access to the books and
records of CIPS, UE and their affiliates should be approved, subject to the
reservation of Applicants' right to object to the production of documents on any
basis under applicable law and Commission rules. Applicants cannot be required
to produce documents to Staff if such production is contrary to law or
Commission rules. If Applicants object in the future to the production of
documents and Staff determines that the objection has no merit, Staff can bring
the objection before the Commission. If the Commission finds that Applicants'
objection is not well-founded, the Commission can compel Applicants to produce
the requested material.
Applicants also request that the Commission terminate, upon consummation of
the merger, certain conditions for transactions among CIPS and its affiliates
that the Commission established in its Order on Reopening in Docket No. 86-0256,
the proceeding in which the Commission approved the establishment of CIPSCO as
the holding company for CIPS. In this context, the Commission defined affiliate
to include "only [CIPSCO] and any non-utility company a majority of whose stock
is owned by [CIPSCO]." Order on Reopening, p. 16. Applicants made this request
in light of the new arrangements that will be required by the merger, which are
subject to the approval of the SEC and this Commission. Staff witness Smith
agreed that the conditions imposed in Docket No. 86-0256 should be terminated.
No party objected to the termination of those conditions.
The Commission finds that the conditions for transactions among CIPS and
its affiliates established in the Order on Reopening in Docket No. 86-0256 are
no longer appropriate and should be terminated.
The Commission finds that the evidence demonstrates that the Applicants
will maintain such procedures and controls as are required by the Act to permit
a fair and reasonable allocation of costs and facilities between utility and
non-utility operations.
X. ABILITY TO RAISE CAPITAL ON REASONABLE TERMS AND TO MAINTAIN A REASONABLE
CAPITAL STRUCTURE
Section 7-204 provides that before the Commission can approve a proposed
reorganization, the Commission must further find that "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." Additionally, Section 6-103 of the Act provides that, in any
reorganization of a public utility, "the amount of capitalization [of the public
utility], including . . . all stocks and stock certificates and bonds, notes and
other evidences of indebtedness, shall be such as is authorized by the
Commission." Section 6-103 also requires that, in approving the utility's
capitalization in a reorganization, the Commission must find that the amount of
capitalization does not exceed the fair value of the property involved.
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Applicants offered evidence that CIPS and UE should be able to attract
capital on favorable terms and conditions after the merger. Applicants' witness
Craig D. Nelson testified that CIPS' financial position as a high-quality credit
risk should remain stable, and that CIPS' debt should be attractive to
investors. (App. Ex. CDN-1, p. 7) According to Applicants' witness Birdsong,
UE's position is similarly attractive. Further, evidence offered by Applicants
indicated that the increased market capitalization and earning power of Ameren
will make its equity more attractive to investors. Mr. Nelson indicated that the
predictability of dividend practice provides an additional element of stability.
Evidence submitted by Applicants shows that both CIPS and UE have
conservative capital structures, consistent with a AA first mortgage bond
rating. Applicants' Exhibit CDN-3 indicates that as of June 30, 1995, CIPS'
capital structure consisted of common equity 50.2%, preferred stock 7.1% and
long-term debt 42.7%, while UE's capital structure consisted of common equity
52.1%, preferred stock 5.1% and long-term debt 42.8%. The merger will produce
only minor changes in those capital structures, and the post-merger capital
structures will be reasonable, according to Mr. Nelson and Mr. Koertner.
Applicants presented their proposed capital structure and forecasted
capital requirements in Exhibits CDN-4, CDN-6, JEB-8 and JEB-9. No party raised
an objection to the Applicants' proposed capital structures.
The Commission finds that the proposed merger will not significantly impair
the ability of CIPS and UE to raise necessary capital on reasonable terms or to
maintain a reasonable capital structure. The Commission further finds that the
capitalization proposed for CIPS and UE is reasonable and should be approved for
purposes of the reorganization only. The amounts of the capitalization for CIPS
and UE do not exceed the fair market values of their respective properties. The
Commission makes no finding with regard to the reasonableness of CIPS' or UE's
capital structure for ratemaking purposes.
XI. CIPS AND UE WILL REMAIN SUBJECT TO ALL APPLICABLE LAWS, REGULATIONS, RULES,
DECISIONS AND POLICIES GOVERNING THE REGULATION OF ILLINOIS PUBLIC
UTILITIES
Before it can approve a proposed reorganization, the Commission must find
that "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(e). Since Applicants' proposed transfer of the
service area from UE to CIPS has been denied, both CIPS and UE will continue to
be regulated as Illinois public utilities after the merger and reorganization.
The Commission finds that CIPS and UE will be subject to the laws, regulations,
rules, decisions and policies governing the regulation of Illinois public
utilities after the merger and reorganization.
XII. THE JOINT DISPATCH AGREEMENT
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CIPS and UE will jointly dispatch their electric generating resources
pursuant to a Joint Dispatch Agreement. (App. Ex. GWM-6 (Rev.)) They require the
Commission's approval to enter into the Joint Dispatch Agreement pursuant to
Section 7-101(3) of the Act.
Applicants' witness Moorman testified that the Joint Dispatch Agreement
will allow CIPS and UE to achieve substantial economies, which were estimated to
be approximately $92 million over the next ten years.
In its brief on exceptions to the Hearing Examiner's Second Proposed Order,
QST contended that the Commission lacked jurisdiction to approve the Joint
Dispatch Agreement. QST's exceptions in this regard are beyond the scope of
exceptions to the Second Proposed Order. The parties were instructed to only
address the issues considered in the reopened record of this proceeding. The
time for submitting exceptions pertaining to the Joint Dispatch Agreement has
long since passed. Therefore, QST's exceptions on this issue will not be
considered.
The Commission finds that the entry of CIPS and UE into the Joint Dispatch
Agreement is prudent, reasonable, and in the public interest and consents
thereto.
