<PAGE>
As filed with the Securities and Exchange Commission on July 15, 1997
File No. 70-8945
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
______________________________
AMENDMENT NO. 1
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 (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. 1 (i) to file additional information
regarding the retention by Ameren of the gas utility operations of UE and CIPS,
(ii) to file certain Exhibits hereto as described below and (iii) to reply to
comments of the Missouri Public Service Commission filed with the Commission in
this docket on March 17, 1997.
B. Retention of Gas Operations
Item 3. A. 2. a. i. of the Application describes Ameren's position that, in
light of current conditions, the Act does not prohibit UE or CIPS from
continuing to conduct their gas operations as part of the single integrated
public utility system to be controlled by Ameren after the Transaction. In
particular, part (A) of that section demonstrates the significant level of lost
economies that would result if each of the UE gas operations and the CIPS gas
operations were separately operated -- i.e., as two stand-alone companies. As
pointed out in such part, the lost economies would be significantly higher than
in other cases where the Commission held that the additional system could be
retained.
In Item 3.A.2.b.ii.(B) of the Application, Ameren demonstrates that the gas
operations of UE and the gas operations of CIPS, together, constitute a "single
integrated public utility system." Because the existing separate gas systems of
UE and CIPS may be operated as a single integrated system, it may be appropriate
to analyze the loss of economies that would occur if the gas operations were to
be divested on the assumption that the gas operations of UE and CIPS are
combined as part of the divestiture into a single new and separate gas utility
company. In order to demonstrate the effects of such a divestiture of both the
UE and CIPS gas operations into a single separate entity, UE and CIPS have
prepared a Supplemental Analysis of the Economic Impact of a Divestiture of the
Gas Operations of UE and CIPS (the "Supplemental Study").
The Supplemental Study uses the same methodology as used in the original
Analysis of Economic Impact of Divestiture of the Gas Operations of UE and CIPS
dated September 19, 1996 and
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previously filed in this matter as Exhibit K-1 (the "1996 Study"), except that
it is assumed that one newly formed corporation would assume all of the divested
gas operations. As would be expected, the Supplemental Study shows that total
lost economies are less than shown by the 1996 Study because the "double" costs
of two corporations are eliminated. However, even assuming that only one new
company were created, the lost economies are significantly higher than in
Commission precedents. See Exhibit K-2 to the Application. Thus, the
Supplemental Study supports, as does the 1996 Study, the conclusion that the
test of Clause A of Section 11(b)(1) is met in this case.
Historically, in determining whether lost economies are "substantial" under
Section 11(b)(1)(A), the Commission has given consideration to four ratios,
which measure the projected loss of economies as a percentage of: (1) total gas
operating revenues; (2) total gas expense or "operating revenue deductions"; (3)
gross gas income; and (4) net gas income or net gas utility operating income.
Although the Commission has declined to draw a bright-line numerical test under
Section 11(b)(1)(A), it has indicated that cost increases resulting in a 6.78%
loss of operating revenues, a 9.72% increase in operating revenue deductions, a
25.44% loss of gross income and a 42.46% loss of net income would afford an
"impressive basis for finding a loss of substantial economies." In re Engineers
Public Service Co., 12 SEC 41, 59 (Sept. 16, 1942) ("Engineers").
Here, the lost economies would be far greater than in Engineers if the gas
properties of UE and CIPS were to be operated as a combined new single entity on
a stand-alone basis, with no offsetting increase in benefits to consumers.
These lost economies result from the need to replicate services, the sacrifice
of economies of scale, the costs of reorganization, and other factors, and are
described more fully in the Supplemental Study (Exhibit K-1.1 hereto).
As set forth in the Supplemental Study, divestiture of the gas operations of
UE and CIPS into one stand-alone company would result in lost economies of
$34.8 million. (This compares to lost economies of $22.1 million for UE and
$36.3 million for CIPS, totalling $58.4 million, as found by the 1996 Study).
These lost economies compare with 1995 pro forma combined gas operating revenues
of $217.4 million for UE and CIPS; pro forma combined gas operating revenue
deductions of $197.9 million; pro forma combined gas gross income of $19.6; and
pro forma combined gas net income of $13.8 million.
On a percentage basis, the lost economies amount to 252% of 1995 pro forma
combined gas net income -- far in excess of the loss of net income in Unitil
Corp., 51 SEC Docket 562 (Apr. 24, 1992) (Unitil), where the Commission allowed
the retention of gas
3
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utility operations, and the 30% loss in New England Electric System that the
Commission has described as the highest loss of net income in any past
divestiture order./1/ As a percentage of 1995 pro forma combined gas operating
revenues, these lost economies described in the Supplemental Study amount to 16%
- --losses higher than the losses in any past divestiture order. The projected
loss of economies as a percentage of operating revenues is even higher than the
loss in Unitil./2/ As a percentage of
- ---------------------
/1/ See Unitil Corp., 51 SEC Docket 562, 567 & n.42 (Apr. 24, 1992) ("The
Commission has required divestment where the anticipated loss in income of
the stand-alone company was approximately 30%" or "29.9% of net income
before taxes") (citing SEC v. New England Elec. Sys., 390 U.S. 207, 214
n.11 (1968)). This percentage compares to the 425% of 1995 UE gas net
income and 424% of 1995 CIPS gas net income shown by the 1996 Study.
/2/ The loss as a percentage of operating revenues in Unitil was 13.94%. The
highest loss of operating revenues in any case ordering divestiture is
commonly said to be 6.58%. See, e.g., Unitil Corp., 51 SEC Docket 562, 567
n.41 (Apr. 24, 1992) ("[o]f cases in which the Commission has required
divestment, the highest estimated loss of operating revenues of a stand-
alone company was 6.58%") (citing In re Engineers Public Service Co., 12
SEC 41 (Sept. 16, 1942)). In fact, however, the 6.58% ratio is not cited in
Engineers and is a post hoc calculation derived from claimed cost increases
which the Commission had found were "overstated" and "doubtful" in a number
of respects. Engineers Public Service Co., 12 SEC at 80-81. See also In re
Philadelphia Co., 28 SEC 35, 51 n.26 (June 1, 1948) (Engineers' "estimate .
. . of increased expenses . . . was overstated in several respects"). While
the SEC made no finding as to actual cost increases or ratios for the Gulf
States gas properties, it found that Engineers' estimate of divestiture-
related cost increases for certain sister gas properties in Virginia were
also overstated and cut them and the resulting ratios in half. Engineers
Public Service Co., 12 SEC at 60. If the same 50% discount had been applied
to Engineers' Gulf States gas properties, the loss of operating revenues
would have been 3.29%, the increase in expenses would have been 4.73%, the
loss of gross income would have been 10.43%, and the loss of net income
would have been 12.63%. Disregarding the 6.58% ratio incorrectly attributed
to the Engineers/Gulf States case, the highest loss of operating revenues
in any past divestiture order was 5.85%. See table of ratios in In re New
England Elec. Sys., 41 SEC 888, 905 App. (Mar. 19, 1964). This figure would
be even lower if adjusted for the increase in purchased gas costs since the
1940s. The percentage shown by the Supplemental Study compares to the
(continued.....)
4
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1995 pro forma combined gas expenses or operating revenue deductions, the lost
economies described in the Supplemental Study would amount to 17.6% -- higher
than the losses in any past divestiture order and higher than the losses in both
Unitil and Entergy, another case in which the Commission authorized the
retention of gas operations./3/ As a percentage of 1995 pro forma combined gas
gross income, the lost economies described in the Supplemental Study amount to
178% --far in excess of the highest loss of gross income in any divestiture
order. The applicable percentages in past cases are summarized in Exhibit K-2
previously filed (Table of Estimated Losses of Economies in Prior Decisions on
Divestiture and Retention of Gas Operations).
In order to recover these lost economies, the single, new stand-alone company
divested from UE and CIPS would need to increase customer rates by about 23%
($50.4 million) in order to provide an 11.07% rate of return on rate base. This
rate of return was conservatively estimated using the weighted average
approximate costs for capital of UE and CIPS rather than the higher returns that
would likely be required by the financial community for a single, stand-alone
company.
Finally, it should be noted that the lost economies would, in the absence of
rate relief, result in a negative rate of return on rate base for the gas
operations of minus 4.78% --significantly more detrimental than the 2.01%
projected stand-
- -------------------------
/2/(continued.....)
25% and 28% reduction, respectively, for UE and CIPS shown by the 1996
Study.
/3/ The highest percentage of loss related to operating revenue deduction is
sometimes attributed to the Gulf States gas properties of Engineers Public
Service Co. See, e.g., In re New England Elec. Sys., 41 SEC 888, 905 App.
(March 19, 1964) (attributing 9.46% to the Engineers/Gulf States case).
This percentage, however, is based on claimed losses expressly rejected by
the Commission in the Engineers decision. In re Engineers Public Service
Co., 12 SEC 41, 80-81 (Sept. 16, 1942). Disregarding the 9.46% figure
erroneously attributed to the Engineers case, the highest expense
percentage in the cases ordering divestiture appears to have been either
8.01% or 7.42%, depending on how the ratio is calculated. See In re North
American Co., 18 SEC 611 (Apr. 7, 1945); In re Philadelphia Co., 28 SEC 35,
51 Table VI (June 1, 1948) (attributing expense ratio of 7.42% to North
American) with In re New England Electric System, 41 SEC 888, 905 App.
(1964) (attributing expense ratio of 8.01% to North American). The combined
total loss as a percentage of gas operating revenue deductions shown in the
1996 Study was 29.5%.
5
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alone rate of return in Unitil, where retention was authorized. This return is
significantly lower than the returns of other utilities in the region and
represents a decline from UE's and CIPS' indicated rates of return for 1995.
The above data show that, even assuming the gas operations of CIPS and UE were
divested by forming one stand-alone company, the loss of economies would be
significant, in excess of that present in other cases where retention was
allowed and sufficient to support a finding that requirement of Clause A of
Section 11(b)(1) is met in this case. This conclusion is even more dramatically
demonstrated if it is assumed that each gas operation would be in a separate
stand-alone company as shown by the 1996 Study.
Additional support for the conclusion that retention of the gas operations is
supported by the Act is found in the Legal Memorandum on the Retention of Gas
Operations by Ameren Corporation (the "Gas Legal Memorandum") filed herewith as
Exhibit K-3.
C. Additional or Updated Exhibits.
The Exhibits filed herewith include Exhibit D-2.2, the Report and Order of the
Missouri Public Service Commission (MPSC) dated February 21, 1997 (the "Final
Missouri Order), approving the merger between Union Electric Company (UE) and
Central Illinois Public Service Company (CIPSCO) and the pleading filed by UE
accepting conditions contained therein. In the Final Missouri Order, the MPSC
adopted and approved the terms of the Stipulation entered into by the parties.
(See Exhibit D-2.3) The MPSC also imposed two other conditions beyond those
reflected in the Stipulation. First, Ameren must agree to file or join in the
filing of regional independent system operator ("ISO") proposal at the FERC no
later than December 31, 1997, or, if not, by March 31, 1998, Ameren must develop
and file with the MPSC a plan for establishing an independent entity charged
with the operation, pricing and planning of its transmission system. Second, UE
must file with the MPSC by January 1, 1998, a report assessing the potential
ability of the merged companies to exercise market power in the price of
deregulated retail generation. UE has consented to these two conditions. The
Final Missouri Order became effective March 4, 1997.
As described in Part A hereto, the Supplemental Study and the Gas Legal
Memorandum are also filed herewith.
Finally, recent financial information and Exhibits are filed as noted in Item
6 below.
6
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D. Reply to Comments of the Missouri Public Service Commission
Ameren has no objection to the late-filed comments being received and
considered by the Commission. However, Ameren does not believe that any reason
exists to grant the requested relief as the issues raised were the subject of
negotiation and were fully addressed in agreements accepted by the MPSC when it
approved the merger on February 21, 1997.
In negotiations during the pre-approval process, the MPSC Staff expressed the
desire to retain the ability of the MPSC to continue regulatory oversight of UE
and Ameren. The MPSC Staff proposed that contracts contain similar language to
that which has been suggested in its comments. For a variety of reasons,
including that placing the language in contracts would have been an
administrative hardship and may have unnecessarily created uncertainties
regarding the enforceability of contracts, the proposal ultimately was dropped
and other means were adopted to provide the assurances the MPSC Staff sought.
Thus, the Stipulation (previously filed as Exhibit D-2.3 hereto) signed by UE
and approved by the MPSC contains numerous provisions specifically designed to
preserve the MPSC's ability to examine books and records of the merged companies
and to engage in ratemaking determinations. For example, the Stipulation
states, in part as follows:
8. State Jurisdictional Issues
a. Access to Books, Records, and Personnel. UE and its prospective
holding company, Ameren, agree to make available to the [MPSC], at
reasonable times and places, all books and records and employees and
officers of Ameren, UE and any affiliate or subsidiary of Ameren as
provided under applicable law and [MPSC] rules; provided, that Ameren,
UE and any affiliate or subsidiary of Ameren shall have the right to
object to such production of records or personnel on any basis under
applicable law and [MPSC] rules excluding any objection that such
records and personnel are not subject to [MPSC] jurisdiction by
operation of the Public Utility Holding Company Act of 1935. . . .
****
d. Contracts Required to be Filed with the SEC. All contracts,
agreements or arrangements, including any amendments thereto, of any
kind between UE and any affiliate, associate, holding, mutual service,
or subsidiary company within the same holding company system, as these
terms are defined in 15 U.S.C. (S) 79b, as subsequently amended,
required to be filed with
7
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and/or approved by the Securities and Exchange Commission ("SEC")
pursuant to PUHCA, as subsequently amended, shall be conditioned upon
the following without modification or alteration: UE and Ameren and
each of its affiliates and subsidiaries will not seek to overturn,
reverse, set aside, change or enjoin, whether through appeal or the
initiation or maintenance of any action in any forum, a decision or
order of the [MPSC] which pertains to recovery, disallowance, deferral
or ratemaking treatment of any expense, charge, cost or allocation
incurred or accrued by UE in or as a result of a contract, agreement,
arrangement or transaction with any affiliate, associate, holding,
mutual service or subsidiary company on the basis that such expense,
charge, cost or allocation has itself been filed with or approved by
the SEC or was incurred pursuant to a contract, arrangement, agreement
or allocation method which was filed with or approved by the SEC.
(Stipulation, Exhibit D-2.3, pp. 22-24) (emphasis supplied).
-----------
In addition, the Stipulation contains a contingent jurisdictional
stipulation providing for pre-approval of contracts by the MPSC in the event
that anyone raises objection to MPSC action on the basis of SEC preemption.
(Stipulation, Attachment D)(U-1 Exhibit D-2.3). Thus, Ameren and UE have
clearly demonstrated that they did not act to deprive the MPSC of jurisdiction
in structuring the transaction so that Ameren would become a registered holding
company. Furthermore, there are agreements in place which are more than
adequate to govern relationships between the parties. Including the conditions
proposed by the MPSC would not add to that protection already in place, but has
the potential to create administrative hardship and uncertainty for Applicants
post-merger.
For these reasons Applicants respectfully request that the Commission
decline to include in its Order conditions suggested by the MPSC unit's
comments.
8
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Item 6. Exhibits and Financial Statements
A. Exhibits
The following Exhibits are filed with this Amendment No. 1:
D-2.2 Final MPSC Report and Order dated February 21, 1997
G-1.1 Financial Data Schedule (March 1997) (Electronic filing only)
I-1.1 Annual Report of UE on Form 10-K for the year ended December 31,
1996 (Incorporated by reference)
I-2.1 Annual Report of CIPSCO and CIPS on Form 10-K for the year ended
December 31, 1996 (Incorporated by reference)
I-3.1 Portions of UE 1996 Annual Report to Shareholders (Exhibit 13 to
UE 1996 Form 10-K; Incorporated by reference)
I-4.1 Statement of CIPS on Form U-3A-2 dated February 28, 1997
(Incorporated by reference)
I-5.1 UE Quarterly Report on Form 10-Q for the quarter ended March 31,
1997 (Incorporated by reference)
I-6.1 CIPSCO and CIPS Quarterly Report on Form 10-Q for the quarter
ended March 31, 1997 (Incorporated by reference)
K-1.1 Supplemental Analysis of the Economic Impact of a Divestiture of
the Gas Operations of UE and CIPS (the "Supplemental Study")
K-3 Legal Memorandum Regarding Standards for Retention of Gas
Properties
9
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B. Financial Statements
FS-1.1 Ameren Unaudited Pro Forma Combined Condensed Consolidated
Balance Sheets as of March 31, 1997 (see Quarterly Report of UE
on Form 10-Q for the quarter ended March 31, 1997 (Exhibit I-5.1
hereto), at p. 11)
FS-2.1 Ameren Unaudited Pro Forma Combined Condensed Consolidated
Statements of Income for the years ended December 31, 1996, 1995
and 1994 (see Annual Report of UE on Form 10-K for the year ended
December 31, 1996 (Exhibit I-1.1 hereto), at pp. 17-19)
FS-3.1 CIPSCO Consolidated Balance Sheets as of March 31, 1997 (see
Quarterly Report of CIPSCO on Form 10-Q for the quarter ended
March 31, 1997 (Exhibit I-6.1 hereto), at p. 5)
FS-4.1 CIPSCO Consolidated Statements of Income for its last three
fiscal years (see Annual Report of CIPSCO on Form 10-K for the
year ended December 31, 1996 (Exhibit I-2.1 hereto), at p. 40)
FS-5.1 CIPS Balance Sheets as of March 31, 1997 (see Quarterly Report of
CIPS on Form 10-Q for the quarter ended March 31, 1997 (Exhibit
I-6.1 hereto), at p. 8)
FS-6.1 CIPS Statements of Income for its last three fiscal years (see
Annual Report of CIPS on Form 10-K for the year ended December
31, 1996 (Exhibit I-2.1 hereto), at p. 66)
FS-7.1 UE Consolidated Balance Sheet as of March 31, 1997 (see Quarterly
Report of UE on Form 10-Q for the quarter ended March 31, 1997
(Exhibit I-5.1 hereto), at p. 2)
FS-8.1 UE Statement of Income for its last three fiscal years (see UE
Annual Report to Shareholders for the year ended December 31,
1996 (Exhibit I-3.1 hereto), at p. 22)
10
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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. 1 to
Application/Declaration to be signed on its behalf by the undersigned thereunto
duly authorized.
Date: July 15, 1997
AMEREN CORPORATION
/s/ William E. Jaudes
-------------------------------------
By: William E. Jaudes
Secretary
11
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Exhibit Index
to Amendment No. 1
<TABLE>
<CAPTION>
A. Exhibits
Form of
Exhibit No. Description Transmission
- ----------- ----------- ------------
<S> <C> <C>
D-2.2 Final MPSC Report and Order dated Electronic
February 21, 1997 (filed herewith)
G-1.1 Financial Data Schedule (March 1997) Electronic
(filed herewith)
I-1.1 Annual Report of UE on Form 10-K for By Reference
the year ended December 31, 1996
(Incorporated by reference)
I-2.1 Annual Report of CIPSCO and CIPS on By Reference
Form 10-K for the year ended
December 31, 1996 (Incorporated by
reference)
I-3.1 Portions of UE 1996 Annual Report to By Reference
Shareholders (Exhibit 13 to UE 1996
Form 10-K; Incorporated by
reference)
I-4.1 Statement of CIPS on Form U-3A-2 By Reference
dated February 28, 1997
(Incorporated by reference)
I-5.1 UE Quarterly Report on Form 10-Q for By Reference
the quarter ended March 31, 1997
(Incorporated by reference)
I-6.1 CIPSCO and CIPS Quarterly Report on By Reference
Form 10-Q for the quarter ended
March 31, 1997 (Incorporated by
reference)
</TABLE>
<PAGE>
Form of
Exhibit No. Description Transmission
- ----------- ----------- ------------
K-1.1 Supplemental Analysis of the Electronic
Economic Impact of a Divestiture of
the Gas Operations of UE and CIPS
(the "Supplemental Study") (filed
herewith)
K-3 Legal Memorandum Regarding Standards Electronic
for Retention of Gas Properties
(filed herewith)
B. Financial Statements
Form of
F.S. No. Description Transmission
-------- ----------- ------------
FS-1.1 Ameren Unaudited Pro Forma Combined By Reference
Condensed Consolidated Balance Sheets
as of March 31, 1997 (see Quarterly
Report of UE on Form 10-Q for the
quarter ended March 31, 1997 (Exhibit
I-5.1 hereto), at p. 11)
FS-2.1 Ameren Unaudited Pro Forma Combined By Reference
Condensed Consolidated Statements of
Income for the years ended December
31, 1996, 1995 and 1994 (see Annual
Report of UE on Form 10-K for the year
ended December 31, 1996 (Exhibit I-1.1
hereto), at pp. 17-19)
FS-3.1 CIPSCO Consolidated Balance Sheets as By Reference
of March 31, 1997 (see Quarterly
Report of CIPSCO on Form 10-Q for the
quarter ended March 31, 1997 (Exhibit
I-6.1 hereto), at p. 5)
FS-4.1 CIPSCO Consolidated Statements of By Reference
Income for its last three fiscal years
(see Annual Report of CIPSCO on Form
10-K for the year ended December 31,
1996 (Exhibit I-2.1 hereto), at p. 40)
FS-5.1 CIPS Balance Sheets as of March 31, By Reference
1997 (see Quarterly Report of CIPS on
Form 10-Q for the quarter ended March
31, 1997 (Exhibit I-6.1 hereto), at
p. 8)
<PAGE>
Form of
F.S. No. Description Transmission
- -------- ----------- ------------
FS-6.1 CIPS Statements of Income for its last By Reference
three fiscal years (see Annual Report
of CIPS on Form 10-K for the year
ended December 31, 1996 (Exhibit I-2.1
hereto), at p. 66)
FS-7.1 UE Consolidated Balance Sheet as of By Reference
March 31, 1997 (see Quarterly Report
of UE on Form 10-Q for the quarter
ended March 31, 1997 (Exhibit I-5.1
hereto), at p. 2)
FS-8.1 UE Statement of Income for its last By Reference
three fiscal years (see UE Annual
Report to Shareholders for the year
ended December 31, 1996 (Exhibit I-3.1
hereto), at p. 22)
<PAGE>
Exhibit D-2.2
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF MISSOURI
In the Matter of the Application of Union Electric )
Company for an Order Authorizing (1) Certain Merger )
Transactions Involving Union Electric Company; )
(2) the Transfer of Certain Assets, Real Estate, )
Leased Property, Easements and Contractual ) Case No. EM-96-149
Agreements to Central Illinois Public Service ) ------------------
Company; and (3) in Connection Therewith, Certain )
Other Related Transactions. )
================================================================================
REPORT AND ORDER
================================================================================
Issue Date: February 21, 1997
Effective Date: March 4, 1997
<PAGE>
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF MISSOURI
In the Matter of the Application of Union Electric )
Company for an Order Authorizing (1) Certain Merger )
Transactions Involving Union Electric Company; )
(2) the Transfer of Certain Assets, Real Estate, )
Leased Property, Easements and Contractual ) Case No. EM-96-149
Agreements to Central Illinois Public Service ) ------------------
Company; and (3) in Connection Therewith, Certain )
Other Related Transactions )
APPEARANCES
-----------
James J. Cook, Associate General Counsel, Joseph H. Raybuck, Attorney, and
William J. Niehoff, Attorney, Union Electric Company, Post Office Box 149,
St. Louis, Missouri 63166, for Union Electric Company.
Richard W. French, French & Stewart Law Offices, 1001 Cherry Street, Suite 302,
Columbia, Missouri 65201, for Trigen-St. Louis Energy Corporation.
Sondra B. Morgan and James C. Swearengen, Brydon, Swearengen & England, P.C.,
Post Office Box 456, 312 East Capitol Avenue, Jefferson City, Missouri 65102,
for The Empire District Electric Company and UtiliCorp United Inc.
Sondra B. Morgan and Gary W. Duffy, Brydon, Swearengen & England, P.C., Post
Office Box 456, 312 East Capitol Avenue, Jefferson City, Missouri 65102, for
Missouri Gas Energy, a division of Southern Union Company.
Thomas M. Byrne, Associate Counsel, Laclede Gas Company, 720 Olive Street, St.
Louis, Missouri 63101, for Laclede Gas Company.
Robert C. Johnson, Diana M. Schmidt, and Michael R. Annis, Peper, Martin,
Jensen, Maichel and Hetlage, 720 Olive Street, 24th Floor, St. Louis, Missouri
63101, for: Anheuser-Busch, Inc., Barnes and Jewish Hospitals, Chrysler
Corporation, Emerson Electric Company, Hussmann Refrigeration, Lincoln
Industrial, MEMC Electronic Materials, Mallinckrodt, Inc., McDonnell Douglas
Corporation, Monsanto Company, and The Doe Run Company (the Missouri Industrial
Energy Consumers).
James M. Fischer, Attorney at Law, 101 West McCarty Street, Suite 215, Jefferson
City, Missouri 65101,
and
William G. Riggins, Staff Attorney, Kansas City Power & Light Company, 1201
Walnut Street, Post Office Box 418679, Kansas City, Missouri 64141, for Kansas
City Power & Light Company.
<PAGE>
Paul S. DeFord, Lathrop & Gage, 2345 Grand Boulevard, Kansas City, Missouri
64108, for Illinois Power Company.
Marilyn S. Teitelbaum, Schuchat, Cook & Werner, 1221 Locust Street, Second
Floor, St. Louis, Missouri 63103, for Local 2, Local 309, Local 702 and Local
1455, International Brotherhood of Electrical Workers, AFL-CIO.
Daryl R. Hylton, Assistant Attorney General, and Michelle Smith, Assistant
Attorney General, Office of the Attorney General, Post Office Box 899, Jefferson
City, Missouri 65102, for the State of Missouri, at the relation of Jeremiah W.
(Jay) Nixon, Attorney General.
Lewis R. Mills, Jr., Deputy Public Counsel, Office of the Public Counsel, Post
Office Box 7800, Jefferson City, Missouri 65102, for the Office of the Public
Counsel and the public.
Steven Dottheim, Acting General Counsel, Roger W. Steiner, Assistant General
Counsel, and Aisha Ginwalla, Assistant General Counsel, Missouri Public Service
Commission, Post Office Box 360, Jefferson City, Missouri 65102, for the staff
of the Missouri Public Service Commission.
ADMINISTRATIVE
- --------------
LAW JUDGE: Joseph A. Derque, III.
- ---------
REPORT AND ORDER
================
Procedural History
------------------
On November 7, 1995, Union Electric Company (UE) filed an application with
the Missouri Public Service Commission (Commission) requesting an order from the
Commission authorizing certain merger transactions, the transfer of certain
assets, real estate, leased property, easements and contractual agreements, and
authorizing certain other transactions, all to effectuate a proposed merger
between UE and CIPSCO Incorporated (CIPSCO).
UE is a Missouri corporation engaged in the provision of energy services to
the public in the state of Missouri and regulated by the Commission as a public
utility. CIPSCO is an Illinois corporation and the parent corporation of its
wholly owned subsidiary, Central Illinois Public
2
<PAGE>
Service Company (CIPS). CIPS is engaged in the business of providing energy
services in the state of Illinois and, as such, is a regulated public utility in
that state.
In addition, two other corporations have been formed for the purpose of
facilitating the proposed merger, those being Arch Merger, Inc. (Arch) and
Ameren Corporation (Ameren). The corporate structure resulting from the proposed
merger will include Ameren as a federally regulated utility holding company,
with UE as a Missouri subsidiary operating company and CIPS and CIPSCO as other
subsidiaries. The merger transactions are intended to result in a tax-free
exchange.
In addition to the Staff of the Commission (Staff), UE, and the Office of
the Public Counsel (OPC), the following parties were also granted intervention:
the Missouri Industrial Energy Consumers (MIEC)/1/; Laclede Gas Company (LGC);
The Empire District Electric Company (EDE); Locals 2, 309, 702 and 1455 of the
International Brotherhood of Electrical Workers, AFL-CIO (Unions); Kansas City
Power & Light Company (KCPL); the State of Missouri ex rel. The Attorney General
(State); Missouri Gas Energy, a division of Southern Union Company (MGE);
Trigen-St. Louis Energy Corporation (Trigen); Illinois Power Company (IP); and
UtiliCorp United Inc. (UtiliCorp).
- -----------------------
/1/The MIEC is composed of the following: Anheuser-Busch, Inc., Barnes and
Jewish Hospitals, Chrysler Corporation, Emerson Electric Company, Hussmann
Refrigeration, Lincoln Industrial, MEMC Electronic Materials, Mallinckrodt,
Inc., McDonnell Douglas Corporation, Monsanto Company, and The Doe Run Company.
3
<PAGE>
Findings of Fact
----------------
The Missouri Public Service Commission, having considered all of the
competent and substantial evidence upon the whole record, makes the following
findings of fact.
A. Stipulation And Agreement
On July 12, 1996, a Stipulation And Agreement was filed purporting to
settle all issues raised by the parties and seeking Commission approval of the
proposed transaction. This Stipulation And Agreement is appended to this Report
And Order as Attachment 1 and incorporated herein by reference.
Various intervenors did not sign the proposed Stipulation And Agreement.
Those parties were given the opportunity to exercise their due process right to
compel an evidentiary hearing, but all chose not to do so. Those parties who are
not signatories to the agreement are LGC, MIEC, IP, and the Unions. All have
stated in filed documents that, while not signatories to the agreement, none
wish to litigate any issue and none are opposed to Commission approval of the
proposed stipulation. The Commission, therefore, in accordance with rule 4 CSR
240-2.115, will treat the Stipulation And Agreement as a unanimous stipulation
and agreement.
The Stipulation And Agreement contains the following terms and conditions.
In setting out this summary it is not the intent of the Commission to alter any
terms and conditions therein.
The Stipulation And Agreement specifies that the proposed merger, as
specified in the merger agreement, filed with the original application on
November 7, 1995, should be approved by the Commission as not
4
<PAGE>
detrimental to the public interest, subject to the conditions and modifications
as set out in the remainder of the Stipulation And Agreement.
UE has agreed that it will not seek to recover the asserted merger premium of
$232 million in rates in any Missouri proceeding. The merger premium represents
the portion of the purchase price that exceeds the current book value of the
acquired company's assets or market value of the acquired company's stock. UE
will, however, retain the right to state, in any future proceedings, alleged
benefits of the merger. UE will forgo any additional specific adjustments to
cost of service related to the merger savings or any claim to merger savings
other than the adjustments to cost of service and claims to merger savings
resulting from the Commission's approval of the Stipulation And Agreement or the
benefits and savings which would occur through regular ratemaking treatment or
the current Experimental Alternative Regulation Plan (ARP) or the new
Experimental Alternative Regulation Plan (EARP) effective July 1, 1998, pursuant
to the Stipulation And Agreement.
Actual prudent and reasonable merger transaction and transition costs
(estimated to be $71.5 million) shall be amortized over ten years beginning the
date the merger closes. The annual amortization of merger transaction and
transition costs will be the lesser of: (1) the Missouri jurisdictional portion
of the total Ameren amount of $7.2 million; or (2) the Missouri jurisdictional
portion of the total Ameren unamortized amount of actual merger transaction and
transition costs incurred to date. No rate base treatment of the unamortized
costs will be included in the determination of rate base for any regulatory
purposes in Missouri.
UE commits that it will propose and file with the Commission an experimental
retail wheeling pilot program for 100 MW of electric power,
5
<PAGE>
to be available to all major classes of Missouri retail electric customers, as
soon as practical, but no later than March 1, 1997./2/ The commitment to file
such a pilot program for Commission consideration and determination covered by
this provision is made by UE alone. Prior to filing its proposal with the
Commission, UE will seek substantive input from Missouri retail electric
customers, Staff, OPC and others.
The parties concur that earnings monitoring in Case No. EO-96-14 will
result in a general change in rates charged and revenues collected after August
31, 1998. The change in revenues collected will be equal to the average annual
total revenues credited to customers during the three ARP years ending June 30,
1998, adjusted to reflect normal weather. Any rate reduction shall be spread
within and among revenue classes on the basis of the Commission decision in Case
No. EO-96-15, which is the UE customer class cost of service and comprehensive
rate design docket created as a result of Case No. ER-95-411. In the event that
a Commission decision has not been reached in Case No. EO-96-15, the parties
will jointly or severally propose to the Commission a basis or bases on which a
rate reduction may be spread on an interim basis within and among the classes
pending issuance of the Commission's decision in Case No. EO-96-15.
UE will make a good faith effort to provide the earnings report for the
final Sharing Period in Case No. ER-95-411 in time to implement this rate
reduction on September 1, 1998. In the event the earnings data is not available,
or in the event the review process of the earnings data or the weather
normalization review process does not allow for a September 1, 1998 effective
date, the following will occur: An additional
- -----------------------
/2/The Commission will entertain a motion to modify the above date in order
to ensure that UE has the opportunity to receive "substantive input" from the
parties and others.
6
<PAGE>
credit, equal to the excess revenues billed between September 1, 1998 and the
effective date of the rate reduction, will be made. Said credit will be made at
the same time and pursuant to the same procedures as the Sharing Credits in Case
Nos. ER-95-411 and EO-96-14. If no Sharing Credits are to be made for the third
Sharing Period in Case Nos. ER-95-411 and EO-96-14, the excess revenue credit
will be made as expeditiously as possible.
UE shall file tariff sheets for Commission approval consistent with this
section.
The EARP will be instituted July 1, 1998 at the end of the ARP created in
Case No. ER-95-411. In its Report And Order approving this Stipulation and
Agreement, the Commission shall create a new docket to facilitate the EARP (EARP
Docket). All signatories to the Stipulation And Agreement shall be made
parties to the EARP Docket, as intervenors or as a matter of right, as will the
parties to Case No. EO-96-14 who are not parties to Case No. EO-96-149, without
the necessity of taking further action.
The following sharing grid is to be utilized as part of the EARP:
===============================================================
Sharing Sharing
Earnings Level (Missouri Level Level
Retail Electric Operations) ------- --------
UE Customer
===============================================================
1. Up to and including 12.61% 100% 0%
Return and Equity (ROE)
2. That portion of earnings 50% 50%
greater than 12.61% up to and
including 14.00% ROE
3. That portion of earnings 10% 90%
greater than 14.00% up to and
including 16.00% ROE
4. That portion of earnings 0% 100%
greater than 16.00% ROE
===============================================================
The EARP will be in effect for a full three-year period.
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<PAGE>
In the event UE files an electric rate increase case, any Sharing Credits due
for the current or prior Sharing Period will remain the obligation of UE, and
the EARP shall terminate at the conclusion of the then current Sharing Period.
In the event any signatory to the Stipulation and Agreement files a rate
reduction case, any Sharing Credits due for the current or prior Sharing Period
will remain the obligation of UE, and the parties to that case will recommend to
the Commission whether the EARP should remain in effect as currently structured,
be modified or terminated.
Upon any termination of the EARP pursuant to the foregoing, the signatories
will have no further obligation under this section.
Monitoring of the EARP will be based on UE supplying to Staff and OPC, on a
timely basis, the reports and data identified in the Stipulation and Agreement.
These reports and data must be provided as part of the EARP. Staff, OPC and the
other signatories participating in the monitoring of the EARP may follow up with
data requests, meetings and interviews, as required, to which UE will respond on
a timely basis. UE will not be required to develop any new reports, but
information presently being recorded and maintained by UE may be requested.
The sharing of earnings in excess of 12.61 percent, as contemplated in the
sharing grid set out above, is to be accomplished by the granting of a credit to
UE's Missouri retain electric customers by applying credits to customers' bills
in the same manner as applied in Case No. ER-95-411, and as set forth in the
Stipulation and Agreement.
In the final year of the EARP, UE, Staff, OPC and other signatories to the
Stipulation and Agreement shall meet to review the monitoring reports and
additional information required to be provided. By
8
<PAGE>
February 1, 2001, UE, Staff and OPC will file and other signatories may file
their recommendations with the Commission as to whether the EARP should be
continued as is, continued with changes, or discontinued. The rates resulting
from the Stipulation and Agreement will continued in effect after the three-year
EARP period until UE's rates are changed as a result of a rate increase case, a
rate reduction case, or other appropriate Commission action.
UE and its prospective holding company, Ameren, agree to make available to
the Commission, at reasonable times and places, all books and records and
employees and officers of Ameren, UE and any affiliate or subsidiary of Ameren
as provided under applicable law and Commission rules; provided, that Ameren, UE
and any affiliate or subsidiary of Ameren shall have the right to object to such
production of records or personnel on any basis under applicable law and
Commission rules, excluding any objection that such records and personnel are
not subject to Commission jurisdiction by operation of the Public Utility
Holding Company Act of 1935 (PUHCA).
UE, Ameren and any affiliate or subsidiary thereof agree to continue
voluntary and cooperative discovery practices.
UE, Ameren and each of its affiliates and subsidiaries shall employ
accounting and other procedures and controls related to cost allocations and
transfer pricing to ensure and facilitate full review by the Commission and to
protect against cross-subsidization of non-UE Ameren businesses by UE's retail
customers.
UE and Ameren and each of its affiliates and subsidiaries will not seek to
overturn, reverse, set aside, change or enjoin, whether through appeal or the
initiation or maintenance of any action in any forum, a decision or order of the
Commission which pertains to recovery, disallow-
9
<PAGE>
ance, deferral or ratemaking treatment of any expense, charge, cost or
allocation incurred or accrued by UE in or as a result of a contract, agreement,
arrangement or transaction with any affiliate, associate, holding, mutual
service or subsidiary company on the basis that such expense, charge, cost or
allocation has itself been filed with or approved by the Securities and Exchange
Commission (SEC) or was incurred pursuant to a contract, arrangement, agreement
or allocation method which was filed with or approved by the SEC. This provision
is also applied to both gas and electric contracts filed with the Federal Energy
Regulatory Commission (FERC).
No preapproval of affiliated transactions will be required, but all
filings with the SEC or FERC for affiliated transactions will be provided to the
Commission and the OPC. The Commission may make its determination regarding the
ratemaking treatment to be accorded these transactions in a later ratemaking
proceeding or a proceeding respecting any alternative regulation plan.
Finally, the parties have agreed to a proposed system support agreement
between UE and CIPS for a term of ten years. This agreement allows UE to
transfer its current Illinois customers to CIPS, and provides for the transfer
of electric power and capacity to CIPS for the ten-year period. This is capacity
and energy currently used to supply UE's Illinois customers. The Stipulation and
Agreement provides that the Commission has the authority to allocate energy and
capacity addressed in the system support agreement in future ratemaking
proceedings.
10
<PAGE>
B. Market Power Issues
In its September 25, 1996 order, the Commission requested additional
testimony regarding the potential harm to the public interest from any increase
in market power which may be created by the approval of the merger. Because
market power might be of greatest concern to Missouri customers if full retail
competition were authorized, the Commission specifically requested that the
parties include retail competition as a scenario in their analysis.
In response to this request, UE witness Rodney Frame stated that because
retail competition will require changes to existing institutions that will
affect how markets should be analyzed, it is neither reasonable nor advisable to
address the implications of market power until these more fundamental issues are
addressed. UE witness Maureen A. Borkowski stated that UE's transmission system
was designed so that its power plants would serve its native load. Therefore,
the import capability into the St. Louis area is limited by the capacity of its
own transmission system. Further, Ms. Borkowski stated that these limits only
become important to retail competition, and it would be premature to deal with
such a scenario now. Mr. Frame believed that market power problems are likely
to require more scrutiny when generation supplies are deregulated and individual
retail customers can shop among alternative suppliers. UE witness Donald E.
Brandt stated that the time to address potential market power problems
associated with deregulation and retail customer choice is when the decision is
made to go down that path, not now. Further, Mr. Brandt stated that any market
power which UE or Ameren possesses in the retail market is currently mitigated
by the regulatory oversight of the Commission.
11
<PAGE>
OPC stated that the Commission is correct in its concern for the potential
harm to the public interest from an increase in market power from the merger,
especially under the assumption of retail competition. OPC's witness Dr.
Richard A. Rosen recommended that the Commission require UE to analyze carefully
and thoroughly whether the ability of the merged utilities to exercise market
power under retail competition is likely to be greater than the ability of
either individual utility. If there is a significant increase in market power
resulting from the merger, the Commission should identify and implement all
appropriate measures to mitigate the market power. OPC takes the position that
the applicants for the merger have the responsibility to analyze market power,
and that the Commission should require the companies to perform such an analysis
as a condition for approving the merger. OPC does not argue that such a study
must be completed prior to the Commission giving approval of the merger.
Instead, it believes that if market power proves to be a problem, appropriate
measures are available to mitigate market power, and the Commission should
mandate such measures prior to implementation of retail competition.
In his testimony, Staff's witness Dr. John W. Wilson presented an analysis
of market power under retail competition. He defined the relevant market to be
requirements power for both wholesale and retail customers served in the joint
service territories of UE and CIPS. Two scenarios were considered: with and
without pancaked transmission rates. With pancaked transmission rates, Dr.
Wilson found that Ameren would have a price advantage over any competitors
having to pay an additional transmission charge, and would therefore have
significant market power. Without pancaked transmission rates, the relevant
geographic market was found to
12
<PAGE>
be limited by the nonsimultaneous first contingency total transfer capability
into the Eastern Missouri (EMO) and South Central Illinois (SCILL) subregions of
the Mid-America Interconnected Network (MAIN). Taking these transmission
constraints into account, Dr. Wilson performed a concentration analysis to
measure the likelihood of the merged firm exercising market power and found
significant increases in concentration that exceeded the "safe harbor" limits
established in the Department of Justice/Federal Trade Commission Merger
Guidelines ("Guidelines"). Dr. Wilson then examined other factors, as suggested
by the Guidelines, including: (1) the potential of the merger to give rise to
anticompetitive effects; (2) entry conditions; (3) efficiencies; and (4) whether
one of the firms is likely to exit the market because of financial stress. He
found that the merger was likely to enhance the anticompetitive behavior
associated with markets that are characterized as oligopolistic (few competitors
with each recognizing that its own competitive conduct will significantly affect
the other competitors), and will likely elicit defensive responses that allow
dominant firms to exercise price leadership. With Ameren having just under 35
percent of the share of total capacity in the relevant market, Dr. Wilson
expressed concern that the merged firm may find it profitable to increase price
and reduce output below pre-merger levels because "the lost markups on the
foregone sales may be outweighed by the resulting price increase on the merged
base of sales" (Guidelines S 2.22). Market dominance was also seen as a
potential barrier to entry for new firms. Most significant was the potential for
vertical market power (the ability to exert market power in one or more
horizontal markets as a result of the monopoly control of an essential element
in a vertical chain of horizontal markets), based on Ameren's control of the
transmission
13
<PAGE>
system required to serve the requirements markets for generation within UE's and
CIPS's service territories.
While Dr. Wilson recommended against approval of the merger, the Staff
continues to support the Stipulation and Agreement, as do UE and OPC. However,
Dr. Wilson has made several recommendations regarding mitigation of market power
should the Commission approve the merger. These include: (1) Ameren turning over
the operation of its transmission system to an Independent System Operator (ISO)
with a region-wide "postage-stamp" transmission rate; (2) divestiture of
generation resources to reduce barriers to entry that arise from vertical
integration; (3) introduction of retail access in Ameren's service territory to
stimulate entry into retail generation sales; and (4) denial of stranded cost
recovery by the merged entity to assure that any merger savings will be used to
offset any above-market, uneconomic cost for generation.
UE witnesses Mr. Brandt and Ms. Borkowski stated that requiring it to
eliminate pancaking or to participate in an ISO would be unnecessary,
inappropriate and premature. For example, UE witness Rodney Frame argued that
requiring UE to join an ISO could produce adverse consequences for UE's native
load customers due to cost shifting of a $42 million increase in transmission
costs. Mr. Frame also cited FERC's Order 889, which sets forth a code of conduct
and which requires that transmission owners participate in an Open Access Same-
Time Information System (OASIS) for handling any concerns for the exercise of
vertical market power in the markets that exist today. Thus, UE argues that the
Commission should not require it to participate in an ISO until the terms of
participation are known, and should also delay any consideration of the impact
on retail markets until retail competition becomes a reality.
14
<PAGE>
Dr. Wilson stated that the purpose for turning the operation of the
transmission system over to an ISO is to alleviate the concern that, as the
owner of both transmission and generation, the vertically integrated utility
would be able to use the transmission system to "depress competition in
generation markets." Dr. Wilson further pointed out that if an ISO is not
established in a fully independent manner, vertically integrated owners of
generation and transmission could have influence over who becomes and remains as
the ISO operator, in which case nonowner generation rivals may not receive equal
consideration.
Dr. Rosen stated that while FERC Order 888 recognizes transmission access
and pricing as core requirements to deal with potential vertical market power
abuse, the FERC also identified regional ISOs as an important measure for
mitigating potential vertical market power. Dr. Rosen summarized the FERC
guidelines which specify that an ISO: "1) have no financial interest in the
economic performance of any market power participant; 2) should have control
over the operation of interconnected transmission facilities within its region;
3) should identify constraints on the system and be able to take operational
action to relieve those constraints within the trading rules; and 4) should make
transmission system information publicly available to all suppliers on a timely
basis." In addition, Dr. Rosen noted that the FERC identified expansion of
transfer capability by enlarging transmission capacity as a mitigation measure
for vertical market power, but recognized that utilities must obtain approvals
for such expansion from state and local authorities under applicable laws.
The Commission finds there are sufficient facts in evidence to be
concerned about the potential increase in market power from the proposed merger.
The merger could have a significant adverse impact on the degree
15
<PAGE>
of competition within UE's Missouri service territory due to limited transfer
capability for imported power, as well as the disincentives caused by pancaked
transmission rates. In order to eliminate pancaked transmission rates, Ameren
would need to belong to a regional transmission group having a region-wide
transmission rate. To address the vertical market power concern that Ameren
could use its transmission system to restrict competition from other generation,
the regional transmission group should be an entity that will independently
operate the transmission systems of the vertically integrated utilities within
the region. While the Commission agrees that UE and Ameren should not
participate in an ISO at "any cost" to the Missouri ratepayers, now is the time
for UE to take into account the impact that vertical market power could have on
the requirements market under retail competition. Therefore, the Commission
approves the merger upon the condition that UE shall participate in a regional
ISO that eliminates pancaked transmission rates and that is consistent with the
ISO guidelines set out in FERC Order 888. Such an ISO proposal could be formed
in conjunction with the current efforts by UE and other regional utilities to
establish a Midwest ISO or be organized by the merged company with membership
open to other regional utilities. While the Commission understands that joining
an ISO at "any cost" would be unwise, the participation by UE and Ameren in an
ISO is a prudent, necessary condition to assure that the merger is not
detrimental to the public interest.