XIII. FINDINGS AND ORDERING PARAGRAPHS
The Commission, having considered the entire record, is of the opinion and
finds that:
CIPS is an Illinois corporation providing electric and natural gas services
in Illinois as a public utility within the meaning of the Act;
(1) Union Electric is a Missouri corporation providing electric and
natural gas services in Illinois as a public utility within the
meaning of the Act;
(2) CIPSCO is an Illinois corporation formed as the holding company parent
of CIPS;
(3) Ameren was formed by CIPSCO and UE for the purpose of consummating the
proposed merger and reorganization and becoming the public utility
holding company for UE and CIPS after the merger;
(4) the Commission has jurisdiction over CIPS, CIPSCO and UE and over the
subject matter hereof;
(5) the recitals of fact and conclusions reached in the prefatory portion
of this Order are supported by the evidence of record and are hereby
adopted as findings of fact;
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(6) the evidence demonstrates that the proposed merger should reasonably
be granted and that the public will be convenienced thereby;
(7) the Applicants have supplied the information required of them by
Section 7-204A of the Act;
(8) the proposed merger and reorganization meets the criteria set forth in
Section 7-204 of the Act in that:
(a) the proposed merger and reorganization will not diminish the
ability of CIPS and UE to provide adequate, reliable, efficient,
safe and least-cost public utility service;
(b) the proposed merger and reorganization will not result in
unjustified subsidization of non-utility activities by CIPS and
UE or its customers;
(c) costs and facilities will be fairly and reasonably allocated
between utility and non-utility activities in a manner such that
the Commission may identify those costs and facilities which are
properly included by UE and CIPS for ratemaking purposes;
(d) the proposed merger and reorganization will not significantly
impair the ability of CIPS and UE to raise necessary capital on
reasonable terms or to maintain a reasonable capital structure;
(e) CIPS' and UE's Illinois utility operations will be subject to all
applicable laws, regulations, rules, decisions and policies
governing the regulation of Illinois public utilities;
(1) the joint application of CIPSCO, CIPS and UE for approval of the
merger and reorganization should be approved subject to the following
conditions that are necessary to protect the interests of CIPS, UE and
their customers:
(a) Applicants' proposed merger cost recovery and sharing savings
plan is not approved;
(b) CIPS and UE shall file a rate case or alternative regulatory plan
within six months after the closing of the merger; CIPS and UE
shall 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;
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(c) Applicants' proposed transfer of UE's existing Illinois electric
and gas service area and certain related facilities to CIPS is
not approved;
(d) Applicants shall abide by the jurisdictional conditions set forth
in the Appendix to this Order;
(e) Applicants shall provide access to Staff to all the books and
records of CIPS, UE and their affiliates, subject to Applicants'
reservation of the right to object to the production of documents
on any basis under applicable law and Commission rules;
(2) the reorganization, consisting of the merger of CIPSCO into Ameren and
UE with Arch Merger, is in the public interest and the consent,
authority and approval of this Commission should be granted for the
proposed reorganization, and the performance of the Merger Agreement,
subject to the conditions set forth in Finding (10);
(3) if legislation becomes effective that would arguably affect the
Commission's authority to require that UE and CIPS file a rate case or
alternative regulatory plan within six months after the consummation
of the merger, UE and CIPS should file a petition with the Commission
requesting that this requirement be modified or eliminated, as
appropriate;
(4) the revised General Services Agreement, in the form of Applicants'
Exhibit WLB-2, is reasonable and in the public interest and should be
approved, subject to the condition that revenues shall not be used as
a factor to allocate costs thereunder and to condition (e) in Finding
(10) above;
(5) the conditions for transactions among CIPS and its affiliates that are
contained in the Order in Docket No. 86-0256 (the Order in which CIPS
was permitted to reorganize by establishing CIPSCO as its holding
company) are no longer appropriate and, therefore, no longer required;
(6) the Joint Dispatch Agreement, which would govern the allocation of
costs and revenues related to the central dispatch of the combined
CIPS and UE generating resources, is reasonable and should be
approved; the Commission hereby consents to CIPS' and UE's entry into
such agreement;
(7) CIPS' and UE's post-merger capitalization is hereby approved for
purposes of the merger and reorganization, but not for ratemaking
purposes;
(8) the accounting for the merger by the "pooling of interests" method is
appropriate and should be approved;
(9) the proposed merger and reorganization are unlikely to have a
significant adverse impact on the competitiveness of existing and
future Illinois retail
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<PAGE>
markets; it is not necessary or appropriate to impose conditions on
the merger in order to address any market power concerns;
(10) consent, authority and approval of the Commission should be granted to
CIPS, CIPSCO, UE and Ameren, to the extent necessary, to do any and
all other things not contrary to law or to the rules and regulations
of the Commission or inconsistent with the Application that are
incidental, necessary or appropriate to the performance of any and all
acts specifically authorized by the Commission in this Order.
IT IS THEREFORE ORDERED that consent, authority and approval are hereby
granted for the merger and reorganization of CIPSCO Incorporated, Central
Illinois Public Service Company, Union Electric Company, Ameren Corporation and
Arch Merger, Inc., by virtue of the merger of CIPSCO Incorporated with Ameren
Corporation and Union Electric Company with Arch Merger, Inc., with Ameren
Corporation remaining as the surviving holding company and Central Illinois
Public Service Company and Union Electric Company remaining as public utilities
in Illinois, subject to the conditions set forth in Finding (10) hereinabove.
IT IS FURTHER ORDERED that consent, authority and approval are hereby
granted for the performance of the Merger Agreement, subject to the conditions
set forth in Finding (10) hereinabove.
IT IS FURTHER ORDERED that Central Illinois Public Service Company and
Union Electric Company shall file with the Commission written notice of
completion of the merger and the effective date thereof within 30 days after the
effective date of the merger.
IT IS FURTHER ORDERED that Union Electric Company and Central Illinois
Public Service Company shall comply with the requirement in Finding (12) of this
Order.
IT IS FURTHER ORDERED that the revised General Services Agreement, in the
form of Applicants' Exhibit WLB-2, is hereby approved, subject to the conditions
set forth in Finding (13) of this Order.
IT IS FURTHER ORDERED that the entry by Central Illinois Public Service
Company and Union Electric Company into the Joint Dispatch Agreement, which
would govern the allocation of costs and revenues related to the central
dispatch of the combined Central Illinois Public Service Company and Union
Electric Company generating resources, is hereby approved.
IT IS FURTHER ORDERED that CIPS' and UE's post-merger capitalization is
hereby approved for purposes of the merger and reorganization, but not for
ratemaking purposes.
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IT IS FURTHER ORDERED that the conditions for transactions among Central
Illinois Public Service Company and its affiliates which are contained in the
Order in Docket No. 86-0256 are hereby terminated.
IT IS FURTHER ORDERED that Ameren Corporation is hereby authorized to
account for the merger by the "pooling of interests" method.
IT IS FURTHER ORDERED that consent, authority and approval of the
Commission is granted to CIPSCO Incorporated, Central Illinois Public Service
Company, Union Electric Company and Ameren Corporation, to the extent necessary,
to do any and all other things not contrary to law or to the rules and
regulations of the Commission or inconsistent with the Application that are
incidental, necessary or appropriate to the performance of any and all acts
specifically authorized by the Commission in this Order.
IT IS FURTHER ORDERED that subject to the provisions of Section 10-113 of
the Public Utilities Act and 83 Ill. Adm. Code 200.880, this order is final; it
is not subject to the Administrative Review Law.
By order of the Commission this 10th day of September, 1997.
Chairman
APPENDIX
The Applicants will not object if the Commission approves the Merger
subject to the following two conditions:
1. Retail Rate Authority.
All contracts, agreements, tariffs or arrangements, including any
amendments thereto, of any kind between CIPS or UE and any Affiliated
Interest(s), as that term is defined in the Illinois Public Utilities Act,
that are required to be filed with and/or approved by the SEC pursuant to
the Public Utilities Holding Company Act, and/or FERC, pursuant to the
Federal Power Act, as hereinafter amended, or the Natural Gas Act, as
hereinafter amended, shall be conditioned upon the following without
modification or alteration: Neither CIPS, UE, nor any Affiliated Interest
will seek to overturn, reverse, set aside, change or enjoin, whether
through appeal or the initiation
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or maintenance of any action in any forum, a decision or order of the
Illinois Commission which pertains to recovery, disallowance, deferral or
ratemaking treatment of any expense, charge, cost or allocation incurred or
accrued by CIPS or UE in or as a result of a contract, tariff, agreement,
arrangement or transaction with any Affiliated Interest on the basis that
such expense, charge, cost or allocation has itself been filed with,
accepted for filing, made effective or approved by the SEC and/or FERC or
was incurred pursuant to a contract, tariff, arrangement, agreement or
allocation method which was filed with, accepted for filing, made effective
or approved by the SEC and/or FERC.
2. Affiliated Interest Authority.
CIPS and UE will file with Illinois Commission all contracts, tariffs,
agreements, arrangements or transactions between CIPS or UE and any
Affiliated Interest(s) that require approval under Section 7-101 of the
Illinois Public Utilities Act, irrespective of whether such contracts,
tariffs, agreements, arrangements or transactions have been filed with,
accepted for filing, made effective or approved by or are otherwise subject
to the jurisdiction of the SEC and/or FERC. Neither CIPS, UE, nor any
Affiliated Interest will 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 Illinois Commission under
Section 7-101 of the Illinois Public Utilities Act, as hereinafter amended,
which pertains to a contract, tariff, agreement, arrangement or transaction
between CIPS or UE and any Affiliated Interest on the basis that such
contract, tariff, agreement, arrangement or transaction has been filed
with, accepted for filing, made effective or approved, or is otherwise
subject to the jurisdiction of the SEC and/or FERC.
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STATE OF ILLINOIS
ILLINOIS COMMERCE COMMISSION
Central Illinois Public Service Company )
CIPSCO Incorporated )
Union Electric Company ) 95-0551
)
Joint application for approval of merger )
and reorganization. )
CONCURRING OPINION
------------------
October 8,1997, concurring opinion filed by Commissioner Brent Bohlen to the
Order entered September 10,1997:
The Applicants introduced considerable evidence about cost savings that
will be attained through the proposed reorganization and merger. In its order
the Commission concludes that the proposal meets the required public convenience
standard because the benefits to Illinois ratepayers from those cost savings are
reasonably likely to exceed the burdens to those ratepayers. Those benefits
would flow to ratepayers as a result of the rate case or alternative regulation
proceeding that the companies have committed to file and that the Commission has
required in its order.
I am troubled, however, by the need to include the following finding in the
Finding and Ordering Paragraphs of the order:
(12) if legislation becomes effective that would arguably affect the
Commission's authority to require that UE and CIPS file a rate case or
alternative regulatory plan within six months after the consummation
of the merger, UE and CIPS should file a petition with the Commission
requesting that this requirement be modified or eliminated, as
appropriate;
The Applicants raised the issue of the need for such a paragraph in APPLICANTS'
INITIAL BRIEF ON REOPENING ON MARKET POWER ISSUES, June 25,1997, page 25,
footnote 10. The pending legislation that raised the issue was Senate Bill 55,
which passed the Illinois House last spring. (See APPLICANTS' REPLY BRIEF
REGARDING EXCEPTIONS TO SECOND HEARING EXAMINER'S PROPOSED ORDER, page 7.) The
language of Senate Bill 55 apparently referenced is:
Sec. 16-111. Rates and restructuring transactions during mandatory
transition period. (a) During the mandatory transition period, ... , the
Commission shall not ... (iii) in any
<PAGE>
order approving any application for a merger pursuant to 7-204 that was
pending as of May 16,1997, impose any condition requiring any filing for
an increase, decrease, or change in, or other review of, an electric
utility's rates;
The apparent reason for the language is to prevent a company from having to take
a "double hit" of electric rate decreases, one from the rate case or alternative
regulatory proceeding that would pass certain savings on to customers and a
second from the residential rate reduction provisions of Sec. 16-111(b).