The Commission also finds that the concerns expressed by OPC regarding
horizontal market power are valid. Such market power can take place at any level
of the production chain as a consequence of there being a very small number of
competing sellers and significant barriers to entry.
16
<PAGE>
Specifically, Dr. Richard A. Rosen expressed concern about horizontal market
power for the generation end of the production chain, as well as in the retail
merchant (demand-side aggregator) markets. Dr. Rosen expressed concern that
alternative generators might find it difficult to enter certain submarkets for
electricity such as the base load, long term market for capacity and energy, or
areas where transmission constraints and strategically located generation
facilities combine to form local "load pockets." In the retail merchant markets,
Dr. Rosen believes that new aggregators would find it difficult to compete with
the incumbent utility because of lack of name recognition.
In order to deal with this potential for horizontal market power, Dr.
Rosen proposed a two-part analysis: (1) theoretical and empirical
characterizations of the market; and (2) simulations of the particular
electricity market under consideration. In both, the unique characteristics of
electricity markets in at least the nine submarkets (base, cycling and peaking
by short, medium and long term) should be examined. In the first analysis, Dr.
Rosen suggested that a more sophisticated version of the Herfindahl-Hirschman
Index (HHI) be developed. In the second analysis, Dr. Rosen recommended that
the simulations include real data from various utilities in a proposed ISO, and
that various gaming scenarios and bidding strategies be analyzed.
The Commission finds that there are sufficient facts in evidence for it to
be concerned about horizontal market power for both generation and aggregation.
The Commission also finds that these concerns are in part related to the merger
of the two companies, but are also related to conditions that should be
considered before implementing retail competition. OPC's proposal balances these
two relationships. Therefore, the
17
<PAGE>
Commission will require UE and interested parties to assess the potential
ability of the merged companies to exercise vertical and especially horizontal
market power in price deregulated retail generation markets. Based on this
analysis, if the market power under retail competition proves to be a problem,
then the Commission will consider taking appropriate action to mitigate market
power prior to establishing statewide retail competition. Because the level of
detail and development of a study of horizontal market power will require
significant effort and time, the Commission will require UE to undertake this
study with the participation of Staff and OPC, with a completion date of January
1, 1998. This study need not be submitted before the merger is completed.
Therefore, the Commission finds the proposed Stipulation And Agreement to
be reasonable and in the public interest if it is modified to include the
conditions which the Commission requires to mitigate market power.
As set out in the Stipulation, after review of both the testimony filed in
this matter and the proposed merger agreement of November 7, 1995, the
Commission also finds the proposed merger, as modified and subject to the
conditions of the attached Stipulation And Agreement, to not be detrimental to
the public interest. Therefore, the Commission will approve the proposed
Stipulation And Agreement as set out in Attachment 1 and the resulting merger
transaction, and order UE to file tariffs in accordance therewith.
Conclusions of Law
------------------
The Missouri Public Service Commission has arrived at the following
conclusions of law.
18
<PAGE>
The applicant, Union Electric Company, is a public utility under the
jurisdiction of the Commission, regulated generally by Chapter 393, RSMo 1994.
Specifically, the proposed sale, transfer and assignment of certain rights,
properties, and assets is controlled by Section 393.190(1), which states in
part:
No gas corporation, electrical corporation, water corporation or
sewer corporation shall hereafter sell, assign, lease, transfer,
mortgage or otherwise dispose of or encumber the whole or any part
of its franchise, works or system, necessary or useful in the
performance of its duties to the public, nor by any means, direct
or indirect, merge or consolidate such works or system, or franchises,
or any part thereof, with any other corporation, person or public
utility, without having first secured from the commission an order
authorizing it to do so.
The Commission has found the Stipulation And Agreement, as set out in
Attachment 1 hereto, to be just and reasonable, and will approve the Stipulation
And Agreement. In addition, the Commission finds the proposed merger
transaction, as reflected in the contractual agreement contained as a part of
the Union Electric Company filing of November 7, 1995, and subject to the
conditions and modifications as set out in the above Stipulation And Agreement,
is not detrimental to the public interest.
The Commission further concludes that Union Electric Company should file
tariffs in full compliance with the merger agreement, the Stipulation And
Agreement, and this Report And Order.
IT IS THEREFORE ORDERED:
1. That the Stipulation And Agreement, marked Attachment 1 to this Report
And Order, will be approved by order of the Commission provided that Union
Electric Company files a pleading in this docket within ten (10)
19
<PAGE>
days of the date of issuance of this order consenting to the following
conditions:
(a) No later than December 31, 1997, Union Electric Company shall
file or join in the filing of a regional ISO proposal at the
Federal Energy Regulatory Commission that eliminates pancaked
transmission rates, that is consistent with the ISO guidelines
set out in FERC Order 888, and the meets the following
requirements:
(1) If the ISO proposal filed filed at FERC is the result of the
current efforts by UE and other utilities to establish a
Midwest ISO, UE shall simultaneously file at this Commission
a request for approval of its participation in the proposed
ISO;
(2) If the Midwest ISO proposal is filed at FERC and UE has
chosen not to participate, then UE shall advise this
Commission within thirty (30) days of the FERC filing why it
is not participating in the Midwest ISO;
(3) If the Midwest ISO proposal is not filed before the FERC by
December 31, 1997, then by March 31, 1998 UE shall file with
this Commission a plan for establishing an independent
entity charged with the operation, pricing and planning of
its transmission system. This plan shall be developed in
cooperation with Staff and the Office of the Public Counsel,
shall provide for the formation and expansion of this
20
<PAGE>
independent entity to include other utilities, and shall be
filed with the FERC; and
(b) By January 1, 1998 and with the participation of Staff and the
Office of Public Counsel, Union Electric Company shall file with
this Commission a report that assesses the potential ability of
the merged companies to exercise vertical and especially
horizontal market power in price deregulated retail generation.
2. That, with the consent of the parties, the testimony of Union Electric
Company witnesses Rodney Frame, Maureen A. Borkowski and Donald E. Brandt;
Office of the Public Counsel witness Dr. Richard A. Rosen; and the Commission
Staff witness Dr. John W. Wilson is hereby entered into evidence and made a part
of the record in this proceeding.
3. That this Report And Order shall become effective on March 4, 1997.
BY THE COMMISSION
/s/ Cecil I. Wright
Cecil I. Wright
Executive Secretary
( S E A L )
McClure and Kincheloe, CC., concur;
Zobrist, Chm., Crumpton and Drainer,
CC., concur, with concurring opinions
to follow.
Dated at Jefferson City, Missouri,
on this 21st day of February, 1997.
21
<PAGE>
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF MISSOURI
In the Matter of the Application of )
Union Electric Company for an Order )
Authorizing (1) Certain Merger )
Transactions Involving Union Electric )
Company; (2) the Transfer of Certain ) Case No. EM-96-149
Assets, Real Estate, Leased Property, ) ------------------
Easements and Contractual Agreements )
to Central Illinois Public Service )
Company; and (3) in Connection )
Therewith, Certain Other Related )
Transactions. )
CONCURRING OPINION OF COMMISSIONER HAROLD CRUMPTON
==================================================
AND VICE CHAIR M. DIANNE DRAINER
================================
We concur with the Commission's decision in Case No. EM-96-149, which
approved the Stipulation and Agreement and specified that the proposed merger
transaction between Union Electric Company (UE) and CIPSCO Incorporated (CIPSCO)
is not detrimental to the public interest. However, we respectfully do not agree
with the majority that the additional conditions set out in the order are
appropriate or necessary at this time. It is premature to state that
participation in an independent system operator (ISO) company is a necessary
condition in order to assure that the merger is not detrimental to the public
interest. Although we would encourage UE to recognize that becoming a member of
an ISO is a prudent move in the current pre-competitive electric environment, it
is going too far to make it a necessary condition when, in fact, there is
presently no Midwest ISO established for UE to join in Missouri. Additionally,
although the Commission states "that joining an ISO at 'any cost' would be
unwise", it does not define the criteria that UE should use to evaluate when the
ISO concept has become too costly to join.
<PAGE>
With respect to the obligation placed on UE to complete a market power
report in this docket, we agree with UE witness Rodney Frame that it was
premature to require an analysis of the market power implications of the
proposed merger, given the many uncertain and unknown changes facing the
electric industry. It would be more prudent at this time to open a new docket to
review the restructuring of the electric industry and retail wheeling in
Missouri, in which all interested parties may participate. If and when
competition and restructuring become a part of the electric utility environment
in Missouri, there should be an assessment of all market power issues for all
electric companies in the state. This was not the case to demand such an
assessment. We should not be bureaucratic in demanding a report in this docket
which will be incomplete because numerous variables needed for a future market
power analysis are currently unknown. In addition, parties essential to
providing a thorough market power report have not been given the opportunity to
participate in the drafting of that report.
Finally, all companies have limited human resources to depend upon to
gather data and write analytical reports. These resources place expense demands
on companies that translate into increased revenue requirements. Therefore, we
must be prudent when requesting additional reporting documents from companies.
Respectfully Submitted,
/s/ Harold Crumpton
Harold Crumpton
Commissioner
(SEAL)
/s/ M. Dianne Drainer
M. Dianne Drainer
Vice Chair
Dated at Jefferson City, Missouri,
on this 6th day of March, 1997.
<PAGE>
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF MISSOURI
In the Matter of the Application of Union Electric )
Company for an Order Authorizing (1) Certain )
Merger Transactions Involving Union Electric )
Company; (2) the Transfer of Certain Assets, ) Case No. EM-96-149
Real Estate, Leased Property, Easements and ) ------------------
Contractual Agreements to Central Illinois Public )
Service Company; and (3) in Connection There- )
with, Certain Other Related Transactions. )
CONCURRING OPINION
------------------
Zobrist, Chairman:
This case stands as an example of the difficult issues facing state
commissions considering mergers and consolidations at a time when Congress and
state legislatures debate the merits of restructuring the electric industry.
On the important issue of market power, I found it puzzling that the
parties apparently avoided discussion of this topic in their efforts to arrive
at the Stipulation and Agreement. If such discussions occurred, the record
initially contained very little hint of it. While there exists no universally
accepted method to analyze post-merger market power under the current system of
monopoly franchises, all parties must engage in a comprehensive effort to
develop the analytical tools to study this issue. While economies of scale
through consolidation and merger may bring the benefits of lower prices, better
service and more choices to customers, the market power of such new entities
cannot be allowed to manipulate prices to generate excessive profits.
The study which the Commission ordered should use those tools which can
best measure the ability of Ameren to achieve benefits for its customers. I
encourage the Commission's Staff
1
<PAGE>
and the Office of the Public Counsel to work constructively with the company to
produce an analysis which is meaningful and practical. The parties should
consider the use of computer models, such as those which are a part of the
record in the proposed merger of Northern States Power Company and Wisconsin
Electric Power Company into Primergy Corporation. See In re Wisconsin Elec.
Power Co., et al., Docket No. EC95-16-000 (F.E.R.C., Aug. 29, 1996) (presiding
administrative law judge's initial decision). Although these kinds of tools may
be works in progress, like the Hatfield Model and other proxy cost models being
developed in the telecommunications arena, they should be explored and used if
they offer hope of advancing the analysis.
I am not certain that the Federal Energy Regulatory Commission's adoption
of the Department of Justice/Federal Trade Commission Merger Guidelines, which
include the Herfindal-Hirschman Index (HHI), gives us the best tool to analyze
market power in the electricity industry. See In re Commission's Merger Policy
under the Federal Power Act: Policy Statement, Order No. 592, Docket No.
RM96-6-000 (F.E.R.C., Dec. 18, 1996). It may be that the Guidelines are a first
and necessary step in a long series of steps to better market analysis. I expect
that more sophisticated tools will develop as the electricity industry changes.
Any future merger case brought before this Commission should contain a
careful analysis of market power issues, in addition to the traditional means
used to measure the alleged merger benefits for ratepayers. All parties,
including Staff, should be careful in their selection of expert witnesses.
Staff's position endorsing the Stipulation and Agreement in this case was
weakened by its retention of an expert who opposed Staff's recommendations.
While he offered certain helpful observations on market power, his argument for
divestiture under the facts of this case was not at
2
<PAGE>
all persuasive.
Finally, I believe that the Commission wisely approved this merger upon the
condition that Union Electric Company and its holding company Ameren join an
independent system operator (ISO). The concept of an ISO which offers non-
discriminatory access to the integrated transmission system over a broad region
is the last, best hope for those who wish to avoid mitigating market power at
the local level through the divestiture of generation assets. Many knowledgeable
individuals have expressed the belief that an ISO cannot function as a truly
independent operator because the transmission owners will refuse to grant the
necessary authority to the ISO governors. While such skepticism may be
justified, I believe that governing principles can be developed which grant
sufficient powers to the "trustees" of the transmission system to make the ISO
truly independent. See "Declaration of Independence" (signed by 18 state
commissioners) (Oct. 22, 1996). This Declaration, which follows my opinion,
expresses the belief that an ISO can function properly only if its independence
is guaranteed. While the owners of the transmission system are entitled to
retain a voice in the operation, maintenance and planning of the system, they
must absolutely relinquish any ability to control or unduly influence the ISO.
Otherwise, they have proven the case that divestiture is the only solution.
/s/ Karl Zobrist
----------------------------------
Karl Zobrist, Chair
March 10, 1997
3
<PAGE>
A DECLARATION OF INDEPENDENCE
Why Transmission and System Operation Must Be Truly Independent
from the Ownership of Generation
Efforts to restructure the electric power industry are based on the
conviction that open competition in power supply will advance consumer
interests better than traditional economic regulation. The objective of
restructuring must be to create conditions that will allow genuine competition
to thrive. The ultimate measure of success is whether competition delivers
benefits to consumers, not just to those in the electricity business, either
competitive electricity suppliers or providers of monopoly wire services.
To succeed, the restructuring process must address the inherent market
power problems caused by ownership or control of the monopoly transmission
system that connects competitive generators with their customers. The
divergent interests of suppliers and customers are clear:
* In competitive electricity markets, all generators will benefit from
high prices while customers benefit from low prices;
* In competitive markets, higher prices achieved through any action,
including control of the transmission system, by any generator or
group of generators, will benefit all generators;
* Decisions regarding transmission pricing, dispatch rules, and new
investment in the transmission system can add value to generation. An
unnecessarily constrained transmission system will lead to overpriced
electricity and excess profits for suppliers;
* Many techniques for leveraging transmission and system operation to
add value to generation assets are complex, subtle, and difficult to
control through regulatory oversight.
This means that steps taken to deregulate supply could harm rather than
advance consumer interests, if not paired with measures to sever suppliers'
control over transmission services.
To ensure that the transmission system is operated and expanded to suit
the needs of society at large rather than the narrower interest of generators,
most nations implementing competition in generation have chosen to completely
separate the ownership of power plants from ownership or control of
transmission lines. Such
<PAGE>
separation provides a clear, workable and effective means of protection
against the potential for many types of abuse.
However, many US utilities oppose divestiture of either generation or
transmission assets. They offer instead to separate ownership from control, by
placing control of the transmission system in an "Independent System Operator"
or ISO. Unfortunately, most ISO proposals put forth to date have been
seriously deficient in one or both of two key areas: (1) the scope of
functions entrusted to the ISO is too limited, so it does not effectively
control transmission pricing and system operation, and (2) the ISO is not
truly independent.
Each ISO should have a mandate to manage and expand the portion of the
nation's grid under its control so as to ensure reliability while minimizing
costs. The management of the transmission system involves the exercise of
hundreds of small and large decisions, many of them subjective judgment calls,
involving such matters as the pricing of transmission service, construction of
new lines, and operation and maintenance of the existing system. All of these
decisions should be made by the ISO, subject to regulatory oversight. The
transmission system should be operated and expanded so as to encourage rather
than limit competitive challenges among suppliers.
Most ISO proposals fall short by giving suppliers substantial, or in some
cases, majority control of the system. Independence is not achieved by simply
sharing control of the transmission system among different types of
suppliers. To achieve independence, ISOs should be responsible to boards that
are completely independent of suppliers. In the absence of a clear structural
solution such as divestiture, we must create solutions equivalent to a non-
voting "transmission trust": generating companies must cede all control of
their transmission lines to the ISO; they will be entitled to fair
compensation on their investment, but afforded no opportunity to influence the
use of those lines.
The ISO should, in turn, be subject to appropriate regulatory oversight.
This regulatory framework should strive to harmonize the interests of the ISO
with those of the public: reliability and stability, low generation and
transmission prices, and minimum environmental impact. Such regulation must
reflect both federal and state interests, ensuring the development of regional
markets while recognizing states' interests in siting, and in shaping
regulatory reform to suit local concerns.
Effective regulation of regional markets and transmission systems may
require creation of new regional governance
<PAGE>
mechanisms, such as regional joint boards or councils under existing or new
enabling legislation. However this is accomplished, FERC, the States, and
Congress must insist upon creation of ISOs that have authority to operate and
improve regional transmission systems, and that are truly independent from
the owners of generation resources. Only when transmission constraints cannot
be used to leverage above-market value from generation assets will the
public's interests in genuine competition be well served.
Richard H. Cowart, Chair John B. Howe, Char
Suzanne D. Rude Janet Gail Besser
David Coen Massachusetts DPU
Vermont PSB
Karl Zobrist, Chair Edward M. Meyers, Com.
Duncan E. Kincheloe District of Columbia PSC
Missouri PSC
Roger Hamilton, Chair Wayne Shirley, Chair
Ron Eachus New Mexico PUC
Joan Smith
Oregon PUC Renz D. Jennings, Chair
Arizona Corp. Commission
John Hanger Craig A. Glazer, Chair
Pennsylvania PUC Ohio PUC
James J. Malachowski, Chair Karl A. McDermott
Paul E. Hanaway Illinois Commerce Com.
Kate F. Racine
Rhode Island PUC Sharon L. Nelson, Chair
Richard Hemstad, Com.
William R. Gillis, Com.
Washington U & TC
<PAGE>
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF MISSOURI
In the matter of the Application )
of Union Electric Company for an )
order authorizing: (1) certain merger )
transactions involving Union Electric )
Company; (2) the transfer of certain ) Case No. EM-96-149
Assets, Real Estate, Leased Property, )
Easements and Contractual Agreements )
to Central Illinois Public Service )
Company; and (3) in connection )
therewith, certain other related )
transactions. )
NOTICE OF ACCEPTANCE OF CONDITIONS
----------------------------------
COMES NOW Union Electric Company and states that it accepts the conditions
set forth in the Ordered section, paragraph 1(a)(1)-(3) and 1(b), in the
Missouri Public Service Commission Report and Order effective March 4, 1997.
Respectfully submitted,
UNION ELECTRIC COMPANY
By /s/ James J. Cook
------------------------------
James J. Cook, MBE 22697
Joseph H. Raybuck, MBE 31241
William J. Niehoff, NBE 36448
Attorneys for
Union Electric Company
1901 Chouteau Avenue
P.O. Box 149 (M/C 1310)
St. Louis, Missouri 63166
(314) 554-2237
(314) 554-2976
(314) 554-2514
(314) 554-4014 (fax)
CERTIFICATE OF SERVICE
----------------------
I hereby certify that on this 24th day of February, 1997, a copy of the
foregoing was served upon All Parties of Record.
/s/ James J. Cook
------------------------------
James J.Cook
<PAGE>
EXHIBIT G-1.1
AMEREN CORPORATION
UNAUDITED PRO FORMA COMBINED
FINANCIAL DATA SCHEDULE
(Thousands of Dollars Except Per Share Amounts)
Three Months Ended March 31, 1997
<TABLE>
<CAPTION>
Pro Forma Pro Forma
Caption Heading UE CIPSCO Adjustments Combined
--------------- ---------- ---------- ----------- ----------
<C> <S> <C> <C> <C> <C>
1 Total net utility plant $5,390,727 $1,455,388 $ 106,165 $6,952,280
2 Other property and investments 100,366 115,830 0 216,196
3 Total current assets 435,682 194,399 52,250 682,331
4 Total deferred charges 39,572 29,743 (2,694) 66,621
5 Balancing amount for total assets 849,642 174,877 0 1,024,519
6 Total assets 6,815,989 1,970,237 155,721 8,941,947
7 Common stock 510,619 356,812 (866,059) 1,372
8 Capital surplus, paid in 716,879 0 866,059 1,582,938
9 Retained earnings 1,091,090 302,592 0 1,393,682
10 Total common stockholders equity 2,318,588 659,404 0 2,977,992
11 Preferred stock subject to mandatory redemption 0 0 0 0
12 Preferred stock not subject to mandatory redemption 155,197 80,000 0 235,197
13 Long term debt, net 1,879,651 493,303 115,556 2,488,510
14 Short term notes 33,900 0 0 33,900
15 Notes payable 0 0 0 0
16 Commercial paper 0 41,025 14,444 41,025
17 Long term debt-current portion 5,000 58,000 0 77,444
18 Preferred stock-current portion 0 0 0 0
19 Obligations under capital leases 80,798 0 0 80,798
20 Obligations under capital leases-current portion 32,631 0 0 32,631
21 Balancing amount for capitalization and liabilities 2,310,224 638,505 25,721 2,974,450
22 Total capitalization and liabilities 6,815,989 1,970,237 155,721 8,941,947
23 Gross operating revenue 487,258 225,343 48,377 760,978
24 Federal and state income taxes expense 21,335 9,476 2,033 32,844
25 Other operating expenses 400,336 191,394 40,943 632,673
26 Total operating expenses 421,671 200,870 42,976 665,517
27 Operating income (loss) 65,587 24,473 5,401 95,461
28 Other income (loss), net (204) 146 (2,940) (2,998)
29 Income before interest charges 65,383 24,619 2,461 92,463
30 Total interest charges 33,753 8,155 2,461 44,369
31 Net income 29,426 15,551 0 44,977
32 Preferred stock dividends 2,204 913 0 3,117
33 Earnings available for common stock 29,426 15,551 0 44,977
34 Common stock dividends 64,849 17,716 4,567 87,132
35 Total annual interest charges on all bonds * 0 0 0 0
36 Cash flow from operations 63,351 (14,104) 13,181 62,428
37 Earnings per share-primary $0.29 $0.46 0 $0.33
38 Earnings per share-fully diluted $0.29 $0.46 0 $0.33
</TABLE>
* Required on fiscal year-end only
<PAGE>
Exhibit K-1.1
UNION ELECTRIC COMPANY
&
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
SUPPLEMENTAL ANALYSIS OF
THE ECONOMIC IMPACT OF A
DIVESTITURE OF THE GAS OPERATIONS OF
UE AND CIPS
The management and staffs of Union Electric Company (UE) and Central Illinois
Public Service Company (CIPS) conducted this supplemental study to the "Analysis
of the Economic Impact of a Divestiture of the Gas Operations of UE and CIPS"
dated September 19, 1996. The Analysis dated September 19, 1996 determined the
economic effects on shareholders and customers of divesting UE and CIPS of their
natural gas assets and businesses by spinning them off into two separate and
distinct entities. This supplemental study evaluates the additional costs from
lost economies that would be associated with the spin-off of UE's and CIPS'
natural gas assets and businesses followed by a combination of the two entities
into one gas entity, all of which would take place after the merger and creation
of Ameren Corporation.