With respect to this issue, it is important to note that Sec. 16-111(b) in
Senate Bill 55 includes the following language:
Provided, further, that any electric utility for which a decrease in base
rates has been or is placed into effect between October 1,1996 and the
dates specified in the preceding sentences of this subsection, other than
pursuant to the requirements of this subsection, shall be entitled to
reduce the amount of any reduction or reductions in its base rates required
by this subsection by the amount of such other decrease.
This language is apparently in response to the decreases in electricity base
rates of MidAmerican Energy Company (MidAmerican) ordered by the Commission
since October 1, 1996. MidAmerican was formed by the merger of Iowa-Illinois Gas
and Electric Company and Midwest Resources (See Docket No. 94-0439.). The
Commission's order in that merger led to the filing by MidAmerican of an
alternative regulatory proceeding (See Docket No. 96-0274.), which in turn led
to the Commission's filing of Docket No. 96-0510. In Docket No. 96-0510 the
Commission ordered MidAmerican to decrease its rates by approximately 12
percent. The above language in Sec. 16-111(b) would allow ratepayers to enjoy
the merger benefits but would allow the company to credit those rate decreases
against any rate cuts ordered by Sec. 16-111(b). This prevents the company from
getting a "double hit" of rate decreases on top of rate decreases.
One might suggest that it makes no difference whether the decrease comes
from a rate case or from restructuring legislation. But there are two important
differences. First, unless the rate case or alternative regulatory proceeding
is actually done, one will not know the amount by which the rates would be
decreased by such proceeding. The decreases might exceed those required in
Senate Bill 55-style legislation. In MidAmerican the rate decreases as a result
of the merger were about 12 percent. Second, and more important to some
portions of the customer base, as currently written Senate Bill 55 provides
mandatory rate decreases only for residential customers. Rate decreases as a
result of a rate case or alternative regulatory proceeding presumably would be
allocated to commercial and industrial customers as well as residential
customers.
I have some difficulty identifying entities that would have an interest in
seeing that the language in Sec. 16-111(a)(iii) above is included in
restructuring legislation. It would seem that only a party with a pending
electric utility merger application before the Commission would have such an
incentive. I believe that the instant application was the only electric utility
merger case pending before the Commission on May 16, 1997. Could it be possible
that the Applicants
2
<PAGE>
would seek legislative action that would vitiate their commitment to the
Commission to file a rate case or alternative regulatory proceeding while the
instant case was still pending? I trust not.
Perhaps the potential move to a new regulatory environment would cause
parties situated similarly to the Applicants to reconsider their commitment.
But if that were the case, wouldn't such a party come before the Commission to
amend or qualify its commitment to reflect this new position and afford the
Commission the opportunity to properly weigh whether the standard for approval
of the application is met under this new position? I trust so.
It should be noted that the commitment to pass cost savings on to
ratepayers by filing a rate case or alternative regulatory proceeding following
approval of the instant application was also made by Central Illinois Public
Service Company in its recent successful attempt to get Commission approval of
certain actions in Docket No. 96-0345, which provided the utility with many
millions of dollars in cost savings. (See CIPS Ex. WAK-8 at page 5 and CIPS Ex.
RJM-5 at pp. 4-5 of Docket No. 96-0345.) The rate case or alternative
regulatory proceeding ordered in the instant docket also would pass benefits
from the approval of Docket No. 96-0345 on to ratepayers.
Given the state of the record, with the commitment to file a rate case or
alternative rate proceeding presented at least three times under oath in two
separate proceedings, I can only assume that the Applicants intend to honor
their word and that they have done nothing and will do nothing to influence
legislation to in any way interfere with their commitment. I therefore concur
with this Order's approval of the application and merger. But without the
promised rate case or alternative regulatory proceeding, I have serious concern
as to whether the public convenience standard would be met in the instant
proceeding.
It would seem that parties situated similarly to the Applicants could seek
to have language adopted in restructuring legislation that would treat
Commission-ordered merger rate case decreases in a manner like MidAmerican's
rate decreases. In that way such applicants could keep their commitment to the
rate case or alternative regulatory proceeding to allow all customers (i.e.
commercial and industrial as well as residential) to benefit from the merger
savings, and at the same time the credit for those decreases would protect such
applicants from a "double hit" of rate decreases.
3
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Exhibit D-4.2
UNITED STATES OF AMERICA
------------------------
NUCLEAR REGULATORY COMMISSION
-----------------------------
In the Matter of )
)
UNION ELECTRIC COMPANY ) Docket No. 50-483
)
(Callaway Plant. Unit 1) )
ORDER APPROVING APPLICATION REGARDING THE CORPORATE MERGER
AGREEMENT BETWEEN UNION ELECTRIC COMPANY AND CIPSCO
INCORPORATED TO FORM A HOLDING COMPANY
I.
Union Electric Company (UEC) is sole owner of Callaway Plant, Unit 1, UEC
holds Facility Operating License No. NPF-30 issued by the U.S. Nuclear
Regulatory Commission (NRC) pursuant to Part 50 of Title 10 of the Code of
Federal Regulations on October 18, 1984. Under this license, UEC has the
authority to own and operate Callaway Plant, Unit 1. Callaway Plant is located
in Callaway County, Missouri.
II.