July 10, 1997
<PAGE>
TABLE OF CONTENTS
-----------------
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
SECTION I. EXECUTIVE SUMMARY AND CONCLUSIONS 1
SECTION II. GENERAL STUDY ASSUMPTIONS 5
SECTION III. NEWGAS-UE/CIPS
A. OVERVIEW 7
B. ANALYSIS 8
C. SCHEDULE OF EXHIBITS 15
</TABLE>
<PAGE>
===============================================
SECTION I. EXECUTIVE SUMMARY AND CONCLUSIONS
===============================================
On September 19, 1996, the management and staffs of Union Electric Company (UE)
and Central Illinois Public Service Company (CIPS) completed a study entitled
"Analysis of the Economic Impact of a Divestiture of the Gas Operations of UE
and CIPS" (Study). The Study, submitted as Exhibit K-1 to the Form U-1 filed on
October 31, 1996, demonstrated that substantial additional costs from "lost
economies" would be associated with the divestiture of the separate gas
companies of UE and CIPS.
The present study, entitled "Supplemental Analysis of the Economic Impact of a
Divestiture of the Gas Operations of UE and CIPS" (Supplemental Study),
evaluates the additional costs from lost economies that would be associated with
the spin-off of UE's and CIPS' natural gas assets and businesses followed by a
combination of the two entities into one gas entity, all of which would take
place after the merger and creation of Ameren Corporation. The Supplemental
Study shows that while lost economies would be somewhat smaller if the gas
operations of UE and CIPS were combined, the additional costs are nonetheless
very significant. The Supplemental Study further demonstrates that continued
retention of the gas operations by UE and CIPS following the merger is in the
best interest of the ratepayers and shareholders alike.
As with the original Study, where possible, estimates of the operating costs
were compared to similar investor-owned gas distribution companies in the
Midwest. The effects on shareholders were calculated using the increased costs
caused by divestiture assuming no rate relief. The effects on customers were
calculated assuming recovery of additional costs through rate increases. To
facilitate comparisons, the Supplemental Study utilizes data for the same time
period used in the Study.
INCOME TAXES ON THE DIVESTITURE TRANSACTION
- -------------------------------------------
Under current law, the divestiture of the gas businesses of UE and CIPS into a
single, combined company, after the merger and creation of Ameren Corporation,
could be accomplished on a tax-free basis. However, legislation is pending in
the U.S. Congress that, if passed, would apply to this transaction and would
impose substantial income taxes.
Under the proposed legislation, CIPS would be subject to income tax on the
difference between the fair market value of its gas assets (as of the date they
are spun off from CIPS) and the tax basis of those assets. Using the net book
value as a conservative minimum fair market value for these assets, it is
estimated that these income taxes would be at least $24,000,000. These costs
would, if incurred, substantially increase the lost economies already
illustrated in Section I, Tables I-1 and I-2, to follow.
1
<PAGE>
SHAREHOLDERS
- ------------
The projected effects on the shareholders of the lost economies resulting from
the spin-off of UE's and CIPS' gas businesses into NEWGAS-UE/CIPS are shown in
Table I-1:
<TABLE>
<CAPTION>
TABLE I-1*
ANNUAL EFFECT OF LOST ECONOMIES ON SHAREHOLDERS
------------------------------------------------------------
NEWGAS-UE/CIPS
------------------------------------------------------------
<S> <C>
Lost Economies $34,768,000
Lost Economies as a Percent of:
Total Gas Operating Revenue 15.99%
Total Gas Operating Revenue Deductions 17.57%
Gross Gas Income 177.66%
Net Gas Income 252.34%
In the Absence of Rate Relief:
Return on Rate Base -4.78%
Return on Net Plant -4.32%
------------------------------------------------------------
* The effect of lost economies shown in this table does not
reflect income tax liability from proposed tax legislation,
as previously explained.
------------------------------------------------------------
</TABLE>
In Table I-1, Lost Economies represents the increased costs, excluding income
taxes, to operate as one stand-alone company. Total Gas Operating Revenue is the
sum of all gas revenues for the 12 months ended December 31, 1995. Total Gas
Operating Revenue Deductions include all purchased gas and gas withdrawn from
storage, operation and maintenance expenses, depreciation and taxes other than
income taxes. Gross Gas Income is the difference between Total Gas Operating
Revenue and Total Gas Operating Revenue Deductions. Net Gas Income is Gross Gas
Income minus Income Taxes. (See SECTION III.C. NEWGAS-UE/CIPS Exhibit 1 for
detailed information.)
GAS CUSTOMERS
- -------------
The projected effect on gas customers, assuming the stand-alone organization is
allowed rate increases to recover lost economies and applicable income taxes, is
shown in Table I-2:
2
<PAGE>
<TABLE>
<CAPTION>
--------------------------------------------------
TABLE I-2*
ANNUAL EFFECT OF LOST ECONOMIES ON GAS CUSTOMERS
--------------------------------------------------
RATE REVENUE NEWGAS-UE/CIPS
<S> <C>
Pre Spin-off $217,425,000
Post Spin-off $267,857,000
Dollar Increase $ 50,432,000
Percent Increase 23.20%
--------------------------------------------------
* The effect of lost economies shown in this
table does not reflect income tax liability from
proposed tax legislation, as previously explained
--------------------------------------------------
</TABLE>
(See SECTION III.C. NEWGAS-UE/CIPS Exhibit 1 for detailed information
supporting Table I-2.)
ELECTRIC CUSTOMERS
- ------------------
In addition to the forgoing impacts, divesting the gas business would result in
rate increases of .73% for CIPS electric customers and .11% for UE electric
customers. This impact is due to each company transferring all common property
into the electric rate base, requiring rate increases to maintain the existing
rates of return.
CONCLUSIONS
- -----------
The economies that CIPS and UE realize from combined electric and gas operations
provide significant benefits to customers and shareholders. This Supplemental
Study demonstrates that spinning off the two gas divisions into a separate
entity would be inefficient due to lost economies, which would be passed on to
gas customers, electric customers and/or to shareholders. Without increased
rates, the immediate negative effect on shareholders' earnings would be
substantial, making ownership of shares in NEWGAS-UE/CIPS unattractive.
The pass-through of increased costs to customers would cause significant
increases in gas rates, with no increase in the level or quality of service. The
rate increases required to operate NEWGAS-UE/CIPS would total about $50,432,000
(Table I-2). Such increases would make NEWGAS-UE/CIPS less competitive at a time
when competition in the energy industry is rapidly increasing due to Federal
Energy Regulatory Commission (FERC) Order 636 and other FERC and state
regulatory initiatives. In addition, NEWGAS-UE/CIPS would receive none of the
benefits expected to accrue from the proposed merger.
It is estimated there would be no substantial benefits from the divestiture of
the gas businesses for electric customers. Minimal savings could be achieved for
items such as data processing costs, and minimal personnel reductions could
occur in the combination gas and electric districts. These savings would be
offset by additional costs such as changing meter reading routes and modifying
data processing applications.
3
<PAGE>
Proposed tax legislation would substantially increase the lost economies,
previously illustrated on Tables I-1 and I-2.
4
<PAGE>
SECTION II. GENERAL STUDY ASSUMPTIONS
The assumptions, information and data utilized for this Supplemental Study are
based on the industry expertise and experience of the management and staffs of
UE and CIPS. Below are the major assumptions employed for this Supplemental
Study, which are substantially the same as was used in the original Study:
1. Organization: Each of the gas organizations to be spun off would combine to
operate as one independent, stand-alone, publicly held, regulated company. It
would have all the necessary management personnel, along with facilities,
equipment, materials, supplies, etc., required to operate as a stand-alone
company.
2. System Operation & Maintenance: The gas and electric systems would continue
to be operated and administered in the existing manner to insure safe and
reliable service. In addition, current system renewal programs would be
continued.
3. Staffing: A sufficient number of employees would be included within the
stand-alone gas company to ensure that customers receive the present level
and quality of service.
4. Labor Costs: Labor cost estimates were based upon assessments of work
assignments, using UE and CIPS wage structures. Senior management salary
estimates were based on industry averages.
5. Non-labor Costs: These costs were estimated based upon actual costs incurred
by UE and CIPS for their gas businesses assuming the customers of NEWGAS-
UE/CIPS would receive existing levels and quality of service.
6. Cost Pass-through: Full pass-through to customers of increased costs due to
lost economies would be allowed in formal rate proceedings.
7. Specific Labor Assumptions:
---------------------------
a) Organization size and spans of control were estimated using existing UE
and CIPS structures, adjusted to recognize the broader functional
responsibilities that would exist in the new, smaller company.
b) Pensions and benefits were estimated as a percent of direct labor cost.
c) Employee benefits would be similar to the combined companies of UE and
CIPS.
8. Capital Expenditure and Cost Assumptions:
-----------------------------------------
a) The accounting for direct and indirect capital expenditures would remain
the same as that currently used in the combined utilities of UE and CIPS.
b) The actual capital costs for the divested company would be considerably
higher than those of UE and CIPS. Since gas purchases are highly
seasonal, the
5
<PAGE>
b) The actual capital costs for the divested company would be considerably
higher than those of UE and CIPS. Since gas purchases are highly
seasonal, the stand-alone gas company would experience great volatility
in its cash positions. At the same time, the book value of the assets of
NEWGAS-UE/CIPS would be much smaller than those of the combined utility
predecessors. As a result, the new company would be perceived as riskier
and would be subject to higher borrowing rates. Because of the
constraints of the CIPS and UE mortgage indentures, the debt associated
with the spun-off facilities would have to be refinanced at today's
rates.
9. Transition Cost Assumptions: Costs such as the legal, investment banking,
filing and printing fees associated with the public spin-off of stock,
creation of new indenture agreements, negotiation of new service contracts
and costs to establish business processes would be incurred and amortized
appropriately.
10. Transactions Between Companies: All transactions and transfers between
NEWGAS-UE/CIPS and UE/CIPS, would be arms-length transactions based upon
fair market values.
11. Other Assumptions:
------------------
a) Facility costs would include separate headquarters, storerooms, and
office space for employees currently using facilities shared by the
electric and gas businesses.
b) To facilitate the assessment of financial effects, it was assumed the
costs for outsourcing and performing work in-house would be comparable.
c) Information Services work would be outsourced.
d) Additional equipment (i.e., vehicles, trenchers, heavy power operated
equipment) would be leased under an operating lease.
e) External auditing costs were estimated based on industry surveys.
f) Insurance costs were quotes based on protecting the gas utility against
losses and damages to leased properties used in its operations, as well
as injuries and damage claims.
g) Regulatory commission expenses would be similar to those currently
incurred in connection with formal cases before regulatory commissions
involving gas operations.
h) Potential costs for clean-up of environmental sites (coal gasification
plants) would be the same whether or not the gas businesses are spun
off. For this reason such costs were not considered in this Supplemental
Study.
6
<PAGE>
================================================================================
SECTION III.A. NEWGAS-UE/CIPS OVERVIEW
================================================================================
Spinning off UE's and CIPS' gas operations into a separate stand-alone company
(NEWGAS-UE/CIPS) would result in the following:
. NEWGAS-UE/CIPS would need to establish service functions duplicating those at
UE and CIPS, including treasury, financial planning, accounting, tax planning
and compliance, rates, risk management, employee benefits, marketing, legal,
customer service, regulatory and public affairs.
. Annual operating revenue deductions, exclusive of income taxes, for NEWGAS-
UE/CIPS would be about 18% ($34.8 million) greater than UE's and CIPS gas
operating revenue deductions. (SECTION III.C, Exhibit 1).
. NEWGAS-UE/CIPS' customers would experience a rate increase of about 23%
($50.4 million) in order to provide an 11.07% rate of return for stockholders
(SECTION III.C, Exhibit 1).
. NEWGAS-UE/CIPS would be at a competitive disadvantage because of high
operating expenses.
. There would be no substantial benefits for customers or stockholders.
7
<PAGE>
================================================================================
SECTION III.B. NEWGAS-UE/CIPS ANALYSIS
================================================================================
The UE and CIPS gas distribution systems serve a total of approximately 288,000
(as of December 31, 1995) customers over a 23,000 square mile area in Missouri
and Illinois. There are 7,150 miles of mains and 3,955 miles of service lines
in the combined systems. Natural gas revenues for 1995 were $217.4 million on
total system throughputs of 53.5 billion cubic feet of gas.
UE and CIPS operate as tightly integrated companies with many employees
supporting both gas and electric operations. Of UE's and CIPS' 8,618 employees
(as of December 31, 1995), only 349 devote 100% of their time to gas operations.
Shared operations include customer service personnel who deal with service
requests for both gas and electric customers, and meter readers who read both
the electric and gas meters. Additionally, UE's and CIPS' gas and electric
businesses also share services in the areas of treasury, financial planning,
accounting, tax planning and compliance, rates, risk management, employee
benefits, marketing, legal, customer service, regulatory and public affairs.
The shared gas/electric responsibilities of many of UE's and CIPS' employees
have enabled UE and CIPS to provide quality service at low costs.
ORGANIZATION STRUCTURE AND STAFFING IMPACT
- ------------------------------------------
The UE and CIPS organizations, as of December 31, 1995, were used as a pattern
for developing the NEWGAS-UE/CIPS organization structure. See SECTION III.C,
Exhibit 5 for the proposed organization. Divesting the gas operations would
eliminate the effective use of shared staff to the detriment of both the gas and
electric operations. To operate the gas business on a stand-alone basis, 553
additional employees would be required, in addition to the 349 employees
mentioned above. UE and CIPS could expect very minimal staffing reductions in
the electric business as a result of a gas divestiture. SECTION III.C, Exhibit
6 shows the proposed staffing, salaries, and wages summary, while Exhibit 2d
shows that NEWGAS-UE/CIPS would incur an estimated net labor increase, including
benefits, of $14,522,000. Exhibit 7 shows that with this proposed staffing,
NEWGAS-UE/CIPS compares favorably with other gas utilities in the number of
customers per employee. The following comments demonstrate some of the reasons
for additional staffing:
Each customer of UE and CIPS receives one bill for both gas and electric
service and pays with one check. When treasury personnel process the
checks, automated equipment posts both electric and gas payments to
customers' accounts. NEWGAS-UE/CIPS would have to hire staff to handle gas
payments that are now handled at essentially no additional cost by UE and
CIPS. Spinning off the gas operations would only minimally reduce the
workload on UE's and CIPS' cash
8
<PAGE>
processing personnel, since most gas customers also have electric service
and would still send a check monthly.
UE's and CIPS' meter readers read gas and electric meters in the same
routes. NEWGAS-UE/CIPS would have to hire meter readers to re-trace the
same routes to read the gas meters. Spinning off the gas operations would
not reduce the number of meter readers needed by UE and CIPS since their
routes would remain essentially the same.
UE's Finance, Accounting and Corporate Services and CIPS' Finance and
Accounting personnel maintain the books of the Companies and arrange for
insurance. They arrange for long-term financing and borrow short-term
funds for operations. They maintain stockholder records and perform
various investor services. NEWGAS-UE/CIPS would require personnel to
provide the same services. Spinning off the gas operations would not
provide any measurable savings for UE and CIPS in the finance and
accounting area, since all the existing books and records of the Company
would remain essentially unchanged, insurance needs would be similar, and
staff time devoted to financing activities would not be significantly
reduced.
UE's and CIPS' Human Resources Divisions administer benefit and salary
plans. NEWGAS-UE/CIPS would need to hire personnel to perform the same
duties. Spinning off the gas operations would not provide substantial
savings to UE and CIPS, because each of UE's and CIPS' existing benefit and
salary plans, and the associated reporting requirements, would remain.
UE's Supply Service Division and CIPS' Purchasing and General Services
Departments provide materials, supplies, transportation equipment, etc. to
operating divisions. NEWGAS-UE/CIPS would need to hire personnel to
perform the same duties for gas operations. Spinning off the gas
operations would reduce the number of purchase orders handled by UE and
CIPS as well as the amount of material handled and storage costs. However,
the quantities involved are a small percentage of the total, so few, if
any, staffing reductions could be affected and no facilities could be
eliminated, making the actual savings for UE and CIPS minimal.
UE's engineering staff provides engineering expertise to gas operating
divisions, while CIPS has dedicated gas engineering staff. NEWGAS-UE/CIPS
would need to hire personnel to perform gas engineering duties since CIPS
gas engineering would not be capable of performing all of the additional
work previously performed by UE engineering. Spinning off the gas
operations would reduce the workload on UE engineering personnel, but since
gas operations analysis is a small
9
<PAGE>
percentage of their work, spread over a geographically dispersed area, UE
would not be able to eliminate any engineering positions.
UE's legal staff provides legal, regulatory and claims services for UE's
operating divisions, while CIPS uses outside counsel to perform these
services. NEWGAS-UE/CIPS would need to hire personnel to perform these
duties, or pay the increased cost of additional outside counsel. Since
many legal issues are not divided into gas and electric considerations, the
amount of work performed by UE's legal departments would not decrease
significantly, and there would be no staffing reductions.
INDEPENDENT ACCOUNTANT IMPACT
- -----------------------------
UE and CIPS hire independent accountants to audit the financial statements of
the companies. NEWGAS-UE/CIPS would need to hire independent accountants to
perform the same duties. UE and CIPS would not achieve any savings, since the
existing level of work for the independent accountants would remain the same.
INFORMATION TECHNOLOGY IMPACT
- -----------------------------
UE and CIPS provide extensive information technology assistance to its operating
and support divisions. NEWGAS-UE/CIPS would need to provide the same assistance
to its divisions. Hardware costs are reflective of the quantity of information
to be processed, so NEWGAS-UE/CIPS' hardware and telecommunications costs would
be substantially less than UE's and CIPS'. Software costs are generally less
dependent on quantity and more dependent on function, so NEWGAS-UE/CIPS'
software costs would be similar to UE's and CIPS'. See SECTION III. C, Exhibit
2b, which identifies a net increase in cost for information services of
$14,754,000.
Divesting the gas operations would eliminate opportunities for sharing
information technology resources to the detriment of both the gas and electric
operations:
NEWGAS-UE/CIPS would be subject to the same regulatory accounting
requirements as UE and CIPS, so similar general ledger, payroll
distribution, fixed asset and other accounting systems would be needed. It
is estimated that the required software would be similar to UE's and CIPS',
and would cost about $4.8 million. UE and CIPS would retain all existing
software, resulting in no software savings. Also, UE and CIPS would expend
considerable resources changing accounting systems to reflect the
divestiture of the gas business.
UE and CIPS operate integrated material management, purchasing and accounts
payable systems. The systems provide ordering, purchasing, tracking,
receiving,
10
<PAGE>
paying and inventory control functions. To maintain existing levels of
customer service, NEWGAS-UE/CIPS would need a similar integrated system,
which would cost about $2.4 million. UE and CIPS would require slightly
less data storage, producing negligible savings. There would be no software
savings since UE and CIPS would require all existing software.
UE's investor services system handles stockholder and bondholder service
requests, makes dividend and bond payments and keeps track of unclaimed
checks and correspondence. CIPS currently outsources these
responsibilities. NEWGAS-UE/CIPS would need a system with capabilities
similar to those of UE to maintain the current level of service to
stockholders and bondholders. Such a system would cost about $450,000. UE
and CIPS would retain the same number of stockholders and bondholders,
resulting in no savings.
UE's and CIPS' customer information systems are extensively integrated with
numerous other systems, providing seamless flow of information and
efficient processing of customer service requests, payments and data
updates. When customers call, the systems retrieve information and
presents it to the call-taker, requiring customers to spend less time on
the line. The systems automatically handle customers' payments made by
mail, electronically, at pay stations or banks, or by charitable and
government organizations. It provides a multitude of services such as
budget billing, installment financing payments, combined billing for
electric and gas, preferred pay dates, etc. NEWGAS-UE/CIPS would require a
similar system to maintain the current level of service to customers.
Recently installed utility billing systems have cost $25 - $50 million.
Scaling down might be possible for a small utility, making the estimated
cost about $20 million. Since there would be fewer customer records to
process, UE and CIPS would require less data storage, postage, forms, etc.,
saving about $330,000 annually. UE and CIPS would expend considerable
resources to final bill existing combination gas/electric customers and re-
establish the electric accounts.
Both UE and CIPS maintain distribution job management systems that receive
and track customer requests for service or work, maintain the status of
jobs for customer inquiries, automatically bill the customers for work
completed and provide accurate accounting and work order control. NEWGAS-
UE/CIPS would need a similar system, costing about $4,000,000, to maintain
current levels of customer service. UE and CIPS would no longer process
gas customers but data storage savings would be insignificant.
UE maintains pension management software that provides valuation of the
retirement plan for accounting purposes, maintains records of retirees,
accumulates information for active employees for pension calculations and
interfaces with
11
<PAGE>
payroll systems to maintain accurate information. CIPS currently outsources
this work. To maintain the current levels of work for both UE's and CIPS'
gas employees, NEWGAS-UE/CIPS would need a system similar to UE's, costing
about $100,000. The assumed reduction of about 349 UE and CIPS employees
who perform only gas related work would have a minimal effect on UE's and
CIPS' data storage requirements, providing insignificant savings.
UE and CIPS maintain sophisticated human resources, payroll, scheduling,
time entry and absence tracking systems. The systems provide scheduling
for time worked, vacation and other allowed time. They track absences and
automatically update records and restore sick leave bank balances. The
systems provide distributed entry of time worked and the associated
accounting. The systems provide for the reporting of information to
government, regulatory and other agencies. NEWGAS-UE/CIPS would need a
similar system. UE's and CIPS' systems combined cost more than $6 million
to develop. Since the UE and CIPS systems include processes required only
for electric generating plant operations, NEWGAS-UE/CIPS could use simpler
software, estimated at about $4,000,000. Processing 349 fewer employees
would provide insignificant savings for UE and CIPS.
UE's and CIPS' Information Technology personnel maintain the above systems.
To maintain similar systems, it is estimated NEWGAS-UE/CIPS would expend
about $2,150,000 annually. NEWGAS-UE/CIPS software maintenance would cost
about three-fourth's of UE's cost since some systems would not exist in a
gas-only company. Because all of the existing systems would remain, UE and
CIPS would achieve no maintenance savings by spinning off the gas
operations.
UE and CIPS maintain communications networks, telephone services, radio
systems, etc. To maintain similar systems, NEWGAS-UE/CIPS would need
personnel and equipment costing about $5,860,000 annually. Due to fewer
employees and locations, NEWGAS-UE/CIPS would spend an amount estimated at
10 percent of UE's and 36 percent of CIPS' costs. UE and CIPS would
achieve minimal savings because the number of locations would remain the
same, although slightly less equipment (e.g. telephones) would be needed
because there would be fewer employees at some locations.
UE and CIPS maintain data centers to serve all of the above systems. To
operate similar systems, NEWGAS-UE/CIPS would need a similar data center,
costing about $3,700,000 annually. There would be no equipment or
manpower savings for UE and CIPS, since all existing systems would remain.
12
<PAGE>
INSURANCE COSTS
- ---------------
UE and CIPS obtain property, liability, directors and officers, workers
compensation and other insurance. NEWGAS-UE/CIPS would require similar
policies, at similar costs. See SECTION III.C, Exhibit 2c, which shows an
estimated increase in insurance cost of $525,000 to NEWGAS-UE/CIPS. Since all
coverages would remain in effect, UE and CIPS would experience no savings for
insurance.
OFFICE AND CREW FACILITIES COSTS
- --------------------------------
UE and CIPS maintain combined electric and gas office and crew facilities at
several locations. NEWGAS-UE/CIPS would need facilities for office and crew
personnel at each of the existing combined electric/gas locations. See SECTION
III.C, Exhibit 2e-2, which identifies $3,038,549 in additional office and crew
facilities costs. Since UE and CIPS would still operate the electric systems,
the existing office and crew facilities would still be needed at each location.
TRANSPORTATION AND MOTORIZED EQUIPMENT COSTS
- --------------------------------------------
UE and CIPS maintain transportation and motorized equipment used by both gas and
electric crew and support personnel. NEWGAS-UE/CIPS would need to obtain
similar equipment for gas operations. NEWGAS-UE/CIPS' additional transportation
cost would be about $637,271 as identified in SECTION III.C, Exhibit 2g-1.
Since vehicle needs correlate closely with personnel needs, it is estimated that
the reduction in equipment to be achieved by UE and CIPS would equal the
additional equipment required by NEWGAS-UE/CIPS, except for vehicles used by
meter readers to read both electric and gas meters. UE and CIPS would still need
about the same number of meter reader vehicles currently used in the combination
gas and electric districts, but the costs currently allocated to the gas
business would be absorbed by the electric customers, resulting in increased
annual meter reading vehicle costs to UE and CIPS of about $79,497.
TRANSITION COSTS
- ----------------
The divestiture of the gas operations of UE and CIPS and the creation of a
stand-alone gas company would be a complex legal and financial transaction that
would involve substantial transition costs. These costs would include legal and
financial advising fees, and the services of independent accountants, actuaries
and other consultants. Real estate services would be needed to procure
facilities. Several hundred personnel would have to be hired and trained.
Benefit plans would need to be established. The estimated transition costs of
$11,031,000 for NEWGAS-UE/CIPS were developed by calculating
13
<PAGE>
the average of such costs incurred in several other publicly reported business
spin-offs. See SECTION III.C, Exhibit 2f.
COST OF CAPITAL
- ---------------
The effective cost of capital for the stand-alone gas business was based upon
capitalization ratios of UE's and CIPS' capital structure as of December 31,
1995, and estimated current costs of debt and equity, which average about
11.07%. See SECTION III.C, Exhibit 4 for detailed information.
INCOME TAXES ON THE DIVESTITURE TRANSACTION
- -------------------------------------------
Under current law, the divestiture of the gas businesses of UE and CIPS into a
single, combined company, after the merger and creation of Ameren Corporation,
could be accomplished on a tax-free basis. However, legislation is pending in
the U.S. Congress that, if passed, would apply to this transaction and would
impose substantial income taxes.
Under the proposed legislation, CIPS would be subject to income tax on the
difference between the fair market value of its gas assets (as of the date they
are spun off from CIPS) and the tax basis of those assets. Using the net book
value as a conservative minimum fair market value for these assets, it is
estimated that these income taxes would be at least $24,000,000. These costs
would, if incurred, substantially increase the lost economies already
illustrated in Section I, Tables I-1 and I-2.
CONCLUSION
- ----------
The Supplemental Study concludes that a separate gas distribution company would
require 902 full-time employees, an increase of approximately 158% over the
number of employees currently devoted to UE and CIPS gas operations full-time.
Based upon the assumptions set forth in SECTION II and the staffing requirements
of the organizational structure, increased annual costs (excluding Federal and
State income taxes) for NEWGAS-UE/CIPS are projected to be $34,768,000.
The exhibits (SECTION III.C) that follow show the economic effects of operating
UE's and CIPS' gas divisions as one separate entity.
14
<PAGE>
================================================================================
SECTION III.C. NEWGAS-UE/CIPS SCHEDULE OF EXHIBITS
================================================================================
<TABLE>
<CAPTION>
Exhibit No. Exhibit Title
========================= ===================================================
<S> <C>
1 Income Statement, Proforma Adjustments & Revenue
Requirement
1a Consolidation of UE's & CIPS' Income Statements
2 Estimated Additional Operating Expenses
2a Estimated External Audit Fees Based on Survey Data
2b Estimated Information Services Costs
2c Estimated Increased Cost of Insurance Coverage
2d Estimated Net Labor Increase, Including Benefits
2e-1 & 2e-2 Estimated Operating Lease Facilities and Furniture
Costs
2f Estimated Transition Costs
2g-1 thru 2g-3 Estimated Net Increase in Transportation &
Motorized Equipment Expense
3 Rate Base
3a Consolidation of UE's and CIPS' Rate Base
3b Consolidation of UE's and CIPS' Common Plant
Allocated to Gas
4 Cost of Capital
5 Corporate Structure
6 Salaries and Wages Summary
7 Comparable Investor Owned Gas Companies (Customers
Per Employee Ratios)
8 Estimated Executive Salaries
9 UE's and CIPS' Electric Rate Base & Rate of Return
9a Consolidation of UE's and CIPS' Electric Rate Base
</TABLE>
15
<PAGE>
NEWGAS-UE/CIPS EXHIBIT 1
NEWGAS-UE/CIPS INCOME STATEMENT
PROFORMA ADJUSTMENTS & REVENUE REQUIREMENT
(In Thousands of Dollars)
<TABLE>
<CAPTION>
Existing
UE/CIPS
Consolidated Proformed Revenue
Year Ending Proforma NEWGAS- Requirement
12/31/95 (1) Adjustments (2) UE/CIPS Increase (3)
------------ --------------- ---------- ------------
<S> <C> <C> <C> <C>
Operating Revenue: $ 217,425 $ - $ 217,425 $ 267,857
Operating Revenue Deductions:
- -----------------------------
Purchased Gas $ 118,652 $ 118,652 $ 118,652
Gas Withdrawn From Storage $ 6,653 $ 6,653 $ 6,653
O & M $ 43,379 $ 34,011 $ 77,390 $ 77,390
Depreciation $ 11,526 $ 11,526 $ 11,526
Taxes Other Than Income $ 17,645 $ 757 $ 18,402 $ 18,402
--------- -------- ---------- ---------
Total Operating Revenue Deductions $ 197,855 $ 34,768 $ 232,623 $ 232,623
--------- -------- ---------- ---------
Gross Gas Income $ 19,570 $ (15,198) $ 35,234
Federal & State Income Taxes (4) $ 5,792 $ (4,407) $ 10,218
--------- ---------- ---------
Net Gas Income $ 13,778 $ (10,791) $ 25,016
========= ========== =========
Rate Base (5) $ 237,408 $ 225,980 $ 225,980
========= ========== =========
Indicated Rate of Return 5.80% -4.78% 11.07%(6)
========= ========== =========
</TABLE>
(1) See Exhibit 1a for consolidation detail.
(2) See Exhibit 2 for a detailed summary of proforma adjustments.
(3) An increase of $50,432,000 or 23.20% in revenue is required to achieve a
rate of return of 11.07%. For the purposes of this Supplemental Study,
gross receipts taxes were not considered since both the resulting revenue
and taxes (revenue deduction) would nullify any impact from this
calculation.
(4) For twelve months ended 12/31/95, UE's and CIPS' combined effective Federal
& State Income Taxes were 29.60% of gross income. This effective tax rate
was used to calculate taxes for the Proformed NEWGAS-UE/CIPS and Revenue
Requirement Increase columns.
(5) See Exhibit 3.
(6) The effective rate of return is assumed to be the weighted cost of capital
per Exhibit 4.
<PAGE>
NEWGAS-US/CIPS EXHIBIT 1a
CONSOLIDATION OF UE's & CIPS' INCOME STATEMENTS
FOR THE YEAR ENDING 12/31/95
<TABLE>
<CAPTION>
Existing Existing Existing
UE Gas CIPS Gas UE/CIPS
Company Company Consolidated
Year Ending Year Ending Year Ending
12/31/95 12/31/95 12/31/95
----------- ----------- ------------
<S> <C> <C> <C>
Operating Revenue: $ 87,814 $ 129,611 $ 217,425
Operating Revenue Deductions:
Purchased Gas $ 47,189 $ 71,463 $ 118,652
Gas Withdrawn From Storage $ 4,062 $ 2,591 $ 6,653
O & M $ 16,822 $ 26,557 $ 43,379
Depreciation $ 4,722 $ 6,804 $ 11,526
Taxes Other Than Income $ 7,683 $ 9,962 $ 17,645
-------- --------- ---------
Total Operating Revenue Deductions $ 80,478 $ 117,377 $ 197,855
-------- --------- ---------
Gross Gas Income $ 7,336 $ 12,234 $ 19,570
Federal & State Income Taxes (3) $ 2,131 $ 3,661 $ 5,792
-------- --------- ---------
Net Gas Income $ 5,205 $ 8,573 $ 13,778
======== ========= =========
</TABLE>
<PAGE>
NEWGAS-UE/CIPS EXHIBIT 2
NEW GAS-UE/CIPS
ESTIMATED ADDITIONAL OPERATING EXPENSES
PROFORMA ADJUSTMENTS
(In Thousands of Dollars)
<TABLE>
<CAPTION>
Exhibit
Reference
Number Amount
--------- -------
<S> <C> <C>
External Auditing Costs 2a $ 188
Information Services (Outsourced) 2b $14,754
Insurance Premiums 2c $ 525
Labor & Benefits 2d $14,522
Leased Facilities/Furniture 2e-2 $ 3,039
Transition Costs (Amortized) 2f $ 1,103
Transportation & Work equipment 2g-1 $ 637
-------
Total Additional Expenses $34,768
Less: FICA and Unemployment Insurance 2d $ 757
-------
TOTAL ADDITIONAL O & M EXPENSES $34,011
=======
</TABLE>
<PAGE>
NEWGAS-UE/CIPS EXHIBIT 2a
NEWGAS-UE/CIPS EXTERNAL AUDITOR COSTS
ESTIMATED EXTERNAL AUDIT FEES BASED ON SURVEY DATA
PROFORMA ADJUSTMENT
<TABLE>
<CAPTION>
<S> <C>
Surveys comparing External Audit Fees Amount
------------------------------------- ======
Average fee for Utility companies with less than 300,000 Customers in 1994 $191,000
Average fee for Peer Group comparison with less than 300,000 Customers in 1994 $188,000
--------
Average of External Audit Fee Surveys $189,500
Average Audit Fee for Pension Plans with less than 5,000 employees $ 38,693
--------
Total Estimated Annual Audit Fees for NEWGAS-UE/CIPS $228,193
Less: External Audit Fees Allocated to UE's & CIPS' Gas operations in 1995 $ 40,000
--------
Net Estimated Annual Audit Fees Increase for NEWGAS-UE/CIPS $188,193
========
Sources: Illinois Power Audit Fee Peer Group Comparison - 1994
American Gas Association/Edison Electric Institute External Audit Fees - October 1995
</TABLE>
<PAGE>
NEWGAS-UE EXHIBIT 2b
<TABLE>
<CAPTION>
<S> <C>
NEWGAS-UE/CIPS INFORMATION SERVICES
ESTIMATED INFORMATION SERVICES (IS) COSTS
PROFORMA ADJUSTMENT
(In Thousands of Dollars)
Software Application Costs: Amount
-------------------------- ------
General Ledger/Capital Projects/Asset Management/Accounts Payable $ 4,800
Payroll Distribution $ 250
Investor Services $ 450
Customer Information System (CIS) $20,000
Computer Telephone Integration System (CTI) $ 1,000
Distribution Operating Job Management (DOJM) $ 4,000
Gas Systems $ 6,250
Materials Management Information System (MMIS) $ 2,400
Pension Manager $ 100
Payroll/Human Resource System $ 3,000
Time Reporting $ 1,000
Miscellaneous $ 1,500
-------
Total Software Application Costs $44,750
-------
Annual System Operating Costs
Data Processing $ 3,700
Software Maintenance and Support $ 2,153
Telecommunciations $ 5,864
-------
Total Annual System Operating Costs $11,717
-------
Estimated Cost to Outsource IS
------------------------------
Annualized Software Application Costs (10 year amortization) $ 4,475
Total Annual System Operating Costs $11,717
-------
Total Annual Cost to Outsource Information Services $16,192
Less: IS Expenses Allocated to UE's and CIPS' Gas Operations in 1995 $ 1,438
-------
Net Increase in Cost for Information Services $14,754
=======
</TABLE>
<PAGE>
NEWGAS-UE EXHIBIT 2c
NEWGAS-UE/CIPS
ESTIMATED INCREASED COST OF INSURANCE COVERAGE
PROFORMA ADJUSTMENT
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C> <C>
Estimated Net Increase to
Limits Stand Alone NEWGAS-
Coverage (Millions) Deductible Premium Cost UE/CIPS
- -------------------------- ---------- ---------- ------------ ------------
Property $ 5 $ 250,000 $ 40,000
General Liability $ 60 $ 250,000 $ 350,000
Auto Liability $ 1 $ - $ 100,000
Directors & Officers Liability $ 10 $ 250,000 $ 75,000
Workers Compensation Statutory $ 350,000 $ 122,000
Fiduciary Liability $ 5 $ 5,000 $ 10,000
Crime (Fidelity) $ 5 $ 5,000 $ 10,000
----------
Total NEWGAS-UE/CIPS Premium $ 707,000
Less: 1995 Insurance Cost Allocated to UE and CIPS Gas Operations $ 182,000
----------
Net Increase in Insurance Costs for NEWGAS-UE/CIPS $525,000
========
Source: Premiums are based on estimated costs obtained from the UE Secretary's
Department, Insurance Division.
</TABLE>
<PAGE>
NEWGAS-UE EXHIBIT 2d
NEWGAS-UE/CIPS
ESTIMATED NET LABOR INCREASE, INCLUDING BENEFITS
PROFORMA ADJUSTMENT
(In Thousands of Dollars)
<TABLE>
<CAPTION>
<S> <C> <C> <C>
Total Estimated Salaries and Wages for NEWGAS-UE/CIPS (Exhibit 6) $ 40,484
Less: Amount for Construction & Removals (26.72%) - (1) $ 10,817
--------
Total Estimated NEWGAS-UE/CIPS Salaries & Wages Charged to O & M $ 29,667
Less: 1995 UE and CIPS Gas Salaries & Wages Charged to O & M $ 19,441
--------
Increase in NEWGAS-UE Salaries & Wages Charged to O & M $ 10,226
Benefits (2):
Employee Life, Hospitalization, savings plans, etc. $ 2,250
Pension Plan $ 931
FICA & Unemployment Insurance $ 757
Other $ 358
--------
Total Benefits $ 4,296
--------
NEWGAS-UE/CIPS Net Labor Increase, Including Benefits $ 14,522
========
(1) The amount of direct labor allocated to construction and removal is based
on the actual amount spent by UE and CIPS in 1995.
(2) Benefit costs were estimated based upon the cost (as a percentage of
payroll) currently budgeted for:
Life, Hospitalization, savings plans, post employment benefit, etc. 22.00%
Pension Plan 9.10%
FICA & Unemployment Insurance 7.40%
Other 3.50%
--------
Total 42.00%
========
</TABLE>
<PAGE>
NEWGAS-EU/CIPS EXHIBIT 2e-1
NEWGAS-UE/CIPS
ESTIMATED OPERATING LEASE FACILITIES
PROFORMA ADJUSTMENT
<TABLE>
<CAPTION>
Office Space Calculation
---------------------------------------------------
Management Office Space
& Staff Needs in Cost Per Total Works Total Leased
Employee Square Feet Square Foot Office Space Hqtrs. Facilities
Count (1) (2) Cost (3) Cost
---------- ------------ ----------- ------------ ------- ------------
<S> <C> <C> <C> <C> <C> <C>
General Office:
St. Louis, Mo. 357 109,956 $15.00 $1,649,340 -- $1,649,340
Southeast District (MO):
Cape Girardeau 13 4,004 $ 6.00 $ 24,024 $38,400
Chaffee 0 -- $ -- $17,000
Dexter 0 -- $ -- $38,400
-------
Total $ 117,824
Wentzville District (MO):
Louisiana 9 2,772 $ 5.50 $ 15,246 $17,000
Troy 0 -- $ -- $17,000
-------
Total $ 49,246
Little Dixie District (MO):
Boonville 0 -- $ -- $17,000
Centralia 0 -- $ -- $17,000
Columbia 17 5,236 $ 9.00 $ 47,124 $ --
Mexico 0 -- $ -- $38,400
Moberly 0 -- $ -- $38,400
-------
Total $ 157,924
Capital District (MO):
Jefferson City 12 3,696 $ 8.00 $ 29,568 $38,400
Versailles 0 -- $ -- $17,000
-------
Total $ 84,968
Alton District (IL): 10 3,080 $ 9.00 $ 27,720 $38,400 $ 66,120
Eastern Division (IL):
Effingham 3 -- $ -- $ -- $17,000
Hoopeston 3 -- $ -- $ -- $17,000
Mattoon 18 5,544 $10.00 $ 55,440 $55,400
Paris 3 -- $ -- $ -- $17,000
Robinson 3 -- $ -- $ -- $17,000
Taylorville 3 -- $ -- $ -- $17,000
-------
Total $ 195,840
</TABLE>
<PAGE>
NEWGAS-UE/CIPS EXHIBIT 2e-2
NEWGAS-UE/CIPS
ESTIMATED OPERATING LEASE FACILITIES AND FURNITURE COSTS
PROFORMA ADJUSTMENT
<TABLE>
<CAPTION>
Office Space Calculation
----------------------------------------------------------
Management Office Total Total
& Staff Space Cost Per Office Works Leased
Employee Needs in Square Space Hqtrs. Facilities
Count Square Feet (1) Foot (2) Cost (3) Cost
---------------------------------------------------------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Southern Division (IL):
Benton 3 - $ - $ - $ 17,000
Carbondale 3 - $ - $ - $ 17,000
Marion 16 4,928 $ 9.00 $ 44,352 $ 55,400
--------
Total $ 133,752
Western Division (IL):
Beardstown 18 5,544 $ 7.00 $ 38,808 $ 55,400
Canton 3 - $ - $ - $ 17,000
Jerseyville 3 - $ - $ - $ 17,000
Macomb 3 - $ - $ - $ 17,000
Petersburg 3 - $ - $ - $ 17,000
Quincy 3 - $ - $ - $ 55,400
--------
Total $ 217,608
Estimated Office Furniture Operating Lease Expense For All Areas: $ 602,000
-----------
NEWGAS-UE FACILITIES - GRAND TOTAL $ 3,274,622
Less: UE & CIPS allocated costs for gas facilities $ 236,073
-----------
NET NEWGAS-UE FACILITIES COST: $ 3,038,549
===========
</TABLE>
(1) This cost was based on an average of 308 square feet per employee.
(2) Cost per square foot per annum was obtained from UE's Real Estate
Department and/or calculated by taking the purchased cost of buildings amortized
over 7 years to determine the lease expense.
(3) This includes space for construction and service supervision, staff,
materials and supplies, and vehicles and equipment. Annual lease costs were
based on actual appraised values of utility facilities capable of accommodating
applicable staff, materials & equipment. Columbia, Mo. is the only city having a
UE headquarters facility already dedicated to gas operations.
<PAGE>
NEWGAS-UE/CIPS EXHIBIT 2f
NEWGAS-UE/CIPS ESTIMATED TRANSITION COSTS
PROFORMA ADJUSTMENT
Transition costs required to establish a new corporation would include the
following:
Legal fees
Financial advisory fees
Consulting services of independent accountants,
actuaries, and others
Real estate services for acquisitions
Hiring and training costs to staff newly created
positions
Benefit plans established
Data Conversion
Transition costs for NEWGAS-UE/CIPS were estimated based upon an average of the
following published transition costs for other corporate spin-offs:
<TABLE>
<CAPTION>
Transition
Original Corporation Spin-off Company Costs(000)
-------------------- ---------------- ----------
<S> <C> <C>
Baxter International Caremark $ 13,300
Adolph Coors ACX Technologies $ 7,200
Dial Corporation GFC Financial $ 13,000
Union Carbide Praxair $ 11,000
Ryder Avial $ 9,000
Price Costco Price Enterprises $ 15,250
Humana Galen $ 15,000
Honeywell Aliant $ 4,500
----------
Average Transition Costs of the Above Companies $ 11,031
----------
Annual amortization of Transition Costs for NEWGAS-UE/CIPS (10%) $ 1,103
=========
</TABLE>
Source: Transition costs reported in SEC Form 10-K filings.
<PAGE>
NEWGAS-UE/CIPS
EXHIBIT 2g-1
NEWGAS-UE/CIPS
ESTIMATED NET INCREASE IN TRANSPORTATION &
MORTORIZED EQUIPMENT EXPENSE
PROFORMA ADJUSTMENT
<TABLE>
<CAPTION>
Est. Annual
Location (1): Cost
- ------------------------- ----------
<S> <C> <C>
General Office $ 104,136
Southeast District $ 415,068
Wentzville District $ 185,976
Little Dixie District $ 813,132
Capital District $ 429,624
Alton District $ 232,320
Eastern Division $ 127,620
Southern Division $ 115,500
Western Division $ 133,680
==========
NEWGAS-UE/CIPS TOTAL $2,557,056
Less: Amount Charged by UE & CIPS to Gas Operations in 1995 $1,919,785
----------
NET INCREASE IN EXPENSE $ 637,271
==========
</TABLE>
(1) See Exhibits 2g-2 & 2g-3 for detail information. Projected costs were
based on management's assessment of transportation & equipment needs and
operating & maintenance experience.