By letter dated February 23, 1996, as supplemented by letters dated April
24, 1996, and November 15, 1996. UEC informed the Commission that it had
entered into a merger agreement with CIPSCO Incorporated (CIPSCO) which would
provide for UEC to become a wholly-owned operating company of Ameren Corporation
(Ameren). Ameren was formed to implement the merger agreement, and is presently
owned equally by UEC and CIPSCO. Under the merger agreement, current holders of
common stock in Ameren. UEC requested, to the extend necessary, the
Commission's approval, pursuant to 10 CFR 50.80. Notice of this application for
approval was published in the FEDERAL REGISTER on June 10, 1996 (61 FR 29434),
and an
<PAGE>
Environmental Assessment and Finding of No Significant Impact was published in
the FEDERAL REGISTER on November 22, 1996 (61 FR 59469).
Under 10 CFR 50.80, no license shall be transferred, directly or
indirectly, through transfer of control of the license, unless the Commission
shall give its consent in writing. Upon review of the information submitted in
the letter of February 23, 1996, as supplemented by letters dated April 24,
1996, and November 15, 1996, and other information before the Commission, the
NRC staff has determined that consummation of the merger agreement between UEC
and CIPSCO, resulting in UEC becoming a wholly-owned subsidiary of a holding
company. Ameren, will not affect the qualifications of UEC as holder of the
license for Callaway Plant, and that the transfer of control of the license, to
the extent effected by the consummation of the merger agreement between UEC and
CIPSCO, is otherwise consistent with applicable provisions of law, regulations,
and orders issued by the Commission, subject to the conditions set forth herein.
These findings are supported by the Safety Evaluation dated October 16, 1997.
III.
Accordingly, pursuant to Section 161b, 161i, 161o, and 184 of the Atomic
Energy Act of 1954, as amended, 42 USC 2201(b), 2201(i), 2201(o) and 2234, and
10 CFR 50.80. IT IS HEREBY ORDERED that the Commission approves the application
regarding the merger agreement between UEC and CIPSCO, under which Ameren will
become the holding company of UEC, subject to the following: (1) UEC shall
provide the Director of the Office of Nuclear Rector Regulation a copy of any
application, at the time it is filed, to transfer (excluding grants of security
interests or liens) form UEC to its proposed parent or to any other affiliated
company, facilities or other assets for the production, transmission, or
distribution of electric energy having a depreciated book value exceeding ten
percent (10%) of UEC's consolidated net utility plant, as
2
<PAGE>
recorded on UEC's books of account; and (2) should the merger agreement between
UEC and CIPSCO not be implemented by September 30, 1998, this Order shall become
null and void, provided, however, on application and for good cause shown, such
date may be extended.
This Order is effective upon issuance.
IV.
By November 21, 1997, any person adversely affected by this Order may file
a request for a hearing with respect to issuance of the Order. Any person
requesting a hearing shall set forth with particularity how that interest is
adversely affected by this Order and shall address the criteria set forth in 10
CFR 2.714(d).
If a hearing is to be held, the Commission will issue an order designating
the time and place of such hearing.
The issue to be considered at any such hearing shall be whether this Order
should be sustained.
Any request for a hearing must be filed with the Secretary of the
Commission, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001,
Attention: Rulemakings and Adjudications Staff, or may be delivered to 11555
Rockville Pike, Rockville, Maryland between 7:45 am and 4:15 pm Federal
workdays, by the above date. Copies should be also sent to the Office of the
General Counsel, and to the Director, Office of Nuclear Reactor Regulation, U.S.
Nuclear Regulatory Commission, Washington, DC 20555, and to Gerald Charnoff,
Esquire/Thomas A. Baxter, Esquire, Shaw, Pittman, Potts & Trowbridge, 2300 N.
Street, N.W., Washington, D.C. 20037, attorneys for UEC.
For further details with respect to this Order, see the application dated
February 23, 1996, and supplemental letters dated April 24, 1996 and November
15, 1996, which are available for
3
<PAGE>
public inspection at the Commission's Public Document Room, the German Building,
2120 L Street, NW., Washington, D.C. and at the local public document room
located at the Callaway County Public Library, 710 Court Street, Fulton,
Missouri 65251.
FOR THE NUCLEAR REGULATORY COMMISSION
Samuel J. Collins, Director
Office of Nuclear Reactor Regulation
Dated at Rockville, Maryland,
this 16th day of October 1997
4
<PAGE>
UNITED STATES NUCLEAR REGULATORY COMMISSION
-------------------------------------------
UNION ELECTRIC COMPANY
----------------------
CALAWAY PLANT, UNIT 1
---------------------
DOCKET NO. 50-483
-----------------
POST OPERATING LICENSE ANTITRUST REVIEW
---------------------------------------
FINDING OF NO SIGNIFICANT CHANGES
---------------------------------
By letter dated February 23, 1996, as supplemented by letters dated April
24, 1996 and November 15, 1996, Union Electric Company (UEC), holder of the
Operating License for the Callaway Nuclear Plant, requested NRC approval
regarding a merger agreement with Central Illinois Public Service Company
(CIPSCO), under which UEC would become a wholly-owned subsidiary for the newly
formed Ameren Corporation, a registered public utility holding company.
Presently, 50 percent of Ameren is owned by UEC, and 50 percent is owned by
CIPSCO.
The staff has examined, from a competitive standpoint, events which have
occurred since issuance of the Callaway, Unit 1 construction permit to UEC and
the operating license. In addition, the staff has considered the structure of
the electric utility industry in the State of Missouri, and the record and
testimony developed in related proceedings at the Federal Energy Regulatory
Commission (FERC).
The staff's analysis is as follows:
After the merger, UEC will continue to own and operate the Callaway
Nuclear Plant. UEC will continue to be engaged principally in the
generation, transmission, distribution and retail and wholesale sale
of electricity and in the distribution and retail sale of natural gas
in Missouri.
Based upon the information provided by the licensee, the proposed
merger and restructuring will not adversely affect the operation of
the Callaway facility nor
<PAGE>
the bulk power services market served by the Callaway facility. For
the most part, the transmission systems of UEC and CIPSCO do not
overlap, so the merger for the most part would not eliminate one
independent and potentially competing transmission alternative. Also,
the licensee has filed consolidated (one system) open access
transmission tariffs, which make available all of the direct
interconnections of both companies as receipt and delivery points.