<PAGE>
NEWGAS-UE/CIPS EXHIBIT 2g-2
NEWGAS-UE/CIPS
ESTIMATED TRANSPORTATION & MOTORIZED EQUIPMENT EXPENSE
PROFORMA AJDUSTMENT
<TABLE>
<CAPTION>
General Office(GO)\ Pool Southeast District Wentzville District
------------------------ ------------------------ -----------------------
Rate Per Est. Annual Est. Annual Est. Annual
Description Month Number Cost Number Cost Number Cost
- --------------------------- -------- ------------------------ ------------------------ -----------------------
<S> <C> <C> <C> <C> <C> <C> <C>
GO\Pool Vehicles - Standard $ 470 10 $ 56,400
- --------------------------- -------- ------------------------ ------------------------ -----------------------
GO\Pool Vehicles - Compact $ 442 9 $ 47,736
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Manager $ 470 1 $ 5,640 1 $ 5,640
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Operations Superintendent $ 442 1 $ 5,304 1 $ 5,304
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Construction Supervisor $ 442 3 $ 15,912 3 $ 15,912
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Distribution Supervisor $ 442 1 $ 5,304 1 $ 5,304
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Supervising Engineer $ 442 1 $ 5,304 1 $ 5,304
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Engineer $ 442 1 $ 5,304 0 $ -
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Engineer Assistant $ 505 2 $ 12,120 1 $ 6,060
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Office Manager $ 442 1 $ 5,304 1 $ 5,304
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Meter Reader $ 505 5 $ 30,300 2 $ 12,120
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Customer Service Advisor $ 442 1 $ 5,304 1 $ 5,304
- --------------------------- -------- ------------------------ ------------------------ -----------------------
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Other transportation &
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Motorized Equipment
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Not Indicated Above $ - $ 319,272 $ 119,724
- --------------------------- -------- ------------------------ ------------------------ -----------------------
TOTAL $ 104,136 $ 415,068 $ 185,976
============ ============== ==============
Little Dixie District Capital District Alton District
------------------------ ------------------------ -----------------------
Rate Per Est. Annual Est. Annual Est. Annual
Description Month Number Cost Number Cost Number Cost
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Manager $ 470 1 $ 5,640 1 $ 5,640 1 $ 5,640
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Operations Superintendent $ 442 1 $ 5,304 1 $ 5,304 1 $ 5,304
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Construction Supervisor $ 442 4 $ 21,216 4 $ 21,216 2 $ 10,608
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Distribution Supervisor $ 442 3 $ 15,912 2 $ 10,608 0 $ -
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Supervising Engineer $ 442 1 $ 5,304 1 $ 5,304 1 $ 5,304
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Engineer $ 442 1 $ 5,304 1 $ 5,304 0 $ -
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Engineer Assistant $ 505 3 $ 18,180 2 $ 12,120 0 $ -
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Office Manager $ 442 1 $ 5,304 1 $ 5,304 0 $ -
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Meter Reader $ 505 7 $ 42,420 3 $ 18,180 2 $ 12,120
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Customer Service Advisor $ 442 1 $ 5,304 1 $ 5,304 1 $ 5,304
- --------------------------- -------- ------------------------ ------------------------ -----------------------
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Other transportation &
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Motorized Equipment
- --------------------------- -------- ------------------------ ------------------------ -----------------------
Not Indicated Above $ 683,244 $ 335,340 $ 188,040
- --------------------------- -------- ------------------------ ------------------------ -----------------------
TOTAL $ 813,132 $ 429,624 $ 232,320
============ ============== ============
</TABLE>
<PAGE>
NEWGAS-UE/CIPS EXHIBIT 2g-3
NEWGAS-UE/CIPS
ESTIMATED TRANSPORTATION & MOTORIZED EQUIPMENT EXPENSE
PROFORMA ADJUSTMENT
<TABLE>
<CAPTION>
---------------------- ------------------------ --------------------
Eastern Division Southern Division Western Division
---------------------- ------------------------ --------------------
- --------------------------- -------- ------ ----------- ------ ----------- ------ -----------
Rate Per Est. Annual Est. Annual Est. Annual
Description Month Number Cost Number Cost Number Cost
- --------------------------- -------- ------ ----------- ------ ----------- ------ -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Manager $ 470 1 $ 5,640 1 $ 5,640 1 $ 5,640
Superintendent $ 442 6 $ 31,824 6 $ 31,824 6 $ 31,824
H/R Supervisor $ 442 1 $ 5,304 1 $ 5,304 1 $ 5,304
New Business Supervisor $ 442 1 $ 5,304 1 $ 5,304 1 $ 5,304
C/S & N/B Representatives $ 442 4 $ 21,216 4 $ 21,216 4 $ 21,216
Engineer $ 442 2 $ 10,608 2 $ 10,608 2 $ 10,608
Operating Supervisor $ 442 1 $ 5,304 1 $ 5,304 1 $ 5,304
Meter Reader $ 505 7 $ 42,420 5 $ 30,300 8 $ 48,480
- --------------------------- -------- ------ ----------- ------ ----------- ------ -----------
DIVISION TOTALS $127,620 $115,500 $133,680
=========== =========== ===========
</TABLE>
<PAGE>
NEWGAS-UE/CIPS EXHIBIT 3
NEWGAS-UE/CIPS
RATE BASE
(In Thousands of Dollars)
<TABLE>
<CAPTION>
Existing
UE/CIPS Reduction
Consolidated for UE's & NEWGAS-
Year Ending CIPS' Common UE/CIPS
12/31/95 Gas Plant (1) Net of Common
(Exhibit 3a) (Exhibit 3b) Plant 12/31/95
------------ ------------- --------------
<S> <C> <C> <C>
Gas Plant In Service $408,192 $(12,762) $395,430
Reserve For Depreciation $147,197 $ (1,334) $145,863
-------- -------- --------
Net Plant $260,995 $(11,428) $249,567
Materials & Supplies $ 12,940 $ 12,940
Prepayments $ (750) $ (750)
Customer Advances $ (1,401) $ (1,401)
Accumulated Deferred Income
Taxes $(34,376) $(34,376)
-------- -------- --------
TOTAL RATE BASE $237,408 $(11,428) $225,980
======== ======== ========
</TABLE>
(1) Mainly buildings and equipment jointly used by the electric and gas
departments. Under a divestiture, all common property would go with the electric
company.
<PAGE>
NEWGAS-UE/CIPS EXHIBIT 3a
CONSOLIDATION OF UE's & CIPS' RATE BASE
FOR YEAR ENDING 12/31/95
<TABLE>
<CAPTION>
Existing Existing Existing
UE Gas CIPS Gas UE/CIPS
Company Company Consolidated
Year Ending Year Ending Year Ending
12/31/95 12/31/95 12/31/95
----------- ----------- ------------
<S> <C> <C> <C>
Gas Plant In Service $179,985 $228,207 $408,192
Reserve For Depreciation $ 53,744 $ 93,453 $147,197
-------- -------- --------
Net Plant $126,241 $134,754 $260,995
Materials & Supplies $ 11,892 $ 1,048 $ 12,940
Prepayments $ 236 $ (986) $ (750)
Customer Advances $ (937) $ (464) $ (1,401)
Accumulated Deferred Income
Taxes $(12,616) $(21,760) $(34,376)
-------- -------- --------
TOTAL RATE BASE $124,816 $112,592 $237,408
======== ======== ========
</TABLE>
<PAGE>
NEWGAS-UE/CIPS EXHIBIT 3b
<TABLE>
<CAPTION>
CONSOLIDATION OF UE's & CIPS' COMMON PLANT
ALLOCATED TO GAS FOR YEAR ENDED 12/31/95
UE CIPS UE & CIPS
Common Plant Common Plant Common Plant
Allocated to Allocated to Allocated to
Gas Plant(1) Gas Plant (1) Gas Plant (1)
----------- ------------- --------------
<S> <C> <C> <C>
Gas Plant In Service $ 5,738 $ 7,024 $ 12,762
Reserve For Depreciation $ 1,083 $ 251 $ 1,334
----------- ------------ --------------
Net Plant $ 4,655 $ 6,773 $ 11,428
=========== ============ ==============
(1) Mainly buildings and equipment jointly used by the electric and gas
departments. Under a divestiture, all common property would go with the electric
company.
</TABLE>
<PAGE>
NEWGAS-UE/CIPS EXHIBIT 4
<TABLE>
<CAPTION>
NEWGAS-UE/CIPS
STAND-ALONE COST OF CAPITAL
UE CIPS UE/CIPS
--------------------------------- --------------------------------- -------------------------------
Weighted
Capital- % of Capital- % of Capital-
ization UE/CIPS Gas Weighted ization UE/CIPS Gas Weighted ization Cost Weighted
Type of Capital Ratios Rate Base Ratios Ratios Rate Base Ratios Ratios Component Cost
- ------------------------ -------- ----------- -------- -------- ----------- -------- -------- --------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Long Term Debt 41.00% 53.17% 21.80% 42.41% 46.83% 19.86% 41.66% 8.41% 3.50%
Preferred 5.10% 53.17% 2.71% 7.08% 46.83% 3.32% 6.03% 8.41% 0.51%
Common Equity 53.90% 53.17% 28.66% 50.51% 46.83% 23.65% 52.31% 13.50% 7.06%
------
Weighted Cost of Capital 11.07%
======
</TABLE>
Note: Capitalization ratios are based on the total UE and CIPS capital
structures as of 12/31/95. Debt and equity were estimated at then current costs.
Current cost of debt and preferred = 30 year, 10 Year No Call first mortgage
bond @ 7.91% (all-in-cost) + 50 basis points. Bond and preferred stock rate
provided on April 19, 1996 by Smith Barney.
<PAGE>
NEWGAS-UE/CIPS EXHIBIT 5
NEWGAS-UE/CIPS
Organization Chart
President & CEO
Vice President - Customer Service
Manager - Customer Service Support
Manager - Southeast District
Manager - Wentzville District
Manager - Little Dixie District
Manager - Capital District
Manager - Alton District
Manager - Eastern Division
Manager - Western Division
Manager - Southern Division
Manager - Corporate Communications
Manager - Gas Marketing
Vice President - Corporate Services
Manager - Purchasing
Manager - Stores
Manager - Motor Transportation
Manager - Real Estate & Facilities
Manager - General Services
General Counsel
Associate General Counsel - Regulatory
Associate General Counsel - Claims
Vice President - Finance
Manager - Accounting
Manager - Tax
Manager - Internal Audit
Secretary/Treasurer
Manager - Investor Relations
Manager - Treasury Operations
Assistant Secretary - Insurance & Records
Vice President - Human Resources
Manager - Employment Services
Manager - Industrial Relations
Vice President - Gas Supply
Manager - Gas Supply
Manager - System Planning & Engineering
Manager - Corporate Planning
<PAGE>
NEWGAS-UE/CIPS EXHIBIT 6
NEWGAS-UE/CIPS
SALARIES AND WAGES SUMMARY (In Thousands of Dollars)
<TABLE>
<CAPTION>
Totals
--------------------------
Employees Salaries/Wages Employees Salaries/Wages
--------- -------------- --------- --------------
<S> <C> <C> <C> <C>
Executive Staff & Secretarial Support 16 $ 1,120
Customer Service Division:
Customer Service Support 62 $2,698
Gas Marketing 25 $1,218
Southeast District 46 $2,041
Wentzville District 26 $1,190
Little Dixie District 102 $4,376
Capital District 45 $2,106
Alton District 34 $1,592
Eastern Division 96 $3,834
Western Divsion 107 $4,242
Southern Division 73 $2,915
Corporate Communications 5 $ 262
--- ------
Customer Service Division Total 621 $26,474
Corporate Services Division:
Purchasing 9 $ 533
Stores 7 $ 369
Motor Transportation 4 $ 225
Real Estate & Facilities 4 $ 225
General Services 36 $1,364
--- ------
Corporate Services Division Total 60 $ 2,716
General Counsel Division:
Regulatory 6 $ 370
Claims 5 $ 268
--- ------
General Counsel Division Total 11 $ 638
Controller Division:
Accounting, Payroll, Accounts Payable 42 $1,751
Internal Audit 11 $ 640
Tax 14 $ 713
--- ------
Controller Division Total 67 $ 3,104
Secretary/Treasurer Division:
Investor Relations 4 $ 199
Treasury Operations 18 $ 755
Insurance & Records 8 $ 351
--- ------
Secretary/Treasurer Division Total 30 $ 1,305
Human Resources Division:
Employment Services 36 $1,848
Industrial Relations 5 $ 285
--- ------
Human Resources Division Total 41 $ 2,133
Gas Supply:
Gas Supply 6 $ 365
System Planning & Engineering 30 $1,645
Corporate Planning 20 $ 984
--- ------
Gas Supply Division Total 56 $ 2,994
--- -------
GRAND TOTAL 902 $40,484
=== =======
</TABLE>
<PAGE>
NEWGAS-UE/CIPS EXHIBIT 7
COMPARABLE INVESTOR OWNED GAS UTILITIES
CUSTOMERS PER EMPLOYEE
<TABLE>
<CAPTION>
Customers
Companies Customers Employees Per Employee
- ---------------------- --------- --------- ------------
<S> <C> <C> <C>
NEWGAS-UE/CIPS 288,000 902 319
Connecticut Natural Gas 138,000 642 215
ENERGEN 435,000 1,488 292
Southern Connecticut Gas 153,000 572 267
United Cities Gas 295,000 1,343 220
Yankee Gas Service 177,000 670 264
</TABLE>
Source: American Gas Association - Directory of Member Companies
(Selection Criteria - Total Number of Customers Similar to NEWGAS-UE and NEWGAS-
CIPS as shown in the previous Study, and also to NEWGAS-UE/CIPS in this
Supplemental Study)
<PAGE>
NEWGAS-UE/CIPS EXHIBIT 8
ESTIMATED EXECUTIVE SALARIES
----------------------------
Salary Survey Data for Companies with Revenues less than $300 million were used
to establish a reasonable range for the NEWGAS-UE/CIPS executive salary levels.
For existing positions that would become part of the spun-off company, existing
UE salaries were used.
NEWGAS-UE/CIPS
--------------
POSITION SURVEY DATA RANGE SALARY LEVELS
-------- ----------------- -------------
President $212,000 $200,000
Vice President Level $73,600-$106,300 $80,000-$110,000
Source: 1996 Edison Electric Institute Executive Compensation Survey
<PAGE>
NEWGAS-UE/CIPS EXHIBIT 9
UE/CIPS ELECTRIC RATE BASE & RATE OF RETURN
TWELVE MONTHS ENDED 12/31/95
(In Thousands of Dollars)
<TABLE>
<CAPTION>
Existing
UE/CIPS Addition
Electric For Common UE/CIPS
Consolidated Plant (1) Electric
(Exhibit 9a) (Exhibit 3b) As Adjusted
------------ ---------- -----------
<S> <C> <C> <C>
Electric Plant In Service $ 10,081,927 $ 12,762 $10,094,689
Reserve For Depreciation $ 3,858,615 $ 1,334 $ 3,859,949
------------ ---------- -----------
Net Plant $ 6,223,312 $ 11,428 $ 6,234,740
Fuel and Materials & Supplies $ 223,883 $ 223,883
Prepayments $ 20,606 $ 20,606
Customer Advances $ (7,677) $ (7,677)
Accumulated Deferred Income Taxes $ (1,175,397) $(1,175,397)
------------- ---------- ------------
TOTAL RATE BASE $ 5,284,727 $ 11,428 $ 5,296,155
============ ========== ===========
NET OPERATING INCOME $ 534,247 $ 534,247
------------ -----------
RETURN ON RATE BASE 10.11% 10.09%
============ ===========
(1) This represents an allocation of all plant and property jointly used by the electric
and gas departments. Under a divestiture, all common property would go with the
electric company.
</TABLE>
<PAGE>
NEWGAS-UE/CIPS EXHIBIT 9a
CONSOLIDATION OF UE's & CIPS' ELECTRIC RATE BASE
FOR THE YEAR ENDING 12/31/95
<TABLE>
<CAPTION>
UE's CIPS' Existing
Electric Electric UE/CIPS
Company Company Electric
as of 12/31/95 as of 12/31/95 Consolidated
-------------- -------------- ------------
<S> <C> <C> <C>
Electric Plant In Service $7,796,628 $2,285,299 $10,081,927
Reserve For Depreciation $2,819,806 $1,038,809 $ 3,858,615
---------- ---------- -----------
Net Plant $4,976,822 $1,246,490 $ 6,223,312
Fuel and Materials & Supplies $ 184,684 $ 39,199 $ 223,883
Prepayments $ 13,425 $ 7,181 $ 20,606
Customer Advances $ (6,935) $ (742) $ (7,677)
Accumulated Deferred Income Taxes $ (848,543) $ (326,854) $(1,175,397)
---------- ---------- -----------
$4,319,453 $ 965,274 $ 5,284,727
========== ========== ===========
</TABLE>
<PAGE>
EXHIBIT K-3
JONES, DAY, REAVIS & POGUE
77 West Wacker Drive
Suite 3500
Chicago, Illinois 60601
(312) 782-3939
LEGAL MEMORANDUM ON THE RETENTION OF
GAS OPERATIONS BY AMEREN CORPORATION
------------------------------------
INTRODUCTION
The combination of Union Electric Company ("UE") and Central Illinois
Public Service Company ("CIPS") in a merger transaction (the "Transaction") will
result in UE and CIPS becoming wholly owned subsidiaries of Ameren Corporation
("Ameren"), a holding company which will be registered under the Public Utility
Holding Company Act of 1935 (the "Act"). Ameren has filed an
Application/Declaration on Form U-1 (as amended, the "Application") seeking the
approval of the Securities and Exchange Commission (the "Commission") under the
Act for the Transaction and related matters. The Application seeks the
Commission's authorization for UE and CIPS to retain their gas utility systems
following the consummation of the Transaction. This memorandum supplements the
Application with respect to legal issues related to Ameren's request for
authority to retain these gas systems following its registration as a holding
company under the Act.
SUMMARY
Both the legislative history of the Act as well as the Commission's early
interpretation of the Act indicate that the purpose of the Act was to facilitate
the process by which state utility regulatory commissions determine whether
registered combination gas and electric holding company systems are permissible,
and not to impose a more restrictive federal view./1/ In addition, as the
Commission has noted in a number of prior decisions, the Act is intended to
provide for a flexible regulatory scheme that is capable of adapting to changes
in the utility industry. The industry is in the process of its most radical
change (from regulation to competition) since the changes which occurred in the
1930's and 1940's as a result of the adoption of the Act. It is clear that the
industry is currently evolving in a direction that requires utility company
systems to offer their customers a range of energy options in order to remain
competitive. In the short time since the Application was filed in October,
1996, the industry has taken a dramatic and unmistakable turn toward
"convergence" -- the development
- --------------------
/1/ See Note 7 and accompanying text below.
<PAGE>
of an "energy" industry. In this new industry, companies provide electricity,
gas and a variety of energy services and products to customers.
Because of these changes, and to maintain the traditions of a flexible
regulatory scheme, the Commission should analyze the retention of UE's and CIPS'
gas systems by focusing on those sections of the Act (Sections 8 and 21) that
give primacy to state utility commission decisions with regard to combination
registered holding companies and should "watchfully defer" to such local
decision makers who are in the optimum position to regulate the combination
utility. The Division of Investment Management (the "Division") in a report
approved by the Commission for issuance by the Division in 1995 entitled "The
Regulation of Public Utility Holding Companies" (the "1995 Report") urged a
flexible administration of the Act. Under such flexible analysis of Sections 8
and 21, Ameren must be allowed to retain the gas systems of UE and CIPS as long
as the Missouri Public Service Commission ("MPSC") and the Illinois Commerce
Commission ("ICC"), who have, and will continue to have, direct jurisdiction
over Ameren's gas operations in their respective states, permit the continued
existence of a combination system.
The MPSC has given final approval to the Transaction. UE has provided
combination service in Missouri for many years and no issue relating to such
combination service was raised in the MPSC proceeding. The MPSC has not found
any detriment to the public interest in this area. An order of the ICC is
expected this summer. No issue concerning combination gas and electric
operations has been raised by any party in the ICC proceeding.
Even if the Commission chooses not to focus on state commission
determinations, Section 11 of the Act contains additional provisions that permit
the retention of UE's and CIPS' gas systems -- namely, the so-called A-B-C
clauses (the "A-B-C Clauses") of Section 11(b)(1), under which the Commission in
the past has permitted retention of an additional utility system within a
registered holding company system. Again, the standards set forth in this
section should be read in light of the current changes in the utility industry.
In any event, Ameren without a doubt meets these standards with regard to the
retention of the gas operations discussed herein.
DISCUSSION
I. Section 10(c)
Section 10(c) of the Act provides that, notwithstanding the provisions of
Section 10(b), the Commission shall not approve:
(1) an acquisition of securities or utility assets, or of any other
interest, which is unlawful under the provisions of Section 8 or is
detrimental to the carrying out of the provisions of Section 11/2/; or
- --------------------
/2/ By their terms, Sections 8 and 11 only apply to registered holding
companies and are
(continued...)
2
<PAGE>
(2) the acquisition of securities or utility assets of a public utility or
holding company unless the Commission finds that such acquisition will
serve the public interest by tending towards the economical and the
efficient development of an integrated public utility system . . . .
Section 10(c)(1) requires that the proposed acquisition be lawful under
Section 8. Section 8 prohibits registered holding companies from acquiring,
owning interests in or operating both a gas and an electric utility serving
substantially the same area if state law prohibits it or requires specific
approval for such combinations. Each of UE and CIPS has provided combination
gas and electric utility services in Missouri and Illinois for many years.
Because Missouri and Illinois law do not in any way prohibit or require special
approval for combination gas and electric utilities serving the same area, the
Transaction does not raise any issue under Section 8 and, accordingly, the first
clause of Section 10(c)(1). As more fully discussed below, Section 8 in fact
indicates that a registered holding company may own both gas and electric
utilities where there is no conflicting state policy.
Section 10(c)(1) also requires that the Transaction not be detrimental to
carrying out the provisions of Section 11. Three provisions of Section 11 are
relevant here.
Section 11(a) of the Act requires the Commission to examine the corporate
structure of registered holding companies to ensure that unnecessary
complexities are eliminated and voting powers are fairly and equitably
distributed. Similarly, Section 11(b)(2) directs the Commission "to ensure that
the corporate structure or continued existence of any company in the holding
company system does not unduly or unnecessarily complicate the structure, or
unfairly or inequitably distribute voting power among security holders, of such
holding company system." As described in the Application, the Transaction will
not result in unnecessary complexities or unfair voting powers. As noted, in
this regard Ameren will be similar to the existing registered holding companies.
See Item 3.A.1(a) and (c) of the Application.
- -------------------------------
/2/(...continued)
therefore inapplicable at present to UE, CIPSCO or CIPS, since none of
these companies is now a registered holding company. The retention by UE of
the combination gas and electric business was approved in In re Union Elec.
Co., 40 SEC 1072 (Apr. 2, 1962). While divestiture had been ordered in In
re Union Elec. Co., 1972 SEC LEXIS 4264 (Sept. 19, 1972), jurisdiction over
such issue was reserved and UE was allowed to retain its gas properties in
In re Union Elec. Co., 45 SEC 489 (Apr. 10, 1974), the leading case
concerning operation of combination utilities by exempt holding companies.
The current view of the Commission as to retainability of combination
utilities for an exempt holding company is reflected in CIPSCO Inc., 47 SEC
Docket 174 (Sept. 18, 1990) where the retention by CIPSCO and CIPS of the
combination gas and electric business was unconditionally approved by the
Commission. The following discussion of Sections 8 and 11 is included only
because, under the present Transaction structure, Ameren will register as a
holding company after consummation of the Transaction.
3
<PAGE>
Finally, Section 11(b)(1) generally requires a registered holding company
system to limit its operations "to a single integrated public utility system,
and to such other businesses as are reasonably incidental, or economically
necessary or appropriate to the operations of such integrated public utility
system." One or more "additional" integrated public utility systems may be
retained if, as here, the "A-B-C Clauses" described below are satisfied. This
Memorandum will address the issue raised under Section (10)(c)(1) and by
reference Section 11(b)(1) of whether Ameren may retain, through control of UE
and CIPS, control of integrated combination gas and electric utility companies.
As detailed below, retention by Ameren of the combination utilities will not be
detrimental to the carrying out of any of the provisions of Section 11.
II. Retention of Gas Operations
This Memorandum will first demonstrate how Ameren would clearly meet the
traditional A-B-C Clauses requirements, but will also demonstrate that the
Commission should approve the Transaction without reference to the Clauses --
that is, on the basis that the acquisition by Ameren of combination companies
CIPS and UE is not detrimental to the provisions of Section 11 because they
constitute a "single integrated public utility system."
(A) Ameren Satisfies the Traditional "A-B-C" Test
Section 11(b)(1) of the Act generally requires a registered holding company
system to limit its operations "to a single integrated public utility system,
and to such other businesses as are reasonably incidental, or economically
necessary or appropriate to the operations of such integrated public utility
system." Section 11(b)(1) of the Act expressly permits a registered holding
company to control one or more "additional integrated public utility systems"
if:
A) each of such additional systems cannot be operated as an
independent system without the loss of substantial economies which can be
secured by the retention of control by such holding company of such system;
B) all of such additional systems are located in one state, adjoining
states, or a contiguous foreign country; and
C) the continued combination of such systems under the control of
such holding company is not so large (considering the state of the art and
the area or region affected) as to impair the advantages of localized
management, efficient operation, or the effectiveness of regulation.