This has the potential to expand wholesale bulk power trading
opportunities in the region. The single-system open access
transmission tariffs should make entry by new non-utility generators
easier than before the merger, which should increase competition for
long term generating capacity.
Market forces resulting from deregulation of the electric utility
industry appear to be the driving force for the proposed merger. In
testimony before FERC, licensee representatives stated that the
rationale for the merger was to reduce the combined operating costs
of UEC and CIPSCO. Both companies have been aggressively pursuing
cost reductions to remain competitive, and have reached the practical
limits of that strategy. Without a fundamental change in their way of
doing business, it would become increasingly difficult to continue
reducing costs. By combining utility operations, both companies have
an opportunity to achieve more cost efficiency than either company
could achieve independently.
The staff recommends that the Director of the Office of Nuclear
Reactor Regulation issue a no significant antitrust change finding in
connection with UEC's request dated February 23, 1996, as
supplemented by letters dated April 23, 1996, and November 15, 1996.
Based on the staff's analysis, it is my finding that the proposed
implementation of the merger agreement between UEC and CIPSCO, which provides
for UEC to become a wholly-owned subsidiary of the newly formed Ameren
Corporation, does not represent a "significant change."
Dated at Rockville, Maryland, this 16th day of October 1997.
FOR THE NUCLEAR REGULATORY COMMISSION
Samuel J. Collins, Director
Office of Nuclear Reactor Regulation
2
<PAGE>
SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION
-------------------------------------------------------------
PROPOSED MERGER
---------------
UNION ELECTRIC COMPANY
----------------------
CALLAWAY PLANT, UNIT 1
----------------------
DOCKET NO. 50-483
-----------------
1.0 INTRODUCTION
------------
By letter dated February 23, 1996, as supplemented by letters dated April 24,
1996, and November 15, 1996, Union Electric Company (UEC) submitted an
application for approval of the implementation of a merger agreement between UEC
and Central Illinois Public Service Company, Incorporated (CIPSCO), under which
UEC would become a wholly-owned subsidiary of a new company, Ameren Corporation
(Ameren). Ameren was formed to implement the merger agreement, and presently is
owned equally by UEC and CIPSCO. UEC is the holder of Facility Operating
License No. NPF-30 for the Callaway Plant, Unit 1. Ameren, after becoming the
parent company to UEC, would hold all common stock in UEC. UEC would continue
to remain the owner/operator of the single unit Callaway Plant. After the
merger, UEC would remain as "electric utility" as defined in 10 CFR 50.2,
engaged in the generation, transmission, and distribution of electric energy for
wholesale and retail sale. Current UEC common stockholders would exchange their
shares for Ameren common stock, and current CIPSCO shareholders likewise would
exchange their common shares for Ameren common stock.
Pursuant to 10 CFR 50.80, no license for a production or utilization facility,
or any right thereunder, shall be transferred, assigned, or in any manner
disposed of either voluntarily or involuntarily, directly or indirectly, through
transfer of control of the license to any person, unless the Commission gives
its consent in writing. The Commission may approve the transfer of control of a
license, after notice to interested persons (61 FR 29434). Such action is
contingent upon the Commission's determination that the licensee following the
transfer of control is qualified to be the holder of the license and the
transfer of such control is otherwise consistent with the applicable provisions
of law, regulations, and orders of the Commission.
2.0 ANTITRUST CONSIDERATIONS
------------------------
Callaway Application
- --------------------
UEC, the sole owner and operator of the Callaway Plant, Unit 1, has entered into
a merger agreement with CIPSCO, which provides for UEC to become a wholly-owned
subsidiary of the newly formed Ameren Corporation, a registered public utility
holding company. In addition, Central Illinois Public Service Company ("CIPS")
(CIPSCO's principal utility operating subsidiary) and CIPSCO Investment Company
(CIPSCO's subsidiary for conducting non-utility businesses) will also become
wholly-owned operating subsidiaries of Ameren.
<PAGE>
By letter dated February 23, 1996, as supplemented by letters dated April 24,
1996, and November 15, 1996, the Nuclear Regulatory Commission (NRC) staff
received an application from UEC requesting that the license be amended to
reflect UEC's status as an operating company subsidiary of Ameren Corporation,
and that consent be granted pursuant to 10 CFR (S) 50.80.
After review of the filings in this proceeding, the record and testimony
developed in the related proceedings at the Federal Energy Regulatory Commission
(FERC) and other public information, the staff has determined that there are no
antitrust concerns resulting from the changes proposed in the subject request.
Consequently, the Director of the Office of Nuclear Reactor Regulation has
issued a post-operating license no significant antitrust change finding in
connection with UEC's request.
Previous NRC Antitrust Reviews
- ------------------------------
The staff previously conducted antitrust licensing reviews of UEC at the
Callaway construction permit and operating license phases. The review conducted
for the operating license was completed on January 24, 1984, and concluded that
there were no significant antitrust changes since the construction permit
antitrust review and that a second full antitrust review was not required. The
staff's conclusion stated in part:
Many changes with competitive implications have occurred in the
applicant's service area since the initial antitrust review at the
construction permit stage: 1) The applicant, at the suggestion of the
Department of Justice, revised many of its wholesale power contracts
with the effect of freeing up competitive options for wholesale
customers; 2) Anticipated growth in demand for electricity did not
materialize and the high cost of money along with escalating
construction costs all provided the impetus for cancellation of Unit
2 of the Callaway Nuclear Plant: 3) State legislation provided the
means for smaller municipal power systems to band together to form
joint action agencies, thereby enhancing their bargaining positions
in negotiating bulk power supply agreements throughout the State of
Missouri; 4) Antitrust litigation involving the applicant was
initiated; and 5) The applicant consummated an acquisition and
initiated a merger involving its three electric subsidiaries during
the interim period since the initial antitrust review at the
construction permit (CP) stage...