(1) Clause (A)
Since 1968, in interpreting clause (A) of Section 11(b)(1), the Commission
has looked to the Supreme Court decisions in SEC v. New England Elec. Sys., 384
U.S. 176 (1966) ("NEES I") and SEC v. New England Elec. Sys., 390 U.S. 207
(1968) ("NEES II"). In NEES I, the Supreme Court accepted the Commission's
interpretation of the "loss of
4
<PAGE>
substantial economies" language of clause (A) to require an applicant seeking to
own an electric and gas utility system to show that the additional system, if
separated from the principal system, would be incapable of independent economic
operation.
Historically, in determining whether lost economies are "substantial" as
required under Section 11(b)(1)(A), the Commission has given consideration to
four ratios, which measure the projected loss of economies as a percentage of:
(1) total gas operating revenues; (2) total gas expense or "operating revenue
deductions"; (3) gross gas income; and (4) net gas income or net gas utility
operating income. Although the Commission has declined to draw a bright-line
numerical test under Section 11(b)(1)(A), it has indicated that cost increases
resulting in a 6.78% loss of operating revenues, a 9.72% increase in operating
revenue deductions, a 25.44% loss of gross income and a 42.46% loss of net
income would afford an "impressive basis for finding a loss of substantial
economies." In re Engineers Public Service Co., 12 SEC 41, 59 (Sept. 16, 1942)
("Engineers").
Here, the lost economies would be far greater than in Engineers if the gas
properties of UE and CIPS were to be operated on a stand-alone basis, with no
offsetting increase in benefits to consumers. These lost economies result from
the need to replicate services, the sacrifice of economies of scale, the costs
of reorganization, and other factors, and are described more fully in the
Analysis of the Economic Impact of a Divestiture of the Gas Operations of UE and
CIPS (the "1996 Study") (Exhibit K-1 to the Application) and the Supplemental
Analysis of the Economic Impact of a Divestiture of the Gas Operations of UE and
CIPS (the "Supplemental Study") (Exhibit K-1.1 to the Application). The 1996
Study and the Supplemental Study are referred to as the "Gas Study."
The lost economies of this case would exceed those of Engineers, whether
the gas operations are divested to two, stand-alone companies or one, stand-
alone company.
Two Companies. As set forth in the 1996 Study, divestiture of the gas
operations of UE and CIPS into two stand-alone companies would result in lost
economies of $22.1 million for UE and $36.3 million for CIPS. These lost
economies compare with 1995 gas operating revenues of $87.8 million for UE and
$129.6 million for CIPS; gas operating revenue deductions of $80.5 million for
UE and $117.4 million for CIPS; gas gross income of $7.3 million for UE and
$12.2 million for CIPS; and gas net income of $5.2 million for UE and $8.6
million for CIPS.
On a percentage basis, the lost economies amount to 425% of 1995 UE gas net
income and 424% of 1995 CIPS gas net income (424% of pro forma combined gas net
income). As a percentage of 1995 gas operating revenues, these lost economies
described in the 1996 Study amount to 25% for UE and 28% for CIPS. As a
percentage of 1995 gas expenses or operating revenue deductions, the lost
economies described in the 1996 Study would amount to 27% for UE and 31% for
CIPS. Finally, the 1996 Study shows that as a percentage of 1995 gas gross
income, the lost economies amount to 301% for UE and 297% for CIPS. In order to
recover these lost economies, the stand-alone company divested from UE would
need to increase customer rates by about 38% ($33.7 million) in order to provide
an 11.15% return on rate base. Similarly, the stand-alone company divested from
CIPS would need to increase
5
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customer rates by about 31% (40.7 million) in order to provide a 10.98% rate of
return on rate base. Without rate relief, the stand-alone companies would have
significant negative returns of minus 8.73% and 15.93% for UE and CIPS,
respectively.
The gas system operations of UE and CIPS, of course, are currently
operating as separate operations because UE and CIPS are unaffiliated companies.
Each company's gas operations are closely integrated with their electric
operations. To present a truly accurate picture of the loss that would be
sustained to shareholders and ratepayers by a divestiture of such operations, it
is appropriate to consider each gas operation separately. In other words, the
analysis should be of the loss to UE of the spin-off of the UE gas system in a
separate company AND the loss to CIPS of the spin-off of the CIPS gas system in
a separate company. Section 11(b)(1) clearly allows a registered holding
company to retain "one or more" additional systems. As shown by the 1996 Study,
as summarized in the preceding paragraphs, the loss of economies resulting from
the separate divestiture of the UE and CIPS gas systems would be devastating and
significantly more than in several Commission precedents. (Exact comparisons
will be detailed below). Accordingly, Ameren should, according to Commission
precedent be allowed to retain the gas operations of UE and CIPS.
One Company. When the Transaction is consummated, UE and CIPS will operate
as a "single integrated public utility system." As a result, it may be relevant
to consider whether, as such a single system, and assuming the Transaction had
occurred, the divestiture of the gas operations into a SINGLE, new stand-alone
company would also produce a "loss of substantial economies" within the meaning
of Section 11(b)(1)(A) of the Act. As demonstrated by the Supplemental Study,
such a divestiture would clearly result in such a loss of substantial economies.
As set forth in the Supplemental Study, divestiture of the gas operations
of UE and CIPS into one stand-alone company would result in lost economies of
$34.8 million. (This compares to lost economies of $22.1 million for UE and
$36.3 million for CIPS, totalling $58.4 million, as found by the 1996 Study).
These lost economies compare with 1995 pro forma combined UE and CIPS gas
operating revenues of $217.4 million; pro forma combined gas operating revenue
deductions of $197.9 million; pro forma combined gas gross income of $19.6; and
pro forma combined gas net income of $13.8 million.
On a percentage basis, the lost economies shown by the Supplemental Study
amount to 252% of 1995 pro forma combined gas net income -- far in excess of the
loss of net income in Unitil Corp., 51 SEC Docket 562 (Apr. 24, 1992) (Unitil),
where the Commission allowed the retention of gas utility operations, and the
30% loss in New England Electric System that the Commission has described as the
highest loss of net income in any past divestiture order./3/ As a percentage of
1995 pro forma combined gas operating revenues, these lost economies
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/3/ See Unitil Corp., 51 SEC Docket 562, 567 & n.42 (Apr. 24, 1992) ("The
Commission has required divestment where the anticipated loss in income of
the stand-alone company was approximately 30%" or "29.9% of net income
before taxes") (citing SEC v. New England Elec. Sys., 390 U.S. 207, 214
n.11 (1968)). This percentage compares to the 425% of 1995 UE gas net
income and 424% of 1995 CIPS gas net income shown by the 1996 Study.
6
<PAGE>
described in the Supplemental Study amount to 16% -- losses higher than the
losses in any past divestiture order. The projected loss of economies as a
percentage of operating revenues is even higher than the loss in Unitil./4/ As
a percentage of 1995 pro forma combined gas expenses or operating revenue
deductions, the lost economies described in the Supplemental Study would amount
to 17.6% -- higher than the losses in any past divestiture order and higher than
the losses in both Unitil and Entergy, another case in which the Commission
authorized the retention of gas operations./5/ As a percentage of 1995 pro
forma combined gas gross income, the lost economies described in the
Supplemental Study amount to 178% -- far in excess of the highest loss of gross
income in any divestiture order. The applicable percentages in past cases are
summarized in Exhibit K-2 to the Application (Table of Estimated Losses of
Economies in Prior Decisions on Divestiture and Retention of Gas Operations).
In order to recover these lost economies, the single, new stand-alone
company divested from UE and CIPS would need to increase customer rates by about
23% ($50.4 million) in order to provide an 11.07% rate of return on rate base.
This rate of return was conservatively
- ----------------------
/4/ The loss as a percentage of operating revenues in Unitil was 13.94%. The
highest loss of operating revenues in any case ordering divestiture is
commonly said to be 6.58%. See, e.g., Unitil Corp., 51 SEC Docket 562, 567
n.41 (Apr. 24, 1992) ("[o]f cases in which the Commission has required
divestment, the highest estimated loss of operating revenues of a stand-
alone company was 6.58%") (citing In re Engineers Public Service Co., 12
SEC 41 (Sept. 16, 1942)). In fact, however, the 6.58% ratio is not cited in
Engineers and is a post hoc calculation derived from claimed cost increases
which the Commission had found were "overstated" and "doubtful" in a number
of respects. Engineers Public Service Co., 12 SEC at 80-81. See also In re
Philadelphia Co., 28 SEC 35, 51 n.26 (June 1, 1948) (Engineers' "estimate .
. . of increased expenses . . . was overstated in several respects"). While
the SEC made no finding as to actual cost increases or ratios for the Gulf
States gas properties, it found that Engineers' estimate of divestiture-
related cost increases for certain sister gas properties in Virginia were
also overstated and cut them and the resulting ratios in half. Engineers
Public Service Co., 12 SEC at 60. If the same 50% discount had been applied
to Engineers' Gulf States gas properties, the loss of operating revenues
would have been 3.29%, the increase in expenses would have been 4.73%, the
loss of gross income would have been 10.43%, and the loss of net income
would have been 12.63%. Disregarding the 6.58% ratio incorrectly attributed
to the Engineers/Gulf States case, the highest loss of operating revenues
in any past divestiture order was 5.85%. See table of ratios in In re New
England Elec. Sys., 41 SEC 888, 905 App. (Mar. 19, 1964). This figure would
be even lower if adjusted for the increase in purchased gas costs since the
1940s. The percentage shown by the Supplemental Study compares to the 25%
and 28% reduction, respectively, for UE and CIPS shown by the 1996 Study.
/5/ The highest percentage of loss related to operating revenue deduction is
sometimes attributed to the Gulf States gas properties of Engineers Public
Service Co. See, e.g., In re New England Elec. Sys., 41 SEC 888, 905 App.
(March 19, 1964) (attributing 9.46% to the Engineers/Gulf States case).
This percentage, however, is based on claimed losses expressly rejected by
the Commission in the Engineers decision. In re Engineers Public Service
Co., 12 SEC 41, 80-81 (Sept. 16, 1942). Disregarding the 9.46% figure
erroneously attributed to the Engineers case, the highest expense
percentage in the cases ordering divestiture appears to have been either
8.01% or 7.42%, depending on how the ratio is calculated. See In re North
American Co., 18 SEC 611 (Apr. 7, 1945); In re Philadelphia Co., 28 SEC 35,
51 Table VI (June 1, 1948) (attributing expense ratio of 7.42% to North
American) with In re New England Electric System, 41 SEC 888, 905 App.
(1964) (attributing expense ratio of 8.01% to North American). The combined
total loss as a percentage of gas operating revenue deductions shown in the
1996 Study was 29.5%.
7
<PAGE>
estimated using the weighted average approximate costs for capital of UE and
CIPS rather than the higher returns that would likely be required by the
financial community for a single, stand-alone company. See the Supplemental
Study, Exhibit 4.
Finally, it should be noted that the lost economies would, in the absence
of rate relief, result in a negative rate of return on rate base for the gas
operations of minus 4.78% -- significantly more detrimental than the 2.01%
projected stand-alone rate of return in Unitil, where retention was authorized.
This return is significantly lower than the returns of other utilities in the
region and represent a decline from UE's and CIPS' indicated rates of return for
1995. See the Supplemental Study.
The above data show that, even assuming the gas operations of CIPS and UE
were divested by forming one stand-alone company, the loss of economies would be
significant, in excess of that present in other cases where retention was
allowed and sufficient to support a finding that requirement of Clause A of
Section 11(b)(1) is met in this case. This conclusion is even more dramatically
demonstrated if it is assumed that each gas operation would be in a separate
stand-alone company as shown by the 1996 Study.
(2) Clauses (B) and (C) of Section 11(b)(1) are Satisfied.
The remaining requirements of Section 11(b)(1) are met because the gas
operations of UE and CIPS are located in the adjoining states of Missouri and
Illinois and because the continued combination of the gas operations under
Ameren is not so large, considering the state of the art and the area or region
affected, as to impair the advantages of localized management, efficient
operation or the effectiveness of regulation. The gas systems are confined to a
relatively small area and are not as large as other gas systems in the same area
and will preserve the advantages of localized management, efficient operation
and effectiveness of regulation. Moreover, as the Commission has recognized
elsewhere, the determinative consideration is not size alone or size in an
absolute sense, either big or small, but size in relation to its effect, if any,
on localized management, efficient operation and effective regulation. See
Centerior Energy Corp., 35 SEC Docket 769 (Apr. 29, 1986). From these
perspectives, it is clear that the continued combination of the gas operations
under Ameren is not too large.
Even after the combination, the gas operations of UE and CIPS, with some
285,403 customers combined in only two states, will be significantly smaller
than neighboring Northern Illinois Gas Company (1,769,800 customers), People's
Gas Light and Coke Company (842,510 customers), Laclede Gas Co. (553,000
customers), Missouri Gas Energy (450,000 customers) and Illinois Power Co.
(388,170 customers).
Localized management is discussed for the Transaction as a whole under Item
3.A.2.b.(ii)(A) and (B) of the Application. Applied solely to the gas
operations, the current UE and CIPS gas systems enhance localized management
within the larger corporate structure and will continue to do so after the
Transaction is completed.
8
<PAGE>
As a result of the Transaction, the centralized functions of Ameren will
continue to be handled from St. Louis, Missouri and Springfield, Illinois and
from regional offices. No reduction in customer service or support crews is
expected. Management will therefore remain geographically close to the gas
operations, thereby preserving the advantages of a localized management.
With respect to efficient operation, as described in Item 3.A.2.b.(ii) of
the Application, as part of the Ameren system, the gas operations of UE and CIPS
are expected to reduce delivered gas costs by $37 million in the first 10 years
after the Mergers. Substantially all of these reductions will be passed on
directly to customers under the purchased gas adjustment ("PGA") clauses in UE's
and CIPS' tariffs, if all of the system's purchased gas costs continue to
receive PGA treatment as at present. Far from impairing the advantages of
efficient operation, the combination of the gas operations under Ameren will
facilitate and enhance the efficiency of gas operations. As discussed in Item
3.A.2.a.(i)(B) of the Application, the "state of the art" with respect to gas
operations has changed significantly in recent years. In the light of current
communications technology and the nature of today's gas business, the
combination of the UE and CIPS gas businesses, under the control of Ameren, will
not jeopardize local control and will significantly improve operating
efficiency.
Based on its traditional application of the A-B-C Clauses, therefore, the
Commission should find that UE and CIPS may retain the combined gas businesses
as an "additional" integrated system.
(B) The Commission Should Not Require Ameren to Satisfy the
Traditional "A-B-C" Test.
Although for many years the Commission has interpreted the Act as not
permitting a registered holding company to control subsidiaries that were
combination gas and electric utilities, except where the "A-B-C" test is met,
there are significant legal and policy reasons for the Commission to revise its
interpretation of the Act, in light of recent changes both in national energy
policy and in the energy markets./6/
(1) The Act Does Not Prohibit Combination Companies.
Nothing in the Act directly prohibits a registered holding company from
owning an integrated gas and electric system if such a structure does not
violate the laws of the state(s) having jurisdiction over such a system.
Section 8 of the Act provides that:
[w]henever a State law prohibits, or requires approval or
authorization of, the ownership or operation by a single company of
the utility assets of an electric utility company and a gas utility
company serving substantially the same territory, it shall be unlawful
for a registered holding company, or any
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/6/ These changes are described below and have been recognized by the
Commission. See Consolidated Natural Gas, Release No. 35-26512 (Apr. 30,
1996); Northeast Utilities, Release No. 35-26554 (August 13, 1996).
9
<PAGE>
subsidiary company thereof . . . (1) to take any step, without the
express approval of the state commission of such State, which results
in its having a direct or indirect interest in an electric utility
company and a gas company serving substantially the same territory; or
(2) if it already has any such interest, to acquire, without the
express approval of the state commission, any direct or indirect
interest in an electric utility company or gas utility company serving
substantially the same territory as that served by such companies in
which it already has an interest.
Thus, on its face, the Act only precludes the use of the registered holding
company form to circumvent any state law restrictions on the ownership of gas
and electric assets by the same company.
Further, the legislative history of the Act indicates that Congress saw the
question of whether combination companies are desirable as one that should be
left to the states. The Senate Committee on Interstate Commerce in its report
on the Act noted that the provision in Section 8 concerning combination
companies "is concerned with competition in the field of distribution of gas and
electric energy -- a field which is essentially a question of State policy, but
which becomes a proper subject of Federal action where the extra-State device of
a holding company is used to circumvent State policy."/7/ In addition, attached
to the committee report is the Report of the National Power Policy Committee on
Public-Utility Holding Companies, which sets forth a recommended policy that:
"Unless approval of a State commission can be obtained the commission would not
permit the use of the holding-company form to combine a gas and electric utility
serving the same territory where local law prohibits their combination in a
single entity."
Congress clearly recognized that local regulators are in the best position
to assess the needs of their communities. The Act was never intended to
supplant local regulation but, rather, was intended to create conditions under
which local regulation was possible. Section 21 of the Act states:
Nothing in [the Act] shall affect . . . the jurisdiction of any other
commission, board, agency or officer of . . . any State, or political
subdivision of any State, over any person, security, or contract,
insofar as such jurisdiction does not conflict with any provision of
[the Act]. . . .
The legislative history reveals that Section 21 of the Act was further intended
"to ensure the autonomy of State commissions [and] nothing in the [Act] shall
exempt any public utility company from obedience to the requirements of State
regulatory law." S. Rep. No. 621, 74th Cong., 1st Sess. 10 (1935).
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/7/ The Report of the Committee on Interstate Commerce, S. Rep. No. 621 74th
Cong., 1st Sess. 31 (1935).
10
<PAGE>
The Act should not be used as a tool to override state policy, particularly
where the holding company involved is subject to both state and federal
regulation and where the affected state regulatory commissions have supported
the combined electric and gas operations in one holding company system. To do
otherwise would be to act contrary to Congress' intent.
(2) The Commission's Interpretation of the Act.
In its early decisions under the Act, the Commission adhered to the concept
that Section 8 of the Act evidenced the policy of Congress that the decision of
whether to allow combination companies was one that states should make (although
the Commission might have to implement it in certain cases) and, where such
systems were permissible, the role of the Commission was to ensure that both
such systems were integrated as defined in the Act. If the electric systems
were integrated and the electric and gas properties were in close geographic
proximity and were related so that substantial economies were obtained by their
coordination under common control, then combined ownership by the registered
holding company would be permitted. See American Water Works & Elec. Co., 2 SEC
972 (Dec. 30, 1937); 1995 Report at 62. If a combination company did not
violate state policy, there was no need for the Commission to exercise
jurisdiction to implement state policy.
By the early 1940s, however, the Commission, faced with further perceived
abuses and based on then existing competitive conditions, switched its focus to
Section 11 and adopted a narrow interpretation of the standards contained
therein as the controlling factor with regard to combination registered holding
companies./8/ In this period of the administration of the Act, facing vigorous
constitutional challenges to the Act's validity as well as concerted resistance
in many proceedings to the specific attempts to order divestiture by holding
companies of utility subsidiaries, the Commission pursued a policy of strict
interpretation of the Act to best effectuate the directive from Congress that
the monolithic holding companies be broken up./9/ Furthermore, in connection
with its analysis of combination companies under Section 11, the Commission
frequently noted a policy concern existing at that time which advocated
separating the management of gas and electric utilities based on the belief that
the gas utility business tended to be overlooked by combination company
management who focused on the
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/8/ See, e.g., In re Columbia Gas & Elec. Corp., 8 SEC 443, 463 (Jan. 10,
1941); In re United Gas Improvement Co., 9 SEC 52 (1941); SEC v. New
England Elec. Sys., 384 U.S. 175 (1966). It should be noted that the
Commission continued to give primacy to state utility commission
determinations in making decisions regarding combination exempt holding
companies. See, e.g., In re Northern States Power Co., 36 SEC 1 (Sept. 16,
1954); Delmarva Power & Light Co., 46 SEC 710 (Oct. 19, 1976); WPL
Holdings, Release No. 35-24590 (Feb. 26, 1988); CIPSCO Inc., 47 SEC Docket
174 (Sept. 18, 1990).
/9/ That goal has been long accomplished. 1995 Report at ix.
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<PAGE>
electric business. Therefore, it was believed that gas utilities would benefit
from having separate management focused entirely on the gas utility business.
/10/
(3) The Commission Should Revise Its Interpretation of the Act.
The Commission is not bound by its historical emphasis on Section 11 of the
Act when assessing combination companies. An agency may revise its
interpretation of its governing statute where its revised interpretation is
reasonable and where it provides a reasoned basis for its change. Chevron USA,
Inc. v. Nat'l Resources Defense Council, Inc., 467 U.S. 837 (1984); Rust v.
Sullivan, 500 U.S. 173, 186-87 (1991) (agency's reversal of policy in effect for
18 years was consistent with intent of statute and was supported by reasoned
analysis, and thus permissible).
The Supreme Court has indicated that the governing principle is the intent
of Congress, not an agency's long-standing practice. In Chevron, the Court
stated:
When a court reviews an agency's construction of the statute
which it administers, it is confronted with two questions. First,
always, is the question whether Congress has directly spoken to the
precise question at issue. If the intent of Congress is clear, that
is the end of the matter; for the court, as well as the agency, must
give effect to the unambiguously expressed intent of Congress. If,
however, the court determines Congress has not directly addressed the
precise question at issue, the court does not simply impose its own
construction on the statute, as would be necessary in the absence of
an administrative interpretation. Rather, if the statute is silent or
ambiguous with respect to the specific issue, the question for the
court is whether the agency's answer is based on a permissible
construction of the statute.
Chevron, 467 U.S. at 842-43 (citations omitted; emphasis added).
Moreover, the Court has stated:
[An agency's] revised interpretation [of a statute] deserves deference
because an initial agency interpretation is not instantly carved in stone
and the agency, to engage in informed rulemaking, must consider varying
interpretations and the wisdom of its policy on a continuing basis. An
agency is not required to establish rules of
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/10/ See, e.g., In re Philadelphia Co., 28 SEC 35, 48 (June 1, 1948); In re
North American Co., 11 SEC 194, 216-17 (Apr. 14, 1942); In re Illinois
Power Co., 44 SEC 140 (Jan. 2, 1970). The principal reasons for this
change in policy was to better administer the Act in light of perceived
abuses and conditions in the industry at the time. As noted, industry
conditions are significantly different now than in the 1940s. Also, the
actual statutory basis for this changed policy rested on a very technical
interpretation of the definition of "integrated public utility system."
As will be shown, this strained interpretation ignores the clear language
of Section 8. See 1995 Report at 63, 65. As noted below, the Commission
has the authority to reinterpret the meaning of the Act in light of
changed conditions.
12
<PAGE>
conduct to last forever, but rather must be given ample latitude to adapt
its rules and policies to the demands of changing circumstances.
Rust, 500 U.S. at 186-87 (citations and internal quotation marks omitted).
The Commission has begun a re-evaluation of the requirements of Section 11
in light of contemporary conditions. To date, that review has principally
focused on the meaning of the A-B-C Clauses and whether it is necessary to
continue a narrow, restrictive interpretation of those provisions.
In NEES I, the Supreme Court specifically recognized that the language of
clause (A) of Section 11(b)(1) was "not crystal clear" and deferred to the
Commission's "expertise on the total competitive situation." 384 U.S. at 185
(emphasis in original); see also NEES II, 390 U.S. at 219. In NEES I and NEES
II, the Court accepted the Commission's interpretation of Clause A as a
"construction well within the permissible range given to those who are charged
with the task of giving an intricate statutory scheme practical sense and
application." 384 U.S. at 185.