In the 1984 finding of no significant antitrust changes, the staff expressed
concern with the applicant's activities in one instance involving negotiations
between Union Electric and its smaller wholesale power customers regarding
wheeling services. The outstanding issues were subsequently resolved through
litigation and substantive negotiations between Union Electric and its smaller
wholesale power customers.
On March 12, 1992, UEC purchased the Missouri retail electric distribution
properties of Arkansas Power and Light Company. This acquisition increased
UEC's customers by 26,000 in 10 counties in southeastern Missouri adjacent to
UEC's existing service territory.
2
<PAGE>
In December 1992, UEC sold its Iowa retail and wholesale electric distribution
properties to Iowa Electric Light & Power Company and its northern Illinois
electric distribution properties to Central Illinois Public Service Company.
UEC served approximately 21,000 customers in the area sold.
Other Review Proceedings
- ------------------------
In addition to the instant review, reviews of the proposed merger are in
progress at the FERC, the SEC, the Missouri Public Service Commission, and the
Illinois Commerce Commission.
Public Comments on Application
- ------------------------------
Pursuant to 10 CFR (S) 2.101 of the NRC's rules and regulations, the staff
published in the Federal Register/1/ notice of receipt of a request from UEC for
----------------
approval of the transfer of control of the license for Callaway Plant, Unit 1,
that would result from the consummation of the proposed merger agreement between
UEC and CIPSCO, the subject of this Safety Evaluation.
No comments have been received expressing concerns with the proposed merger
agreement.
Department of Justice Review
- ----------------------------
By letter dated January 14, 1997, a draft copy of this document was forwarded to
the Department of Justice (DOJ) for review and comment. By letter dated July
18, 1997, the DOJ replied indicating that it concluded that the merger is
unlikely to create competitive concerns that would violate the Clayton Act.
NRC Staff Findings
- ------------------
After reviewing Union Electric Company's application requesting approval under
10 CFR (S) 50.80 of the transfer of control of the Callaway Plant, Unit 1
license, documentation submitted in related proceedings before the FERC, and
other relevant public information, the staff has made the following findings:
The license amendment request would add a footnote after the words
"Union Electric Company" in paragraph 1.A of NPF-30 that identifies
that following the merger, Union Electric will become a wholly-owned
operating subsidiary of Ameren Corporation. After the merger, UEC
will continue to own and operate the Callaway Nuclear Plant. UEC will
continue to be engaged principally in the generation, transmission,
distribution and retail and wholesale sale of electricity and in the
distribution and retail sale of natural gas in Missouri.
__________________________
/1/ 61 Fed. Reg. 29434, June 10, 1996.
3
<PAGE>
Based upon the information provided by the licensee, the proposed
merger and restructuring will not adversely affect the operation of
the Callaway facility nor the bulk power services market served by
the Callaway facility. For the most part, the transmission systems of
UEC and CIPSCO do not overlap, so the merger for the most part would
not eliminate one independent and potentially competing transmission
alternative. Also, the licensee has filed consolidated (one system)
open access transmission tariffs, which make available all of the
direct interconnections of both companies as receipt and delivery
points. This has the potential to expand wholesale bulk power trading
opportunities in the region. The single-system open access
transmission tariffs should make entry by new non-utility generators
easier than before the merger, which should increase competition for
long term generating capacity.
Market forces resulting from deregulation of the electric utility
industry appear to be the driving force for the proposed merger. In
testimony before the FERC, licensee representatives stated that the
rationale for the merger was to reduce the combined operating costs
of UEC and CIPSCO. Both companies have been aggressively pursuing
cost reductions to remain competitive, and have reached the practical
limits of that strategy. Without a fundamental change in their way of
doing business, it would become increasingly difficult to continue
reducing costs. By combining utility operations, both companies have
an opportunity to achieve more cost efficiency than either company
could achieve independently.
Conclusion
- ----------
Based on the above, the Director of the Office of Nuclear Reactor Regulation
issued a post-OL no significant antitrust change finding in connection with
UEC's request dated February 23, 1996, as supplemented by letters dated April
23, 1996, and November 15, 1996.
3.0 TECHNICAL QUALIFICATIONS AND MANAGEMENT OF THE CALLAWAY, PLANT, UNIT 1
----------------------------------------------------------------------
OPERATION
---------
UEC stated in its letter dated February 23, 1996, that the merger will have no
effect on the operation of the Callaway Plant, Unit 1, or the provisions of the
License. UEC will continue to own and operate Callaway after the merger, as
required by the License. After the consummation of the merger, UEC will
continue to operate and support Callaway using the existing organizational
structure and personnel.
Based upon the above, the staff finds that the proposed merger will not
adversely affect UEC's technical qualifications or management of the Callaway
Plant, Unit 1.
4.0 FOREIGN OWNERSHIP, CONTROL, OR DOMINATION
-----------------------------------------
The licensee stated in its February 23, 1996, letter that the common
shareholders of UEC and CIPSCO immediately prior to the merger (except for the
holders of Union Electric Dissenting
4
<PAGE>
shares) will be common shareholders of Ameren immediately upon the consummation
of the merger. By letter dated November 15, 1996, the licensee stated that as of
November 13, 1996, less than 1 percent of both UEC and CIPSCO common stock
shares were registered to foreign holders. In addition, the licensee stated that
all officers and directors of UEC are U.S. citizens, and that new directors who
will be installed when the merger agreement is consummated will all be U.S.
citizens.
The staff does not know or have reason to believe that the proposed transaction
will result in UEC being owned, controlled, or dominated by alien, a foreign
corporation, or a foreign government.
5.0 FINANCIAL QUALIFICATION ANALYSIS
--------------------------------
UEC proposes the implementation of a merger agreement with CIPSCO under which
Ameren would become the parent company to UEC and would hold all common stock in
UEC upon completion of the merger. Ameren is a Missouri Corporation owned in
equal shares by UEC and CIPSCO, and was formed to effect the transactions
contemplated by the merger agreement. UEC would continue to remain the
owner/operator of the single unit Callaway Plant. After the merger, UEC would
remain an "electric utility" as defined in 10 CFR 50.2 engaged in the
generation, transmission, and distribution of electric energy for wholesale and
retail sale. Current UEC common stockholders would exchange their common shares
for common shares in Ameren, as would current CIPSCO common shareholders.
UEC indicates that, after the proposed merger, it will remain "committed to
provide all funds necessary for the safe operation, maintenance, repair,
decontamination and decommissioning of Callaway in conformance with NRC
regulations, subject to the same conditions, terms, and obligations of the
License. After the merger, UEC's financial ability to fund the above costs will
be equal to, or greater than, its ability without the merger. The merger will
result in cost efficiencies to help maintain competitive rates." (Attachment 1
to letter from UEC to the NRC dated February 23, 1996, p. 9)
UEC indicates that it will remain an "electric utility" as defined in 10 CFR
50.2. That is, UEC will continue to be engaged in the generation, transmission,
and distribution of electricity and will remain subject to the rate regulatory
authority of the Missouri Public Service Commission, the Illinois Commerce
Commission, and the FERC. The NRC concurs with this assessment. Thus, pursuant
to 10 CFR 50.33(f), UEC is not subject to further financial qualifications
review.
However, in view of the NRC's concern that mergers involving formation of
holding companies can lead to a diminution of assets necessary for the safe
operation and decommissioning of a licensee's nuclear power plants, and pursuant
to 10 CFR 50.33(f)(4), the NRC has sought to obtain commitments from its
licensees that initiate such restructurings not to transfer significant assets
from the licensee to an unlicensed corporate affiliate without notifying the
NRC. UEC has made such a commitment:
5
<PAGE>
UEC will provide the Director of the Office of Nuclear Reactor
Regulation a copy of any application, at the time it is filed, to
transfer (excluding grants of security interests or liens) from UEC
to its proposed parent or to any other affiliated company, facilities
or other assets for the production, transmission, or distribution of
electric energy having a depreciated book value exceeding ten percent
(10%) of UEC's consolidated net utility plant, as recorded on UEC's
books of account. (UEC letter of November 15, 1996)
The staff believes such reporting is important to providing reasonable assurance
that UEC will continue to maintain adequate resources to operate and
decommission its Callaway Plant, Unit 1 safely.
Based on the foregoing, the staff concludes that the implementation of the
proposed merger agreement between UEC and CIPSCO will not adversely affect UEC's
financial qualifications with respect to the Callaway plant.
6.0 CONCLUSION
----------
Based on the above determinations, the staff concludes that the proposed
transaction will not affect the qualifications of UEC as holder of the Callaway
Plant, Unit 1 license, and that the transfer of control of the license, to the
extent effected by the proposed merger, is otherwise consistent with the
applicable provisions of law, regulations, and orders issued by the Commission
pursuant thereto.
Principal Contributors: M. Davis
R. Wood
K. Thomas
Date: October 16, 1997
6
<PAGE>
EXHIBIT K-2.1
Updated Table of Estimated Lost Economies
The following table compiles data on "lost economies" as shown by the
identified Commission precedent, in each case showing the increased cost or lost
economies of divestiture of gas operations as a percentage of (A) Operating
Revenues, (B) Operating Revenue Deductions, (C) Gross Income and (D) Net Income.
See Exhibit K-2 for details for all precedent except New Century Energies.
<TABLE>
<CAPTION>
A B C D
- - - -
Operating
Operating Revenue Gross Net
Revenues Deductions Income Income
---------- ----------- ------- -------
- ---------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1. Ameren/1/ 15.99% 17.57% 177.66% 252.34%
2. New Century Energies/2/
(PSC) 6.44 7.18 62.54 85.06
(Cheyenne) 10.77 12.3 86.36 109.94
3. CINergy
(CG&E) 7.88 8.49 108.71 211.02
(ULH&P) 10.93 12.65 80.49 129.00
(Lawrenceburg) 14.46 17.34 87.09 102.28
</TABLE>
__________________
/1/ Based on Supplemental Gas Study, filed as Exhibit K-1.1.
/2/ Release No. 35-26748 (Aug 1, 1997)
<PAGE>
<TABLE>
<CAPTION>
A B C D
- - - -
Operating
Operating Revenue Gross Net
Revenues Deductions Income Income
---------- ----------- ------- -------
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
4. Engineer's Public 6.78 9.72 25.44 42.46
Service Co./3/
5. Gulf States Utilities 16.13 16.70 472.24 N/A
6. Fitchburg Gas & 13.94 15.33 153.87 N/A
Electric
7. NEES 4.83 6.03 23.28 29.94
8. Middle South 5.18 6.63 23.68 N/A
9. General Public 4.87 5.42 47.84 113.24
Utilities
(New Jersey P&L)
10. Philadelphia Co. 3.00 3.79 14.03 N/A
11. North American 5.85 8.01 21.68 24.34
Company (St. Louis
Co. Gas)
12. Engineers Public
Service Co./4/
(Gulf States) 6.58 9.46 20.85 25.25
(Virginia 3.38 4.86 11.25 21.23
Electric)
</TABLE>
__________________
/3/ Percentages referred to as showing an "impressive basis for finding a
loss of substantial economies." 12 S.E.C. at 59. See New Century
-----------
Energies, Release No. 35-26748 (Aug. 1, 1997)
--------
/4/ As calculated in New England Elec. Sys., 41 SEC 888 (Mar. 19, 1964).
---------------------
<PAGE>
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. In
addition, this corporation is exploring other non-electric or gas utility
related activities in St. Louis./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).
--------
/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./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 seeks to
develop new markets for the provision of energy services. 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/
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/
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