The NEES interpretation however, is not the only permissible
interpretation. There is strong support for the Commission's application of a
different interpretation of Clause A, and the Commission may use its expertise
to develop a different interpretation which is both consistent with Congress'
intent and which properly addresses the "demands of changing circumstances."
Rust, 500 U.S. at 186-87. This Commission is free to apply its expertise to
administer the Act in light of changes in legal, regulatory and economic
circumstances which were not foreseen at the time of the NEES decisions,
including federal legislation (described below) which has "substantially
changed" the Act. See Chevron, 476 U.S. at 842.
The Division recognized in the 1995 Report that the Commission should no
longer be bound by the narrow interpretation of Clause (A) under the NEES
decisions. In so doing, the Division stated:
[T]he SEC has generally required electric registered holding companies
that seek to own gas utility properties to satisfy the requirements of
the A-B-C clauses concerning additional integrated systems. In
contrast, exempt holding companies have generally been permitted to
retain or acquire combination systems so long as combined ownership of
gas and electric operations is permitted by state law and is supported
by the interested regulatory authorities.
In the past, the SEC has construed the A-B-C clauses narrowly to
permit retention only where the additional system, if separated from
the principal system, would be incapable of independent economic
operations. Although the Supreme Court upheld the SEC's reading, two
justices dissented, contending that the "serious impairment" standard
was at odds with the wording of the Act, had little basis in the
statutory history or aims of the Act, and could not be sustained by
agency or
13
<PAGE>
judicial precedent. The dissenting justices believed that the
statutory language "called for a business judgment of what would be a
significant loss."
Applicants in recent matters have argued that, in a competitive
utility environment, any loss of economies threatens a utility's
competitive position, and even a "small" loss of economies may render
a utility vulnerable to significant erosion of its competitive
position. There is general support for a more relaxed standard. A
number of commenters emphasize that these are essentially state
issues. It does not appear that the SEC's precedent concerning
additional systems precludes the SEC from relaxing its interpretation
of section 11(b)(1)(A). Indeed, the SEC has recognized that section
11 does not impose "rigid concepts" but rather creates a "flexible"
standard designed "to accommodate changes in the electric utility
industry."
Congress, in 1935, recognized that competition in the field of
distribution of gas and electric energy is essentially a question of
state policy. The Act was intended to ensure compliance with state
law in this regard. Moreover, it appears that the utility industry is
evolving toward the creation of one-source energy companies that will
provide their customers with whatever type of energy supply they want,
whether electricity or gas. Accordingly, the Division believes it is
appropriate to reconcile the treatment of registered and exempt
companies in this regard, and so recommends that the SEC permit
registered holding companies to own gas and electric utility systems
pursuant to the A-B-C clauses of section 11(b)(1), where the affected
states agree./11/
The Commission approved the Report on June 20, 1995.
The Division's recommendation regarding Clause A would represent sound
policy by the Commission. Indeed, the policy so expressed would equally support
a finding that a combination company, if it meets the requirements of the
American Water Works decision, constitutes a single integrated public utility
system. From a policy perspective, the Commission's historic concern
underpinning its 1964 NEES decision and a host of earlier decisions where the
retainability of gas properties by registered electric systems was at issue --
namely, of fostering competition between electric and gas -- is simply no longer
valid given the current "state of the art" in the electric and gas utility
industries. In the three decades since the Commission decided the NEES cases,
profound economic and regulatory factors have wrought a fundamental
transformation in the gas supply and electric generation industry, rendering
obsolete the Commission's earlier premises regarding the primacy of competition
between gas and electric service and the lack of competition within electric and
gas service.
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/11/ 1995 Report at 74, 75, 76. Footnotes omitted.
14
<PAGE>
The Commission itself has noted that the Act "creates a system of pervasive
and continuing economic regulation that must in some measure at least be
refashioned from time to time to keep pace with changing economic and regulatory
climates." Union Electric Co., 45 S.E.C. 489,503 n.52 (1974), aff'd sub nom.
City of Cape Girardeau v. SEC, 521 F.2d 324 (D.C. Cir. 1974). See also Eastern
Utilities Assoc., Holding Co. Act Release No. 26232 (Feb. 15, 1995). The
Commission has specifically recognized that the "changing realities of the
utility industry" include "the increasing integration of energy markets, as
deregulation and competition increase." Consolidated Natural Gas Co., Release
No. 35-26512 (Apr. 30, 1996) ("Consolidated").
The Commission took further steps toward the conclusion urged here in
Consolidated. In that case, Consolidated, a registered gas utility company,
received approval to enter into the wholesale electric marketing business. The
Commission indicated it would approve retail marketing of electricity when state
laws had developed to allow such activity. Quoting an earlier release, the
Commission noted that "the utility industry is evolving toward a broadly based
energy-related business that is no longer focused solely on the traditional,
regulated, production and distribution functions of a utility." Under the
Consolidated decision, Consolidated (a gas utility) may own electric generating
facilities (e.g., through an EWG) and may sell electricity through the approved
marketing subsidiary. Several months after Consolidated, the Commission took a
further step. Recognizing that "the electric and gas industries are no longer
separate, but are instead increasingly integrated," the Commission approved the
application of an electric registered holding company system to engage in retail
marketing of energy commodities (including electricity and gas). SEI Holdings,
Release No. 35-26581 (Sept. 26, 1996) ("SEI Holdings"). Thus, registered
holding companies are now able to offer their wholesale and retail customers
integrated gas and electric energy services -- exactly what Ameren wishes to
offer its customers. Consolidated, SEI Holdings and the cases following them
strongly suggest that the Commission is changing its interpretation of the Act
including those activities deemed "detrimental to carrying out the provisions of
Section 11."/12/
UE and CIPS have conducted combined electric and gas operations for many
years. As the energy markets have developed, especially in recent years, CIPS
and UE have developed, and are further developing, as "energy service"
companies. The provision of gas and electric products is only the start of a
utility's job. In addition, the utility must provide an entire package of both
energy products and services. In this area, CIPS' and UE's efforts are part of
a trend by utilities to organize themselves as "energy service companies," that
is,
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/12/ See Northeast Utilities, Release No. 35-26554 (Aug. 13, 1996) and cases
cited in note 14 thereof. See also American Electric Power Co., Release
No. 35-26572 (Sept. 13, 1996). While Consolidated, and SEI Holdings do
not directly interpret the meaning of "single integrated public utility
company," but rather find that the approved marketing activities
constitute a permissible other business under Section 11(b)(1), the
finding by the Commission that marketing of electricity by a gas
registered holding company system is not "detrimental to the carrying out
of the provisions of Section 11" constitutes substantial support for the
proposition urged here: that combination companies are likewise not
detrimental to the purposes of Section 11. The Commission has extended
Consolidated to also allow electric registered holding company systems to
engage in electric and gas brokering and marketing activities.
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as providers of a total package of energy services rather than merely suppliers
of gas and electric products. The goal of an energy service company is to
retain its current customers and obtain new customers in an increasingly
competitive environment by meeting customers' needs better than the competition.
An energy service company can provide the customer with a low cost energy option
(i.e., gas, electricity or conservation) without inefficient subsidies.
As energy services companies, UE and CIPS are not solely electric or gas
utilities and do not operate in a manner which could lead to the abuses which,
under competitive conditions previously prevailing in the industry, were
perceived as likely to arise from the combination of gas and electric utilities
under common ownership in a single holding company system -- i.e., the "favoring
of one of these competing forms of energy over the other." NEES I at 183.
Rather, UE and CIPS offer (and the Ameren system will offer) diverse forms of
energy to their consumers, thereby allowing customers to choose among different
forms of energy and fostering efficiency and conservation. This increasing
competition to supply all forms of energy will prevent a holding company from
"favoring" one form over the other. Furthermore, consumers and regulators today
must be -- and are -- more careful with limited energy resources than was
required in 1935. See Eastern Utilities Associates, Release No. 35-26232 (Feb.
15, 1995) and the 1995 Report at 22-23 and 30-31. One energy company which
allows its customers to select among different forms of energy based on
environmental and economic factors is a sensible means of allocating scarce
national resources under the purview of local regulators who are most familiar
with the needs of local constituencies.
This trend is exemplified by several transactions including the proposed
merger of Texas Utilities, an electric utility, with Enserch Corp., which is a
natural gas concern, and the acquisition by Enron Corp., a major integrated gas
company with electric power marketing business, of the electric utility Portland
General Corp. Referring to such cross industry transactions, Elizabeth A.
Moler, Former Chairwoman of the Federal Energy Regulatory Commission ("FERC")
said: "They have the potential to increase competition and make more options
available to consumers." Allen R. Myerson, Enron Will Buy Oregon Utility In
Deal Valued at $2.1 Billion, New York Times, July 23, 1996 at D1. Since these
transactions were announced, Houston Industries, an exempt electric utility
holding company, announced a merger with NorAm Energy Corp., a natural gas
pipeline and local gas distribution company, and Enova Corp., the holding
company for San Diego Gas & Electric, an electric company agreed to merge with
Pacific Enterprises, a natural gas distribution utility. This merger will
produce the largest customer base of any investor owned utility. Benjamin A.
Holden, Deal Valued at $2.8 Billion Would Establish Giant for California Energy,
Wall Street Journal, Oct. 15, 1996 at A3. Each of these companies is responding
to industry realities and customer demands that utilities be capable of
supplying total energy services, not merely one energy commodity. As the
Commission noted in SEI Holdings, "Industry trends and competitive pressures
make it important for registered system companies to be poised to compete in new
markets as they are created." See also Consolidated Natural Gas, Release No.
35-26512 (Apr. 30, 1996). Since the Ameren Application was filed in October,
1996, at least five other "convergence" transactions have been announced,
including: Brooklyn Union Gas Co. and Long Island Lighting Co.; PG&E Corp. and
Valero Energy; Destec Energy Inc. and NGC Corp.; Duke Power and PanEnergy and
Pacificorp and TPC Corp.
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These proposed cross industry transactions clearly demonstrate that market
forces are demanding the unified delivery of energy services and that such
combinations will be beneficial to the interests of investors and consumers and
accordingly the public interest. None of the announced mergers is anticipated
to be restrained by the Act./13/ Continued reliance on outdated premises which
prevent registered combination companies and do not reflect current competitive
conditions will put registered holding companies at a severe competitive
disadvantage. FERC Commissioner Donald F. Santa has stated "the cause for
concern about combination electric and gas providers largely has disappeared . .
. . In a converged electric and gas market, there will be additional
opportunities for scale economies, for innovation and for competition -- all of
which should be beneficial to consumers and the economy." Foster Natural Gas
Report, May 29, 1997 at 4.
There are many benefits of such combined electric and gas energy services
providers. For customers, the energy service utility provides the convenience
and efficiency of service by a single energy provider and reduces transaction
costs incurred in gathering and analyzing information, contacting energy
suppliers and negotiating terms of service. For the communities in which the
energy service company operates, the combining of gas and electric operations
simplifies community planning on energy-related matters through coordination
with a single energy provider. For society, the combination energy services
company will allow customers to efficiently choose energy sources thus ensuring
an environmentally efficient allocation of energy. For utility shareholders and
employees, the energy services company is better able to respond to a
competitive environment and to remain an attractive investment opportunity for
shareholders and an appealing employer for utility employees. Thus, combination
utilities benefit all utility stakeholders. The benefits to the public interest
from these combinations is demonstrated by the approvals several have already
received from FERC./14/
The development of energy services companies stems from dramatic changes in
the regulatory framework of the industry. In the gas area, regulatory changes
have introduced competition into what was formerly a monopoly and have expanded
the availability of "transportation-only service" as an alternative to sales
services from the local gas utility company. CIPS and UE have "open access"
transportation-only service tariffs on file with their respective state
commissions, and approximately 39% and 14% of the gas delivered by CIPS and UE,
respectively, in 1995 was directly purchased by customers. FERC Order 636 is
resulting in the separation of the commodity function from the transportation
function at both wholesale and retail levels.
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/13/ It appears that most, if not all, the proposed mergers of predominantly
gas businesses with predominantly electric businesses can be structured to
meet the intrastate exemption of Section 3(a)(1) or otherwise not be
subject to the Act. The benefits to investors and consumers that will
flow from such combinations should not be limited to only those
enterprises operating within one state, but should be available to all
investors and consumers.
/14/ See e.g., Duke Power Company and PanEnergy Company, 79 FERC (P) 61,236
(May 28, 1997); San Diego Gas & Electric Co. and Enova Energy, Inc., 79
FERC (P) 61,372 (June 25, 1997).
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As a result, combination utilities such as UE and CIPS have less ability
than they did in 1935 to "favor" electric -- the principal policy concern in
decisions ordering the separation of gas and electric systems -- by curtailing
the availability or increasing the price of gas./15/ Combination utilities also
have less incentive to favor electric over gas in light of the increasing
importance of demand-side management, the costs and risks involved in the
construction of new generating capacity and the incentives to avoid such
construction, and, as noted in the June 1994 issue of The Electricity Journal,
the emergence of integrated resource planning involving both gas and electric
service.
In the electric area, the Energy Policy Act of 1992 and the Public Utility
Regulatory Policies Act of 1978 have introduced competition into the electric
utility business. As the chairman of the Senate Banking Committee stated as
early as three years ago:
"[The Act] was substantially changed by the Energy Policy Act of 1992.
That law restructured the utility industry to promote greater
competition for the benefit of energy customers. The Energy Policy
Act of 1992 was the product of a cooperative effort on the part of the
Banking Committee and the Energy Committee to create a more market-
oriented regulatory framework for the energy industry." Hearing on
S.182, The Communications Act of 1994, before the Comm. on Commerce,
Science and Transportation, 103rd Cong. 2nd Sess. 344-345 (1994)
(prepared Statement of Senator Riegle) (emphasis added).
As a continuation of the trend towards more competition, on April 24, 1996,
the FERC entered Orders 888 and 889. These orders, entered after more than a
year of debate and public comment, open up wholesale power sales to competition.
All utilities subject to Order 888 must provide transmission service to
qualified wholesale buyers and sellers on terms set by universally applicable
tariffs. This mandatory "wholesale wheeling" will bring competition to the
market for electricity provided to customers for resale./16/
Finally, many states have adopted electric open access or customer choice
laws or regulations or have other "retail wheeling" measures under discussion
which are likely to have the effect of extending electric supply competition to
the retail level. Illinois and Missouri are each in the process of evaluating
various options that could increase electric supply competition at the retail
level./17/ Federal legislation is being proposed which would require
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/15/ See, e.g., NEES I at 183-184. It is important to note that this issue --
basically an antitrust issue -- was the principal concern in previous
decisions ordering the separation of gas and electric systems and clearly
is no longer applicable to the changed utility competitive environment.
/16/ UE and CIPS filed their electric open-access transmission tariffs in
compliance with Order 888 on July 9, 1996.
/17/ The Illinois General Assembly has appointed a special legislative
committee to develop a policy to introduce retail electric competition.
Legislation was introduced, and passed in the House, but not adopted by
the Senate, in the 1997 Spring Session of the General Assembly (H.B. 263).
Legislation
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all states to adopt a retail wheeling scheme by early in the next century./18/
These initiatives could soon bring direct commodity competition to retail
electric customers much as such competition already exists for natural gas.
Many of these recent changes to the energy industry are noted in SEI Holdings,
Release No. 35-26581 (Sept. 26, 1996).
Accordingly, instead of relying on the blunt instrument of competition
between gas and electric energy sources (the driving force behind the
Commission's historic interpretation of the Act), national policy has now
created direct competition within the gas and electric utility industries.
Thus, combination ownership does not eliminate competition, since a combination
utility now has competitors for both gas and electric service. Moreover,
competition is not an end in itself, but is merely a means to the end of
efficient, cost-effective service. Since combination ownership creates
efficiencies and no longer has the effect of eliminating competition, there is
no reason for the Commission to prohibit combination ownership, at least under
the circumstances presented here.
Further, there is nothing in national energy policy that would override the
deference Congress intended should be given to the states on this question.
Indeed, as discussed above, in the 1995 Report the Division recommended that the
Commission interpret Section 11(b)(1) of the Act to allow registered holding
companies to hold both gas and electric operations as long as each affected
state utility regulatory commission approves of the existence of such a
company./19/
As noted, the Commission has begun to reevaluate Section 11, to place more
meaning on Section 8 in its review of the A-B-C Clauses and to accommodate
electric and gas marketing by a single registered holding company in its
decisions in Consolidated, SEI Holdings and the cases following them. The
Commission should take the further step, justified by all the same facts,
circumstances and policies, and permitted under Chevron and Rust, to determine
that a registered holding company may control combination gas and electric
utility companies.
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/17/(...continued)
could be adopted in the Fall of 1997. Two Illinois utilities have
initiated pilot programs which give retail customers a choice in
electricity providers. CIPS has received approval to participate as a
supplier in those programs. Further information concerning Illinois
initiatives is included in CIPSCO's 1996 Form 10-K and its 1997 Form
10-Q's filed as exhibits to the Application. In Missouri, a joint
agreement among the parties in the MPSC proceeding to approve the
Transaction calls for UE to propose an experimental retail wheeling pilot
program in Missouri for 100 mW of electric power. This agreement filed as
Exhibit D-2.3 was included in the settlement approved in the final MPSC
Order. See Exhibit D-2.2 to the Application.
/18/ See, e.g., HR 655 (105th Cong.; 1st Session) (by 2000); S 237 (105th
Cong.; 1st Session) (by 2003).
/19/ The 1995 Report urges flexible interpretation of the ABC Clauses.
However, as demonstrated herein, there is ample reason, in light of
changed national energy policy for the Commission to go further and return
to its pre-1940s reliance on Section 8's clear language to permit State-
sanctioned combination companies.
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Such a reemphasis on Section 8 fits within the overall regulatory scheme of
the Act. Section 11 of the Act is flexible and was designed to change as the
policy concerns over the regulation of utility holding companies changed./20/
Moreover, a registered holding company would still be required to demonstrate
that any acquisition or transaction by which it would become a combination
company would not be detrimental to carrying out the provisions of Section 11 of
the Act. In other words, its electric system would have to constitute an
integrated electric system and its gas system would have to constitute an
integrated gas system and both systems would have to be capable of being
operated efficiently together (all facts which are clearly present in the
instant case). See American Water Works & Elec. Co., 2 SEC 972 (Dec. 30, 1937).
Thus, the standards of Section 11 would still have to be met, but the
application of those standards should take into account the fundamental policy
of the Act and allow local regulators to make the threshold determination with
regard to combination companies.
As shown under Item 3.A.b.ii. of the Application, the electric systems of
UE and CIPS constitute an "integrated" electric system and the gas systems
constitute an "integrated" gas system. Moreover, as the Gas Study clearly
shows, the electric system and the gas system together are operated as a single
integrated energy company. The integration standard of the Act is designed to
require efficient operations. The Gas Study shows that separating the existing
gas systems from the existing fully integrated companies would result in a loss
of significant economies if two new companies were formed and even if only one
new company conducted the integrated gas operations. These economies relate to
more than just corporate operations but also include substantial savings
resulting from such operational matters as joint gas and electric meter reading,
combined field service facilities, combined engineering services, combined
customer service facilities and combined transportation services. Section 11
was intended to require the separation and independent operation of utilities
that were commonly controlled through the holding company but had no operational
connection. That situation is not presented in any way by the Transaction, thus
the purposes of the Act would not be compromised in any way by approval of
retention of the combination gas and electric businesses.
Furthermore, the Commission has had the opportunity to review the gas
utility operations of UE and CIPS in prior orders and found that continued
combination activity would not be "detrimental to the public interest or the
interest of investors or consumers" and would not be "detrimental to the
carrying out of the provision of Section 11." See the CIPSCO and Union Electric
cases cited in note 2 above.
(4) UE's and CIPS' Combination Systems Are Not Prohibited by State
Law
Each of UE and CIPS as a combination company is permissible pursuant to the
terms of Section 8 of the Act because the continued combined activities in no
way violate state
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/20/ In re Mississippi Valley Generating Co., 36 SEC 159 (Feb. 9, 1955) (noting
that Congress intended the concept of integration to be flexible); Unitil
Corp., 51 SEC Docket 562 (Apr. 24, 1992) (noting that Section 11 contains
a flexible standard designed to accommodate changes in the industry).
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policy. Moreover, continuation of each as a combination company is in the public
interest. The ICC and MPSC have on numerous occasions over the years had
opportunity to review the combined operations in light of public interest
standards in rate cases and other proceedings. These cases have approved cost
allocation methods, accounting procedures and other factors which insure that
combination activities are not harmful to customers. Furthermore, as part of
state merger approvals, approval of the ICC will be sought for the acquisition
by CIPS of the UE Illinois gas properties. The MPSC has given final approval to
the Transaction, including the transfer of the gas properties. Although the
transfer of UE's Illinois utility properties to CIPS has been contested in the
ICC proceeding, the concern does not relate to combining gas and electric
properties. Finally, as required by Section 11, in addition to the fact that the
electric systems of CIPS and UE constitute an integrated electric system, the
gas systems will together constitute an integrated gas system as explained in
detail below.
With respect to Section 8, the combination of electric and gas operations
is lawful under all applicable state laws for each of UE and CIPS and has been
considered and approved indirectly on numerous occasions by Missouri and
Illinois regulators who have, and will continue to have, direct jurisdiction
over the Ameren gas operations. The use of Ameren as a holding company for two
combination companies will not circumvent any state regulations, since the gas
utility operations of each of UE and CIPS individually will continue to be
regulated by the relevant jurisdictions. Both the ICC and the MPSC will have the
opportunity to review the continued operation of combination companies as part
of their approval of the Transaction and would have the ability to impose
conditions on their approval if they felt it necessary to protect the public
interest. See, e.g., 220 ILCS 5/7-204. Given the long-standing operation of
combined electric and gas businesses in both Missouri and Illinois, the
statutory authority of the MPSC and ICC and the many opportunities for review of
such combined operations, including the review of the Transaction, it is clear
that state regulators do not believe combination operations lead to harm to
utility customers. UE and CIPSCO will notify the Commission when the ICC
approval is received.
Such state commission actions manifest the recognition by those commissions
that the existence of both gas and electric systems in the Ameren holding
company system will allow Ameren's customers greater choice to meet their energy
needs, especially given the fact that the electric and gas systems operate in
substantially the same territory, while sharing in the synergies that result
from the Transaction. Moreover, the prior fear that a holding company such as
Ameren would be able to greatly emphasize one form of energy over the other
based on its own agenda has dissipated both because of the competitive nature of
the energy market, which requires utilities to meet customer energy supply
requirements or risk losing the customer to a competing supplier, and because
state regulators will have sufficient control over, and would be unlikely to
approve, a combination company that attempts to undertake such practices.
For all these reasons, the Commission should change its policy and approve
the retention by UE and CIPS of their respective gas properties as contemplated
by the Transaction. No policy would be furthered by requiring divestiture, and,
indeed, state and national policy would be thwarted by such a requirement.
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CONCLUSION
For the reasons set forth above, and in Ameren's Application and supporting
exhibits, it is respectfully submitted that the Commission should allow Ameren
to retain the gas utility operations of UE and CIPS following the consummation
of the Transaction and the registration of Ameren as a holding company under the
Act.
Jones, Day, Reavis & Pogue
July 15, 1997
22
